Wall Fracture Research Articles

Modeling proppant transport and settlement in 3D fracture networks in geothermal reservoirs

In this paper, we develop an efficient proppant transport model using the Eulerian-Eulerian approach for simulating proppant transport in fractures and 3D fracture networks in geothermal reservoirs. The proposed model accounts for proppant settling, pack/bed formation, bridging/screenout, proppant concentration effect, fracture wall effect, and the transition from Poiseuille flow (fracture channel) to Darcy flow (proppant pack). Notably, the heat transfer process and its impact on proppant transport are also considered—a facet often overlooked in previous proppant transport models. A three-dimensional displacement discontinuity method (3D DDM) that incorporates the stress shadow effect is employed to generate the fracture geometry. The governing equations for slurry flow, proppant transport, and heat transfer are discretized and solved using the finite volume method (FVM). The model is verified against analytical solutions and published experimental data, demonstrating good agreement with these references. To demonstrate the proposed model, we applied it to both low-temperature (depleted hydrocarbon wells) and high-temperature (dry hot rocks) enhanced geothermal systems (EGS). The simulation results highlight the significant influence of reservoir temperature on proppant transport and settlement in a reservoir environment. Heating of the slurry by higher temperature reservoir rocks reduces fluid viscosity and accelerates proppant settling, thereby shortening the transport distance and reducing the coverage area of the proppant. Both ultra-light and micro-proppant are effective in mitigating proppant settlement in enhanced geothermal systems. However, proppant is susceptible to bridging at fracture intersections, where the fracture widths are narrower due to more pronounced stress shadow effects in these areas. Consequently, the use of micro-proppant could offer substantial benefits over ultra-light proppant in enhancing proppant coverage area in enhanced geothermal systems.

Image Restoration of Electrical Well Logging Based on Fourier Convolution

Imaging logging is an important technical means in logging evaluation of complex reservoirs. Through imaging logging, a two-dimensional image of the resistivity distribution around the well can be obtained, which can be used to evaluate the development of well wall fractures and caves and the formation sedimentary structure. However, due to the characteristics of resistivity imaging logging instruments, blank strips will appear on the resistivity logging image, which increases the difficulty of computer processing of electrical imaging data. The current image repair method and the existing neural network image repair method are not effective enough when the part to be filled is large. Therefore, there is an urgent need for an intelligent repair method based on deep learning. Based on a fast Fourier convolution-based imaging logging image blank strip filling network, this paper constructs the electrical imaging logging images of the southwest oil and gas field as a data set, and trains a new deep learning algorithm for intelligent filling of blank strips in imaging logging images based on fast Fourier convolution. The time of various algorithms is compared. The results show that the algorithm has a better repair effect in imaging logging images with large strip widths, and the repair efficiency is significantly improved. This method can realize the rapid, accurate and intelligent repair of blank strips in imaging logging, achieve the rapid generation of full-borehole images, and solve the difficulties in obtaining full-borehole images.

Quantification of immiscible displacement in a rough-walled fracture through direct visualization

Subsurface substance migration in the fractured rock aquifer is mainly controlled by fractures, and immiscible fluid-fluid displacement in fractures is important to many geophysical processes and engineering activities. Using a fracture-visualization system, we present the qualitative and quantitative assessment of fracture geometry associated with fluid movement and distribution in the rough fracture. Based on fracture geometry and statistical analysis, we first conducted a quantitative study of fracture surface roughness and aperture distribution. Then, fractal dimensions of displacement front and residual oil distribution were determined by image processing procedures. Influenced by wettability and micro-scale roughness, at the end of the displacement, residual oil saturation of molded sample is lower (6.45%–25.74%), and displacement pattern is more uniform, indicating that displacement effect is better. Due to smaller differences in residual oil saturation (9.08%) under different injection directions, the impact of wettability on the displacement process is greater than that of anisotropic roughness. Additionally, the fractal dimension of the displacement front increased under low injection rates initially but decreased when the rate was increased later. Overall, visualized temporal monitoring of experimental images enabled us to provide a preliminary assessment of the impact of anisotropic roughness and the material constituting the fracture wall on invading fluid saturation and the fractal dimension of the displacement front under various injection rates.

Characteristics and effectiveness of deep and ultradeep tight sandstone fractures: Insights from geologic and geophysical data analysis

Effective natural fractures are those that contribute to reservoir storage and conductivity. In this study, the effectiveness of fractures in deep and ultradeep reservoirs (depths > 6 km) is evaluated by using geophysical image logs, cores, microstructures, mechanical tests, and geologic evidence of the tectonic context (including current in situ stress) and sedimentary faces and diagenesis. Intraformational open-mode fractures are the most common fracture type in this tectonically active region, and their effectiveness is affected by the coupling between past tectonic activity, in situ stress, and chemical reactions such as mineral precipitation or dissolution (diagenesis). Our results show that the effectiveness of fractures is mainly related to the aperture and filling, and fractures formed by early tectonic movement are more likely to be filled by minerals, reducing their effectiveness. Strata near orogenic belts in strongly cemented, tight diagenetic facies exhibit a greater abundance of mineral-filled fractures, whereas dissolution increases the fracture apertures, produces secondary pores in host rocks, and roughens the fracture walls. The effective normal stress acting on the fracture surface decreases when the fracture is parallel to the maximum horizontal stress component, so the fracture has a large aperture and, therefore, is more effective. The results of our laboratory measurements reveal that the contribution of fractures to the reservoir space is limited, and the reservoir space provided by fractures accounts for only 13% of all types of reservoir space, whereas the presence of fractures increases reservoir permeability by 1–2 orders of magnitude. Fractures improve the effectiveness of the reservoir by connecting the dispersed pores in the reservoir matrix. Fractures with a low angle to the maximum horizontal stress component have greater apertures and permeabilities and are the main channels for fluid flow.

Self-growing biomimetic functional hydrogel particles for conformance control in tight reservoir fracture network

Hydraulic fracturing is gradually becoming a common approach for enhancing the oil production from tight reservoirs. Blocking agents such as soft particle systems are necessary as a means of conformance control to mitigate the side effect of reservoir heterogeneity due to hydraulic fracturing. In this work, a novel technique based on the mussel biomimetic concept is proposed to generate self-growing biomimetic functional hydrogel particles (SG-BFHPs). The fracture conformance control capacity of the products is evaluated, and the results show that multi-scale (0.5–3.0 mm) SG-BFHPs can cohere and grow at the reservoir condition, and the median agglomerated particle size can increase by 20–25 times. High flow resistance (Frr = 10.7–11.8), facilitated by the higher adhesion between the biomimetic particles and the pore walls, can be established by SG-BFHPs while maintaining a good injectivity. In the single-fracture model, the increased oil recovery by SG-BFHPs is about 12.2 %, and in the matrix-fracture model can be increased from 9.2 %–13.5 % to 25.8 %–28.8 %. AFM experiments show that SG-BFHPs have stronger adhesion between particles or rock surface than conventional hydrogel particles. After conformance control of SG-BFHPs, the particles are distributed in an irregular structure in the fractures and adsorbed on the fracture wall under the effect of inter-particle cohesion and adhesion, which can realize fracture channel adjustment by the particle self-growing. The SG-BFHPs studied in this paper provide valuable insights for the development of dispersed particle gel, which is of great significance in improving oil recovery in tight reservoirs.

Steady-state relative permeability measurements in rough-walled fractures: The effects of wettability and aperture

Tight subsurface geosystems provide significant prospects for the recovery and storage of mass and energy. Because of the tightness of these systems, natural and engineered fractures are the main conveyance conduits transporting the fluids from the tight rock matrix to the wellbore or vice versa. During the fracturing process, most of the newly induced fractures are considered water-wet, however during injection/production, the wettability of the fractures gradually changes. These changes are mainly due to the interactions between the resident and injected fluids, or the exposure of the virgin fracture surfaces to the resident fluids during production. This alteration in wettability can affect the trapping and flow dynamics, e.g., relative permeability, of the fluids flowing in the fracture. Furthermore, fluid injection and production into and from these systems impact the fractures pore pressure and hence the effective stress they are exposed to, resulting in variations in the fracture aperture. In this study, we present a comprehensive macro-scale experimental investigation focusing on the impact of wettability and aperture on steady-state two-phase relative permeability in rough-walled fractures. Using the stead-state measurement technique, we meticulously characterized oil-brine relative permeabilities and residual trapping in water-wet, oil-wet, and mixed-wet rough-walled fractures induced in Eagle Ford shale rock samples. Additionally, we assessed the influence of fracture aperture size on these properties during both drainage and imbibition flow processes. Our results indicate significant phase interference in oil-brine flow in non-water-wet rough-walled fractures, which renders the commonly used x-curve and Corey models inadequate to represent the steady-state oil-brine relative permeabilities measured in our study, leading to substantial overestimations. Mixed-wet fractures exhibited reduced relative permeabilities compared to oil-wet fractures, which in turn demonstrated lower relative permeabilities than water-wet counterparts. The observed trends stem from evolving fluid configuration and transport dynamics within the fractures as surface wettability transitions. Furthermore, an increase in fracture aperture corresponded with an increase in relative permeability. This was attributed to a broader flow area, diminished capillarity, attenuated impact of fracture wall roughness and tortuosity effects, and a reduction in bypassing and trapping events, all synergistically contributing to the mitigation of phase interference. Similarly, an increase in fracture aperture led to a marked decrease in post-waterflooding endpoint oil saturation and post-oil flooding endpoint brine saturation. Finally, we provided generalized correlation models based on experimental results from fractures with varying conductivities and wettability, yielding a more accurate representation of fracture relative permeabilities compared to traditional models. The data and correlation models produced in this study improve our understanding and prediction of multiphase flow in subsurface fractures and offer insights into rapid production decline in unconventional shale reservoirs.

The flow and heat transfer characteristics of supercritical mixed-phase CO2 and N2 in a 3D self-affine rough fracture

Utilizing a three-dimensional self-affine function, we constructed the fracture morphology and established a numerical model considering the thermal-hydraulic coupling (TH) mechanism to simulate the flow and heat transfer processes of CO2 and N2 in a single fracture under supercritical mixed-phase conditions in dry hot rock. The fractal dimension of the fracture was set to 2.5, and the Joint Roughness Coefficient (JRC) roughness coefficient was 13.71. The model accurately simulated the flow and heat transfer processes of supercritical mixed-phase CO2 and N2 fluids within the fracture under the conditions of 50 MPa underground pressure, 200 °C rock exterior temperature, initial temperature of 32 °C for the heat transfer fluid, and inlet velocities ranging from 0.005 to 0.03 m/s. The results revealed that the output thermal power curves for nine different ratios of CO2 and N2 could be classified into three categories.Among the four conventional thermodynamic parameters, specific heat capacity and density significantly impacted output thermal power. The convective heat transfer process between the fluid and the rock wall resulted in temperature fluctuations, primarily influenced by the sharp edges of the fracture wall. As the inlet velocity increased, the outlet-inlet temperature difference monotonically decreased. The fluid with a composition of 45 % N₂ and 55 % CO₂ exhibited the smallest reduction in temperature, with a value of 50.52 °C. Meanwhile, the output thermal power monotonically increased, with the fluid composition of 5 % N2 and 95 % CO2 experiencing the most significant increase, reaching 122.22 W.

Simulation of Microcapsule Transport in Fractured Media Using Coupled CFD‐DEM

AbstractGeothermal energy is sustainable and gaining momentum as a solution to energy crises and environmental issues. However, challenges like production temperature and thermal breakthrough can impact geothermal project efficiency. One innovative solution to alleviate the thermal breakthrough is to inject polymer‐based materials that are encapsulated in microcapsules into fractures to modify fracture permeability and prevent preferential flow. In our study, we utilized a coupled computational fluid dynamics and discrete element method to simulate the transport of microcapsules under various scenarios controlled by microcapsule size, microcapsule concentration, and fracture roughness. For a smooth fracture, the results indicate that small microcapsules can travel through a smooth fracture regardless of their concentrations. Large microcapsules can transport through a smooth fracture when present in lower concentrations. However, medium and mixed‐size microcapsules tend to cause the sealing of a smooth fracture, irrespective of their concentrations. For a rough fracture, the transport of microcapsules is complicated by their interactions with the rough fracture walls. The presence of two sealing positions in a rough fracture adds further complexity to this transport phenomenon. The size and concentration of microcapsules control one sealing location, while the rough fracture walls determine the other sealing location. The rough walls substantially affect microcapsule transport, rendering the role of microcapsule size and concentration less significant. The simulation results suggest that complex fracture surfaces significantly elevate the occurrence of sealing behavior. To mitigate sealing behavior within more complex fractures, it would be beneficial to use smaller and lower concentrations of microcapsules.

Numerical Simulation of Proppant Transport in Transverse Fractures of Horizontal Wells

Proppant transport and distribution law in hydraulic fractures has important theoretical and field guidance significance for the optimization design of hydraulic fracturing schemes and accurate production prediction. Many studies aim to understand proppant transportation in complex fracture systems. Few studies, however, have addressed the flow path mechanism between the transverse fracture and horizontal well, which is often neglected in practical design. In this paper, a series of mathematical equations, including the rock elastic deformation equation, fracturing fluid continuity equation, fracturing fluid flow equation, and proppant continuity equation for the proppant transport, were established for the transverse fracture of a horizontal well, while the finite element method was used for the solution. Moreover, the two-dimensional radial flow was considered in the proppant transport modeling. The results show that proppant breakage, embedding, and particle migration are harmful to fracture conductivity. The proppant concentration and fracture wall roughness effect can slow down the proppant settling rate, but at the same time, it can also block the horizontal transportation of the proppant and shorten the effective proppant seam length. Increasing the fracturing fluid viscosity and construction displacement, reducing the proppant density and particle size, and adopting appropriate sanding procedures can all lead to better proppant placement and, thus, better fracturing and remodeling results. This paper can serve as a reference for the future study of proppant design for horizontal wells.

New correlations to estimate the rough fracture permeability using computational fluid dynamics simulation

In fractured reservoirs, the fracture network provides the main path for fluid flow. Appropriate estimation of the fracture permeability influences the precise prediction of the reservoir’s future performance. Commonly, for a known geometry of natural or induced fracture, the permeability is estimated by applying local cubic law. One major drawback of this approach is that the fracture surface roughness, which has a significant effect on fracture permeability, is not considered. Moreover, the knowledge about the impact of fracture surface roughness on fracture permeability is not currently sufficient. In this research, the fluid flow in fractures with rough-walled surfaces was studied using computational fluid dynamics. For this purpose, the fluid flow through fractures was simulated by applying appropriate roughness for fracture walls. Furthermore, two correlations, based on response surface methodology and power-law models, were proposed to predict fracture permeability as a function of four independent variables (surface roughness, fracture aperture, angle, and porosity). The results of the two presented correlations were validated, and the statistical analysis indicates that both models are appropriate to predict fracture permeability. The findings of this study will be of great assistance with understanding and characterization of the fluid flow in rough fractures and can be used in future works.

Study on the Flow Behavior of Gas and Water in Fractured Tight Gas Reservoirs Considering Matrix Imbibition Using the Digital Core Method

Tight gas reservoirs possess unique pore structures and fluid flow mechanisms. Delving into the flow and imbibition mechanisms of water in fractured tight gas reservoirs is crucial for understanding and enhancing the development efficiency of such reservoirs. The flow of water in fractured tight gas reservoirs encompasses the flow within fractures and the imbibition flow within the matrix. However, conventional methods typically separate these two types of flow for study, failing to accurately reflect the true flow characteristics of water. In this study, micro-CT imaging techniques were utilized to evaluate the impact of matrix absorption and to examine water movement in fractured tight gas deposits. Water flooding experiments were conducted on tight sandstone cores with different fracture morphologies. Micro-CT scanning was performed on the cores after water injection and subsequent static conditions, simulating the process of water displacement gas in fractures and the displacement of gas in matrix pores by water through imbibition under reservoir conditions. Changes in gas–water distribution within fractures were observed, and the impact of fracture morphology on water displacement recovery was analyzed. Additionally, the recovery rates of fractures and matrix imbibition at different displacement stages were studied, along with the depth of water infiltration into the matrix along fracture walls. The insights gained from this investigation enhance our comprehension of the dynamics of fluid movement within tight gas deposits, laying a scientific foundation for crafting targeted development plans and boosting operational efficiency in such environments.

Numerical characterization of acid fracture wall etching morphology and experimental investigation on sensitivity factors in carbonate reservoirs

Carbonate reservoirs are marked by their low porosity and permeability, naturally occurring fractures that develop in a stochastic fashion and exhibit significant heterogeneity. Deep acidification techniques are essential for the efficient development of such oil and gas reservoirs. The effective distance of acid etching (acid etch fracture length) and the fracture conductivity stand as the two most critical parameters for assessing the efficacy of acidizing. The primary objective of using this technique is to extend the effective distance of the acid etch and enhance the fracture conductivity. The "relay-style" full-length acid etched fracture testing method is employed, achieving an accurate match between the testing temperature, pressure, fracture length, and the actual acid fracturing conditions. It employs a large-scale rock plate acid etching experimental device, in conjunction with 3D laser scanning technology, and utilizes orthogonal experimental design methods to conduct detailed numerical characterization of the rock plate fracture surfaces before and after etching with various acid fluid types, acid injection amounts, and acid injection rates. It quantifies the change in the concentration of the residual acid fluid after the acid-rock reaction, calculating the etching volume of the acid fluid and the length of the acidizing fracture. The experimental results demonstrate that both the gelled acid and the clean diverting acid exhibit long acidification distances and strong inhomogeneous etching capabilities. The etch morphology of the clean diverting acid is dominated by pitting-type and stripe-like dissociation, exhibiting a wavy pattern. In contrast, the etch morphology of the gelled acid appears band-like and groove-like. As the acid injection amount increases, the etch length increases. Under on-site working conditions, etch lengths of 46.42 m and 41.63 m were recorded for 20% gelled acid and clean diverting acid, respectively, after 60 min acid injection time. The factors affecting the etch length sensitivity are in the following order: acid injection rate > acid type > etching time. The optimal acid fracturing parameters to achieve the maximum etch length are: The etch is performed at a pump rate of 600 mL/min for 90 min using gelled acid. Quantitative characterization of acid etch fracture morphology can optimize designing parameters of acid fracturing techniques, enhance the efficiency of their modification, and further enhance the development benefits of oil and gas carbonate rock reservoirs.

Numerical Simulation of Proppant Transport in Major and Branching Fractures Based on CFD-DEM.

This research investigated the effect of branching fracture, proppant, and fracturing fluid on proppant transport based on the CFD-DEM coupling model. The obtained results show that the balance height of embankment in the major fracture decreases gradually with increasing angle between major and branching fractures, while it increases gradually in the branching fracture. This is because the additional resistance of fracturing fluid flow at the joint increases with increasing angle, leading to the decrease of the fracturing fluid velocity. The proppant is prone to settling in branching fractures, resulting in the increase of embankment height in the branching fracture. At angles of 45, 60, and 90°, as the diameter of the proppant increases from 0.8 to 1.1 mm, the balance height of embankment increases slightly in the major fracture, while it decreases in the branching fracture. The frictional resistance of the fracture wall enhances the difficulty of large proppant entering the branching fracture, resulting in a decrease in the amount of proppant entering the branching fracture and a decrease of the balance height of embankment in the branching fracture. In the low-viscosity fracturing fluid, the proppant quickly deposits at the bottom of the fracture as it enters the fracture. Improving the viscosity of the fracturing fluid can significantly enhance its ability to transport the proppant. The proppant is less likely to quickly settle in high-viscosity fracturing fluids, especially when the fracturing fluid viscosity exceeds 50 mPa·s.

Fracture Morphology Influencing Supersonic CO2 Transport: Application in Geologic CO2 Sequestration

AbstractGeologic carbon sequestration requires CO2 injection into the storage formation at high‐injecting pressure. Such high pressure could induce choked flow accompanying huge variations in thermodynamic properties of CO2 at a converging‐diverging (CD) fractures in the storage formation. In this study, high‐velocity CO2 transport through CD fractures was investigated to quantify the effect of fracture morphology on occurrence of both choked flow and shockwave that constrain the mass flow rate of fluid. In addition, variations in thermodynamic CO2 properties including Mach Number (Ma), defined by the ratio of fluid velocity to sound speed, and shock properties were investigated. The morphological characteristics of CD fractures were determined by nine properties, such as throat diameter, throat length, inlet diameter, outlet diameter, throat diameters of two‐connected CD fractures, fracture wall curvature, roughness amplitude, and frequency. As a result, the throat diameter crucially affected choked flow occurrence and maximum Ma. When the inlet and outlet diameters varied, the profiles for Ma variation were consistent in the converging and diverging segments, respectively. In addition, regardless of change in the throat length, the position of maximum Ma was nearly constant with showing the position length ratio of 0.13–0.14. However, roughness of fracture wall significantly influenced the Ma variation and occurrence of shock. In particular, backflows segregated from the main CO2 flow were observed near the wall roughness.

The migration mechanism of temporary plugging agents in rough fractures of hot dry rock: A numerical study

Plugging and diverting fracturing is a promising technology that aims to enhance the heat extraction efficiency in hot dry rock. The key to the success of this technique is the formation of effective plugging zones in existing fractures. However, given the high temperature and high stress of hot dry rock, the migration and sealing mechanisms of temporary plugging agents in such reservoirs are quite different from those in conventional tight reservoirs. Using the computational fluid dynamics/discrete element method coupled method, this paper numerically investigates the migration mechanism of temporary plugging agents in rough fractures of hot dry rock. First, we construct a model of a rough fracture surface in hot dry rock by performing computerized tomography scanning. Second, we adopt the well-established theory of the joint roughness coefficient to describe the fracture surface roughness. Then a discrete phase model that considers the effect of temperature is constructed to characterize the interparticle interaction of temporary plugging agents. A bidirectional coupling algorithm between the fluid flow in the fracture and the migration of temporary plugging agent particles is adopted. Finally, the effects of key factors such as fracture wall temperature, fracture roughness, injection angle, and injection location on the migration mechanism of granular temporary plugging agents in rough fractures are analyzed in detail. The results show that fracture roughness and temperature have a significant impact on the migration process in hydraulic fractures. When the fracture surface roughness increases by 10.44 as measured by the joint roughness coefficient, the particle force and particle temperature increase by 12.0% and 37.8%, respectively. When the fracture surface temperature increases by 200 K, the particle force and particle temperature increase by 88.2% and 14.4%, respectively.

Numerical simulation of stress field reorientation in multi-fractures

Understanding the stress state caused by a subsequent failure is crucial for successful refracturing. However, there are many differences between the stress reorientation phenomena of a multi-fracture horizontal well and that of a single fracture in a vertical well, including the interaction of multi-fractures. These factors can lead to a change in the stress field of multiple fractures, which is more complex than that of a single fracture. In this paper, based on the elastic theory of porous media and the mechanism of fluid–structure interaction, a finite element numerical model of multi-fracture stress fields is established. The net pressure loaded on the fracture wall was corrected using the fracture line model, which was solved using the separated coupling method with a staggered strategy, and a full coupling simulation of fluid flow and rock deformation was achieved. The results showed that with an increase in production time, the stress reorientation area around the fracture and at both ends first increased at a faster rate, then slowly decreased, and finally disappeared,indicating an optimal refracturing time window. This suggests that the greater the number of fractures, the greater the fracture inclination and fracture bending degree, and the more unfavorable it is for the formation and maintenance of the stress reorientation area near the fracture and at both ends of the fracture. The reorientation of the stress field between horizontal wells may lead to the fracture of the infill wells, causing bending and propagation towards the pressure-depletion area, thus reducing productivity.

A multi-method investigation of the permeability structure of brittle fault zones with ductile precursors in crystalline rock

Brittle faults and fault zones are among the most hydraulically active elements in predominantly impermeable crystalline host rock. They pose a significant challenge to underground infrastructure like nuclear waste repositories. Brittle fault zones frequently occur along pre-existing ductile shear zones as they introduce weakness planes in the rock.Four brittle fault zones of ductile origin were analyzed in the Rotondo Granite at the “BedrettoLab” in the Swiss Central Alps. Scanline mapping, rock sampling and permeability measurements using three different methods provide detailed insights into the heterogeneous fault zone architecture and hydrogeology. Average intact rock permeability is in the range of 10−19 to 10−17 m2. Fluid flow is channeled into single open or partially mineralized fractures of, at point-scale, up to 10−14 m2, demonstrated by selective gas probe permeameter measurements and borehole hydraulic testing. Reduced permeabilities have been measured in close proximity to these permeable features, indicating alteration of and around the fracture walls.

2-D Modeling of hyperconcentrated fluid flow in curvilinear coordinates: dam break study

The hyperconcentrated fluid flow occurs as a result of heavy rainfall, during which a large amount of sediments from the upstream basin is washed away and suddenly increases the flow concentration of the alluvial channels. The stresses exerted by this type of fluid on the bed and body of the stream/river and related structures such as dam lead to the failure them and cause many human and financial losses. One of the important topics in the simulation of dam break caused by non-Newtonian fluid flow is the modeling of frictional stresses. In this research, after collecting several relationships to model the coefficient of friction loss of non-Newtonian fluid, a two-dimensional model was developed based on the numerical solution of shallow water equations in curvilinear coordinates to simulate hyperconcentrated flow. The results of the validation of the model were presented by comparing the measurement data of the suddenly complete dam break caused by the non-Newtonian fluid flow in the form of graphs, which all emphasize the accuracy of the developed model. It was also shown that for a suddenly complete dam break, with an increase in fluid volume concentration from 13.8 to 36.4%, the flow depth at the failure site increases by 18.8%. Next, asymmetric two-dimensional partial dam break of non-Newtonian fluid was simulated and compared with the results of Newtonian fluid. The results showed that the maximum flow velocity in the center of the fracture wall for the non-Newtonian fluid with a concentration of 32.2% is less than half of the maximum velocity of the Newtonian fluid.

A modified SPH framework of for simulating progressive rock damage and water inrush disasters in tunnel constructions

To date, numerically simulating the Fluid–Solid Interaction (FSI) and the entire process of host rock damage and water inrush involved in tunnel construction relies intensively on hybrid methods of two or more numerical codes, which commonly encounter deficiency in learning, modelling and computation. A modified framework of Smoothed Particle Hydrodynamics (SPH), the Coupled Discontinuous SPH (CDSPH) method, was developed to simulate cracking, contacting and large deformation of rock blocks, free surface flow and the FSI for water/mud inrush disasters in tunnel construction through water–rich stratums. The failed SPH particles were transformed to discontinuous particles and new contacts between these particles were formed to simulate the frictional slip and separation/compression between fracture walls. The improved SPH method was employed to a water inrush case of a tunnel and the simulation results indicate that the entire process of progressive rock damage, water inrush and flooding are precisely reproduced by the improved method. The greater kinematic viscosity of fluids and rock wall thickness can increase the flow velocity and hence increasing the impact pressure of floods, and the failure pattern of the rock wall changes from partial outburst to complete failure. Vulnerability analysis of the water inrush reveals a complete damage status for people, vehicles and Non-RC frame buildings, and a moderate to complete damage to RC frame buildings at the tunnel portal. This single code is capable of simulating the behaviour of rocks, fluids and their interactions in catastrophic disasters that is potentially applicable to a wide spectrum of surface and subsurface problems involving FSI.

Modelling of hydrofracturing experiments of granite samples

Based on laboratory experiments and numerical modelling, the propagation of hydraulic fracturing fractures in cylindrical granite samples caused by viscous fluid pumping is described. Comparison of simulation results and laboratory measurements show that the fracture hydraulic resistance much greater than the one predicted by the cubic law that is usually used in hydraulic fracture models. If this hydraulic resistance is not taken into account, the pressure, volume and speed of fracture propagation are predicted incorrectly. It is shown that additional hydraulic resistance can be caused by the fracture walls roughness and can be taken into account by velocity correction factor.