Proppant Density Research Articles

The mechanism of proppant transport dynamic propagation in rough fracture for supercritical CO2 fracturing

Supercritical CO2 fracturing technology has shown great potential for enhancing production in unconventional reservoirs. It is essential to clarify the transport mechanism of proppant under the dynamic propagation conditions within rough fractures. A realistic rough fracture model is reconstructed, and Computational Fluid Dynamics simulations are conducted to track proppant movement during fracture propagation. The typical transport characteristics of proppant within rough fractures are revealed, and the effects of fracture propagation rate, proppant density, mass flow rate, particle size, sand ratio, and temperature on the support effect are discussed. The results show that the flow channels formed by sand carrying fluid in rough fractures are complex, with fracture propagation changing some flow channels. The proppant forms an irregular sand bed interspersed with unfilled areas, and complex flow characteristics are generated. The increase in fractal dimension increases the resistance in the fluid flow process and affects the movement of the proppant, which tends to create unfilled areas. Low density and size of proppant can improve the proppant placement length. In a certain temperature range, high temperature injection of sand carrying fluid can improve the proppant placement effect. In addition, the low sand ratio and high mass flow rate pumping can be used to form the dominant channel, followed by pumping with a high sand ratio and low mass flow rate for effective support.

Proppant transport in secondary Sand fracturing using Eulerian-Eulerian multiphase model Approach

Secondary sand fracturing, an innovative hydraulic fracturing technique, divides the injection of proppant into two stages, altering the reservoir's rock mechanics and fracturing fluid flow paths, thus effectively controlling fracture creation and improving the effectiveness of proppant placement. This methodology facilitates fracture height control and enhances fracture conductivity, benefiting production rate. Despite abundant literature on proppant transport, limited attention has been paid to exploring the specific aspects of secondary sand fracturing. In this study, the Eulerian-Eulerian multiphase model was used to simulate the proppant transport in secondary sand fracturing for the first time. This model accounts for turbulence and the interplay between proppant particles, thus enabling a comprehensive integration of fluid and particulate phases. The effects of proppant performance, fracturing fluid performance, and fluid flow rate on proppant placement were analyzed. In the first sand-addition stage, an innovative sanding index was proposed to evaluate the effectiveness of proppant placement. Combined with the orthogonal experiment, the fluid flow rate significantly influences proppant placement. An escalated flow rate augments both the sandbank leading edge and laying lengths, concurrently diminishing the equilibrium height and the sanding index. In the second sand-addition stage, the equilibrium height increases with the increase of sand ratio, decreases with the increase of flow rate and fluid viscosity, and first increases and then decreases with the increase of particle size and proppant density. This study enriches the comprehension of proppant placement and its governing elements within hydraulic fracturing, thereby furnishing a more empirical and theoretically sound foundation for optimizing secondary sand fracturing practices.

Experimental Study on Proppant Migration in Fractures Following Hydraulic Fracturing

Complex fracture technology is key to the successful development of unconventional oil and gas reservoirs, such as shale. Most current studies focus on how to improve the complexity of the fracture network. It is still unclear whether proppant can enter the branch fractures at all levels after the formation of complex fractures. The effects of construction displacement, proppant particle size, proppant density, fracturing fluid viscosity, sand ratio, and other factors on proppant migration in single fractures and complex fractures were studied using an experimental device independently developed by the laboratory. The results show that the lowest point height of the sandbank and the equilibrium height of the sandbank are directly proportional to the particle concentration and density, respectively, and inversely proportional to the displacement and fracturing fluid viscosity. The equilibrium time of the sandbank is inversely proportional to the displacement, particle concentration, and density, respectively, and proportional to the viscosity of the fracturing fluid. Under the same experimental conditions, the larger the branch angle, the smaller the height of the main/secondary fracture sandbank. In the design of the fracturing process, fracturing fluid with varying viscosities and proppant with different densities should be selected according to the formation conditions and fracturing targets. In the face of long fracture lengths, the combination of low-viscosity fracturing fluid with an appropriate viscosity and low-density proppant can meet the goal of placing proppant over long distances and effectively supporting fractures over extended lengths. Subsequently, high-density proppant or reduced construction displacement are adopted to usefully support fractures in the near-wellbore area. The results of this paper can provide theoretical support for proppant selection and fracturing program design.

Study of proppant plugging in narrow rough fracture based on CFD–DEM method

In unconventional reservoirs, hydraulic fracturing often results in narrow and rough fractures. Nevertheless, the placement in narrow rough fractures is different from conventional fractures. This study utilizes the spectral synthesis method to model these fractures, employing a validated CFD-DEM method to investigate proppant transport within them. The research identifies blocky dunes in narrow rough fractures which are different from the continuous dunes. Furthermore, the study observes additional phenomena including local generations of plugs and automatic collapses of plugs. Changing proppant density leads to the formation of complete plugs. Additional CFD-DEM simulations involve that injecting high-velocity pure fluid can unblock the plugs. Finally, the study explores the effect of fluid viscosity on unblocking and establishes a new phase diagram to guide how to unblock the plugs on-site. This work enhances our understanding of how sand-plugging happens in rough narrow fractures and helps propose effective measures for mitigating sand-plugging issues.

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.

Numerical simulations of proppant transportation in cryogenic fluids: Implications on liquid helium and liquid nitrogen fracturing for subsurface hydrogen storage

The over dependence on fossil fuels for human energy requirements together with the resultant adverse environmental effects in the form of greenhouse gas discharges has redirected our attention towards renewable energy sources. Researchers have identified hydrogen, a non-carbonaceous energy source holding the capacity to substitute fossil fuels, as a viable fuel option that has the potential to be generated utilizing eco-friendly techniques. Studies have identified underground sites that are operational or have the potential to be used for hydrogen storage. Shale formations, characterized by their low permeability, offer promising opportunities for underground hydrogen storage. These formations require stimulation techniques to generate flow channels. Pumping frac-fluid into these formations at high pressure induces fractures in them and the engineered fractures are supported by the proppants injected along with the fluid. Propped fractures form a vital conduit in unconventional gas reservoirs, which are a potential medium for storage of hydrogen. Cryogenic fracturing is an innovative approach that aims to enhance and broaden the capabilities of conventional hydraulic fracturing processes. The transmission and settlement of proppants are influenced by certain critical aspects including their density, size and volume fraction and fluid velocity, which are investigated in this contribution. This study incorporates water and cryogenic fluids like liquid nitrogen (LN2) and liquid helium (LHe) as fracturing fluids. The primary objective of this effort is to analyze proppant transportation phenomenon and the key influential factors in LN2 and LHe. The proppant volume fraction contour, equilibrium dune level (EqDL) and dune height (EqDH) data are illustrated in this research for better understanding of proppant migration. It was observed that when the fracturing fluid is given a higher velocity, the proppant grains experience increased drag force, causing them to penetrate deeper into the fracture. The desired range of proppant volume fraction for improved grain transmission was determined as 0.45 to 0.50 and the critical proppant density that significantly affected the EqDL as 187.2839 lb/ft3.

Sand-Carrying Law and Influencing Factors in Complex Fractures of Nano-Clean Fracturing Fluid

Nano-clean fracturing fluids have broad application potential in coalbed methane reservoir fracturing owing to their high stability, good temperature resistance, low filtration loss, and strong frictional resistance reduction. However, the sand-carrying regularity of nano-clean fracturing fluids in coalbed methane reservoirs is unclear, especially for complex fractures with variable directions. This study established a sand transport model that considers proppant collision, wall friction blocking, fracture fluid filtration loss, and the fracture branching angle to study the sand-carrying law of nano-clean fracturing fluids and its influencing factors in complex fractures. The degrees of influence on equilibrium height and placement rate from high to low were the proppant particle size, proppant density, fracturing fluid properties, sand ratio, and pumping discharge volume, and the correlation degrees obtained by grey correlation analysis are 0.862, 0.861, 0.855, 0.854, and 0.832, respectively. As the complexity of the fractures deepens and the resistance increases, the flow rate of the fracturing fluid is reduced, making it difficult for the proppant to enter the branching joints. The sand-carrying performance of a nano-clean fracturing fluid is better than that of a common clear-water fracturing fluid. The fluid-structure coupling model of a nano-clean fracturing fluid can accurately characterize the sand-carrying law of nano-clean fracturing fluids, providing a research basis for optimizing high efficiency sand-carrying fracturing fluid parameters in coalbed methane reservoir fracturing construction.

Numerical simulation of proppant transport from a horizontal well into a perforation using computational fluid dynamics

With the increasing global demand for oil and gas, the development of unconventional resources such as shale gas is becoming ever more important. The key to developing unconventional oil and gas resources lies in horizontal wells with multistage fracturing technology. In the process of horizontal well segmentation fracturing, the distribution of the proppant among multiple clusters has a significant influence on the fracturing effect. However, the influence of various factors on the entry of proppant into the perforation and then into the fracture along the wellbore is unclear. In this paper, based on the flow characteristics of proppants in fracturing fluids, we investigate the wellbore–perforation proppant transport using a Eulerian multiphase flow model. The effect of different factors on proppant entry into the perforation in horizontal wells is studied. We first verify that the computational fluid dynamics model satisfies the accuracy requirements for studying the sand-carrying efficiency of proppants in a perforation cluster. Second, the effects of the proppant size, proppant density, fracturing fluid viscosity, perforation diameter, and fracturing fluid flow rate on the proppant transport efficiency are investigated. Finally, a mathematical model of the sand-carrying efficiency is established by multivariate nonlinear fitting. The results show that the proppant size has a more significant effect on proppant settling at low wellbore flow rates. Increasing the diameter of the proppant particles can accelerate proppant settling. Higher wellbore flow rates tend to reduce the sand-carrying efficiency, although using a low-density proppant can mitigate the effect of the wellbore flow rate. At low wellbore flow rates, increasing the perforation size makes it easier for the proppant to enter bottom perforations. Increasing the fluid viscosity helps to distribute the proppant evenly between perforations in different directions, but this effect diminishes as the flow rate increases. Finally, a formula for the wellbore sand-carrying efficiency is obtained and validated, providing a basis for optimizing the distribution of the proppant in the perforation. The results from this paper enhance our understanding of the sand and fluid feeding patterns of each perforation cluster and provide direction for improving the construction process and enhancing the fracture inflow capacity.

Proppant Transport Characteristics in Tortuous Fractures Induced by Supercritical CO2 Fracturing

Supercritical CO2 fracturing is an important development trend to reach the goal of "dual carbon" and avoid the problem that hydraulic fracturing is influenced by water resource. In order to clarify the transport characteristics of proppant in the fractures induced by supercritical CO2 fracturing, this paper reconstructs the fracture surface of rock samples after supercritical CO2 fracturing using the laser morphological scanning technology, and establishes a model of proppant carrying and transport of supercritical CO2 in tortuous fractures on the basis of CFD-DEM method. In addition, the transport and placement characteristics of proppant in tortuous fractures are analyzed by comparing with flat fractures, and the effects of proppant density, injection rate of proppant carrying liquid, proppant concentration and other key parameters on proppant transport and distribution in fractures are investigated. And the following research results are obtained. First, compared with those in flat fractures, the flow paths of the proppant carrying supercritical CO2 liquid in tortuous fractures are tortuous and diverse, and the proppant presents stronger fluctuations and jumps laterally and vertically during its transport. Second, the proppant placement in tortuous fractures morphologically presents a wavy or even clustered non-uniform distribution. Third, low-density proppant has a better pass-ability in tortuous fractures, and the high injection rate can reduce the influence of tortuous fracture structure on proppant blocking. Fourth, if the concentration of injected proppant in the tortuous fracture is too low, good fracturing support effect cannot be achieved, and the optimal value under the simulation conditions in this paper is around 3%. In conclusion, the simulation results are of important theoretical and engineering significance to understanding the mechanism of proppant blocking in the pumping process of proppant carrying liquid for supercritical CO2 fracturing and optimizing the field fracturing design.

Numerical Simulation of Proppant Transport and Placement in Hydraulic Fractures with the Hybrid Perkins-Kern-Nordgren-Carter (PKN-C) Model and Particle Tracking Algorithm

Summary Although non-Newtonian fracturing fluids have been widely used, numerical simulation of field-scale proppant transport considering non-Newtonian fracturing fluids is far from satisfactory. In this study, a novel numerical scheme based on the Eulerian-Lagrangian (E-L) method has been developed and validated to simulate such a proppant transport and placement behavior. More specifically, hydraulic fracture propagation is characterized by the Perkins-Kern-Nordgren-Carter (PKN-C) model, and the injected proppants are described using the classic particle tracking algorithm. Proppants are vertically dragged by the gravitational force and horizontally driven by the velocity field conditioned to the fracture propagation and proppant dune packing. The settling velocity of proppants is quantified considering the in-situ shear rate and concentration, while their transport at each dune surface is quantified by performing drag/lift force analysis. The numerical model is first validated by reproducing experimental measurements inside a visual parallel plate. Subsequently, field-scale simulations are performed to identify the factors dominating proppant transport and placement under various conditions. As indicated by simulated results, the accumulated concentration at the lower region of a fracture usually results in a growing proppant dune with a “heel-biased” distribution. The non-Newtonian fluid yields a higher slurry coverage together with a longer proppant dune than the Newtonian fluid when their average viscosities are consistent. In addition to the dependence of the premature tip screenout configuration on the power-law fluid parameter n, both parameters of K and n impose a generally consistent effect (on proppant transport) with that of Newtonian viscosity (i.e., an increase of either K or n effectively improves the average viscosity and mitigates the proppant settling). A mild increase in proppant density and size significantly enhances the proppant dune formation; however, a further increase of these two factors aggravates the “heel-biased” distribution of proppants. Also, an increased leakoff coefficient improves the overall proppant concentration as well as the dune and slurry coverage. The used particle tracking algorithm enables proppant transport to be individually and accurately evaluated and analyzed with an acceptable computational cost, while such a numerical model can deal with both the Newtonian and non-Newtonian fluids at the field scale. This numerical study allows us to optimize the growth, propagation, and coverage of proppant dunes for maximizing fracture conductivity during hydraulic fracturing operations.

Experimental Study on Proppant Transport within Complex Fractures

Summary The process of proppant filling within complex fractures is a key factor that determines the effects of volumetric fracturing operation in shale. To address the need of simulating proppant transport within the complex fractures, a large size visual simulation equipment of particle transport within complex fractures was built. The equipment considers roughness and fluid leakoff on the fracture wall and includes branched fractures of different angles. We ensured that the fluid flow and proppant flow were similar to those in the actual fracture and carried out experiments to obtain the influence of operation parameters and fracture parameters on proppant transport, also including injection of special proppants and channel fracturing. Then, we quantified proppant placement through standardized processing of dune shape pictures. The results show that under the influence of perforation, the near-wellbore dune is distributed in a slope shape, and an increase in the perforation density causes dune migration toward the wellbore and proppant accumulation to a certain height within the wellbore. The carrier fluid flow velocity change from 1.0 to 1.5 m/s within the fracture has the greatest effect on the dune equilibrium height (DEH). The dune height only varies slightly after the proppant concentration reaches 12%. Small size proppants have better transport capacity in the slickwater, and the large size proppants are likely to settle down. Combination injection of increasing proppant size improves the filling effect of complex fractures significantly. Pulse injection and stopping pump during fracturing operation have little effect on the transport of conventional proppants. Nevertheless, stopping pump leads to a significant increase in the dune height of the lower density proppants. An increase in the flow rate within the branched fracture leads to the transition in the dune shape from triangle to trapezoid and rectangle. The dune height within the major fracture determines those within the branched fracture, and the proppant volume flowing into the branched fracture determines the dune length. Proppant accumulation within the branched fracture enhances the difficulty in the diversion of carrier fluid to the branched fracture. The proppant tumble area increases within the inclined fracture, which is conductive to proppant transport. The proppants form the dune through bridging within the horizontal fracture, and the dune is less stable than that within the vertical fracture. A reduction in the proppant density and size leads to a significant increase in the proppant transport distance, and the convection effect by concentration difference of the ultralow-density (ULD) proppant is of great significance for propping of the microfractures. In channel fracturing, the proppant and fiber agglomerates are formed at the fracture point with the relatively large fluid leakoff and wall roughness, and the agglomerates grow laterally against the fracture fluid flow direction. A reasonable increase in the injection rate enhances the connectivity between the channels within the fracture. This study provides guidance for the optimization of volumetric fracturing parameters.

A novel model for the proppant equilibrium height in hydraulic fractures for slickwater treatments

The proppant equilibrium height is the basis of investigating proppant distributions in artificial fractures and has a great significant influence on hydraulic fracturing effect. There are two shortcomings of current research on proppant equilibrium heights, one of which is that the effect of fracture widths is neglected when calculating the settling velocity and another of which is that the settling bed height is a constant when building the settling bed height growth rate model. To fill those two shortcomings, this work provides a novel model for the proppant equilibrium height in hydraulic fractures for slickwater treatments. A comparison between the results obtained from the novel model and the published model and experimental results indicates that the proposed model is verified. From the sensitivity analysis, it is concluded that the proppant equilibrium height increases with an increasing proppant density. The proppant equilibrium height decreases with an increase in the slickwater injection rate and increases with an increase in the proppant injection rate. The increase in proppant diameter results in an increasing the friction factor, which makes proppant equilibrium heights decrease. Meanwhile, the increase in proppant sizes results in an increase in proppant settling rates, which makes the proppant equilibrium height increase. When the effect of the proppant diameter on settling rates is more significant than that on friction factors, the equilibrium height increases with an increasing proppant size. This work provides a research basis of proppant distributions during the hydraulic fracture.

A 3D tortuous fracture network construction approach to analyze proppant distribution in post-fractured shale

To reveal the proppant transport in the tortuous fracture network, a method introducing the normal distribution random function into the quartet structure generation set was proposed to construct the three-dimensional tortuous fracture networks. The tortuosity can be controlled by the variance of random function. And then, the proppant distribution in the tortuous fracture network was simulated with the consideration of the interact between slurry, fracture surface and proppants. Finally, effects of velocity and viscosity of slurry and the density and particle size of proppants on the proppant distribution in three different fracture networks were investigated. The accuracy of this model was verified by the experiment. The simulation reveals that besides the velocity decrease due to the fluid split, the slurry velocity also fluctuates because of the fracture width variation. The transport distance of proppants in tortuous fracture is about 10.7% shorter than that in the smooth fracture, while the distribution height is increased in the tortuous fracture network. Instead of forming the regular sand dune, the proppant is dispersively distributed in the tortuous fracture network. The proppant density and the slurry velocity are the main factors influencing the proppant distribution, followed by the slurry viscosity and proppant size. Proppant with smaller particle size can enter the area with narrow fracture width, so that the distribution of proppant in the fracture is more uniform. The research results can provide some guidance for the optimal design of slurry and pumping schedule in the hydaulic fracturing operation. • The slurry velocity in the main fracture fluctuates because of the fracture width variation. • The proppant is dispersively distributed in the tortuous fracture network. • Proppant density and slurry velocity are main factors influencing the proppant placement. • The structure and tortuosity of the fracture network also affect the proppant placement.

Influence of proppant physical properties on sand accumulation in hydraulic fractures

The proppant accumulation form in fractures is related to the formation conductivity after fracture closure, also closely related to the production rate of oil/gas wells. In order to investigate the influence of proppant physical properties on sand accumulation in fractures, a particle–fluid coupling flow model is established based on the Euler two-fluid model. Geometric parameters of a fracture in tight oil wells are approximately scaled in equal proportion as the physical model, which is solved by the finite volume method. And the model accuracy is verified by comparing with the physical experimental simulation in the literature. Results show that the higher proppant concentration corresponds to the faster particle sedimentation rate, and the greater sand embankment accumulation as well. However, the fluid viscosity will increase, inhibiting proppant migration to the deep part of the fracture. Reducing proppant density and particle size will enhance the fluidization ability of particles, which is conducive to the migration to the deep fracture at the initial stage of pumping. But, it is not beneficial to have a desirable accumulation state in the middle and later pumping stage, so it is difficult to obtain a higher comprehensive equilibrium height.

Quantitative Study on Bed Load Proppant Transport during Slickwater Hydraulic Fracturing

Abstract Bed load proppant transport is a significant phenomenon during slickwater hydraulic fracturing. However, the mechanism of bed load proppant transport is still unclear. In the present study, the proppant transport process during slickwater hydraulic fracturing was simulated with a coupled computational fluid dynamics- (CFD-) discrete element method (DEM) model, and the mechanism of the bed load proppant transport was analyzed. A model for calculating the mass flux of the bed load layer was proposed and verified with experimental results from the literature. The results show that bed load migration is an essential mechanism of proppant transport. When the shear force of fluid acting on the surface of the sand bank reaches the critical Shields number, the proppant in the upper layer of the sand bank begins to migrate in the form of bed load. The movement of the bed load layer increases the time for the sand bank to reach the equilibrium height. In addition, the mass flux of the bed load layer significantly affects the equilibrium height of the sand bank. The mass flux of the bed load layer decreases, and the equilibrium height increases as the proppant density, proppant diameter, or rolling friction coefficient and static friction coefficient of the proppant increase, but the mass flux of the bed load layer increases, and the equilibrium height decreases as the fluid viscosity increases.

Numerical Simulation on Proppant Transport in Fracture Junctions Affected by the Fracture Scale

Abstract The proppant distribution significantly affects the conductivity of fracture networks. However, the law of proppant transport in fracture networks is still unclear, and the influence of fracture scale on the proppant distribution has not been determined. Thus, in the present study, the influence of fracture scale was investigated, and the influences of approaching angle and width ratio on fluid split ratio were analyzed. An Eulerian–Eulerian model was utilized to simulate suspended proppant and bed load proppant migration in fracture junctions. Then, a sensitivity analysis was carried out to evaluate the parameters that may affect the proppant distribution pattern, such as injection velocity, fluid viscosity, and proppant density. The results show that the approaching angle and width ratio significantly influence the fluid split ratio in a small-scale fracture. Moreover, the effect of the approaching angle decreases with an increase in the fracture scale. The split ratio of suspended proppant increases with increasing sand ratio, fluid split ratio, and width ratio. The split ratio of bed load proppant increases with increasing injection rate, fluid viscosity, width ratio, fluid split ratio, and decreasing proppant diameter. In small-scale fracture junctions, the approaching angle affects the split ratio of suspended proppant or bed load proppant by influencing the fluid split ratio; however, the effect is inconspicuous in large-scale fractures. The increase in fluid split ratio with the fracture scale leads to an increase in the split ratio of suspended proppant or bed load proppant.

Numerical Investigation on Proppant–Water Mixture Transport in Slot under High Reynolds Number Conditions

Water hydraulic fracturing involves pumping low viscosity fluid and proppant mixture into the artificial fracture under a high pumping rate. In that high Reynolds number conditions (HRNCs, Re > 2000), the turbulence effect is one of the key factors affecting proppant transportation and placement. In this paper, a Eulerian multiphase model was used to simulate the proppant particle transport in a parallel slot under HRNCs. Turbulence effects in high pumping rates and frictional stress among the proppant particles were taken into consideration, and the Johnson-Jackson wall boundary conditions were used to describe the particle-wall interaction. The numerical simulation result was validated with laboratory-scale slot experiment results. The simulation results demonstrate that the pattern of the proppant bank is significantly affected by the vortex near the wellbore, and the whole proppant transport process can be divided into four stages under HRNCs. Furthermore, the proppant placement structure and the equilibrium height of proppant dune under HRNCs are comprehensively discussed by a parametrical study, including injection position, velocity, proppant density, concentration, and diameter. As the injection position changes from the lower one to the top one, the unpropped area near the entrance decrease by 7.1 times, and the equilibrium height for the primary dune increase by 5.3%. As the velocity of the slurry jet increases from 2 m/s to 5 m/s (Re = 2000–5000), the vortex becomes stronger, so the non-propped area near the inlet increase by 5.3 times, and the equilibrium height decrease by 5.2%. The change of proppant properties does not significantly change the vortex; however, the equilibrium height is affected by the high-speed flush. Thus, the conventional equilibrium height prediction correlation is not suitable for the HRNCs. Therefore, a modified bi-power law prediction correlation was proposed based on the simulation data, which can be used to accurately predict the equilibrium height of the proppant bank under HRNCs (mean deviation = 3.8%).

Numerical simulation of proppant transport in liquid nitrogen fracturing

Liquid nitrogen (LN) fracturing has the potential to reduce the breakdown pressure, avoid formation damage, and eliminate the water usage. However, the proppant-carrying capability of LN fracturing is still unknown since the properties of nitrogen vary significantly with the reservoir temperature and pressure. In this paper, we simulated the proppant transport during LN fracturing in a straight fracture. First, we built the proppant transport model based on a hybrid Eulerian Lagrangian Method. Then, we validated this model against published experimental data. Subsequently, we applied the model to elucidate the factors that affect the transport efficiency. Finally, suggestions for improving the proppant placement are given. The results show that the proppant-carrying capacity of nitrogen increases with the increasing migration distance during LN fracturing. Furthermore, the most effective way to improve the sand placement is reducing proppant density. The key findings can help to understand the proppant migration capacity during LN fracturing.

A Novel Hydraulic Fracturing Method Based on the Coupled CFD-DEM Numerical Simulation Study

For the development of tight oil reservoirs, hydraulic fracturing employing variable fluid viscosity and proppant density is essential for addressing the problems of uneven placement of proppants in fractures and low propping efficiency. However, the influence mechanisms of fracturing fluid viscosity and proppant density on proppant transport in fractures remain unclear. Based on computational fluid dynamics (CFD) and the discrete element method (DEM), a proppant transport model with fluid–particle two-phase coupling is established in this study. In addition, a novel large-scale visual fracture simulation device was developed to realize the online visual monitoring of proppant transport, and a proppant transport experiment under the condition of variable viscosity fracturing fluid and proppant density was conducted. By comparing the experimental results and the numerical simulation results, the accuracy of the proppant transport numerical model was verified. Subsequently, through a proppant transport numerical simulation, the effects of fracturing fluid viscosity and proppant density on proppant transport were analyzed. The results show that as the viscosity of the fracturing fluid increases, the length of the “no proppant zone” at the front end of the fracture increases, and proppant particles can be transported further. When alternately injecting fracturing fluids of different viscosities, the viscosity ratio of the fracturing fluids should be adjusted between 2 and 5 to form optimal proppant placement. During the process of variable proppant density fracturing, when high-density proppant was pumped after low-density proppant, proppants of different densities laid fractures evenly and vertically. Conversely, when low-density proppant was pumped after high-density proppant, the low-density proppant could be transported farther into the fracture to form a longer sandbank. Based on the abovementioned observations, a novel hydraulic fracturing method is proposed to optimize the placement of proppants in fractures by adjusting the fracturing fluid viscosity and proppant density. This method has been successfully applied to more than 10 oil wells of the Bohai Bay Basin in Eastern China, and the average daily oil production per well increased by 7.4 t, significantly improving the functioning of fracturing. The proppant settlement and transport laws of proppant in fractures during variable viscosity and density fracturing can be efficiently revealed through a visualized proppant transport experiment and numerical simulation study. The novel fracturing method proposed in this study can significantly improve the hydraulic fracturing effect in tight oil reservoirs.

Fracturing-Fluid Flowback Simulation with Consideration of Proppant Transport in Hydraulically Fractured Shale Wells.

Involving the fluid-particle hydrodynamic process and hydraulically created fracture network, fracturing-fluid flowback in hydraulically fractured shale wells is a complex transport behavior. However, there is limited research on investigating the influence of proppant transport on the fracturing-fluid flowback behavior and flowback data analysis. In this paper, a flowback model is developed to simulate the flowback behaviors of the carrying fluid and proppant from the recompacted fracture system in shale wells. The development of fluid pressure and proppant concentration profiles of the fractured shale well are presented. The fluid and proppant fluxes among the hydraulic primary fracture and the induced fracture are also calculated. The influences of proppant consideration or not, proppant density, proppant size, fracturing-fluid viscosity, and fracturing-fluid density on the flowback behavior are investigated. The simulation results are useful for fracturing-fluid optimization in the design phase. Finally, two field cases from the Longmaxi Formation, Southern Sichuan Basin, China are used for matching the actual flowback data with the model results. The results prove that the proppant transport has influence on the flowback behavior to some degree and should be considered in the flowback model for a rather elaborate flowback analysis and post-treatment fracture evaluation.