Search Results (18)

The enhancement of proppant conductivity in shale gas fracturing can be effectively achieved through the implementation of coated proppants. After soaking, non-curable viscous resin-coated proppants exhibit progressive viscosity development and spontaneous agglomeration during the transportation phase. Furthermore, upon fracture closure, the formed proppant agglomerates demonstrate significant stability and do not flow back with the fracturing fluid through the wellbore. While contemporary research has mostly focused on proppant coating methodologies, the transportation process of these proppants remains insufficiently investigated. To fill this knowledge gap, a sophisticated migration two-phase flow coupling model was developed utilizing the computational fluid dynamics–discrete element method (CFD-DEM) approach. This model incorporates the bond contact forces between film-coated proppant particles, accounting for their distinctive cementing characteristics during transport. Through comprehensive numerical simulations, the transport properties of film-coated proppants were systematically analyzed. Field application indicated that compared with conventional continuous sand fracturing, the amount of proppant after treatment with viscous resin film was reduced by 35% and the production was increased by about 25–30%. Additionally, the optimization of the field-scale coated proppant transport processes was achieved through the implementation of a lower fracturing displacement combined with staged sand addition. Full article

Solid–liquid two-phase flow often occurs when pumping proppant or temporary plugging agents into hydraulically fractured wells. The final distribution of these injected particles in the fracture has an important influence on the well productivity after hydraulic fracturing. This paper focuses on simulating and analyzing particle migration within slug injection hydraulic fractures in the Sulige gas reservoir. In this study, a particle migration and settlement model in hydraulic fractures is established based on the Multiphase Particle-in-Cell (MP-PIC) method, allowing for effective simulation of particle migration and settlement in fractures. This model is validated by the results of particle-pumping experiments. The influences of fluid viscosity, injection rate, particle density, particle diameter, and particle concentration on the distribution of particles are studied. The results indicate that keeping the viscosity of the particle-carrying liquid above 50 mPa·s is necessary. It is recommended to keep the liquid viscosity above 200 mPa·s so that the particles can move farther in the fractures. For pulse fracturing, a lower flow rate leads to a more dispersed distribution of particles, but for temporary plugging with particles, a lower flow rate can lead to a decrease in particle concentration and reduce the success rate of temporary plugging. Low particle density can lead to more dispersed particles, but the amount of particle settlement will be less, so from the perspective of pulse fracturing, it is recommended that the particle density should not be lower than 2200 $\mathrm{kg}/{\mathrm{m}}^3$. Similarly, the particle size should not be too large for pulse fracturing, and the initial particle concentration should be maintained above $18\%$. Full article

The drilling fluid loss or lost circulation via near-wellbore fractures is one of the most critical problems in the drilling of deep oil and gas resources, which causes other problems such as difficulty in achieving wellbore pressure control and reservoir damage. The conventional treatment is to introduce granular lost circulation material (LCM) into the drilling fluid to plug the fractures. As the migration mechanism of the LCM in irregular fractures has not been completely figured out as of yet, the low success rate of fracture plugging and repeated drilling fluid loss still obstruct the exploitation of deep oil and gas resources. In this paper, the spatial data of actual rock fracture surfaces were obtained through structured light scanning, and an irregular surface identical to the rock was machined on a transparent polymethyl methacrylate plate. On this basis, a visualization experimental apparatus for fracture plugging was established, and the fracture flow space of this device was consistent with that of the actual rock fracture. Employing cylindrical nylon particles as LCM, a visualization experiment study was carried out to investigate the process of LCM bridging and fracture plugging and the influence of LCM injection methods. The experimental results show that the process of fracture plugging includes the sporadic bridging, plugging zone extension and merging, thickening of the plugging zone and complete plugging of the fracture. It was observed in the visualization experiment that a large number of small particles flow deep into the fracture in the traditional fracture plugging method, where all types and sizes of LCM are injected at one time. After changing the injection sequence, which injects the large particles first and the small particles subsequently, it is found that the large particles will form single-particle bridging at a specific depth of the fracture, intercepting subsequently injected particles and thickening the plugging zone, which finally increases the area of the plugging zone by 19%. The visualization experiment results demonstrate that modifying the LCM injection method significantly enhances both the LCM utilization rate and the fracture plugging effect, thereby reducing reservoir damage. This is conducive to reducing the drilling cost of fractured formation. Additionally, the visualized experimental approach introduced in this study can also benefit other research areas, including proppant placement and solute transport in rock fractures. Full article

In previous studies of the transportation of proppants within fractures and the morphology of proppant-supported fractures, researchers have generally treated the fractures as static and have overlooked the interactions between fractures and the proppant during the dynamic closure caused by filtration. To address this limitation, we propose a semi-implicit method to calculate the complete fluid–structure interaction equations for the fracture, fluid, and proppant. The results show that there are three types of closed fracture patterns formed by alternate proppant injection at the end of filtration loss, and the third pattern of fracture formed by injecting small particles first and then large particles has the best support length and filling effect. More effects of the particle size and injection pattern of the injected proppant on the fracture closure pattern after the end of filtration loss are shown graphically and analyzed in detail. Full article

This article studies the migration and settlement laws of backflow proppants after fracturing tight sandstone. This paper proposes a fitting method based on a multi-task learning network to address the issue of interference from multiple physical parameters during the transport and settlement processes of proppants. This method can effectively handle multi-dimensional interference factors and fit the mapping logic of multiple engineering parameters to transport patterns through the continuous correction of multi-layer networks. We first introduce the characteristics of tight sandstone reservoirs and their important value in mining, as well as the status of current research on the migration and settlement laws of proppants at home and abroad. Based on this, we then deeply analyze the sedimentation rate model of proppants in tight sandstone backflow and the equilibrium height of proppants under multiple factors of interference while considering the distribution characteristics of proppants. In order to more accurately simulate the transport and settlement laws of proppants, this paper introduces a multi-task learning network. This network can comprehensively consider multi-dimensional parameters, learn the inherent laws of data through training, and achieve accurate fitting of the transport and settlement laws of proppants. This study trained and tested the model using actual production data, and the results showed that the proposed model can fit the input–output relationship well, thus effectively supporting the study of proppant transport and settlement laws. Full article

During the hydraulic fracturing process of coalbed methane (CBM) reservoirs, significant amounts of secondary coal fines are generated due to proppant grinding and crack propagation, which migrate with the fracturing fluid into surrounding fracture systems. To investigate whether coal fines can form plugs to reduce fluid leak-off during the hydraulic fracturing stage, we conducted physical simulation experiments on coal seam plugging and unplugging to demonstrate that coal fines indeed contribute to reducing fluid leak-off during hydraulic fracturing. We also explored the plugging mechanisms of coal fines under different concentrations and particle sizes in fracturing fluids, and revealed the damage law of coal fines of temporary plugging on reservoir permeability. Research results indicate the leak-off volume of fracturing fluids containing coal fines is lower than an order without coal fines, demonstrating a significant effect of coal fines in decreasing fluid leak-off. The temporary plugging rate of coal fines increases with higher concentrations and decreases with larger particle sizes, achieving rates exceeding 90%. The high temporary plugging effect of coal fines results from the superposition of internal and external filter cakes. Under conditions of small particle size and high concentration, the damage to fractures during the fine return process is minimized. Considering the potential damage of coal fines to propping fractures and wellbore, the concentration of coal fines in fracturing fluids should be kept relatively low while ensuring a high temporary plugging effect. Overall, these findings provide crucial insights into optimizing the temporary plugging performance of coal fines during the hydraulic fracturing stage and controlling their behavior during the fracturing fluid flow-back stage, thereby enhancing reservoir fracturing effectiveness and improving CBM production rates. Full article

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. Full article

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. Full article

In this paper, based on the background of a deep shale reservoir, a solid–liquid two-phase flow model suitable for proppant and fracturing fluid flow was established based on the Euler method, and a large-scale fracture model was established. Based on field parameters, a proppant transport experiment was conducted. Then, on the basis of the experimental fracture model, proppant transport simulation under different influencing factors was carried out. The results show that the laboratory experiment was in good agreement with the simulated results. The process of proppant accumulation in fractures can be divided into three stages according to the characteristics of sand banks. The displacement mainly affects the sedimentation distance of the proppant in the first stage, and the viscosity of the fracturing fluid represents the strength of the fluid sand carrying performance. Compared with 40/70 mesh proppant, 70/140 mesh proppant is more easily fluidizable, the fracture width has less influence on proppant migration and placement, and the perforation location only affects the accumulation pattern at the fracture entrance, but has less influence on proppant placement in the remote well zone. Full article

China’s argillaceous limestone reservoir has a lot of oil and gas resources, and hydraulic fracturing of the argillaceous limestone reservoir faces many difficulties. The first problem is that the heterogeneity of the argillaceous limestone reservoir is strong, and it is difficult to optimize fracturing parameters. The second problem is that there are a lot of natural fractures in the argillaceous limestone reservoir, which leads to a lot of fracturing fluid loss. The third problem is that the closure pressure of the argillaceous limestone reservoir is high, and the conductivity of fractures decreases rapidly under high closure pressure. The last problem is that the fracture shape of the argillaceous limestone reservoir is complex, and the law of proppant migration is unclear. The main research methods in this paper include reservoir numerical simulation, fluid-loss-reducer performance evaluation, flow conductivity tests and proppant migration visualization. To solve the above problems, this paper establishes the fracturing productivity prediction model of complex lithology reservoirs and defines the optimal hydraulic fracturing parameters of the argillous limestone reservoir in the Sichuan Basin. The 70/140 mesh ceramide was selected as the fluid loss additive after an evaluation of the sealing properties of different mesh ceramides. At the same time, the hydraulic fracture conductivity test is carried out in this paper, and it is confirmed that the fracture conductivity of 70/140 mesh and 40/70 mesh composite particle-size ceramics mixed according to the mass ratio of 5:5 is the highest. When the closure pressure is 40 MPa, the conductivity of a mixture of 70/140 mesh ceramic and 40/70 mesh ceramic is 35.6% higher than that of a mixture of 70/140 mesh ceramic and 30/50 mesh ceramic. The proppant migration visualization device is used to evaluate the morphology of the sand dike formed by the ceramsite, and it is clear that the shape of the sand dike is the best when the mass ratio of 70/140 mesh ceramsite and 40/70 mesh ceramsite is 6:4. The research results achieved a good stimulation effect in the SC1 well. The daily oil production of the SC1 well is 20 t, and the monitoring results of the wide-area electromagnetic method show that the fracturing fracture length of the SC1 well is up to 129 m. Full article

The placement of proppant within fractures is critical to the effectiveness of hydraulic fracturing. To elucidate the migration and placement patterns of proppant within multi-branched fractures during hydraulic fracturing, we conducted simulation experiments under both single-fracture and multi-branched-fracture conditions, varying injection rates and proppant sizes. The results of the research indicate that increasing the injection rate effectively increases the magnitude of vortex formation at the leading edge of sandbars and the drag forces acting on the proppant particles, resulting in increased particle migration distances. However, effective proppant packing near the wellbore entrance is not achieved at higher injection rates, leaving the fractures susceptible to closure under in situ stress, thereby reducing overall fracture conductivity. In addition, increasing the proppant size results in higher settling velocities and weakens the vortex’s ability to entrain the proppant particles. This results in shorter proppant placement distances, and the proppant cannot effectively reach the distant branched fractures. In addition, the diversionary effect of the branched fractures gradually reduces the flow rate in the distant branches, resulting in poorer proppant placement efficiency. Based on these findings, we recommend an approach that initially increases injection rates while reducing proppant size to ensure proppant placement in distant wellbore fractures and branched fracture networks. Subsequently, larger proppants can be used to effectively fill fractures close to the wellbore. Full article

The presence of a reasonable flowback system after fracturing is a necessary condition for the high production of shale gas wells. At present, the optimization of the flowback system lacks a relevant theoretical basis. Due to this lack, this study established a new method for evaluating the conductivity of artificial fractures in shale, which can quantitatively characterize the backflow, embedment, and fragmentation of proppant during the flowback process. Then, the mechanism of the stress sensitivity of artificial fractures on fracture conductivity during the flowback stage of the shale gas well was revealed by performing the artificial fracture conductivity evaluation experiment. The results show that a large amount of proppant migrates, and the fracture conductivity decreases rapidly in the early stage of flowback, and then the decline gradually slows down. When the effective stress is low, the proppant is mainly plastically deformed, and the degree of fragmentation and embedment is low. When the effective stress exceeds 15.0 MPa, the fragmentation and embedment of the proppant will increase, and the fracture conductivity will be greatly reduced. The broken proppant ratio and embedded proppant ratio are the same under the two choke-management strategies. In the mode of increasing choke size step by step, the backflow proppant ratio is lower, and the broken proppant is mainly retained in fractures, so the damage ratio of fracture conductivity is lower. In the mode of decreasing choke size step by step, most of the proppant flows back from fractures, so the damage to fracture conductivity is greater. The research results have important theoretical guiding significance for optimizing the flowback system of shale gas wells. Full article

Staged multi-cluster fracturing of horizontal wells is one of the most important tools to achieve efficient development of unconventional oil and gas reservoirs. The multi-stage fracturing technique forms complex fractures with multiple clusters and branches in the formation, causing competing diversions leading to more complex proppant transport patterns, and the proppant placement method determines the flow conductivity of complex fractures, so it is necessary to investigate the proppant transport patterns in complex fractures. To address this issue, a field-scale geometric model is established for numerical simulation, and the multiphase flow diversion pattern in the wellbore, the proppant distribution pattern under different network conditions, and the optimization of different construction parameters are investigated. The results are obtained as follows: the distribution of solid and liquid phases in each cluster of the well conforms to the trend of variable mass flow; the proppant is distributed at the heel end in multiple clusters of fractures, and the sand and liquid are unevenly distributed among clusters of fractures, and the number of branching affects the proppant transport; through sensitivity analysis of the influencing factors, the pumping displacement, fracturing fluid viscosity and proppant particle size are optimized, and the construction parameters of 14 m³/min, 5 mPa·s, 70/140 mesh, 12% sand ratio are determined. This study has a certain guiding significance for the optimization of fracturing parameters in this block. Full article

The bedding planes of unconventional oil and gas reservoirs are relatively well developed. Bedding planes directly interfere with hydraulic fracture expansion. Determining how bedding planes influence hydraulic fractures is key for understanding the formation and evolution of hydraulic fracturing networks. After conducting X-ray diffraction analysis of shale, we used Python programming to establish a numerical model of mineral heterogeneity with a 0-thickness cohesive element and a bedding plane that was globally embedded. The influence of the bedding-plane angle on hydraulic fracture propagation was studied. Acoustic emission (AE) data were simulated using MATLAB programming to study fracture propagation in detail. The numerical simulation and AE data showed that the propagation paths of hydraulic fractures were determined by the maximum principal stress and bedding plane. Clearer bedding effects were observed with smaller angles between the bedding surface and the maximum principal stress. However, the bedding effect led to continuous bedding slip fractures, which is not conducive to forming a complex fracture network. At moderate bedding plane angles, cross-layer and bedding fractures alternately appeared, characteristic of intermittent dislocation fracture and a complex fracture network. During hydraulic fracturing, tensile fractures represented the dominant fracture type and manifested in cross-layer fractures. We observed large fracture widths, which are conducive to proppant migration and filling. However, the shear fractures mostly manifested as bedding slip fractures with small fracture widths. Combining the fracture-network, AE, and fractal dimension data showed that a complex fracture network was most readily generated when the angle between the bedding plane and the maximum principal stress was 30°. The numerical simulation results provide important technical information for fracturing construction, which should support the efficient extraction of unconventional tight oil and gas. Full article

In weakly cemented reservoirs or coal-bed methane reservoirs, the conductivity of hydraulic fractures always declines after a period of production, which greatly influences gas production. In this paper, a comprehensive model considering fine-grained particle migration and proppant embedment is proposed to give a precise prediction for conductivity decline. Then, an experiment was conducted to simulate this process. A published experiment using coal fines was also tested and simulated. The results indicate that both fine-grained particle migration and proppant embedment have great negative effect on conductivity of fractures in weakly cemented sandstone and coal-bed methane reservoirs. The formulation we proposed matches the experimental data smoothly and can be widely used in the prediction of conductivity decline in weakly cemented sandstone and coal-bed methane reservoirs. In order to discuss the influencing factors of the filtration coefficient in the particle transport model, a porous media network model was established based on the theoretical model. The simulation results show that the filtration coefficient increases with the increase in particle size and/or throat size, and the filtration coefficient increases with the decrease in the fluid velocity. At the same time, it was found that the large larynx did not easily cause particle retention. Large size particles tend to cause particle retention. Full article