Search Results (8)

Deep coalbed methane reservoirs must utilize hydraulic fracturing technology to create high-conductivity sand-filled fractures for economical development. However, the mechanism by which proppant embedment affects fracture width in coal rock is not yet clear. In this article, using the discrete element particle flow method, we have developed a numerical simulation model that can replicate the dynamic process of proppant embedment into the fracture surface. By tracking particle positions, we have accurately characterized the dynamic changes in fracture width and proppant embedment depth. The consistency between experimental measurements of average fracture width and numerical results demonstrates the reliability of our numerical model. Using this model, we analyzed the mechanisms by which different proppant particle sizes, number of layers, and closure stresses affect fracture width. The force among particles under different proppant embedment conditions and the induced stress field around the fracture were also studied. Numerical simulation results show that stress concentration formed by proppant embedment in the fracture surface leads to the generation of numerous induced micro-fractures. As the proppant grain size and closure stress increase, the stress concentration formed by proppant embedment in the fracture surface intensifies, and the variability in fracture width along the fracture length direction also increases. With more layers of proppant placement, the particles counteract some of the closure stress, thereby reducing the degree of proppant embedment around the fracture surface. Full article

In deep shale gas fracturing, the narrow width of micro fractures presents a challenge for conventional proppants (40/70 mesh, 70/140 mesh), which often fail to enter branch fractures, resulting in inadequate effective support volume. To address this, a high-efficiency propping strategy is proposed based on the hybrid use of micro-proppants and conventional proppants. Utilizing a proppant transport experiment device, the effects of proppant size ratios and injection timing on proppant distribution were investigated to determine the optimal design parameters. The results indicate that the 200/400 mesh micro-proppant can effectively enter the distal micro fractures, thereby mitigating the problem of the non-uniform distribution of the proppant within the fracture network. To ensure effective propping of secondary fractures, the optimal pumping sequence is to inject quartz sand first, followed by ceramic proppants. The recommended ratio of 70/140 mesh quartz sand to 40/70 mesh ceramic proppants is 7:3. Additionally, for blended injection, the optimal mixing ratio of 70/140 mesh quartz sand to micro-proppant is 8:2. Field trials at the L-X1 well in the LZ block demonstrate that this strategy significantly boosts post-fracturing production, with test yields increasing 2.4 to 4 times. Full article

Hydraulic fracturing involving proppant injection is currently the most effective technology to stimulate tight, unconventional reservoirs. The conductivity offered by the created propped and unpropped fracture segments is directly linked to the well deliverability. The accurate modeling of the fracture network conductivity is key to well performance prediction. Unlike most previous studies that have focused on the single-fracture conductivity, a comprehensive fracture network conductivity model was developed by incorporating more complex rock and proppant deformation mechanisms and integrating the conductivity of different propped and unpropped fracture segments through hydraulic–electric analogies. Specifically, for propped fracture segments, the proppant pack permeability was described by simultaneously considering the viscous shear from fracture walls, stress sensitivity, and multiple- or single-proppant-layer placement, while the dynamic width was controlled through proppant pack compaction and proppant embedment. In unpropped fracture segments, as self-supported fracture surface deformation changes the fracture compressibility, the stress-dependent compressibility was utilized to depict the dynamic width. The developed propped and unpropped fracture conductivity models were separately verified against experimental measurement data. Through the hydraulic–electric analogies, a new partially propped fracture network conductivity model was established. For propped fracture segments, an increase in the proppant pack compressibility significantly reduced the fracture conductivity, particularly under high-stress conditions. A larger initial propped fracture aperture offered higher fracture conductivity under identical stress conditions. For single-layer propped fractures, a decrease in the fracture surface elastic modulus from 15 GPa to 10 GPa slightly reduced the fracture conductivity due to greater proppant embedment. For unpropped fractures, a larger compressibility reduction rate (lower fracture compressibility) led to better fracture conductivity maintenance. The fracture network conductivity was dominated by the unpropped fracture segment conductivity when the unpropped length reached 45.5% of the total fracture network length. Full article

Hydraulic fracture is crucial for assuring well production from unconventional reservoirs. For the optimization of hydraulic fracture geometry and the ensuing production of an interlayered reservoir, vertical hydraulic fracture propagation path has been analyzed. However, an effective fluid channel cannot be formed if the proppant is unable to reach the area where the fracture propagates. This paper presents a numerical model using the lattice-based method to investigate the hydraulic fracture propagation and proppant transport mechanism in interlayered reservoirs. The hydraulic fracture propagation model was simulated under different geological and fracturing engineering factors. The results indicate that interlayer Young’s modulus and horizontal stress anisotropy are positively correlated with longitudinal propagation and proppant carrying ability in interlayered formations. The fracturing injection rate has an optimal solution for fracture propagation and proppant carrying since a too low injection rate is unfavorable for fracture penetration of the interlayer, while a too high injection rate increases fracture width instead of further fracture penetration. In conclusion, attention is drawn to fine particle size proppants used in multi-layer reservoirs for fracturing fluid to carry proppants as far as possible to obtain maximum propped area. Full article

For unconventional reservoir hydraulic fracturing design, a greater fracture length is a prime factor to optimize. However, the core observation results from the Hydraulic Fracturing Test Site (HFTS) show that the propped fractures are far less or shorter than expected, which suggests that the roughness and tortuosity of hydraulic fractures are crucial to sand transport. In this study, a transport model of sands is first built based on experimental measurements on the height and transport velocity of the sand bank in fractures with predetermined width and roughness. The fracture roughness is quantified by using the surface height integral. Then, three-dimensional simulations are conducted with this modified model to further investigate the impact of tortuous fractures on sand transport, from which a regression model is established to estimate the propped length of hydraulic fractures at a certain pumping condition. The experiment results show that the height of the sand bank in rough fractures is 20–50% higher than that in smooth fractures. The height of the sand bank decreases with the reduction in slurry velocity and increases with the increase in sand diameter. Sand sizes do little effect on the transport velocity of the sand bank, but the increase in slurry velocity and sand volume fraction can dramatically enhance the migration velocity of the sand bank. The appearance of tortuous fractures decreases the horizontal velocity of suspended particles and results in a higher sand bank compared with that in straight fractures. When the sand bank reaches equilibrium at the tortuous position, it is easy to produce vortices. So, there is a significant height of sand bank change at the tortuous position. Moreover, sand plugging can occur at the entrance of the fractures, making it difficult for the sand to transport deep into fractures. This study explains why the propped length of fractures in HFTS is short and provides a regression model that can be easily embedded in the fracturing simulation to quickly calculate dimensions of the propped fractures network to predict the length and height of propped fractures during fracturing. Full article

Stranded gas emission from the field production because of the limitations in the pipeline infrastructure has become one of the major contributors to the greenhouse effects. How to handle the stranded gas is a troublesome problem under the background of global “net-zero” emission efforts. On the other hand, the cost of water for hydraulic fracturing is high and water is not accessible in some areas. The idea of using stranded gas in replace of the water-based fracturing fluid can reduce the gas emission and the cost. This paper presents some novel numerical studies on the feasibility of using stranded natural gas as fracturing fluids. Differences in the fracture creating, proppant placement, and oil/gas/water flowback are compared between natural gas fracturing fluids and water-based fracturing fluids. A fully integrated equation of state compositional hydraulic fracturing and reservoir simulator is used in this paper. Public datasets for the Permian Basin rock and fluid properties and natural gas foam properties are collected to set up simulation cases. The reservoir hydrocarbon fluid and natural gas fracturing fluids phase behavior is modeled using the Peng-Robinson equation of state. The evolving of created fracture geometry, conductivity and flowback performance during the lifecycle of the well (injection, shut-in, and production) are analyzed for the gas and water fracturing fluids. Simulation results show that natural gas and foam fracturing fluids are better than water-based fracturing fluids in terms of lower breakdown pressure, lower water leakoff into the reservoir, and higher cluster efficiency. NG foams tend to create better propped fractures with shorter length and larger width, because of their high viscosity. NG foam is also found to create better stimulated rock volume (SRV) permeability, better fracturing fluid flowback with a large water usage reduction, and high natural gas consumption. The simulation results presented in this paper are helpful to the operators in reducing natural gas emission while reducing the cost of hydraulic fracturing operation. Full article

Hydraulic fracturing is a well-known production intensification technique in the petroleum industry that aims to enhance the productivity of a well drilled mostly in less permeable reservoirs. The process’s effectiveness depends on the achieved fracture conductivity, the product of fracture width, and the permeability of the proppant pack placed within the fracture. This article presents an innovative method developed by our research activity that incorporates the benefit of the Discrete—and Finite Element Method to describe the in situ behavior of hydraulic fractures with a particular emphasis on fracture conductivity. DEM (Discrete Element Method) provided the application of random particle generation and non-uniform proppant placement. We also used FEM (Finite Element Method) Static Structural module to simulate the elastic behavior of solid materials: proppant and formation, while CFD (Computational Fluid Dynamics) module was applied to represent fluid dynamics within the propped fracture. The results of our numerical model were compared to data of API RP-19D and API RP-61 laboratory measurements and findings gained by publishers dealing with propped fracture conductivity. The match of the outcomes verified the method and encouraged us to describe proppant deformation and embedment and their effect as precisely as possible. Based on the results, we performed sensitivity analysis which pointed out the impact of several factors affecting proppant embedment, deformation, and fracture conductivity and let one be aware of a reasonable interpretation of propped hydraulic fracture operation. However, DEM–CFD coupled models were introduced regarding fracturing before, to the best of our knowledge, the developed workflow of coupling DEM–FEM–CFD for modeling proppant-supported fracture behavior has not been applied yet, thus arising new perspectives for explorers and engineers. Full article

Hydraulic fracturing optimization is very important for low permeability reservoir stimulation and development. This paper couples the fracturing treatment optimization with fracture geometry optimization in order to maximize the dimensionless productivity index. The optimal fracture dimensions and optimal dimensionless fracture conductivity, given a certain mass or volume of proppant, can be determined by Unified Fracture Design (UFD) method. When solving the optimal propped fracture length and width, the volume and permeability of the propped fracture should be determined first. However, they vary according to the proppant concentration in the fracture and cannot be obtained in advance. This paper proposes an iterative method to obtain the volume and permeability of propped fractures according to a desired proppant concentration. By introducing the desired proppant concentration, this paper proposes a rapid semi-analytical fracture propagation model, which can optimize fracture treatment parameters such as pad fluid volume, injection rate, fluid rheological parameters, and proppant pumping schedule. This is achieved via an interval search method so as to satisfy the optimal fracture conductivity and dimensions. Case study validation is conducted to demonstrate that this method can obtain optimal solutions under various constraints in order to meet different treatment conditions. Full article