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The temperature of a deep shale reservoir may reach more than 100°C, and the effect of thermal shock on shale hydraulic fracturing has rarely not been considered in previous studies. Based on mesoscopic damage mechanics and the finite element method, a thermo-hydro-mechanical-damage (THMD) coupling model considering temperature, seepage, stress, and damage fields was constructed to investigate the effects of reservoir temperature, convective heat transfer coefficient (h), in-situ stress difference and bedding plane angle (α θ) on shale hydraulic fracturing. The results show that multiple hydraulic fractures (HFs) can occur under thermal shock and that HFs control the distribution of seepage, temperature, and stress fields. Reservoir temperature, in-situ stress difference and α θ are primary factors affecting hydraulic fracturing, whereas h is a secondary factor. When the reservoir temperature rises from 50°C to 150°C, the initiation and breakdown pressures decrease by 65.5% and 16.7%, respectively. HFs cross the bedding plane more easily, and fracture complexity is obviously enhanced. A higher h is favourable for slightly reducing the initiation and breakdown pressures, but it has little influence on the fracture complexity. Once the in-situ stress difference is low, there is a high fracture complexity, but HFs are more easily captured by bedding planes to limit the propagation of fracture height. When the in-situ stress difference is high, HFs are more likely to form bi-wing fractures. Whether α θ is too large or small, it is not conducive to improving the fracture complexity. In this study, when α θ is 30°, HFs and bedding planes intersect to form a fracture network. Essentially, thermal shock plays a key role in reducing the initiation pressure and forming multiple HFs during the fracturing process, and fracture propagation mainly depends on the injection pressure. The results can serve as reasonable suggestions for the optimization of shale hydraulic fracturing. [ABSTRACT FROM AUTHOR]

The stimulation method of the marine natural gas hydrate (NGH) reservoir through hydraulic fracturing has been proposed to resolve the problem of the low production capacity in the conventional development method of pressure drawdown. Nevertheless, due to the strong plasticity and high argillaceous siltstone content of the marine NGH reservoir, conventional small-particle-size proppant cannot form effective support for fractures after fracturing because of serious embedding in the reservoir. To solve this problem, the large-size phase change proppants were developed in this study. First, an epoxy resin curing system that can reduce curing time to 40 min in low temperature and humid environment was developed. Then, the epoxy resin and curing system was emulsified, and through the optimization of the emulsification process, the particle size of the proppant can be controlled in 0.5–4.5 mm and the cementation between the proppant particles during the curing process can be prevented. Finally, the proppant performances were evaluated. The performance evaluation shows that the cured proppants have regular structure and good compressive strength, and the emulsion proppants have good transport capacity. Their large sizes provide effective propping effects for fractures generated in weakly cemented clayey silt marine NGH reservoirs. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing is an economically effective technology developing the glutenite reservoirs, which have far stronger heterogeneity than the conventional sandstone reservoir. According to the field production experience of Shengli Oilfield, horizontal-well fracturing is more likely to develop a complex fractured network, which improves the stimulated volume of reservoir effectively. But the clear mechanism of horizontal-well hydraulic fracture propagation in the glutenite reservoirs is still not obtained, thus it is difficult to effectively carry out the design of fracturing plan. Based on the characteristics of the glutenite reservoirs, a coupled Flow-Stress-Damage (FSD) model of hydraulic fracture propagation is established. The numerical simulation of fracturing expansion in the horizontal well of the glutenite reservoir is conducted. It is shown that a square mesh-like fracture network is developed near the horizontal well in the reservoir with lower stress difference, in which fracture is more prone to propagate along the direction of the minimum principal stress as well. High fracturing fluids injection displacement and high fracturing fluid viscosity lead to the rise of static pressure of the fracture, which results in the rise of fracture complexity, and greater probability to deflect when encountering gravels. As the perforation density increases, the micro-fractures generated at each perforation gather together faster, and the range of the stimulated reservoir is also relatively large. For reservoirs with high gravel content, the complexity of fracture network and the effect of fracture communication are obviously increased, and the range of fracture deflection is relatively large. In the case of the same gravel distribution, the higher the tensile strength of the gravel, the greater fracture tortuosity and diversion was observed. In this paper, a simulation method of horizontal well fracture network propagation in the reservoirs is introduced, and the result provides the theoretical support for fracture network morphology prediction and plan design of hydraulic fracturing in the glutenite reservoir.

10.3390/pr10050939 11 Pan Y., Xu Y., Yang Z., Wang C., Liao R. Shale Gas Productivity Prediction Model Considering Time-Dependent Fracture Conductivity. Hydraulic fracturing is a technique that can provide space for oil and gas flow by pumping fracturing fluid into a reservoir to fracture rock and filling proppant to create fractures or fracture nets. References 1 Zou Y., Gao B., Ma Q. Investigation into Hydraulic Fracture Propagation Behavior during Temporary Plugging and Diverting Fracturing in Coal Seam. [Extracted from the article]

The tight sandstone oil reservoirs characterized by the low porosity and permeability must be hydraulically fractured to obtain the commercial production. Nevertheless, the post-fracturing production of tight oil reservoirs is not always satisfactory. The influence mechanism of various factors on the fracture propagation in the tight oil reservoirs needs further investigation to provide an optimized fracturing plan, obtain an expected fracture morphology and increase the oil productivity. Thus, the horizontal well fracturing simulations were carried out in a large-scale true tri-axial test system with the samples from the Upper Triassic Yanchang Fm tight sandstone outcrops in Yanchang County, Shaanxi, China, and the results were compared with those of fracturing simulations of the shale outcrop in the 5th member of Xujiahe Fm (abbreviated as the Xu 5th Member) in the Sichuan Basin. The effects of the natural fracture (NF) development degree, horizontal in-situ stress conditions, fracturing treatment parameters, etc. on the hydraulic fracture (HF) propagation morphology were investigated. The results show that conventional hydraulic fracturing of the tight sandstone without NFs only produces a single double-wing primary fracture. The fracture propagation path in the shale or the tight sandstone with developed NFs is controlled by the high horizontal differential stress. The higher stress difference (<12MPa) facilitates forming the complex fracture network. It is recommended to fracture the reservoir with developed NFs by injecting the high-viscosity guar gum firstly and the low-viscosity slick water then to increase the SRV. The low-to-high variable rate fracturing method is recommended as the low injection rate facilitates the fracturing fluid filtration into the NF system, and the high injection rate increases the net pressure within the fracture. The dual-horizontal well simultaneous fracturing increases the HF density and enhances the HF complexity in the reservoir, and significantly increases the possibility of forming the complex fracture network. The fracturing pressure curves reflect the fracture propagation status. According to statistical analysis, the fracturing curves are divided into types corresponding to multi-bedding plane (BP) opening, single fracture generation, multi-fracture propagation under variable rate fracturing, and forming of the fracture network through communicating the HF with NFs. The results provide a reference for the study of the HF propagation mechanism and the fracturing design in the tight sandstone reservoirs. [ABSTRACT FROM AUTHOR]

The simulation of hydraulic fracturing by the conventional ABAQUS cohesive finite element method requires a preset fracture propagation path, which restricts its application to the hydraulic fracturing simulation of a naturally fractured reservoir under full coupling. Based on the further development of a cohesive finite element, a new dual-attribute element of pore fluid/stress element and cohesive element (PFS-Cohesive) method for a rock matrix is put forward to realize the simulation of an artificial fracture propagating along the arbitrary path. The effect of a single spontaneous fracture, two intersected natural fractures, and multiple intersected spontaneous fractures on the expansion of an artificial fracture is analyzed by this method. Numerical simulation results show that the in situ stress, approaching angle between the artificial fracture and natural fracture, and natural fracture cementation strength have a significant influence on the propagation morphology of the fracture. When two intersected natural fractures exist, the second one will inhibit the propagation of artificial fractures along the small angle of the first natural fractures. Under different in situ stress differences, the length as well as aperture of the hydraulic fracture in a rock matrix increases with the development of cementation superiority of natural fractures. And with the increasing of in situ horizontal stress differences, the length of the artificial fracture in a rock matrix decreases, while the aperture increases. The numerical simulation result of the influence of a single natural fracture on the propagation of an artificial fracture is in agreement with that of the experiment, which proves the accuracy of the PFS-Cohesive FEM for simulating hydraulic fracturing in shale gas reservoirs. [ABSTRACT FROM AUTHOR]

Slickwater fracturing can create complex fracture networks in shale. A uniform proppant distribution in the network is preferred. However, proppant transport mechanism in the fracture network is still uncertain, which restricts the optimization of sand addition schemes. In this study, slot flow experiments are conducted to analyze the proppant placement in the complex fracture system. Dense discrete phase method is used to track the particle trajectories to study the transport mechanism into the branch. The effects of the pumping rate, sand ratio, sand size, and branch angle and location are discussed in detail. Results demonstrate that: (1) under a low pumping rate or coarse proppant conditions, the dune development in the branch depends on the dune geometry in the primary fracture, and a high proportion of sand can transport into the branch; (2) using a high pumping rate or fine proppants is beneficial to the uniform placement in the fracture system; (3) sand ratio dominates the proppant placement in the branch and passing-intersection fraction of a primary fracture; (4) more proppants may settle in the near-inlet and large-angle branch due to the size limit. Decreasing the pumping rate can contribute to a uniform proppant distribution in the secondary fracture. This study provides some guidance for the optimization of proppant addition scheme in the slickwater fracturing in unconventional resources. [ABSTRACT FROM AUTHOR]