Hydraulic Fracture Morphology Research Articles

Shale hydraulic fracture morphology and inter-well interference rule under multi-wellbore test

Abstract This study conducted a series of true triaxial hydraulic fracturing experiments on Longmaxi Formation shale. We investigated the interaction between internal factors and external factors on the inter-well interference of 400 mm cubic porous specimens. During dual wellbore fracturing at different formations, forming inter-well interference through secondary hydraulic fractures lead to a lower interference intensity and larger stimulated rock area. When adopting a three-layer well layout during three-wellbore fracturing, the vertical distance between the wells is shortened, activating more bedding planes. Regardless of a horizontal well placement with two wellbores or a three-dimensional two-layer well placement with three wellbores, increasing the vertical stress leads to more potent inter-well interference. There is no absolute positive correlation between the stimulated rock area and inter-well interference. It can be influenced by the presence of natural fractures within the formation that can even lead to a reduction in the stimulated area. When the well placement changes from two horizontal wellbores to three-dimensional two-layer sites with three wellbores and the vertical stress increases, the inter-well interference becomes stronger, but the stimulated rock area only increases by 22.6%. These findings provide crucial guidance for the hydraulic fracturing design of shale reservoirs.

Propagation and complex morphology of hydraulic fractures in lamellar shales based on finite-discrete element modeling

We explore the controls of stress magnitude and orientation relative to bedding on the resulting morphology/topology of hydraulic fractures using a combined finite-discrete element method (FDEM). Behavior is shown conditioned by the ratio of principal stresses λ=σ3/σ1\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$$\\lambda ={\\sigma }_{3}/{\\sigma }_{1}$$\\end{document} and relative inclination of the bedding. When the lateral pressure coefficient (λ\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$$\\lambda$$\\end{document}) is less than 0.67, hydraulic fractures predominantly initiate as tensile fractures along the wellbore, aligning with the maximum principal stress direction. Conversely, for λ≥0.67\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$$\\lambda \\ge 0.67$$\\end{document}, shear cracks are favored to initiate for the minor stress difference, leading to a less predictable initiation and extension direction. Simultaneously, diminished stress differences correspond to elevated reservoir breakdown pressures, displaying a linear correlation with lateral pressure coefficients and little influenced by equivalent bedding orientation. Bedding plane orientation significantly impacts the mode and morphology of hydraulic fracture propagation. Bedding parallel to the direction of the minimum principal stress (σ3\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$${\\sigma }_{3}$$\\end{document}) favors layer-penetrating and bifurcated fractures, whereas inclined bedding facilitates the emergence of numerous steering-type and capture-type fractures. Especially at steeper inclinations (β=60∘\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$$\\beta =60^\\circ$$\\end{document}), hydraulic fractures readily extend along the bedding surface, inducing macroscopic shear slip failure. Under high-stress disparities, the breakdown pressure exhibits greater sensitivity to bedding inclination, and its influence pattern aligns with the variations in tensile strength, typically reaching maximum and minimum values at bedding inclination angles of 0° and 60°, respectively.

Hybrid Deep Learning Approach for Hydraulic Fracture Morphology Diagnosis in Coalbed Methane Wells

Hybrid Deep Learning Approach for Hydraulic Fracture Morphology Diagnosis in Coalbed Methane Wells

Simulation of hydraulic fracture propagation based on implicit gradient non-local model

Fracture extension simulation is an important tool for studying hydraulic fracture characteristics. To solve the problem of mesh sensitivity of strain and fluid pressure during hydraulic crack propagation, the equivalent strain in the damage evolution equation was non-localized, and implicit gradient was performed. A hydraulic-mechanical coupling model based on implicit gradient non-local damage was established. Numerical simulation program was further developed. Comparison of simulation results with experimental data on ‘L’-brittle material verified the validity of the program. The fracture propagation process of hydraulic fracturing in a perforated well was simulated. On this basis, the influence of internal length scale parameters and mesh size of the non-local model on the calculation results was analyzed. The influence of mesh size on hydraulic fracture morphology and damage variables is reduced by introducing an implicit gradient nonlocal model, which effectively alleviates the localization effect in hydraulic-mechanical coupling damage simulation. This new model achieves the nonlocalization of the fluid field by introducing the relationship among porosity-permeability and deformation and damage, which avoids the mesh sensitivity of equivalent strain, damage, fluid pressure, and improves the numerical stability. It provides a new method for simulating hydraulic fracture propagation and studying the failure behavior of porous media materials.

Mechanism of hydraulic fracture vertical propagation in deep shale formation based on elastic–plastic model

Deep shale reservoirs exhibit strong plasticity, and the simulation results from previous fracturing simulations based on elastic models may not adequately account for the effects of plastic. Therefore, the research objective is to develop a 3D finite element method (FEM) model of hydraulic fracture vertical propagation in multilayer reservoirs. The model simultaneously considering Drucker-Prager elastic–plastic rock model and bedding plane. To investigate the impact of various parameters on the vertical propagation pattern of fracture, it is crucial to consider factors such as friction angle, yield strength, interlayer strength, and vertical stress. This study quantitatively characterizes the mechanical parameters such as ground stress, matrix strength, and interface strength on hydraulic fracture morphology. Additionally, a new integrated control diagram is established to provide a comprehensive understanding of these effects. The results indicate that rocks with high friction angles and low yield strength are more resistant to cracking, and hydraulic fractures tend to have narrower fractures. Fracturing from high-strength and high-stress zones to lower zones promotes vertical fracture propagation. The high vertical stress plays a crucial role in preventing the fracturing fluid from entering the interface. Moreover, the strength of the formation interface greatly influences the vertical extension of hydraulic fractures. The bedding plane interface with a high cementation level can enhance the possibility of fracture vertical connection with multiple reservoirs. Conversely, breaking through low strength cemented interfaces in the formation can pose challenges for hydraulic fractures. The present simulation conditions determine that the fracture's ability to cross the layer depends on the ratio of interface strength to matrix strength, which should be between 0.25 and 0.5. These findings offer valuable theoretical guidance on the vertical propagation of fractures in deep multilayer fracturing.

Acoustic Emission Evolution and Hydraulic Fracture Morphology of Changning Shale Stressed to Failure at Different Injection Rates in the Laboratory

Acoustic Emission Evolution and Hydraulic Fracture Morphology of Changning Shale Stressed to Failure at Different Injection Rates in the Laboratory

Numerical simulation of hydraulic fracture extension patterns at the interface of coal-measure composite rock mass with Cohesive Zone Model

This study presents the development of a numerical computational model for hydraulic fracturing of coal-measure rock mass. The model is based on the B-K hybrid fracture energy criterion and is implemented using the extended finite element method (XFEM) and cohesive zone model (CZM) in the ABAQUS software. The study took into account the elastic-plastic damage properties of the coal-measure rock mass, as well as the combined effects of tensile and shear damage during the start and expansion of hydraulic fractures. The expansion trajectories and fracture morphology of hydraulic fractures at the interface of coal-measure rock mass under different lithological combinations (lithological strength differences) and ground stress conditions are revealed, and the main controlling factors affecting the expansion across the bedding are clarified. The study provides valuable insights into the management of hydraulic fracturing in the challenging context of hard roof coal mines, the stimulation of coal-measure gas co-production reservoirs, and the development of effective fracturing stimulation strategies for shale oil reservoirs interlayered with thin sandstone, and it can promote the development of industrial production technology for coal-measure gas and shale oil and gas resources, and is beneficial to increase the proportion of clean energy in China's energy consumption structure, and thus promoting a further reduction in the carbon emissions from energy consumption.

The Analysis of Hydraulic Fracture Morphology and Connectivity under the Effect of Well Interference and Natural Fracture in Shale Reservoirs

Employing multi-stage fracturing technology in horizontally accessed wells is a well-known way to successfully develop shale reservoirs. The interaction between natural fractures and hydraulic fractures has a significant impact on the fracturing effect. In this study, a coupled model of rock deformation and fluid flow was established using the cohesive zone method to simulate the propagation of hydraulic fractures under the synergistic effect of natural fractures and wellbore interference. The influence of in situ stress, fracture spacing, the number of fracture clusters, and the fracturing methods on the formation of fracture networks was analyzed. Studies on the fracture morphology and connectivity of fracture networks show that when the in situ stress difference is small, multiple fractures can easily form, and when the in situ stress difference is large, they can easily gather into a single fracture. An excessive reduction in fracture spacing may impede the optimal propagation and interconnection of hydraulic fractures. The findings reveal that augmenting the fracture spacing from 5 m to 8 m results in a significant 15.59% increase in the overall extent of fracture propagation. Moreover, it also adds to the complexity of the fracture network. Increasing the number of hydraulic fracturing clusters can improve the fracture length and fracture propagation complexity. When the number of fracturing clusters increased from two clusters to five clusters, the maximum fracture propagation width increased by 25.23%. Comparing sequential fracturing and simultaneous fracturing, the results show that simultaneous fracturing can form a more complex fracture network with better connectivity, which is conducive to increasing oil and gas production. The obtained results can provide a reference for horizontal well fracturing designs of shale reservoirs.

Evolution Characteristics of the Microstructure with Different Fracturing Fluids: An Experimental Study of Guizhou Bituminous Coal.

Fracturing fluid is a key factor affecting the hydraulic fracture morphology and coal microstructure, which plays a key role in the hydraulic fracturing effect. To compare the effect of clean water, clean fracturing fluid, and acid fracturing fluid on the pore structure of coal, this paper used high-pressure mercury injection (MIP), low-temperature N2 adsorption (LT-N2A), and scanning electron microscopy (SEM) to determine the pore structure of Guizhou bituminous coal before and after the action of fracturing fluid. The results show that clean water can cause mineral expansion and reduce pore volume by about 6% and clean fracturing fluid and acid fracturing fluid can increase pore volume by 3 and 12%, respectively, due to different degrees of acidity. The MIP data show that the pore structure of coal samples is more complex after the action of different fracturing fluids, and acidic fracturing fluids can increase the fractal dimension of the pore by about 7%. The LT-N2A data showed that the fractal dimension of micropores and transition pores decreased after the action of different fracturing fluids. In general, acid fracturing fluid has the best effect on the coal microstructure, followed by clean fracturing fluid, and the least effect on clean water.

Hydraulic fracture morphology and conductivity of continental shale under the true-triaxial stress conditions

Continental shale oil formations generally exhibit more complex lithology and stronger heterogeneity than marine shale. The coexistence of dense laminas, lithologic interfaces (LIs), and mineral-filled natural fractures (NFs) in such formations can cause complex mechanisms of hydraulic fracture (HF) growth, proppant placement, and conductivity evolution. To obtain an intuitive understanding of this problem, a series of comprehensive laboratory sand fracturing experiments and fracturing conductivity tests were carried out innovatively on downhole shale cores using an improved small-size true triaxial fracturing simulation system combined with multiple examination methods in this work. HF morphology and proppant distribution were characterized through the high-precision CT scanning technique. Moreover, HF conductivity was tested on the cylindrical cores drilled from the fractured specimens. Experimental results show that high breakdown pressure and volatile wellbore pressure during the sand-adding stage were likely presented in the relatively rigid formations. HF growth path is likely to be deflected and bifurcated by the NFs laterally and by the oblique laminas vertically. “╪”-shaped HF also tends to be created due to the interaction of HF with dense horizontal laminas. The local heterogeneity in the continental shale formation can cause significant complexity and uncertainty in HF. The dominant HF nearby the wellbore contains most of the proppant, and the activated laminas, NFs, or/and branches are short of proppant. The volume and area of the proppant-filled HF can only account for less than 20% of the total HF volume and less than 65% of the total HF area, respectively. The distribution of relatively small-size proppant is more uniform and broader than that of large ones. There is a positive correlation between fracture conductivity and the proppant concentration. The conductivity of no proppant-filled fractures (including the HF, activated lamina, and NF) is low and unstable, and can almost be neglected under closure stress beyond approximately 20–25 MPa. The findings in this work are expected to provide practitioners with a bigger map of the performance and effectiveness of the hydraulic fracture they created.

A criterion for a hydraulic fracture crossing a natural fracture in toughness dominant regime and viscosity dominant regime

Hydraulic fracturing is an efficient stimulation technology in the process of unconventional reservoir development, and the hydraulic fracture morphology directly affected oil and gas recovery. In this paper, we proposed a new criterion based on linear elastic fracture mechanics (LEFM) to predict the intersection behavior of hydraulic fracture (HF) and natural fracture (NF) with non-orthogonal angle. The new criterion considered the coupling effects of the fluid flow, stress shadow, and poroelastic response, and was validated with published analytical criteria and laboratory tests. Sensitivity analysis results indicated that an HF tends to cross NF under conditions of short HF half-length, high friction coefficient, high fracturing fluid viscosity and high fracture toughness. In addition, high principal stress difference inhibited the crossing behavior when the intersection angle was less than the transition angle, the HF would be arrested or divert along NF.

A new approach for flow simulation in complex hydraulic fracture morphology and its application: Fracture connection element method

Efficient flow simulation and optimization methods of hydraulic fracture morphology in unconventional reservoirs are effective ways to enhance oil/gas recovery. Based on the connection element method (CEM) and distribution of stimulated reservoir volume, the complex hydraulic fracture morphology was accurately described using heterogeneous node connection system. Then a new fracture connection element method (FCEM) for fluid flow in stimulated unconventional reservoirs with complex hydraulic fracture morphology was proposed. In the proposed FCEM, the arrangement of dense nodes in the stimulated area and sparse nodes in the unstimulated area ensures the calculation accuracy and efficiency. The key parameter, transmissibility, was also modified according to the strong heterogeneity of stimulated reservoirs. The finite difference and semi-analytical tracking were used to accurately solve the pressure and saturation distribution between nodes. The FCEM is validated by comparing with traditional numerical simulation method, and the results show that the bottom hole pressure simulated by the FCEM is consistent with the results from traditional numerical simulation method, and the matching rate is larger than 95%. The proposed FCEM was also used in the optimization of fracturing parameters by coupling the hydraulic fracture propagation method and intelligent optimization algorithm. The integrated intelligent optimization approach for multi-parameters, such as perforation number, perforation location, and displacement in hydraulic fracturing is proposed. The proposed approach was applied in a shale gas reservoir, and the result shows that the optimized perforation location and morphology distribution are related to the distribution of porosity/permeability. When the perforation location and displacement are optimized with the same fracture number, NPV increases by 70.58%, which greatly improves the economic benefits of unconventional reservoirs. This work provides a new way for flow simulation and optimization of hydraulic fracture morphology of multi-fractured horizontal wells in unconventional reservoirs.

Mutual impact of true triaxial stress, borehole orientation and bedding inclination on laboratory hydraulic fracturing of Lushan shale

Unconventional resources like shale gas has been the focus of intense research and development for two decades. Apart from intrinsic geologic factors that control the gas shale productivity (e.g. organic matter content, bedding planes, natural fractures, porosity and stress regime among others), external factors like wellbore orientation and stimulation design play a role. In this study, we present a series of true triaxial hydraulic fracturing experiments conducted on Lushan shale to investigate the interplay of internal factors (bedding, natural fractures and in situ stress) and external factors (wellbore orientation) on the growth process of fracture networks in cubic specimens of 200 mm in length. We observe relatively low breakdown pressure and fracture propagation pressure as the wellbore orientation and/or the maximum in situ stress is subparallel to the shale bedding plane. The wellbore orientation has a more prominent effect on the breakdown pressure, but its effect is tapered with increasing angle of bedding inclination. The shale breakdown is followed by an abrupt response in sample displacement, which reflects the stimulated fracture volume. Based on fluid tracer analysis, the morphology of hydraulic fractures (HF) is divided into four categories. Among the categories, activation of bedding planes (bedding failure, BF) and natural fractures (NF) significantly increase bifurcation and fractured areas. Under the same stress regime, a horizontal wellbore is more favorable to enhance the complexity of hydraulic fracture networks. This is attributed to the relatively large surface area in contact with the bedding plane for the horizontal borehole compared to the case with a vertical wellbore. These findings provide important references for hydraulic fracturing design in shale reservoirs.

Experimental Study on Cyclic Hydraulic Fracturing of Tight Sandstone under In-Situ Stress

Sandstone oil–gas reservoirs in the Junggar Basin, China have great development potential. However, their ultra-deep formation depth leads to high crustal stress and high breakdown pressure. Therefore, in this research, we studied the cyclic hydraulic fracturing of tight sandstone with different combinations of “high-pressure duration + low-pressure duration” under high-stress conditions. Through laboratory experiments, the pump pressure curves, hydraulic fracture morphology, acoustic emission counts, and peak frequency of the samples were obtained. The results showed that: (1) Compared with conventional hydraulic fracturing, the breakdown pressure of cyclic hydraulic fracturing was reduced by more than 30%, the minimum threshold of cyclic pump pressure required for sample breakdown was between 60%Pb and 70%Pb, and cyclic hydraulic fracturing more easily formed complex and diverse hydraulic fractures. (2) In cyclic hydraulic fracturing, under the same upper limit of cyclic pump pressure, the shorter the high-pressure duration, the fewer the cycles required for sample breakdown. (3) Under the same “high-pressure duration + low-pressure duration” condition, the lower the upper limit of the cyclic pump pressure, and the greater the number of cycles required for sample breakdown. (4) The AE cumulative counts curves fluctuated greatly during cyclic hydraulic fracturing, rising in an obvious step-wise manner and the AE peak frequency was banded and mainly divided into three parts: low frequency, medium frequency, and high frequency.

Study on the Hydraulic Fracturing of the Inter-Salt Shale Oil Reservoir with Multi-Interfaces

Hydraulic fracture morphology and propagation mode are difficult to predict in layers of the various lithological strata, which seriously affects exploitation efficiency. This paper studies the fundamental mechanical and microscopic properties of the two main interfaces in inter-salt shale reservoirs. On this basis, cement-salt combination samples with composite interfaces are prepared, and hydraulic fracturing tests are carried out under different fluid velocities, viscosity, and stress conditions. The result shows that the shale bedding and salt-shale interface are the main geological interfaces of the inter-salt shale reservoir. The former is filled with salt, and the average tensile strength is 0.42 MPa, c = 1.473 MPa, and φ = 19.00°. The latter is well cemented, and the interface strength is greater than that of shale bedding, with c = 2.373MPa and φ = 26.15°. There are three basic fracture modes for the samples with compound interfaces. Low-viscosity fracturing fluid and high-viscosity fracturing fluid tend to open the internal bedding interface and produce a single longitudinal crack, respectively, so properly selecting the viscosity and displacement is necessary. Excessive geostress differences will aggravate the strain incompatibility of the interface between different rock properties, which makes the interfaces open easily. The pump pressure curves’ morphological characters are different with different failure modes.

A HYBRID NUMERICAL/ANALYTICAL MODEL OF TRANSIENT SEEPAGE FOR VERTICAL FRACTURED WELL IN TIGHT GAS RESERVOIR BY USE OF FRACTAL THEORY AND CONFORMAL MAPPING METHOD

Insufficient consideration of the complex morphology of hydraulic fractures (HF) and heterogeneous physical properties of fractured reservoirs in seepage models can result in unreliable well testing analyses. The fractal porosity and permeability (FPP) model provides an effective method for characterizing reservoir heterogeneity in the near-wellbore zone. However, its application to scenarios involving irregularly-shaped hydraulic fracture networks and multiple fracture clusters is challenging due to the lack of spatial symmetry. To address this issue, this paper proposes a combined approach of FPP and conformal mapping (FPP-CM) to transform the region of fractured formation into the exterior of the unit disk domain using numerical conformal mapping. The transient seepage flow model of the vertical fracture well (VFW) is then established by coupling it with the FPP model. The typical curve of pressure transient behavior with the division of flow stages was plotted, and the model verification and sensitivity analysis of parameters were conducted. The results indicate that the fractal dimension primarily affects the formation linear flow stage and its subsequent flow stages; with a decrease in fractal dimension resulting in an increase in the position of the typical curve. For VFW with multiple HF wings, a decrease in the included angle of fracture wings causes an increase in the heterogeneity distribution of microfracture physical properties, resulting in an increase in the position of the pseudo-pressure derivative curve during the late flow stage.

A simulation study of hydraulic fracturing design in carbonate reservoirs: a middle east oilfield case study

The interactions between hydraulic fracture morphology and fluid transport mechanisms after large-scale fracturing in low-permeability carbonate reservoirs are important factors that could impact post-fracturing productivity. Using an integrated geology-engineering approach that consists of hydraulic fracturing and reservoir simulation, this paper presents the detailed hydraulic fracturing simulation and design of a low-permeability carbonate reservoir in the Middle East based on sweet spot mapping. The fracturing protocol is determined based on productivity charts, which are obtained via sweet spot mapping of the target carbonate reservoir. The daily production of a horizontal well in the reservoir shows an increase from 870 to 2000 bbl/d after the hydraulic fracturing design and implementation, which is the highest among the existing production wells in same oilfield. The results are shown to be consistent with the proposed productivity chart, which suggests that the implemented workflow could be helpful for the large-scale fracturing implementation of similar carbonate reservoirs.

The hydraulic fracturing design technology and application of geological-engineering integration for tight gas in jinqiu gas field

Tight sandstone gas reservoir of Shaximiao formation in Jinqiu Gas field has the advantages of wide distribution and abundant resources. Due to its low porosity, low permeability and strong spatial heterogeneity, this reservoir puts forward high requirements for sweet spot identification, cluster design and hydraulic fracture morphology prediction. Since the conventional stimulation methods can not meet the requirement of economy, the geological-engineering integration model is established. This optimization model of multiple subjects could layout the relationship among engineering characteristics, hydraulic fracture shape and well productivity. Based on the simulation results, key controlling factors are identified and optimized. And the customized stimulation strategies are recommended for different reservoir quality and different channel sand. Through application of these methods, the average test well productivity in the target field increased from 50,500 cubic meter per day to 434,300 cubic meter per day, and it lay a solid foundation for the efficient development of tight gas in central Sichuan Basin.

Nanomaterials and Technology Applications for Hydraulic Fracturing of Unconventional Oil and Gas Reservoirs: A State-of-the-Art Review of Recent Advances and Perspectives.

The application of hydraulic fracturing stimulation technology to improve the productivity of unconventional oil and gas reservoirs is a well-established practice. With the increasing exploration and development of unconventional oil and gas resources, the associated geological conditions and physical properties are gradually becoming more and more complex. Therefore, it is necessary to develop technologies that can improve the development benefits to meet these challenges. In recent years, improving the effect of hydraulic fracturing stimulation in unconventional oil and gas reservoirs through the use of nanomaterials and technologies has attracted increasing attention. In this paper, we review the current status and research progress of the application of nanomaterials and technologies in various aspects of hydraulic fracturing in unconventional oil and gas reservoirs, expound the mechanism and advantages of these nanomaterials and technologies in detail, and provide future research directions. The reviewed literature indicates that nanomaterials and technologies show exciting potential applications in the hydraulic fracturing of unconventional reservoirs; for example, the sand-carrying and rheological properties of fracturing fluids can be significantly enhanced through the addition of nanomaterials. The use of nanomaterials to modify proppants can improve their compressive strength, thus meeting the needs of different reservoir conditions. The fracturing flowback fluid treatment efficiency and purification effect can be improved through the use of nanophotocatalysis and nanomembrane technologies, while degradable fracturing completion tools developed based on nanomaterials can effectively improve the efficiency of fracturing operations. Nanorobots and magnetic nanoparticles can be used to more efficiently monitor hydraulic fracturing and to accurately map the hydraulic fracture morphology. However, due to the complex preparation process and high cost of nanomaterials, more work is needed to fully investigate the application mechanisms of nanomaterials and technologies, as well as to evaluate the economic feasibility of these exciting technologies. The main research objective of this review is to comprehensively summarize the application and research progress of nanomaterials and technologies in various aspects of hydraulic fracturing in unconventional oil and gas reservoirs, analyze the existing problems and challenges, and propose some targeted forward-looking recommendations, which may be helpful for future research and applications.

Simulation study on the deflection and expansion of hydraulic fractures in coal-rock complexes

The physical difference and structural weak surface of coal-rock complexes greatly influence the morphology of hydraulic fractures (HFs). This study aims to explore the law of deflection and expansion of HFs in coal-rock complexes under different stress conditions. First, a theoretical model for HF deflection in coal-rock complexes was derived. Besides, a numerical model for HF expansion in coal-rock complexes was established based on the traction–separation criterion, the cohesion embedding method and the finite element method for fracture expansion. With the aid of the established model, the laws of morphology and induced stress field evolutions during HF expansion were studied. The following conclusions were drawn. When the HF is closer to the interface, the effect of physical difference is more notable, and the HF is more likely to expand along the coal seam. As the difference between the maximum horizontal principal stress and the vertical ground stress decreases from 8 MPa to 0 MPa, the coal-rock complexes experience HF expansion in the horizontal direction, secondary fracture generation in the Z-axis direction, and HF deflection to the interface in the -Z-axis direction in turn. During HF expansion, a stress difference of about 19 MPa exists between the fracture tip section and the interface, which is favorable for HF initiation and expansion. The effect of physical difference between coal and rock leads to the formation of an induced stress field, which causes a 3–4 times difference in the displacement values in different areas during HF expansion. The abovementioned main causes of HF deflection can provide reference for the design and application of the hydraulic fracturing technology for complex formations with different lithologies.