Formation Of Fracture Networks Research Articles

Investigation of Natural Weak Interface Properties and Their Impact on Fracture Propagation in Shale Reservoirs

Horizontal well multi-cluster fracturing technology is crucial for the economic development of fractured shale reservoirs. The abundance of natural fractures in shale reservoirs significantly influences the propagation path of hydraulic fractures and determines the formation of complex fracture networks. To investigate the impact of natural weak planes on the geometric parameters of fractures in shale reservoirs, we first conducted tests on the mechanical characteristics of core samples from outcropping shale in the Weiyuan area using the indoor three-point bending method and digital image correlation (DIC) technology, providing data validation for subsequent numerical models. Secondly, considering the interaction between hydraulic and natural weak planes in three-dimensional space, we established a three-dimensional numerical model for horizontal well fracturing to simulate the synchronous competition and expansion of fractures in multi-cluster fracturing. Based on this foundation, we analyzed the influence of formation parameters and engineering parameters on the formation patterns of complex fracture networks. The results indicate that the difference in in situ stress is a significant factor affecting the selection of fracture propagation paths. As the in situ stress difference increases, it becomes more challenging to open natural fractures, leading to a reduced probability of activation of natural weak interfaces. When the cohesive strength of natural fractures is smaller, they are more likely to open and capture hydraulic fractures, thereby increasing shear slip length and fracture network area. Each fracturing stage has an optimal perforation density combination, where a higher density of perforations leads to reduced perforation pressure drop and weaker ability to mitigate inter-cluster stress interference. To achieve a comprehensive and balanced development of multi-clusters, the inter-cluster stress interference can be alleviated by increasing the perforation pressure drop. For dense perforation clusters, higher injection rates and viscosity can be employed to ensure the uniform development of multiple perforation clusters. This study provides new insights into predicting the formation of complex fracture networks in shale reservoirs and offers valuable guidance for optimizing hydraulic fracturing designs.

A method for predicting the probability of formation of complex hydraulic fracture networks in shale reservoirs: development and application

A method for predicting the probability of formation of complex hydraulic fracture networks in shale reservoirs: development and application

Comparison of mechanical characteristics of different types of shales in the Ordos Basin

Shale gas is a very important unconventional energy. The mechanical properties of the three types of shale (laminated shale, sandwich shale and foliated shale) are different, and the difference in fracturing effectiveness is very significant. In this paper, the mineral composition, mechanical properties and conductivity of these three different types of shale were studied and compared by X-ray diffraction, triaxial mechanical experiments, and fracture conduction experiments. The study found that the foliated shale has the lowest content of rigid minerals (47.5%), lower elastic modulus and tensile strength (26.98 Gpa and 168.29 MPa, respectively), higher Poisson’s ratio (0.25), the smallest brittleness index (0.48), and larger fracture toughness (0.42). The laminated shale has a higher content of rigid minerals (68.50%), the lowest elastic modulus and tensile strength (25.77 Gpa and 122.46 MPa, respectively), the highest Poisson’s ratio (0.26), the highest brittleness index (0.56), and the lowest fracture toughness (0.18). The sandwich shale has the highest rigid mineral content (78.16%), the highest elastic modulus and tensile strength (35.31 Gpa and 197.37 MPa, respectively), the lowest Poisson’s ratio (0.24), a larger brittleness index (0.52), and larger fracture toughness (0.415). Furthermore, with the increase in the coring angle, the elastic modulus of all three shales increases. In addition, with the increase in closing pressure and the decrease in the sand laying concentration, the proppant embedding depth gradually increases and the conductivity decreases. This means that from the perspective of forming complex fracture networks, the fracturing effect of the foliated shale is unsatisfactory, while the fracturing effect of the laminated and sandwich shales is better. Moreover, it is recommended to prefer directional injection along vertical laminae or at high angles, which is conducive to the formation of complex fracture networks. For laminated shale with low strength, the sand laying concentration should be increased to ensure the conductivity of the fractured fracture. This study provides some technical guidance for the identification of different types of shale fracturing desserts and fracturing processes.

Fracture Propagation Mechanism of Tight Conglomerate Reservoirs in Mahu Sag

Conglomerate reservoirs are usually formed in sag slope belts, which have the characteristics of near-source rapid deposition, rapid sedimentary facies change, and distinct reservoir heterogeneity. Therefore, it is difficult to carry out treatments of stimulation because of insufficient understanding of the propagation mechanism of the unique “gravel-bypassing” and “gravel-penetrating” characteristics of fracture morphologies in Mahu conglomerate reservoirs. In order to study the law of hydraulic fracture propagation in conglomerate reservoirs, based on Brazilian splitting test results for conglomerates with different gravel particle sizes and different cementation degrees, true tri-axial fracturing experiments conducted in the laboratory were performed to conduct experimental research on natural conglomerate outcrops and analyze the effects of gravel size, fracturing fluid viscosity, and pumping rate on hydraulic fracture propagation morphology. The results show that: (1) the gravel cementation strength of fracture pressure is higher and the pressure drops preferably after fracturing. The fracture is more inclined to “pass through the gravel” to propagate in large-particle-size gravel. The poor gravel cementation of fracture pressure is relatively low-level and the pressure after fracture drops slightly, and fractures tend to occur at the margin of gravel; (2) using slick water for fracturing tends to initiate and propagate fractures at multiple points on the wellbore, which is conducive to the formation of complex fracture networks and the improvement of volume stimulation effects. Guanidine-gum fracturing has a higher fracture-forming efficiency and higher net pressure; and (3) a low pumping rate will increase the interaction degree between fractures and gravel, and gravels will cause a change in fracture roughness, resulting in small local fracture widths.

Analytical Investigation on the Shear Propagation Mechanism of Multi-Cracks in Brittle Tight Rocks under Compressive and Shear Loading Conditions

There is abundant shale oil in the ocean and on land. Due to the tight lithology of the reservoir, volume fracturing technology is needed to improve the oil and gas productivity. It is very important to study the expansion law of multiple natural fractures in rock masses and its influencing factors in the process of volume fracturing for the formation of fracture networks. Based on the theory of online elastic fracture mechanics, the calculation method of the stress intensity factor at the end of any I–II composite fracture is established by using effective shear stress and considering the influence of T-stress. The calculation model of the stress intensity factor of any fracture on the main fracture wall or the horizontal section of the main fracture wall is established according to the concrete stress conditions in the process of hydraulic fracturing. Based on the principle of stress superposition, the combined interference stress calculation model of fracture ends is established for the case of multiple penetrating cracks in infinite-plane rock masses. Based on the theory of shear failure and plane strain, a model of the initiation direction and condition of natural cracks on the horizontal section of the main fracture wall and both sides of the main fracture in brittle rock is established when there are many coaxial natural cracks under the action of remote site stress and water pressure on the fracture surface. According to the simulation results, on the main fracture wall, when σH > σv > σh or σH > σh > σv, when the crack angle (CA) is within a certain range and multiple natural cracks (MNC) exist, the required pressure for shear failure decreases. When the fracture angle exceeds a certain size, the required pressure increases. When there are MNC in the horizontal or perpendicular sections of the rock mass on both sides of the main fracture, the required net pressure for shear failure decreases within a certain CA range. When the CA exceeds a certain range, it increases or remains basically unchanged. On the whole, the presence of MNC reduces the net pressure for shear failure, which is conducive to the formation of fracture networks.

The propagation behavior of hydraulic fracture network in a reservoir with cemented natural fractures

AbstractThere are still some problems in the study of hydraulic fracture (HF) network evolution in cemented naturally fractured reservoirs, such as microseismic mapping showing exaggerated stimulated reservoir volume in some cases. In addition, the dominant role of natural fracture (NF) cementation strength, injection rate, in situ stress difference, NF distribution, and fracture initiation sequence of perforations in synthetically influencing fracture network formation needs to be further studied. For this purpose, a three‐dimensional matrix hexahedral element global coupled 0‐thickness cohesive element hydraulic fracturing model was developed. Results show that each interaction between HF and NF causes HF diameter shrinkage, which increases the propagation pressure of HF. When the cementation strength of the NF is low, the HF tends to deviate toward the tip of the NF to form a complex fracture network. Increasing the injection rate and the number of NFs can significantly enhance the complexity of the HF network, but does not change the HF and NF interaction pattern. The in situ stress differences dominate the morphology of the HF network when the cementation strength of NFs is constant. The stress interference of multiple fractures under segmented fracturing may form “S”‐shaped HFs, and the HFs are difficult to maintain a symmetrical morphology in the direction of the well axis. In addition, some NFs in inactivated damaged zones have developed a certain width geometrically due to the induced effect of HF, but they are still isolated by the low permeability matrix and might only generate some microseismic events.

Laboratory hydraulic fracturing in layered tight sandstones using acoustic emission monitoring

Understanding the propagating mechanism of complex fracture network is essential for optimizing the hydraulic fracturing design scheme. Laboratory hydraulic fracturing experiments were performed on three tight sandstone specimens with bedding plane perpendicular, oblique and parallel to the axial direction, respectively. Before hydraulic fracturing, three specimens were first loaded close to the critical stress state under 22.5 MPa confining pressure. The entire hydraulic fracturing process was monitored by acoustic emission (AE) and ultrasonic measurement. The experimental results show that the hydraulic fracturing behaviors were significantly influenced by bedding structure and water infiltration. The bedding plane plays an important role on breakdown pressure, distribution characteristics of AE activities and hydraulic fracture networks. The bedding-oblique specimen exhibits lower breakdown pressure than those of the bedding-parallel and bedding-perpendicular specimens. AE activities in the bedding-oblique specimen is characterized by lower b-value, while higher b-value is found in other two specimens. X-ray computed tomography images of the broken specimens show an excellent agreement between AE hypocenters and macroscopic fractures, indicating geometrical morphology of macroscopic fractures is closely related to the bedding plane and well imaged by AE hypocenters. A bedding-parallel shear fault formed in the bedding-oblique specimen. Complex shear fault linking several bedding-parallel echelon arrays or branches formed in the bedding-parallel and bedding-perpendicular specimens. Water infiltration affects the hydraulic fracturing behaviors by inducing AE events initiate at transition region of wet-dry boundary around the central borehole. In view of the formation of fracture network and the risk of induced seismicity, the influence of bedding structure and water infiltration should be taken into consideration under given in-situ stress regime during the hydraulic fracturing design scheme.

The role of natural fracture activation in hydraulic fracturing for deep unconventional geo-energy reservoir stimulation

The presence of sealed or semi-sealed, multiscale natural fracture systems appears to be crucial for the successful stimulation of deep reservoirs. To explore the reaction of such systems to reservoir stimulation, a new numerical simulation approach for hydraulic stimulation has been developed, trying to establish a realistic model of the physics involved. Our new model successfully reproduces dynamic fracture activation, network generation, and overall reservoir permeability enhancement. Its outputs indicate that natural fractures facilitate stimulation far beyond the near-wellbore area, and can significantly improve the hydraulic conductivity of unconventional geo-energy reservoirs. According to our model, the fracture activation patterns are jointly determined by the occurrence of natural fractures and the in situ stress. High-density natural fractures, high-fluid pressure, and low effective stress environments promote the formation of complex fracture networks during stimulation. Multistage or multicluster fracturing treatments with an appropriate spacing also increase the stimulated reservoir area (SRA). The simulation scheme demonstrated in this work offers the possibility to elucidate the complex multiphysical couplings seen in the field through detailed site-specific modeling.

Hydraulic fracture network propagation in a naturally fractured shale reservoir based on the “well factory” model

In different geological and engineering conditions, it is important to study the stress interference of multiple fractures and interaction of natural fractures in “well factory” fracturing to improve the complexity of fracture networks. For this purpose, a 2D, coupled stress-seepage-damage field cohesive model with random propagation of hydraulic fracture was developed, and a random function was used to simulate the natural fractures distribution in a real reservoir. Orthogonal test was designed to investigate the geological and engineering parameters impacting the evolution of zipper fracturing and modified zipper fracture networks. The results show that in naturally fractured reservoirs, hydraulic fracture can open natural fractures and promote the formation of complex fracture networks by combined, induced manner. Higher stress differences lead to simpler fracture networks and straighter hydraulic fracture propagation paths; When pre-existing natural fracture is longer, the propagation direction of hydraulic fracture is more likely to be paralleled with natural fracture; However, the stress shadow effect of multiple fractures may potentially lead to failure of some hydraulic fracture initiation. In addition, the fracture initiation sequence of multiple fractures has a significant effect on the evolution of the fracture networks. The results of the study have important significance for parameter optimization of well factory fracturing in naturally fractured reservoirs.

Numerical Investigation of Hydraulic Fracture Network Formation of Jointed Shale with Oriented Perforation

This paper aims at exploring the fracture evolution as well as capturing the fracture network formation of jointed shale during hydraulic fracturing process by numerical simulation using the Rock Failure Process Analysis System of Flow (RFPA—Flow). The simulations were successfully completed following two stages. In the first stage, a series of simulations are performed to investigate the influence of different angle-oriented perforations on fracture initiation and propagation. The simulation results agreed well with the experimental results confirming the validity of the RFPA-Flow code in the application. In the second stage, extensive hydraulic fracturing simulations on jointed shale with different angled-joint planes and different angle-oriented perforations were performed. The simulation results demonstrated that the fracture evolution changes significantly as the magnitude of α (the angle between perforation and the joint plane) increased. It was found that a large α value could lead to a larger the tensile stress region around the fracture tip resulting in more joint planes pulled apart. It could also induce more secondary fractures and hence a more complex fracture could be formed. As a result, the α value of 60° to 90° were found to aid in the fracture network generation. On the other hand, the angle β being the angle between the parallel joints and the maximum stress direction was another important factor in fracture evolution. Its influence on fracturing performance was similar to angle α. It was found that the initiation and breakdown pressure of jointed shale were in proportional to the magnitude of angle β. Therefore, this paper introduced an efficient approach to promote the formation of a complex fracture network in jointed shale with the presence of oriented perforation, which could offer valuable guidance for the design of unconventional reservoir reconstruction.

Fracture characterization based on improved seismic amplitude variation with azimuth inversion in tight gas sandstones, Ordos Basin, China

Fractures are essential for gas accumulation in tight sandstones, as they enhance reservoir permeability and provide migration paths for fluid transport. The presence of fractures facilitates the formation of fracture networks during hydraulic fracturing and, therefore, is important for effective development of tight gas sandstones. Accordingly, predicting fracture distribution could provide insight into the reservoir quality of tight gas sandstones. Seismic amplitude variation with azimuth can evaluate the properties of vertical fractures embedded in tight sandstone. This study proposes an improved inversion scheme based on azimuthal amplitude differences to compute anisotropic parameters for fracture characterization by incorporating rock physics relationships. Our proposed method improves the robustness of the anisotropic parameter estimates by removing the effect of the isotropic background using azimuthal amplitude difference data obtained after evaluating fracture strikes. Theoretical modeling and real data analysis illustrated the enhanced sensitivity of the azimuthal amplitude differences to the anisotropy related to fractures. Real data applications indicated that the predicted fracture strikes coincide with the results estimated by tectonic stress field analysis. The computed fracture density correlates with logging permeability, implying considerable influence from fractures on permeability improvement in tight sandstones. Further analysis indicated that the gas production capacity of tight sandstones is affected simultaneously by fractures and gas enrichment. Accordingly, an integrated indicator is proposed to evaluate reservoir quality, that simultaneously considers the degree of fracture development quantified by the fracture density, and gas enrichment represented by rock compressibility. The proposed indicator is correlated positively with comprehensive reservoir properties defined by the cumulative sand layer thickness, porosity, gas saturation, and permeability, providing a reliable and practical pointer to identify favorable areas in tight gas sandstones.

The impact of changes in natural fracture fluid pressure on the creation of fracture networks

Complex fracture networks have been observed in mine-back experiments, core samples, and other fracture diagnostic measurements. The interaction between hydraulic and natural fractures plays a key role in the formation of this complexity in naturally fractured formations. In past studies, changes in fluid pressure in natural fractures induced by interaction with other fractures are neglected when interactions between natural and hydraulic fractures are considered. In this paper, a DDM-based hydraulic fracturing simulator is developed to investigate the effect of changes in fluid pressure in natural fractures on fracture behavior and the resulting geometry of complex fracture networks. A fully implicit method is used to solve for width and pressure simultaneously. The proposed model is validated against an analytical solution for such variations in the vicinity of a penny-shaped fracture. Two kinds of interactions between hydraulic and natural fractures are defined to clearly investigate the mechanism of the far-field failure of natural fractures. Comparisons with and without considering changes in fluid pressure in natural fractures are conducted to show how the geometry of hydraulic fractures changes when changes in fluid pressure in fractures are included. Key parameters such as in-situ stress, natural fracture orientation, and friction coefficient are varied to develop new failure and crossing criteria under different conditions.Simulation results show that (1) changes in fluid pressure in fractures can initiate isolated fractures to create a stimulated rock volume. In some instances this will result in a more branched and complex fracture network; (2) deflection of hydraulic fractures along natural fractures is promoted when the effect of changes in fluid pressure in natural fractures is taken into account; (3) hydraulic fractures tend to deflect along pre-existing natural fractures with no far-field failure when the stress contrast is low; (4) in formations with high in-situ stress contrast, far-field failure of natural fractures occurs more readily and is impacted by the orientation and frictional coefficient of the natural fractures; (5) as expected, well cemented (highly mineralized) fractures with larger frictional coefficients hinder the slip of natural fractures and result in more planar less branched fractures. The results for failure and crossing criteria we developed can improve the understanding of the formation of complex fracture networks in naturally fractured rocks.

Effects of Thermal Stress in Hot Dry Rock Fracturing

Summary China has rich geothermal hot dry rock (HDR) resources, but the development and usage of its thermal energy are still at an early stage. At present, few studies have investigated the variation law for fracturing pressure on the borehole wall and fracture wall under the influence of thermal stress. This study investigates the fracturing pressure around the borehole wall based on rock mechanics and thermal stress analysis. Two models were developed: one for borehole wall fracturing pressure with consideration for thermal stress and the other for temperature difference conditions related to the automatic opening of fractures. By analyzing the temperature variation in the fracture wall, the mechanism for the opening of branch fractures at the fracture wall was investigated based on rock mechanics, the theory of fracture extension in hydraulic fracturing, and the theory of thermal stresses. We developed a computational model for tensile or shear damage related to branch fractures in the fracture wall with consideration for thermal stress, as well as a model for temperature difference conditions for the automatic opening of branch fractures. The simulation results show that the fracturing pressure decreased significantly when thermal stress was considered. Under normal geostress and temperature conditions, large temperature difference conditions are needed for the HDR borehole wall to break naturally because of thermal stress alone. During fracture extension, branch fractures on the fracture wall are more likely to form because of thermal stress. Irrespective of the type of damage (tensile or shear), branch fractures on the fracture wall closer to the borehole required lower net fracturing pressure. The decline in the net fracturing pressure was greater in response to shear damage than to tensile damage. In a high-temperature thermal reservoir, when branch fractures in the fracture wall were subjected to the temperature difference conditions for automatic opening, shear damage was more likely to occur than tensile damage. From the results, the following conclusions were obtained: The developed mechanical model of fracture opening reflects the mechanism of fracturing at the borehole wall and the fracture wall during HDR fracturing, thereby revealing the mechanism of the formation of fracture networks under thermal stress. For HDR fracturing, thermal stress promotes the formation of branch fractures in the fracture wall and increases the occurrence of complex fractures in the near-well region. Under thermal stress, the main fractures are less likely to extend in the optimal direction but instead tend to develop into complex fractures, which is not conducive to fracture connectivity between wells.

Characteristics and Dominant Factors for Natural Fractures in Deep Shale Gas Reservoirs: A Case Study of the Wufeng-Longmaxi Formations in Luzhou Block, Southern China

Abstract In southern Sichuan Basin, the main production layers are characterized by deeply buried, high stress difference, and complex structural conditions. The Luzhou area is far from large faults, and natural fractures are greatly important for shale gas storage and production. Multi-scale natural fractures control the migration, enrichment, and preservation conditions of shale gas, and facilitate the formation of complex fracture network under the action of hydraulic fracturing. In this study, based on the outcrops, drilling cores, geochemical tests, thin section, and other experiments, the development characteristics of the Wufeng-Longmaxi shale in the Luzhou block, Southern China, are statistically analyzed, and the controlling factors (e.g., tectonic factors, organic matter, mineral components, mechanical properties) are discussed in details. Fractures observed in the outcrops are mainly regional fractures with two groups of orthogonal joints. Similarly, fractures observed in the core are also mainly joints fractures perpendicular to the laminae with three typical features (high-density, high-angle, and unfilled). In detail, steeply dipping fractures (75-90°) account for 78.1% of all fractures, with 85.1% being unfilled, 78.1% having a longitudinal extension less than 4 cm, and 65.1% having a spacing less than 2 cm. In brief, there exist cross-scale similarity among outcrops, cores, and microscopic thin sections, which is critical to the shale gas preservation conditions. Based on this understanding, further research is conducted on the relationship between the fracture density and gas content, which shows that (i) when the fracture density is less than 122 number/m, TOC content and fracture density together positively dominate gas content; (ii) when fracture density exceeds 122 number/m, gas content appears negative with fracture density, and TOC content is not the critical factor anymore. The above study establishes quantitative limits for shale gas preservation in the study block. It may assist in providing references for determining the sweet spot area and further deep shale gas exploration and development in the southern Sichuan Basin.

Investigation of the Hydraulic Fracture Propagation Law of Layered Rock Strata Using the Discrete-Particle Model

Hydraulic fracturing is a rock structure transformation method that significantly weakens the mechanical properties of the hard roof strata. Considering the poor hydraulic fracturing effect of special structure such as composite layered rock, this paper carries out hydraulic fracturing numerical simulation experiments and compares the hydraulic fracture morphology and bedding plane interaction mode under different injection rate and injection modes. The experimental results show that the bedding plane can change the trajectory and propagation direction of hydraulic fracture. Under the low injection rate, hydraulic fracturing is conducive to open the bedding plane, but the expansion length of the main hydraulic fracture is easy to be limited. Under the high injection rate, the hydraulic fracture can extend for a long distance. But the fracture morphology tends to be slender and single, which is not conducive to the formation of fracture network. Compared with conventional hydraulic fracturing, stepped variable injection rate hydraulic fracturing can activate more bedding planes, so as to improve the effect of rock strata transformation. The experimental results are instructive in achieving effective control of composite layered rock.

Simulation of volumetric acid fracturing fracture in low permeability carbonate rock

The types of underground paleocarbonate reservoirs in Ordos Basin, China are complex and show a high filling degree as a whole. In the process of acid fracturing, there are many problems, such as unclear understanding of the fracture propagation and extension law of volume acid fracturing, no relevant experimental data on the conductivity of acid corrosion fracture formed after large displacement and large liquid injection, and lack of theoretical basis for volume acid fracturing design. In order to improve the accuracy and effectiveness of acid fracturing design of such reservoirs, taking MW-X well in Ordos Basin as an example, this paper analyzes the influence law of different factors on the formation of complex fracture network by establishing fracture extension model and judgment model of the encounter between hydraulic fractures and natural fractures. Finally, by establishing the acid flow reaction model and productivity prediction model in the fracture, the influence of different factors on the acid fracturing effect is analyzed, and then the volumetric acid fracturing process parameters are optimized.

Numerical study of hydraulic fracturing near a wellbore using dual boundary element method

The pattern and path of hydraulic fracture (HF) from a wellbore circumference have a great impact on subsequent formation of complex fracture networks highly desired for permeability enhancement of unconventional reservoirs. In this paper, a new fully coupled hydraulic fracturing model is developed in the framework of the dual boundary element method (DBEM) that describes the deformation of rock matrix and the finite volume method that simulates the fluid flow in the fracture and the distribution of injection rate among fractures. The DBEM applies displacement boundary integral equation to one crack surface and traction boundary integral equation to the other one. The model presented is first validated against the existing semi-analytical and numerical solutions for single fracture in an infinite domain, and shows excellent agreements with a relative error less than 1% for injection pressure and half fracture length. Then the problem of multiple HFs including natural fractures (NFs) cutting the wellbore is investigated. It is shown that a larger product of fluid viscosity and injection rate or a small in-situ stress difference can smooth the fracture path and enhance the fracture opening. In the presence of multiple fractures, the HF and NF competes in growth, and the results show that the initial permeability and inclination angle of NF can alter the propagation preference from HF to NF. In particular, a large fluid viscosity and a more isotropic stress condition will propagate both NFs and HFs simultaneously.

Study on the Evolution Law of Shale Hydraulic Fracture Interacting with Bedding Layer under Pulsation Loading

Abstract The bedding layers in shale reservoirs are highly developed with numerous bedding joints. In the hydraulic fracturing process, the propagation of hydraulic fractures during shale formation significantly affects the efficient development of reservoirs. In this study, we employed the pulsating cyclic loading technique to develop a model of the interaction between shale hydraulic fractures and bedding layer; in addition, we used a numerical model optimization method for the zero-thickness cohesive element to compare the hydraulic fracture and bedding layer propagation behavior under static and pulsating loading. We studied the propagation behavior of pulsating fracturing bedding layers at different frequencies, amplitudes, and bedding angles. The results revealed that static load fracturing is more conducive to the propagation of primary fracture under the same conditions, and that pulsation fracturing is better for the propagation of bedding layer. The higher frequency and amplitude of the seismic source in the pulsation fracturing process are more favorable to crossing the bedding layers. When the bedding angle is approximately 10°, turning the main fracture along the bedding direction is challenging. The hydraulic fracture along bedding layer propagation was achieved when the bedding angle was approximately 30° and 45°. When the bedding angle was approximately 60° or more, the fracture extended only along one side of the bedding layer. The study results provide guidance for the formation of fracture networks in the field of fracturing construction of shale reservoirs, thus improving the production of shale reservoirs.

Factors controlling the formation of complex fracture networks in naturally fractured geothermal reservoirs

Economic and efficient energy production from enhanced geothermal systems in naturally fractured rocks depends on the stimulation of natural fractures by hydraulic fractures to generate complex connected fracture networks. This fracture network provides pathways for maintaining high fluid injection and production rates which lead to high heat extraction rates. However, little work has been conducted to describe the formation of these complex fracture networks formed by the interaction of multiple hydraulic fractures with natural fractures. This paper presents a dynamic (time dependent), fully coupled hydraulic fracturing model that is capable of capturing fracture propagation, fracture deflection, the interaction between propagating hydraulic fractures and pre-existing natural fractures and fluid flow inside the fractures. The proposed model is validated against an analytical model for a penny-shaped hydraulic fracture. This model is then applied to conduct a detailed parametric study to investigate the effect of pre-existing natural fracture networks on the connectivity and propagation of hydraulic fractures. The orientation, length distribution, width distribution and connectivity of the created fracture network is studied. Simulation results indicate that: (1) the hydraulic fracture network is oriented in the direction of the dominant natural fracture network when the length of the natural fractures is large, and this leads to a large connected fracture area; (2) If the hydraulic fracture propagates at a large angle to the natural fractures, it results in a smaller connected fracture area and a complicated hydraulic fracture network that is dominated by shear failure events; (3) Natural fracture density plays a dominant role in the propagation direction of hydraulic fractures and the resulting connected fracture area; (4) Increasing the injection rate increases the connected fracture area and width while creating more complex hydraulic fracture networks and leads to more fracture dilation and less shear opening of cracks. The detailed parametric study helps us better understand the creation of fracture networks and can serve to guide us in hydraulic fracture design and optimization in naturally fractured geothermal reservoirs.

Insights Into Hydraulic Fracture Growth Gained From a Joint Analysis of Seismometer‐Derived Tilt Signals and Acoustic Emissions

AbstractHydraulic fracturing is performed to enhance rock permeability, for example, in the frame of geothermal energy production or shale gas exploitation, and can potentially trigger induced seismicity. The tracking of increased permeabilities and the fracturing extent is often based on the microseismic event distribution within the stimulated rock volume, but it is debated whether the microseismic activity adequately depicts the fracture formation. We are able to record tilt signals that appear as long‐period transients (180 s) on two broadband seismometers installed close (17–72 m) to newly formed, meter‐scale hydraulic fractures. With this observation, we can overcome the limitations of the microseismic monitoring alone and verify the fracture mapping. Our analysis for the first time combines a catalog of previously analyzed acoustic emissions ([AEs] durations of 20 ms), indirectly mapping the fractures, with unique tilt signals, that provide independent, direct insights into the deformation of the rock. The analysis allows to identify different phases of the fracturing process including the (re)opening, growth, and aftergrowth of fractures. Further, it helps to differentiate between the formation of complex fracture networks and single macrofractures, and it validates the AE fracture mapping. Our findings contribute to a better understanding of the fracturing processes, which may help to reduce fluid‐injection‐induced seismicity and validate efficient fracture formation.