Formation Of Complex Fracture Networks Research Articles

Simulation of Key Influencing Factors of Hydraulic Fracturing Fracture Propagation in a Shale Reservoir Based on the Displacement Discontinuity Method (DDM)

In the process of the large-scale hydraulic fracturing of a shale gas field in the Weiyuan area of Sichuan province, the quantitative description and evaluation of hydraulic fracture expansion morphology and the three-dimensional distribution law are the key points of evaluation of block fracturing transformation effect. Many scholars have used the finite element method, discrete element method, grid-free method and other numerical simulation methods to quantitatively characterize hydraulic fractures, but there are often the problems that the indoor physical simulation results are much different from the actual results and the accuracy of most quantitative studies is poor. Considering rock mechanics parameters and based on the displacement discontinuity method (DDM), a single-stage multi-cluster fracture propagation model of horizontal well was established. The effects of Young’s modulus, Poisson’s ratio, the in situ stress difference, the approximation angle, the perforation cluster number and the perforation spacing on the formation of complex fracture networks and on the geometrical parameters of hydraulic fractures were simulated. The research results can provide theoretical reference and practical guidance for the optimization of large-scale fracturing parameters and the quantitative post-fracturing evaluation of horizontal wells in unconventional reservoirs such as shale gas reservoirs.

Anisotropic Mechanical Behaviors of Shale Rock and Their Relation to Hydraulic Fracturing in a Shale Reservoir: A Review

Shale gas is an important supplement to the supply of natural gas resources and plays an important role on the world’s energy stage. The efficient implementation of hydraulic fracturing is the key issue in the exploration and exploitation of shale gas. The existence of bedding structure results in a distinct anisotropy of shale rock formation. The anisotropic behaviors of shale rock have important impacts on wellbore stability, hydraulic fracture propagation, and the formation of complex fracture networks. This paper briefly reviews previous work on the anisotropic mechanical properties of shale rock and their relation to hydraulic fracturing in shale reservoirs. In this paper, the research status of work addressing the lithological characteristics of shale rock is summarized first, particularly work considering the mineral constituent, which determines its physical and mechanical behavior in essence. Then the anisotropic physical and mechanical properties of shale specimens, including ultrasonic anisotropy, mechanical behavior under uniaxial and triaxial compression tests, and tensile property under the Brazilian test, are summarized, and the state of the literature on fracture toughness anisotropy is discussed. The concerns of anisotropic mechanical behavior under laboratory tests are emphasized in this paper, particularly the evaluation of shale brittleness based on mechanical characteristics, which is discussed in detail. Finally, further concerns such as the effects of bedding plane on hydraulic fracturing failure strength, crack propagation, and failure pattern are also drawn out. This review study will provide a better understanding of current research findings on the anisotropic mechanical properties of shale rock, which can provide insight into the shale anisotropy related to the fracture propagation of hydraulic fracturing in shale reservoirs.

Thermally-induced cracking behaviors of coal reservoirs subjected to cryogenic liquid nitrogen shock

The benefits of using cryogenic liquid nitrogen shock to enhance coal permeability have been confirmed from experimental perspectives. In this paper, we develop a fully coupled thermo-elastic model in combination with the strain-based isotropic damage theory to uncover the cooling-dominated cracking behaviors through three typical cases, i.e. coal reservoirs containing a wellbore, a primary fracture, and a natural fracture network, respectively. The progressive cracking processes, from thermal fracture initiation, propagation or cessation, deflection, bifurcation to multi-fracture interactions, can be well captured by the numerical model. It is observed that two hierarchical levels of thermal fractures are formed, in which the number of shorter thermal fractures consistently exceeds that of the longer ones. The effects of coal properties related to thermal stress levels and thermal diffusivity on the fracture morphology are quantified by the fracture fractal dimension and the statistical fracture number. The induced fracture morphology is most sensitive to changes in the elastic modulus and thermal expansion coefficient, both of which dominate the complexity of the fracture networks. Coal reservoir candidates with preferred thermal-mechanical properties are also recommended for improving the stimulation effect. Further findings are that there exists a critical injection temperature and a critical in-situ stress difference, above which no thermal fractures would be formed. Preexisting natural fractures with higher density and preferred orientations are also essential for the formation of complex fracture networks. The obtained results can provide some theoretical support for cryogenic fracturing design in coal reservoirs.

Characterization of the Fine-Scale Evolution of Damage in Shale under the Influence of Two-Way Stress Differences Based on CT Images and Fractal Theory—The Example of the Anba Dyke in the Wufeng–Longmaxi Formation

To better understand the influence of different levels of two-way stress differences on the development of damage in Anchang diametral laminar shale in the northern Qianbei area, a numerical model of laminar shale with a representative fine-scale structure was established by using RFPA3D-CT. A triaxial compression test was conducted; a three-dimensional mesoscale fracture box dimension algorithm based on digital images was generated by using MATLAB R2020b; and the fractal characteristics were quantitatively analyzed. The results showed that under the influence of the horizontal stress ratio and two-way stress, the greater the two-way stress is, the more notable the plastic characteristics of specimen damage are, and the higher the residual strength is. The specimens with lower two-way stress exhibited obvious brittle damage characteristics. The difficulty degree of complex fracture network formation increased with the increase in the horizontal tension ratio, and the degree of increase in the fracture network complexity gradually decreased. At a horizontal stress ratio of 1.25, the fractal dimension was the highest, which indicates that the cracks were the most pronounced. Fracture formation after specimen damage was the most common phenomenon. Under the condition of a lower horizontal stress ratio, a large number of fracture structures could be generated in shale specimens after damage, promoting the expansion of natural fractures.

Study of stress field induced by natural fracture and its influence on hydraulic fracture propagation

The change of fracture propagation direction caused by stress interference between fractures is one of the main reasons that affect shale gas productivity. Natural fractures will be damaged by the induced stress, and the induced stress field produced by natural fracture damage will in turn affect the propagation of hydraulic fractures. Previous studies usually ignored the impact of stress field variation caused by natural fracture damage, leading to inaccurate fracture propagation simulation results. A new model for simulating hydraulic fracturing-induced stress field is established with consideration of the influence of natural fracture damage. Then, the natural fracture-induced stress is analyzed in open and closed fracture states. Through superposition of stress fields of natural fractures and hydraulic fractures, the interaction among open and closed natural fractures, reservoir and hydraulic fracture, and the corresponding fracture property evolution are studied. The results demonstrate that induced stress is not affected by elastic modulus and Poisson's ratio of the rock. The induced stress difference at the fracture tip is proportional to the net pressure and the length of hydraulic fractures. The results provide guidance for the optimal design of fracturing. When the deflection angle of hydraulic fracture is less than 90°, the maximum induced stress difference at the fracture tip decreases with the reduction in the deflection angle. When the deflection angle of hydraulic fracture is smaller than 90° or the deflection angle of natural fracture is smaller than 45°, the steering of hydraulic fracture is less hindered, which is beneficial to the formation of complex fracture network.

An Optimal Model for Determination Shut-In Time Post-Hydraulic Fracturing of Shale Gas Wells: Model, Validation, and Application

The global shale gas resources are huge and have good development prospects, but shale is mainly composed of nanoscale pores, which have the characteristics of low porosity and low permeability. Horizontal drilling and volume fracturing techniques have become the effective means for developing the shale reservoirs. However, a large amount of mining data indicate that the fracturing fluid trapped in the reservoir will inevitably cause hydration interaction between water and rock. On the one hand, the intrusion of fracturing fluid into the formation causes cracks to expand, which is conducive to the formation of complex fracture networks; on the other hand, the intrusion of fracturing fluid into the formation causes the volume expansion of clay minerals, resulting in liquid-phase trap damage. At present, the determination of well closure time is mainly based on experience without theoretical guidance. Therefore, how to effectively play the positive role of shale hydration while minimizing its negative effects is the key to optimizing the well closure time after fracturing. This paper first analyzes the shale pore characteristics of organic pores, clay pores, and brittle mineral pores, and the multi-pore self-absorption model of shale is established. Then, combined with the distribution characteristics of shale hydraulic fracturing fluid in the reservoir, the calculation model of backflow rate and shut-in time is established. Finally, the model is validated and applied with an experiment and example well. The research results show that the self-imbibition rate increases with the increase in self-imbibition time, and the flowback rate decreases with the increase in self-imbibition time. The self-imbibition of slick water is the maximum, the self-imbibition of breaking fluid is the minimum, and the self-imbibition of mixed fluid is the middle, and the backflow rates of these three liquids are in reverse order. It is recommended the shut-in time of Longmaxi Formation shale is 17 days according to the hydration and infiltration model.

Study on the interaction between hydraulic fracture and natural fracture under high stress

The existence of natural fractures in the reservoir has a great influence on the formation of complex fracture network, but the interaction between hydraulic fractures and natural fractures under high stress was rarely studied. Through laboratory tests, the law and characteristics of the interaction between hydraulic fractures and natural fractures under high stress were studied from the aspects of natural fractures angle, size, quantity, production method and ground stress in this study. Based on these interaction characteristics, a complex fracture network formation method of deep reservoir was proposed, which provided reference for engineering practice. The criterion of interaction between hydraulic fracture and natural fracture was improved, and the calculation method of rock tensile strength in three-dimensional state was proposed, which was applied to the criterion of fracture opening and fracture expansion. Combined with laboratory tests, a special interaction mode of hydraulic fracture passing through a certain position from the direction to end A (F-Type crossing mode) under high stress was proposed, and the criterion of this interaction mode were obtained. The three-dimensional finite discrete element model (FDEM) was used to investigate the effects of natural fracture strength and fracturing fluid viscosity on hydraulic fracture propagation under high stress. The results showed that the natural crack strength has great influence on the width, volume and shape of hydraulic crack. Small difference of fracturing fluid viscosity has little influence on fracture propagation, but high viscosity fracturing fluid has a greater influence on fracture propagation. This study provided reference for hydraulic fracturing engineering.

Research on the impact of pre‐existing geological fractures on hydraulic fracturing in high in situ stress environments

AbstractThe formation of complex fracture network is a difficult problem in the process of deep rock reservoir reconstruction, and the key to the generation of intricate fracture systems in deep reservoirs is to communicate more pre‐existing fractures through hydraulic fracturing, so as to enhance oil recovery. At present, there are few studies on the interactions of hydraulic fractures with pre‐existing fractures under high stress. Therefore, this research studied the influence of the number of pre‐existing fractures on the characteristics of hydraulic fractures by using advanced hydraulic fracturing instruments, and then analyzed the characteristics of hydraulic fractures under different pre‐existing fracture number based on three‐dimensional topography scanning technology and three‐dimensional square box fractal dimension calculation method. Based on the three‐dimensional finite element discrete element method, further research is carried out. The laboratory test findings indicated that the increase of pre‐existing fractures will make the pump pressure curve more stable during the test, and will significantly improve the roughness of hydraulic fractures. The numerical simulation indicated that as the quantity of pre‐existing fractures grows, the fracture area and width also increase, and in instances of a substantial quantity of pre‐existing fractures, the hydraulic fractures are prone to bifurcation, which contributes to the development of intricate fracture networks. With the increase of natural fracture angle, the fracture width decreased, but the fracture area increased. In this study, the influence of the number of pre‐existing fractures on hydraulic fracturing was studied through laboratory tests and numerical simulations, which provided theoretical reference for engineering practice.

Research on the Influence of Shale Reservoir Depth on Fracture Characteristics Based on Xsite

The exploration and development of shale reservoir is faced with both opportunities and challenges, especially the mechanism of influence of shale reservoir depth on hydraulic fracture characteristics is unclear. In this paper, by means of Xsite simulation, four stress levels are set to reflect the depth change from the side, and the influence of depth change on the hydraulic fracture characteristics of shale reservoir is studied. The results reveal a phenomenon: in the low stress environment, the fracture network can be effectively constructed, showing a more spacious space structure; In high-stress environments, the propagation direction of hydraulic fractures is precisely controlled, and these fractures can communicate more closely with the bedding surface. It is worth noting that in the low stress environment, the tensile fracture has a large area and forms a broad fracture network. In contrast, in high-stress environments, shear fractures dominate and their area increases significantly. In addition, the fracture volume is larger under low stress environment, while the total fracture area is more significant under high stress environment. This discovery has far-reaching significance for the formation of complex fracture networks in shale reservoirs, emphasizes the importance of making full use of shale multilayer characteristics, and provides rich and profound theoretical guidance for engineering practice.

Prediction criterion and numerical validation for the interaction between hydraulic fractures and bedding planes.

Shale is a kind of sedimentary rock with an obvious bedding structure. The effect of the bedding plane on hydraulic fracture initiation, propagation, and complex fracture network formation is remarkable and a major problem in hydraulic fracturing and shale oil and gas development. In this study, a criterion is established to predict the evolution behavior of hydraulic fractures (HF) under different confining pressure differences and intersection angles. This criterion is intended to predict the types of interaction between HFs and bedding planes (BPs): penetrating, slipping, or dilating. The dependence of crossing on the intersection angle and the principal stress difference is quantitatively presented using the criterion. Meanwhile, 20 simulations with principal stress differences of 2, 4, 6, and 8 MPa and intersection angles of 30°, 45°, 60°, 75°, and 90° were simulated using the RFPA2D-Flow code. Simulation results exhibit good agreement with the criterion results for a wide range of angles. The investigation showed that HFs tend to penetrate BPs under high confining pressure differences and intersection angles and open BPs under low confining pressure differences and intersection angles. In addition to the above two forms, HFs slip due to shear. The criterion can provide relevant reference about the formation of complex fracture networks in shale layers.

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.

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.

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.

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.

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.

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.

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.