Complex Hydraulic Fracture Network Research Articles

Numerical study of multiple hydraulic fractures propagation in poroelastic media based on energy decomposition phase field methods

This paper proposes a novel phase-filed model for simulating hydraulic fracturing in poroelastic media under complex stress conditions. The main theoretical contribution lies in the fact that a generalized strain energy density decomposition is incorporated to hydraulic fracturing phase field model, which unifies hydrostatic-deviatoric and spectral decompositions and predicts material failure through classical Mohr-Coulomb failure criterion. Based on Biot’s poroelastic theory, an indicator function is used to distinguish between fluid flow in fractures and in pores. The fully coupled equations are solved by combining staggered schemes with Newton-Raphson methods. The proposed model is validated by comparing laboratory experimental results with numerical results. In order to demonstrate the influence of introducing hydrostatic-deviatoric and spectral energy decompositions, we simulated propagation of multiple hydraulic fractures and coalescence of hydraulic fractures with natural fractures. Finally, the effects of stress ratios (σx/σy) on multiple hydraulic fractures are analysed. It is found that when the stress ratio is 2, a more complex hydraulic fracture network is formed in the porous media.

A numerical study of complex fractures propagation path in naturally fractured gas shale: Reorientation, deflection and convergence

Shale gas reservoir is characterized as the naturally fractured formation, which is benefit for complex hydraulic fracture network generation. The propagation path is crucial to determine the reservoir stimulation result, and evaluate the quality of complex hydraulic fracture network. To investigate the propagation path of complex hydraulic fracture in gas shale, the hybrid combined discrete fracture network-finite element method (DFN-FEM) model is involved. Combining a linear hardening and a non-linear softening process, a non-linear traction-separation law is proposed to describe the fracture damage evolution. Validated with open-reported laboratory experiments, the hydraulic-natural fracture (HF–NF) interaction criterion is depicted under four geomechanical and injection factors. Based on a field-scale model of Sichuan basin shale gas reservoir, the complex hydraulic fractures propagation process is simulated with rock deformation and stress shadow. Several propagation path indexes are defined with fracture morphology to discuss the effect of representative geomechanical, injection and multi-clustering parameters. The results show that the tension fractures are predominant to hydraulic fractures propagation path and shear the natural fractures, due to the combined influence of natural fractures network and interference between clusters. The horizontal stress contrast and the injection fluid viscosity is governing to the propagation path and morphology, rather than the friction coefficient and injection rate. Multi-clustered hydraulic fractures converge into a dominant fracture due to the attraction with a short clusters-spacing, while the exclusion is observed along the propagation path with the increase of clusters number.

Fracture Initiation and Propagation in the Hot Dry Rock Subject to the Cyclic Injection Hydraulic Fracturing Treatment

Cyclic injection hydraulic fracturing is a promising way for the geothermal energy exploitation by reactivating the fractures in geothermal reservoir. However, fracture initiation and growth induced by cyclic injection schemes have been inadequately studied for hot dry rock (HDR), and the cyclic injection fracturing optimized often by experience. For this reason, the initiation and propagation of hydraulic fractures in the HDR under different cyclic injection methods were determined by experiment research for hydraulic fracturing. The results show that the cyclic frequency and injection rate play different roles in the stimulation of HDR. The cyclic injection with low frequency-low pressure can create more branched fractures, forming a short but complex hydraulic fracture network. However, when high flow-high frequency injection method is subjected, the branch fractures formed are significantly reduced, but each branch fracture can be fully expanded. To fully exploit the advantages of different injection methods, a numerical model that contains a fracture network was established with PFC software, and an alternating cyclic injection scheme with synergistic control of the cyclic frequency and injection rate was proposed. The comparison results indicated that the alternating cyclic injection method can effectively improve the fracturing effect in the HDR. The stimulation area of the alternating cyclic injection method is about 2.3 times and 2.7 times that of the low flow-low frequency and high flow-high frequency injection methods, respectively. The method presented here can be adopted to optimize the fracture growth regime and provide a scientific basis for EGS hydraulic fracturing design.

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

Effects of coal bedding dip angle on hydraulic fracturing crack propagation

As a commonly used and effective technology for increasing the permeability of coal–rock reservoirs, hydraulic fracturing has been widely used in engineering sites to realize the efficient exploitation and utilization of gas resources in coal–rock reservoirs. The core of hydraulic fracturing is the initiation, propagation, and path of hydraulic cracks. In this paper, the combination of true triaxial physical test and numerical simulation is used to study the influence of coal bedding characteristics on the crack propagation of hydraulic fracturing and to discuss the important role of bedding in hydraulic crack formation. Results show that the control effect of the coal bedding dip angle on the hydraulic crack propagation under the same stress conditions is stronger than that of the maximum principal stress, and the control effect of the bedding on the crack propagation is weaker under the bedding dip angles of 0° and 90°. Reasonable fracturing fluid displacement setting is conducive to the formation of complex hydraulic fracture network structure, small displacement is conducive to the opening of primary natural fractures, and large displacement is conducive to hydraulic cracks that pass through the structural surface and the coal–rock interface. Global and local methods of finite element mesh embedding zero-thickness cohesion element and a pore-pressure node merging method to simulate fracturing are established using Python language and ABAQUS numerical analysis platform, respectively. The numerical simulation results suggest that the main fractures are formed along the principal stress direction, and the secondary branch fractures are formed along the bedding direction under the condition wherein the coal bedding dip angle is 30°. Under the conditions of different stress fields and fracturing fluid discharges, the controlling effect of bedding on hydraulic fracture is closely related to the fracturing parameters.

Present-Day In Situ Stress Analysis in Shale Reservoir of Haiba Block, Southern Sichuan Basin, South China

Natural gas from shale gas reservoirs has been an important contributor for reserve growth, deliverability construction, and profits growth in natural gas industry in the world. Hydraulic fracturing is commonly required in the shale gas commercial development, and thus understanding the present-day in situ stress field is greatly significant for the hydraulic fracturing and efficient development in shale gas reservoirs. However, there are no systematic investigations on the present-day in situ stress field in the Haiba Block from the Sichuan Basin, South China. In this study, the present-day in situ stress orientations and magnitudes in shale reservoir of Haiba Block are investigated based on the well interpretations from borehole image log and geomechanical modeling. Then, the effects of stresses on hydraulic fracturing, horizontal wells, and natural fracture reactivation were discussed. The results indicate that the horizontal maximum principal stress (SHmax) orientation is mainly in the NE-SW-trending, NW-SE-trending, and WNW-ESE-trending in the Haiba Block. The magnitudes of horizontal maximum and minimum principal stresses are 13.5 MPa~85.5 MPa and 2.8 MPa~31.6 MPa, respectively. In the Haiba Block, the differential stress is generally low in the northern part, which indicates that complex hydraulic fracture networks may be produced. While the natural fractures are generally stable under the present-day in situ stress field. When the increase of pore pressure gradient is about 30 KPa/m, nearly all natural fractures in the Longmaxi Formation may be reactivated. The results can provide the insights into a better understanding of the present-day in situ stress distribution so as to optimize perforation orientation, hydraulic fracturing design, and enhance gas production in shale gas reservoirs.

Initiation and Propagation of Multiple Fractures in the Horizontal Well of Shale Reservoirs Under Pulse Injection Hydraulic Fracturing

Pulse injection hydraulic fracturing (HF) can release high-energy peak pressure in a split-second, forming a complex hydraulic fracture network in shale reservoirs. However, the initiation and propagation of multiple fractures in the horizontal well of shale reservoirs under pulse injection HF have been inadequately studied. Hence, in this study, a HF model coupling the fracturing fluid flow along the fracture and the rock deformation was adopted, and the effect of the pulsed injection method on multistage HF of horizontal wells was determined. The results show that the pulsed injection HF can improve the fracturing effect of horizontal wells. However, no matter how the injection displacement and pulse frequency change, the propagation length of cracks at both ends seriously disturbed by stress almost remains unchanged. When the dominant fracture is temporarily shielded, the fluid pressure of the non-dominant fractures at both ends disturbed by stress compression increases, and the non-dominant fractures can be further expanded. Thus, a new composite multistaged HF scheme suitable for horizontal wells with pulse-temporary shielding in shale reservoirs was proposed. The method presented here can be adopted to optimize the fracture growth regime and provide a scientific basis for the fracturing operation of the horizontal well in shale reservoirs.

Comparative Evaluation on the Coupled Fracture Characteristics for Longmaxi Anisotropic Shale

Abstract The shale fracture characteristics are important for realizing the complex hydraulic fracture network, predicting wellbore fracture pressure, and optimizing wellbore trajectory and the rock fragmentation efficiency. Through a three-point bending test of notched semicircular specimens of Longmaxi shale, the coupled relationship of mode-I fracture toughness (Kic), peak fracture force (Pmax), energy release rate (GI), applied work (W), and loading rate was studied by using kernel density analysis method. The results showed that the dynamic characteristics of force-displacement curve exhibited obvious loading angle dependence, including two types of the “deformation accumulation-brittleness” and “deformation accumulation-brittleness-plasticity.” The Kic and GI increased linearly with Pmax increasing. With the increasing of the loading angle, the dispersion degree of Pmax, Kic, GI, and W all increased. The GI increased nonlinearly with the increasing of Kic. With the increasing of the loading rate, the Kic basically increased linearly. The dynamic Kic under static and quasistatic conditions had strong anisotropy. At the high loading rate, the anisotropy index gradually decreased as the loading rate increasing. The results have significant implications for the design of hydraulic fracturing and the exact fracture control of Longmaxi shale.

Effects of hydrostatic pressure on hydraulic fracturing properties of shale using X-ray computed tomography and acoustic emission

The study of the hydraulic fracturing characteristics in shale reservoirs is crucial for improving the permeability of shale gas reservoirs. In this study, hydraulic fracturing tests are conducted on full-diameter shale cores, and the hydraulic fracturing characteristics of shale with different bedding angles under high hydrostatic pressure are studied. The results show that under a hydrostatic pressure of 59 MPa, the shale sample will rupture twice in the breakdown stage during hydraulic fracturing. When the bedding inclination increases from 0° to 90°, the shale fracture breakdown pressure first decreases and then increases, showing an overall downward trend. Under high hydrostatic pressure, shale specimen surface fracture morphology and X-ray computed tomography reveal that a bedding angle close to 45° is more conducive to forming a complex hydraulic fracture network, which makes the fractal dimension of the fracture network larger. The bedding plane of shale is the direct cause of the diverse propagation patterns of hydraulic fractures. The b-value is a parameter that characterizes the magnitude–frequency relationship of an earthquake, and it is closely related to the rock rupture process. The b-value varies with different trends with the expansion of hydraulic fractures, but they all reach the lowest point before the failure of the shale sample. The higher the hydraulic fracture network complexity, the lower the peak b-value is. This work provides a qualitative understanding and scientific explanation of the hydraulic fracturing characteristics of anisotropic shale under hydrostatic pressure.

Investigation on the evaluation method and influencing factors of cross-scale mechanical properties of shale based on indentation experiment

Low-cost, fast and accurate acquisition of multi-scale mechanical properties of shale is essential to realize the complex hydraulic fracture network and the optimization of multi-scale fracture efficiency of bottom hole rock. The macro-scale indentation test is used to study the mechanical parameters of the meso-scale across the scales. The rapid evaluation method of the shale mechanical parameters across the scales is established, which can be used as a method to obtain the mechanical parameters of shale quickly and accurately. The macro-indentation test experiment is carried out through the elastic contact hypothesis, the macro-micro mechanics theory, and the grid indentation experiment method. Considering the coupling effects of peak indentation fluctuations, contact stiffness(S), and the ratio of elastic work to total work (Wu/Wt), the cross-scale distribution characteristics of shale hardness(H) and elastic modulus(E) are studied. The results showed that the elastic modulus and hardness showed a normal distribution on the whole, and the macroscopic indentation process of the rock was accompanied by the meso-scale indentation. For Longmaxi shale, the elastic modulus and hardness have large discreteness and heterogeneity. The kernel density values of elastic modulus and hardness were studied by using kernel density analysis method. Different factors have different effects on the fluctuation amplitude of elastic modulus and hardness. The fluctuation range of the S is the largest, and the fluctuation range of Wu/Wt is the smallest. At the meso-scale, the dispersion of hardness peak value is larger, and the dispersion of elastic modulus peak value is smaller than that of valley value. The S-Wu/Wt-E-H coupling response law presents a “striped” characteristic. The S-Fm-E-H coupling response law presents a “multi-point” distribution. The Fm-Wu/Wt-E-H coupling response law shows a “wave-like” distribution. The hardness of vertical bedding indentation is greater than that of parallel bedding. There is a good linear correlation between the elastic modulus and hardness. With the increase of the elastic modulus, the hardness increases. The research results are helpful to determine the parameters in the actual design of hydraulic fracturing and improving the rock breaking efficiency.

Numerical investigation of complex hydraulic fracture network in naturally fractured reservoirs based on the XFEM

The propagation of hydraulic fracture network in naturally fractured shale reservoirs remains a complicated and challenging issue. To reveal the propagation principle of the complex fracture network, a numerical fracturing model is presented on the basis of the extended finite element method (XFEM) in this work. The intersection criterion containing five intersection patterns is studied. True triaxial fracturing experiment is conducted to verify the fracture geometry obtained from our model. After that, hydraulic fracturing in naturally fractured formations is studied to investigate the influences of natural fracture azimuth on fracture network geometry. The numerical results show that, hydraulic fracture is inclined to open the obtuse angle side of natural fracture in uniform azimuth model. In random azimuth condition, occurring of various intersection patterns enables complex fracture network to generate easier. And hydraulic fracture is harder to propagate if it is closer to the middle domain due to the squeezing effect. Meanwhile, the fracture network can penetrate deeper shale layer under large in-situ stress difference. In addition, the stimulation effect (e.g., Stimulated Reservoir Volume) in random azimuth condition is much stronger than that in uniform azimuth condition. The findings in this work are of benefit to provide us a better understanding of complex hydraulic fracture network and develop high-efficiency fracturing technology.

Monitoring the Geometry Morphology of Complex Hydraulic Fracture Network by Using a Multiobjective Inversion Algorithm Based on Decomposition

The fracturing technique is widely used in many fields. Fracture has a greater impact on the movement of fluids in formations. Knowing information about a fracture is key to judging its effect, but detailed information about complex fracture networks is difficult to obtain. In this paper, we propose a new method to describe the shape of a complex fracture network. This method is based on microseismic results and uses the L-system to establish a method for characterizing a complex fracture network. The method also combines with decomposition to construct a new method called the multiobjective fracture network inversion algorithm based on decomposition (MOFNIAD). The coverage of microseismic monitoring results and the degree of fitting of production data are the two objective functions of the inversion fracture network. The multiobjective fracture network inversion algorithm can be optimized to obtain multiple optimal solutions that meet different target weights. Therefore, this paper established a multischeme decision method that approached the ideal solution, sorting technology and AHP to provide theoretical guidance for finding a more ideal fracture network. According to the error of microseismic monitoring results, we established two cases of fracture to verify the proposed method. Judging from the results of the examples, the fracture network finally obtained was similar to actual fractures.

Stress Distribution in the Upper Shihezi Formation from 1D Mechanical Earth Model and 3D Heterogeneous Geomechanical Model, Linxing Region, Eastern Ordos Basin, Central China

AbstractThe Upper Shihezi sedimentary rocks in the Linxing region has been estimated with a significant volume of tight sandstone gas. However, lateral distribution of the present‐day stress magnitude is poorly understood, which limits further gas production. Hence, a one‐dimensional mechanical earth model and a three‐dimensional heterogeneous geomechanical model are built to address this issue. The results indicate that the strike‐slip stress regime is dominant in the Upper Shihezi Formation. Relatively low stresses are mainly located around wells L‐60, L‐22, L‐40, L‐90, etc, and stress distributions exhibit the similarity in the Members H2 and H4. The differential stresses are relatively low in the Upper Shihezi Formation, suggesting that complex hydraulic fracture networks may be produced. Natural fractures in the Upper Shihezi Formation contribute little to the overall gas production in the Linxing region. In addition, the minimum principal stress gradient increases with Young's modulus, suggesting that the stiffer rocks commonly convey higher stress magnitudes. There is a strong interplay between stress distribution and heterogeneity in rock mechanics. Overall, the relative error between the predicted and measured results is less than 10%, implying that the predicted stress distribution is reliable and can be used for subsequent analysis in the Linxing region.

Complex hydraulic-fracture-network propagation in a naturally fractured reservoir

The formation of a complex hydraulic fracture network in a naturally fractured reservoir is strongly influenced by the distribution of pre-existing natural fractures and the interaction performance of multiple fractures. A numerical model containing a large number of (3120) pore pressure cohesive elements is built for modelling the randomly crossing and branching of hydraulic fractures. The effects of the distribution and cementation strength of pre-existing natural fractures on the propagation of complex hydraulic fracture networks are investigated. The interaction of multiple fractures and the interference effect among adjacent hydraulic fracture branches are also interpreted. The natural fracture is fractured before the hydraulic fracture tip reaches it when the cementation strength of natural fracture is low. The complexity of the hydraulic fracture network could be significantly affected by the cementation strength of pre-existing natural fractures and their distributions. Complex hydraulic fracture networks require much higher injection pressure than that for relatively regular fractures. Hydraulic fracture branches restrict the development of the fracture in length, but promote the formation and development of the complex hydraulic fracture network.

Implications of the in situ stress distribution for coalbed methane zonation and hydraulic fracturing in multiple seams, western Guizhou, China

With 59 sets of well testing data from 32 wells, 70 coal seam gas data from 9 wells, and production data from 17 wells, the in situ stress distribution within depths of 136-1244 m and its implications for coal permeability (0.0001-1.56 mD), gas content (5-22 m 3 /t) and gas productivity in western Guizhou were investigated. Three major depth intervals with different stress regimes were identified. At depths of 800-1244 m, the horizontal stresses increased to high values with depth due to the compressional zone near the axis of the syncline. Permeability changes with depth were consistent with the effective stress variations. The 500–800 m depth interval with a normal faulting stress regime was favorable for good permeability (0.008-0.57 mD, mean 0.2 mD) and a stable pressure gradient (approximately 1 MPa/100 m), and the gas content generally increased with depth to a peak value at 800 m. For the 200-500 m and 800-1244 m depth intervals, extremely low permeability (0.0001-0.17 mD, mean 0.03 mD) resulted in discontinuous changes in gas content and pressure gradient (0.47-1.71 MPa/100 m). Overall, the stress release zone at depths of 500–800 m was favorable for coalbed methane extraction, which agreed with the measured production data. Low horizontal stress anisotropy in western Guizhou contributes to complex hydraulic fracture networks, individual seam fracturing with low proppant concentration and high fracturing fluid volume is suggested for multilayer commingled production. • In-situ stress distribution characteristics of coals in the Western Guizhou. • Permeability and resource distribution show similar belting as with stress regimes. • Stress release zone at 500–800 m depths are favorable for CBM extraction. • Low proppant concentration and high fluid volume are suggested for hydrofracturing. • Individual-seam fracturing is the most effective productivity enhancement method.

Numerical simulation of the feasibility of supercritical CO2 storage and enhanced shale gas recovery considering complex fracture networks

In recent years, the greenhouse gas control has been a hot issue. A solution of injecting supercritical CO 2 (scCO 2 ) in Longmaxi shale gas formation (in Southwest China) is proposed in this study. To evaluate the feasibility of this method that storing CO 2 and enhanced gas recovery (EGR) simultaneously, we first carried out isothermal adsorption experiments on samples from Longmaxi formation to describe the adsorption behavior of CH 4 and CO 2 , and a generalized Ono-Kondo Lattice (OK) model was applied to predict adsorption amount of pure CH 4 /CO 2 and their binary mixtures under supercritical, high-pressure conditions. In addition, discrete fracture network (DFN) model was adopted to characterize the complex hydraulic fracture networks constructed from micro-seismic monitoring (MSM) data and engineering analysis. The porous flow in shale matrix was modeled with the multiple interacting continua (MINC) and fractal theories. A multiscale compositional numerical model based on unstructured tri-prism grids was finally developed and solved by control volume finite element (CVFE) method. The simulation results of base and CO 2 injection cases presented that scCO 2 huff ‘n’ puff in Longmaxi formation might be an effective method for CO 2 storage and EGR, and the orthogonal experiments were designed to optimize scenarios in the field application and obtain a maximum balanced result of EUR and CO 2 storage capacity (CSC) for multistage fractured horizontal well (MFHW) with complex fracture networks in shale. • The OK model was applied to predict pure CH 4 /CO 2 and their mixtures adsorption amount under supercritical conditions. • The hybrid DFN and MINC model was established to describe the flow in fractal porous media and complex fracture system. • The CVFE simulator was successfully conducted for comprehensive analysis of mechanisms of scCO 2 storage and EGR in shale.

Numerical modeling of complex hydraulic fracture networks based on the discontinuous deformation analysis (DDA) method

Hydraulic fracturing is one of the most important technologies for shale gas production. Complex hydraulic fracture networks can be stimulated in shale reservoirs due to the existence of numerous natural fractures. The prediction of the complex fracture network remains a difficult and challenging problem. This paper presents a fully coupled hydromechanical model for complex hydraulic fracture network propagation based on the discontinuous deformation analysis (DDA) method. In the proposed model, the fracture propagation and rock mass deformation are simulated under the framework of DDA, and the fluid flow within fractures is simulated using lubrication theory. In particular, the natural fracture network is considered by using the discrete fracture network (DFN) model. The proposed model is widely verified against several analytical and experimental results. All the numerical results show good agreement. Then, this model is applied to field-scale modeling of hydraulic fracturing in naturally fractured shale reservoirs. The simulation results show that the proposed model can capture the evolution process of complex hydraulic fracture networks. This work offers a feasible numerical tool for investigating hydraulic fracturing processes, which may be useful for optimizing the fracturing design of shale gas reservoirs.

A semianalytical well-testing model of fracture-network horizontal wells in unconventional reservoirs with multiple discretely natural fractures

Microseismic data shows that some unconventional reservoirs comprise well-developed natural fractures and complex hydraulic fracture networks. It is neither practical nor advantageous to simulate a huge number of natural and hydraulic fractures with numerical models. Given that the conventional dual-porosity models are not applicable to the highly discrete natural fractures, the paper develops a semianalytical well testing model for horizontal wells with hydraulic fracture networks and randomly-distributed discretely natural fractures.The proposed model has the capability to analyze the pressure behaviors by considering complex fracture networks and isolated natural fractures rapidly and efficiently. The model includes diffusivity equations in three domains: (1) matrix, (2) discretely natural fractures, and (3) hydraulic fracture networks. The pressure transient solution of these diffusivity equations is obtained by using Laplace transforms and superposition principle. We verify the presented model by performing a case study with a numerical simulator for complex natural fractures.It is found that there are some interesting flow behaviors for fracture-network horizontal well with discretely natural fractures like bilinear flow, “V-shape” caused by fluid supply, pseudo boundary-dominated flow, impact of natural fractures, etc. The pseudo boundary-dominated flow provides us the information about how large the area covered by hydraulic fracture networks. The impact of natural fracture shows the parameters of natural fractures. This work provides a good understanding of transient pressure behaviors in unconventional reservoirs and guidelines for the producer optimize field development and well economics.

Numerical investigation on the hydraulic stimulation of naturally fractured Longmaxi shale reservoirs using an extended discontinuous deformation analysis (DDA) method

The Silurian Longmaxi formation in the Sichuan Basin, which is the most important gas-producing shale reservoir in China, is characterized by relatively small effective thickness, large in-situ stress difference and highly-developed natural fracture (NF) system. Microseismic monitoring shows that complex hydraulic fracture (HF) networks with relatively small height could be stimulated in the Longmaxi shale reservoirs. Traditional two-dimensional (2D) numerical models cannot capture the three-dimensional (3D) nature of the limited-height HFs, which is not suitable for investigating the fracturing of Longmaxi shale reservoirs. This work develops a fully coupled hydro-mechanical model for HF network propagation based on the discontinuous deformation analysis (DDA) method. A new efficient method is proposed to consider the 3D effect in 2D DDA-based fracturing simulations. Hence an approximate 3D solution of fracture-induced stress and deformation could be obtained. This method is verified against previous works. Then, a series of simulations is performed to investigate the influence of reservoir thickness, in-situ stress difference and NF pattern on the hydraulic stimulation of Longmaxi shale reservoirs. Modeling results show that limited reservoir thickness is favorable to the formation of HF network. Complex and dense fracture network is easily to be formed in thin reservoirs. Large in-situ stress difference will impede the hydraulic stimulation. However, when the reservoir thickness is small, dense fracture network is still likely to be formed under large stress differences. Besides, the NF system is essential for the formation of HF network. The modeling results indicate that as a result of the limited thickness and highly-developed NF system, complex and dense fracture networks could be stimulated in the Longmaxi shale reservoirs. This work partly accounts for the initial success of gas recovery in the Longmaxi shale reservoirs. It also provides a feasible numerical method and theoretical supports for further optimization of shale gas exploitation in China.

Study on Propagation Behaviors of Hydraulic Fracture Network in Tight Sandstone Formation with Closed Cemented Natural Fractures

Natural fractures in tight sandstone formation play a significant role in fracture network generation during hydraulic fracturing. This work presents an experimental model of tight sandstone with closed cemented preexisting fractures. The influence of closed cemented fractures’ (CCF) directions on the propagation behavior of hydraulic fracture (HF) is studied based on the hydraulic fracturing experiment. A field-scaled numerical model used to simulate the propagation of HF is established based on the flow-stress-damage (FSD) coupled method. This model contains the discrete fracture network (DFN) generated by the Monte-Carlo method and is used to investigate the effects of CCFs’ distribution, CCFs’ strength, and in-situ stress anisotropy, injection rate, and fluid viscosity on the propagation behavior of fracture network. The results show that the distribution direction of CCFs is critical for the formation of complex HFs. When the angle between the horizontal maximum principal stress direction and the CCFs is in the range of 30° to 60°, the HF network is the most complex. There are many kinds of compound fracture propagation patterns, such as crossing, branching, and deflection. The increase of CCFs’ strength is not conducive to the generation of branched and deflected fractures. When the in-situ stress difference ranges from 3 MPa to 6 MPa, the HF network’s complexity and propagation range can be guaranteed simultaneously. The increase in the injection rate will promote the formation of the complex HF network. The proper increase of fracturing fluid viscosity can promote HF’s propagation. However, when the viscosity is too high, the complex HFs only appear around the wellbore. The research results can provide new insights for the hydraulic fracturing optimization design of naturally fractured tight sandstone formation.