On how pumping hesitations may improve complexity of hydraulic fractures, a simulation study

Yu, Haibin; Taleghani, Arash Dahi; Lian, Zhanghua

doi:10.1016/j.fuel.2019.02.105

Cited by 51 publications

(22 citation statements)

References 15 publications

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“…In this model, no gap between the fracture tip and fluid front is assumed because of the low viscosity of fracturing fluids. The stress equilibrium equation in the domain and associated boundary conditions can be written as [31][32][33][34][35][36]:…”

Section: Governing Equationsmentioning

confidence: 99%

Failure Patterns and Mechanisms of Hydraulic Fracture Propagation Behavior in the Presence of Naturally Cemented Fractures

Wang¹,

Shi²,

Qin³

et al. 2021

Computer Modeling in Engineering &Amp; Sciences

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In this study, we use the extended finite element method (XFEM) with a consideration of junction enrichment functions to investigate the mechanics of hydraulic fractures related to naturally cemented fractures. In the proposed numerical model, the lubrication equation is adopted to describe the fluid flow within fractures. The fluid-solid coupling systems of the hydraulic fracturing problem are solved using the Newton-Raphson method. The energy release rate criterion is used to determine the cross/arrest behavior between a hydraulic fracture (HF) and a cemented natural fracture (NF). The failure patterns and mechanisms of crack propagation at the intersection of natural fractures are discussed. Simulation results show that after crossing an NF, the failure mode along the cemented NF path may change from the tensile regime to the shear or mixed-mode regime. When an advancing HF kinks back toward the matrix, the failure mode may gradually switch back to the tensile-dominated regime. Key factors, including the length of the upper/lower portion of the cemented NF, horizontal stress anisotropy, and the intersection angle of the crack propagation are investigated in detail. An uncemented or partially cemented NF will form a more complex fracture network than a cemented NF. This study provides insight into the formation mechanism of fracture networks in formations that contain cemented NF.

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Section: Governing Equationsmentioning

confidence: 99%

Failure Patterns and Mechanisms of Hydraulic Fracture Propagation Behavior in the Presence of Naturally Cemented Fractures

Wang¹,

Shi²,

Qin³

et al. 2021

Computer Modeling in Engineering &Amp; Sciences

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show abstract

“…The results in Figure 11 indicate that the total SA decreases as the fluid injection rate increases, and it is seen that this reduction is more contributed by the TSA and a little impact by the SSA. However, the general consensus regarding the effect of the injection rate is that an increase in the injection rate contributes to the tensile failure and results in more tensile fracture, whereas a low injection rate favors the formation of natural interface shear failure and act as a lubricant to reduce friction and accommodate shearing (Beugelsdijk et al, 2000;Zou et al, 2016;Yu et al, 2019). This can be explained by Figures 12A,B, which illustrate that a high-injection rate case forms a high-pressure zone, with a breakdown pressure of 87.6 MPa, compared to 27.5 MPa, in a short time around the injection point and has a larger aperture in the reservoir layer, resulting in less fluid energy available to pressurize and extend the fracture in the vertical direction.…”

Section: Injection Ratementioning

confidence: 99%

Lattice Numerical Simulations of Hydraulic Fracture Propagation and Their Geometry Evolution in Transversely Isotropic Formations

et al. 2021

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Accurate prediction of the fracture geometry before the operation of a hydraulic fracture (HF) job is important for the treatment design. Simplified planar fracture models, which may be applicable to predict the fracture geometry in homogeneous and continuous formations, fail in case of fractured reservoirs and laminated formations such as shales. To gain a better understanding of the fracture propagation mechanism in laminated formations and their vertical geometry to be specific, a series of numerical models were run using XSite, a lattice-based simulator. The results were studied to understand the impact of the mechanical properties of caprock and injection parameters on HF propagation. The tensile and shear stimulated areas were used to determine the ability of HF to propagate vertically and horizontally. The results indicated that larger caprock Young’s modulus increases the stimulated area (SA) in both vertical and horizontal directions, whereas it reduces the fracture aperture. Also, larger vertical stress anisotropy and tensile strength of caprock and natural interfaces inhibit the horizontal fracture propagation with an inconsiderable effect in vertical propagation, which collectively reduces the total SA. It was also observed that an increased fluid injection rate suppresses vertical fracture propagation with an insignificant effect on horizontal propagation. The dimensionless parameters defined in this study were used to characterize the transition of HF propagation behavior between horizontal and vertical HFs.

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“…The width of fractures decreases away from the wellbore. For each segment, the width of the segment can be set with an average value based on experience or hydraulic fracturing simulation results [13][14][15]. To model fracture closure more accurately, understanding of fracture properties is of great importance.…”

Section: Fractal Fracture Network and Fracture Discretizationmentioning

confidence: 99%

Semi-Analytical Model for Two-Phase Flowback in Complex Fracture Networks in Shale Oil Reservoirs

Cai

Taleghani

2019

Energies

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Flowback data is the earliest available data for estimating fracture geometries and the assessment of different fracturing techniques. Considerable attention has been paid recently to analyze flowback data quantitively in order to obtain fracture properties such as effective half-length and effective conductivity by simply assuming fractures having bi-wing planar geometries and constant fracture compressibility. However, this simplifying assumption ignores the complexity of fracture networks. To overcome this limitation, we proposed a semi-analytical method, which can be used as a direct model for fast inverse analysis to characterize complex fracture networks generated during hydraulic fracturing. A two-phase oil-water flowback model with a matrix oil influx for wells with bi-wing planar fractures is also presented to identify limitations of the former solution.Since most available flowback studies use constant fracture properties and the assumption of planar fractures, considering variable fracture properties and complex fracture geometries gives this model more robustness for modeling fracture flow during flowback, more realistically. The proposed models have been validated by numerical simulations. The presented procedure provides a simple way for modeling early flowback in complex fracture networks and it can be used for inverse analysis.

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On how pumping hesitations may improve complexity of hydraulic fractures, a simulation study

Cited by 51 publications

References 15 publications

Failure Patterns and Mechanisms of Hydraulic Fracture Propagation Behavior in the Presence of Naturally Cemented Fractures

Failure Patterns and Mechanisms of Hydraulic Fracture Propagation Behavior in the Presence of Naturally Cemented Fractures

Lattice Numerical Simulations of Hydraulic Fracture Propagation and Their Geometry Evolution in Transversely Isotropic Formations

Semi-Analytical Model for Two-Phase Flowback in Complex Fracture Networks in Shale Oil Reservoirs

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