scholarly journals Effect of Multiple Flow Pulses on Hydraulic Fracture Network Propagation in Naturally Fractured Volcanic Rock

Energies ◽  
2020 ◽  
Vol 13 (3) ◽  
pp. 633
Author(s):  
Guangzhi Yang ◽  
Shicheng Zhang ◽  
Jia Wang ◽  
Ning Li ◽  
Xinfang Ma ◽  
...  
Keyword(s):  
Pressure Drop ◽  
Hydraulic Fracture ◽  
Injection Pressure ◽  
Fracture Network ◽  
Injection Rate ◽  
Injection Method ◽  
Injection Scheme ◽  
Fracture Complexity ◽  
Naturally Fractured ◽  
Fluid Leak

Exploring engineering methods for increasing fracture network complexity is important for the development of unconventional oil and gas reservoirs. In this study, we conducted a series of fracturing experiments on naturally fractured volcanic samples. An injection method, multiple flow pulses, is proposed to increase fracture complexity. The results show that fluid leaked into the natural fracture network (NFN) when the injection rate was low (0.2 mL/min); hydraulic-fracture-dominant fracture geometry was created with an injection rate of 2 and 5 mL/min. Under the 2 mL/min-injection scheme with 3 pulses, the injection pressure during the intermittent stage was low (<5 MPa), resulting in a limited increase in fracture complexity. When the number of the flow pulses increased to 5, the pressure drop rate in the fourth and fifth intermittent stage significantly increased, indicating an increase in the aperture of natural fractures (NFs) and in the fluid leak-off effect. Under the 5 mL/min injection scheme containing 5 pulses, besides the enhanced fluid leak-off, a sharp injection pressure drop was observed, indicating the activation of NFs. The complexity and the aperture of the ultimate fracture network further increased. The injection method, multiple flow pulses, can be used to create complex fracture networks effectively.

scholarly journals Numerical Investigation of Hydraulic Fracture Propagation Based on Cohesive Zone Model in Naturally Fractured Formations

Processes ◽  
2019 ◽  
Vol 7 (1) ◽  
pp. 28 ◽  
Author(s):  
Jianxiong Li ◽  
Shiming Dong ◽  
Wen Hua ◽  
Xiaolong Li ◽  
Xin Pan
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Cohesive Zone ◽  
Coupled Model ◽  
Fracture Propagation ◽  
Fracture Network ◽  
Zone Model ◽  
Naturally Fractured ◽  
Hydraulic Fracture Propagation ◽  
Multiple Cluster

Complex propagation patterns of hydraulic fractures often play important roles in naturally fractured formations due to complex mechanisms. Therefore, understanding propagation patterns and the geometry of fractures is essential for hydraulic fracturing design. In this work, a seepage–stress–damage coupled model based on the finite pore pressure cohesive zone (PPCZ) method was developed to investigate hydraulic fracture propagation behavior in a naturally fractured reservoir. Compared with the traditional finite element method, the coupled model with global insertion cohesive elements realizes arbitrary propagation of fluid-driven fractures. Numerical simulations of multiple-cluster hydraulic fracturing were carried out to investigate the sensitivities of a multitude of parameters. The results reveal that stress interference from multiple-clusters is responsible for serious suppression and diversion of the fracture network. A lower stress difference benefits the fracture network and helps open natural fractures. By comparing the mechanism of fluid injection, the maximal fracture network can be achieved with various injection rates and viscosities at different fracturing stages. Cluster parameters, including the number of clusters and their spacing, were optimal, satisfying the requirement of creating a large fracture network. These results offer new insights into the propagation pattern of fluid driven fractures and should act as a guide for multiple-cluster hydraulic fracturing, which can help increase the hydraulic fracture volume in naturally fractured reservoirs.

A New Approach to the Modeling of Hydraulic-Fracturing Treatments in Naturally Fractured Reservoirs

SPE Journal ◽  
2017 ◽  
Vol 22 (04) ◽  
pp. 1064-1081 ◽  
Author(s):  
Sanbai Li ◽  
Dongxiao Zhang ◽  
Xiang Li
Keyword(s):  
Tensile Strength ◽  
Hydraulic Fracturing ◽  
Fractured Reservoirs ◽  
Fracture Network ◽  
Injection Rate ◽  
Naturally Fractured Reservoirs ◽  
Fracture Networks ◽  
Complex Fracture ◽  
Stress Anisotropy ◽  
Naturally Fractured

Summary A fully coupled thermal/hydromechanical (THM) model for hydraulic-fracturing treatments is developed in this study. In this model, the mixed finite-volume/finite-element method is used to solve the coupled system, in which the multipoint flux approximation L-method is used to calculate interelement fluid and heat flux. The Gu et al. (2011) crossing criterion is extended to a 3D scenario to delineate the crossing behaviors as hydraulic fractures meet inclined natural fractures. Moreover, the modified Barton et al. (1985) model proposed by Asadollahi et al. (2010) is used to estimate the fracture aperture and model the shear-dilation effect. After being (partially) verified by means of comparison with results from the literature, the developed model is used to investigate complex-fracture-network propagation in naturally fractured reservoirs. Numerical experiments show that the key factors controlling the complexity of the induced-fracture networks include stress anisotropy, injection rate, natural-fracture distribution (fracture-dip angle, strike angle, spacing, density, and length), fracture-filling properties (the degree of cementation and permeability), fracture-surface properties (cohesion and friction angle), and tensile strength of intact rock. It is found that the smaller the stress anisotropy and/or the lower the injection rate, the more complex the fracture network; a high rock tensile strength could increase the possibility of the occurrence of shear fractures; and under conditions of large permeability of fracture filling combined with small cohesive strength and friction coefficient, shear slip could become the dominant mechanism for generating complex-fracture networks. The model developed and the results presented can be used to understand the propagation of complex-fracture networks and aid in the design and optimization of hydraulic-fracturing treatments.

Finite-Element Simulation of a Hydraulic Fracture Interacting With a Natural Fracture

SPE Journal ◽  
2016 ◽  
Vol 22 (01) ◽  
pp. 219-234 ◽  
Author(s):  
Zuorong Chen ◽  
Robert G. Jeffrey ◽  
Xi Zhang ◽  
James Kear
Keyword(s):  
Finite Element ◽  
Hydraulic Fracture ◽  
Injection Pressure ◽  
Quantitative Information ◽  
Injection Rate ◽  
Interfacial Stress ◽  
Natural Fracture ◽  
Fluid Viscosity ◽  
Fracturing Fluid ◽  
Bedding Planes

Summary In this paper, the problem of a hydraulic fracture (HF) interacting with a pre-existing natural fracture (NF) has been investigated with a cohesive zone finite-element model. The model fully couples fluid flow, fracture propagation, and elastic deformation, taking into account the friction between the contacting fracture surfaces and the interaction between the HF and the NF. The effect of the field conditions—such as in-situ stresses, rock and fracture mechanical and geometrical (initial conductivity of the NF) properties, intersection angle, and the treatment parameters (fracturing fluid viscosity and injection rate)—on the HF propagation behavior has been analyzed. The finite-element-modeling results provide detailed quantitative information on the development of various types of HF/NF interaction, interfacial stress distribution, fracture-geometry evolution, and injection-pressure history, and allow us to gain an in-depth understanding of the relative roles of various parameters. The value of a parameter calculated as the product of fracturing-fluid viscosity and injection rate can be used as an indicator to gauge if crossing or diverting behavior is more likely. In addition, using a finite-element approach allows the analysis to be extended to include the effects of fluid leakoff and poroelastic effect, and allows the study of HF height growth through a system of nonhomogeneous layers and their bedding planes.

Modeling of Hydraulic-Fracture-Network Propagation in a Naturally Fractured Formation

2011 ◽  
Vol 26 (04) ◽  
pp. 368-380 ◽  
Author(s):  
Xiaowei Weng ◽  
Olga Kresse ◽  
Charles-Edouard Cohen ◽  
Ruiting Wu ◽  
Hongren Gu
Keyword(s):  
Hydraulic Fracture ◽  
Fracture Network ◽  
Naturally Fractured ◽  
Network Propagation ◽  
Hydraulic Fracture Network

Modeling of Hydraulic Fracture Network Propagation in a Naturally Fractured Formation

2011 ◽  
Author(s):  
Xiaowei Weng ◽  
Olga Kresse ◽  
Charles Edouard Cohen ◽  
Ruiting Wu ◽  
Hongren Gu
Keyword(s):  
Hydraulic Fracture ◽  
Fracture Network ◽  
Naturally Fractured ◽  
Network Propagation ◽  
Hydraulic Fracture Network

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

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-22
Author(s):  
Jun Zhang ◽  
Yu-Wei Li ◽  
Wei Li ◽  
Zi-Jie Chen ◽  
Yuan Zhao ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fracture Network ◽  
In Situ Stress ◽  
Injection Rate ◽  
Fluid Viscosity ◽  
Tight Sandstone ◽  
Propagation Behavior ◽  
Sandstone Formation

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.

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