Natural Fractures in Unconventional Shale Reservoirs in US and their Roles in Well Completion Design and Improving Hydraulic Fracturing Stimulation Efficiency and Production

2014 ◽  
Author(s):  
Bingjian Li
Keyword(s):  
Hydraulic Fracturing ◽  
Natural Fractures ◽  
Well Completion ◽  
Shale Reservoirs ◽  
Stimulation Efficiency

scholarly journals Numerical Investigation on Propagation Behaviors of a Three-Dimensional Fracture Network Coupled with Microseismicity in Fractured Shale Reservoirs

Energies ◽  
2021 ◽  
Vol 14 (24) ◽  
pp. 8297
Author(s):  
Jianfa Wu ◽  
Haoyong Huang ◽  
Ersi Xu ◽  
Junfeng Li ◽  
Xiaohua Wang
Keyword(s):  
Three Dimensional ◽  
Horizontal Stress ◽  
Fracture Network ◽  
Injection Rate ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Hydraulic Fracture Network ◽  
Shale Reservoirs ◽  
Stimulation Efficiency ◽  
Viscosity Fluid

The formation mechanism and propagation behaviors of a three-dimensional hydraulic fracture network in fractured shale reservoirs remain unclear, especially when the scale of hydraulic fractures is much larger than that of natural fractures. In this study, taking the well XH in the Longmaxi shale reservoir in the Sichuan Basin, China as an example, we develop a fully three-dimensional numerical model for hydraulic fracturing coupled with microseismicity based on the discrete lattice method. We introduce a randomly generated discrete fracture network into the proposed model and explore the formation mechanism of the hydraulic fracture network under the condition that the hydraulic fractures are much larger than natural fractures in scale. Moreover, microseismic events are inversely synthesized in the numerical model, which allows the evolution of the fracture network to be monitored and evaluated quantitatively. In addition, we analyze the effects of injection rate, horizontal stress difference, and fluid viscosity on fracture propagation. Our results show that when the scale of hydraulic fractures is much larger than that of natural fractures, the fracture morphology of “main hydraulic fractures + complex secondary fractures” is mainly formed. We find that a high injection rate can not only create a complex fracture network, but also improve the uniform propagation of multi-cluster fractures and enhance far-field stimulation efficiency. Optimizing the horizontal wellbore intervals with low horizontal stress differences as the sweet spots of hydraulic fracturing is also beneficial to improve the stimulation efficiency. For zones with a large number of natural fractures, it is recommended to use an injection schedule with high viscosity fluid early and low viscosity fluid late to allow the hydraulic fractures to propagate to the far-field to maximize the stimulation effect.

scholarly journals Numerical Simulation of Shale Reservoir Fluid-Driven Fracture Network Morphology Based on Global CZM

2021 ◽  
Vol 9 ◽  
Author(s):  
Yang Yang ◽  
Zixi Jiao ◽  
Longhuan Du ◽  
Hua Fan
Keyword(s):  
Numerical Simulation ◽  
Hydraulic Fracturing ◽  
Fracture Network ◽  
Injection Rate ◽  
Natural Fractures ◽  
Fracturing Fluid ◽  
Geological Conditions ◽  
Complex Fracture Network ◽  
Shale Reservoirs ◽  
Cement Strength

There are a large number of natural fractures in shale reservoirs, which create great challenges to hydraulic fracturing. Activating the natural fractures in reservoirs can form a complex fracture network, enhance fracturing effects, and increase shale gas production. Reservoir geological conditions (low in situ stress, natural fracture distribution, and cement strength) and operation parameters (fracturing fluid viscosity and injection rate) have an important influence on fracture network propagation. In this article, a two-dimensional hydraulic fracturing fluid-mechanic coupling numerical model for shale reservoirs with natural fractures was established. Based on the global cohesive zone model, the influence of geological conditions and operation parameters on the propagation of the hydraulic fracture network and fracturing process is investigated. The numerical simulation results show that when the horizontal in situ stress difference, approach angle, and cement strength are low, it is easier to form a complex fracture network. Research on the construction parameters indicated that when the viscosity of the fracturing fluid is low, it is easier to form a complex network of fractures, but the length of the fractures is shorter; in contrast, the fractures are straight and long. In addition, increasing the injection rate is beneficial for increasing the complexity of the fracture network while increasing the initiation pressure and width of the principal fracture reduces the risk of sand plugging. This article also proposes an optimization solution for hydraulic fracturing operations based on numerical simulation results.

scholarly journals A numerical investigation on the performance of hydraulic fracturing in naturally fractured gas reservoirs based on stimulated rock volume

2020 ◽  
Vol 10 (8) ◽  
pp. 3333-3345
Author(s):  
Ali Al-Rubaie ◽  
Hisham Khaled Ben Mahmud
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Natural Fracture ◽  
Shear Stresses ◽  
Individual Element ◽  
Natural Fractures ◽  
Gas Reservoirs ◽  
Stimulated Reservoir Volume ◽  
Reservoir Volume ◽  
Naturally Fractured

Abstract All reservoirs are fractured to some degree. Depending on the density, dimension, orientation and the cementation of natural fractures and the location where the hydraulic fracturing is done, preexisting natural fractures can impact hydraulic fracture propagation and the associated flow capacity. Understanding the interactions between hydraulic fracture and natural fractures is crucial in estimating fracture complexity, stimulated reservoir volume, drained reservoir volume and completion efficiency. However, because of the presence of natural fractures with diffuse penetration and different orientations, the operation is complicated in naturally fractured gas reservoirs. For this purpose, two numerical methods are proposed for simulating the hydraulic fracture in a naturally fractured gas reservoir. However, what hydraulic fracture looks like in the subsurface, especially in unconventional reservoirs, remain elusive, and many times, field observations contradict our common beliefs. In this study, the hydraulic fracture model is considered in terms of the state of tensions, on the interaction between the hydraulic fracture and the natural fracture (45°), and the effect of length and height of hydraulic fracture developed and how to distribute induced stress around the well. In order to determine the direction in which the hydraulic fracture is formed strikethrough, the finite difference method and the individual element for numerical solution are used and simulated. The results indicate that the optimum hydraulic fracture time was when the hydraulic fracture is able to connect natural fractures with large streams and connected to the well, and there is a fundamental difference between the tensile and shear opening. The analysis indicates that the growing hydraulic fracture, the tensile and shear stresses applied to the natural fracture.

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

2021 ◽  
pp. 014459872098153
Author(s):  
Yanzhi Hu ◽  
Xiao Li ◽  
Zhaobin Zhang ◽  
Jianming He ◽  
Guanfang Li
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fracture Network ◽  
Discontinuous Deformation Analysis ◽  
Deformation Analysis ◽  
Fracture Networks ◽  
Proposed Model ◽  
Discontinuous Deformation ◽  
Shale Reservoirs ◽  
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.

Predicting the azimuth of natural fractures and in-situ horizontal stress: A case study from Sichuan Basin, China

Geophysics ◽  
2021 ◽  
pp. 1-97
Author(s):  
kai lin ◽  
Bo Zhang ◽  
Jianjun Zhang ◽  
Huijing Fang ◽  
Kefeng Xi ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Seismic Data ◽  
Sichuan Basin ◽  
Horizontal Stress ◽  
Seismic Attributes ◽  
Seismic Events ◽  
Natural Fractures ◽  
Microseismic Data ◽  
Maximum Horizontal Stress

The azimuth of fractures and in-situ horizontal stress are important factors in planning horizontal wells and hydraulic fracturing for unconventional resources plays. The azimuth of natural fractures can be directly obtained by analyzing image logs. The azimuth of the maximum horizontal stress σH can be predicted by analyzing the induced fractures on image logs. The clustering of micro-seismic events can also be used to predict the azimuth of in-situ maximum horizontal stress. However, the azimuth of natural fractures and the in-situ maximum horizontal stress obtained from both image logs and micro-seismic events are limited to the wellbore locations. Wide azimuth seismic data provides an alternative way to predict the azimuth of natural fractures and maximum in-situ horizontal stress if the seismic attributes are properly calibrated with interpretations from well logs and microseismic data. To predict the azimuth of natural fractures and in-situ maximum horizontal stress, we focus our analysis on correlating the seismic attributes computed from pre-stack and post-stack seismic data with the interpreted azimuth obtained from image logs and microseismic data. The application indicates that the strike of the most positive principal curvature k1 can be used as an indicator for the azimuth of natural fractures within our study area. The azimuthal anisotropy of the dominant frequency component if offset vector title (OVT) seismic data can be used to predict the azimuth of maximum in-situ horizontal stress within our study area that is located the southern region of the Sichuan Basin, China. The predicted azimuths provide important information for the following well planning and hydraulic fracturing.

Sign in / Sign up

Export Citation Format

Share Document