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.

Some Effects of Stress, Friction, and Fluid Flow on Hydraulic Fracturing

1982 ◽  
Vol 22 (03) ◽  
pp. 321-332 ◽  
Author(s):  
M.E. Hanson ◽  
G.D. Anderson ◽  
R.J. Shaffer ◽  
L.D. Thorson
Keyword(s):  
Fluid Flow ◽  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Research Program ◽  
In Situ Stress ◽  
Material Interfaces ◽  
Fracture Geometry ◽  
Funded Research ◽  
Fracturing Process

Abstract We are conducting a U.S. DOE-funded research program aimed at understanding the hydraulic fracturing process, especially those phenomena and parameters that strongly affect or control fracture geometry. Our theoretical and experimental studies consistently confirm the well-known fact that in-situ stress has a primary effect on fracture geometry, and that fractures propagate perpendicular to the least principal stress. In addition, we find that frictional interfaces in reservoirs can affect fracturing. We also have quantified some effects on fracture geometry caused by frictional slippage along interfaces. We found that variation of friction along an interface can result in abrupt steps in the fracture path. These effects have been seen in the mineback of emplaced fractures and are demonstrated both theoretically and in the laboratory. Further experiments and calculations indicate possible control of fracture height by vertical change in horizontal stresses. Preliminary results from an analysis of fluid flow in small apertures are discussed also. Introduction Hydraulic fracturing and massive hydraulic fracturing (MHF) are the primary candidates for stimulating production from tight gas reservoirs. MHF can provide large drainage surfaces to produce gas from the low- permeability formation if the fracture surfaces remain in the productive parts of the reservoir. To determine whether it is possibleto contain these fractures in the productive formations andto design the treatment to accomplish this requires a much broader knowledge of the hydraulic fracturing process. Identification of the parameters controlling fracture geometry and the application of this information in designing and performing the hydraulic stimulation treatment is a principal technical problem. Additionally, current measurement technology may not be adequate to provide the required data. and new techniques may have to be devised. Lawrence Livermore Natl. Laboratory has been conducting a DOE-funded research program whose ultimate goal is to develop models that predict created hydraulic fracture geometry within the reservoir. Our approach has been to analyze the phenomenology of the fracturing process to son out and identify those parameters influencing hydraulic fracture geometry. Subsequent model development will incorporate this information. Current theoretical and stimulation design models are based primarily on conservation of mass and provide little insight into the fracturing process. Fracture geometry is implied in the application of these models. Additionally, pressure and flow initiation in the fractures and their interjection with the fracturing process is not predicted adequately with these models. We have reported previously on some rock-mechanics aspects of the fracturing process. For example, we have studied, theoretically and experimentally, pressurized fracture propagation in the neighborhood of material interfaces. Results of interface studies showed that natural fractures in the interfacial region negate any barrier effect when the fracture is propagating from a lower modulus material toward a higher modulus material. On the other hand, some fracture containment could occur when the fracture is propagating from a higher modulus into a lower modulus material. Effect of moduli changes on the in-situ stress field have to be taken into consideration to evaluate fracture containment by material interfaces. Some preliminary analyses have been performed to evaluate how stress changes when material properties change, but we have not evaluated this problem fully. SPEJ P. 321^

Finite Element Model Simulations Associated With Hydraulic Fracturing

1982 ◽  
Vol 22 (02) ◽  
pp. 209-218 ◽  
Author(s):  
Sunder H. Advani ◽  
J.K. Lee
Keyword(s):  
Finite Element ◽  
Hydraulic Fracturing ◽  
Finite Element Model ◽  
Hydraulic Fracture ◽  
Element Model ◽  
In Situ Stress ◽  
Fracture System ◽  
Model Simulations ◽  
Fracture Fluid

Abstract Recently emphasis has been placed on the development and testing of innovative well stimulation techniques for the recovery of unconventional gas resources. The design of optimal hydraulic fracturing treatments for specified reservoir conditions requires sophisticated models for predicting the induced fracture geometry and interpreting governing mechanisms. This paper presents methodology and results pertinent to hydraulic fracture modeling for the U.S. DOE's Eastern Gas Shales Program (EGSP). The presented finite-element model simulations extend available modeling efforts and provide a unified framework for evaluation of fracture dimensions and associated responses. Examples illustrating the role of multilayering, in-situ stress, joint interaction, and branched cracks are given. Selected comparisons and applications also are discussed. Introduction Selection and design of stimulation treatments for Devonian shale wells has received considerable attention in recent years1-3. The production of natural gas from such tight eastern petroliferous basins is dependent on the vertical thickness of the organically rich shale matrix, its inherent fracture system density, anisotropy, and extent, and the communication-link characteristics of the induced fracture system(s). The investigation of stimulation techniques based on resource characterization, reservoir property evaluation, theoretical and laboratory model simulations, and field testing is a logical step toward the development of commercial technology for optimizing gas production and related costs. This paper reports formulations, methodology, and results associated with analytical simulations of hydraulic fracturing for EGSP. The presented model extends work reported by Perkins and Kern,4 Nordgren,5 Geertsma and DeKlerk,6 and Geertsma and Haafkens.7 The simulations provide a finite-element model framework for studying vertically induced fracture responses with the effects of multilayering and in-situ stress considered. In this context, Brechtel et al.,8 Daneshy,9 Cleary,10 and Anderson et al.11 have done recent studies addressing specific aspects of this problem. The use of finite-element model techniques for studying mixed-mode fracture problems encountered in dendritic fracturing and vertical fracture/joint interaction also is illustrated along with application of suitable failure criteria. Vertical Hydraulic Fracture Model Formulations Coupled structural fracture mechanics and fracture fluid response models for predicting hydraulically induced fracture responses have been reported previously.12,13 These simulations incorporate specified reservoir properties, in-situ stress conditions, and stimulation treatment parameters. One shortcoming of this modeling effort is that finite-element techniques are used for the structural and stress intensity simulations, while a finite-difference approach is used to evaluate the leakoff and fracture-fluid response in the vertical crack. A consistent framework for conducting all simulations using finite-element modeling is formulated here.

scholarly journals Numerical simulation of horizontal well network fracturing in glutenite reservoir

2018 ◽  
Vol 73 ◽  
pp. 53
Author(s):  
Minhui Qi ◽  
Mingzhong Li ◽  
Yanchao Li ◽  
Tiankui Guo ◽  
Song Gao
Keyword(s):  
Numerical Simulation ◽  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Horizontal Well ◽  
Fracture Propagation ◽  
Simulation Method ◽  
Fracture Network ◽  
Fluid Viscosity ◽  
Coupled Flow ◽  
Hydraulic Fracture Propagation

Hydraulic fracturing is an economically effective technology developing the glutenite reservoirs, which have far stronger heterogeneity than the conventional sandstone reservoir. According to the field production experience of Shengli Oilfield, horizontal-well fracturing is more likely to develop a complex fractured network, which improves the stimulated volume of reservoir effectively. But the clear mechanism of horizontal-well hydraulic fracture propagation in the glutenite reservoirs is still not obtained, thus it is difficult to effectively carry out the design of fracturing plan. Based on the characteristics of the glutenite reservoirs, a coupled Flow-Stress-Damage (FSD) model of hydraulic fracture propagation is established. The numerical simulation of fracturing expansion in the horizontal well of the glutenite reservoir is conducted. It is shown that a square mesh-like fracture network is developed near the horizontal well in the reservoir with lower stress difference, in which fracture is more prone to propagate along the direction of the minimum principal stress as well. High fracturing fluids injection displacement and high fracturing fluid viscosity lead to the rise of static pressure of the fracture, which results in the rise of fracture complexity, and greater probability to deflect when encountering gravels. As the perforation density increases, the micro-fractures generated at each perforation gather together faster, and the range of the stimulated reservoir is also relatively large. For reservoirs with high gravel content, the complexity of fracture network and the effect of fracture communication are obviously increased, and the range of fracture deflection is relatively large. In the case of the same gravel distribution, the higher the tensile strength of the gravel, the greater fracture tortuosity and diversion was observed. In this paper, a simulation method of horizontal well fracture network propagation in the reservoirs is introduced, and the result provides the theoretical support for fracture network morphology prediction and plan design of hydraulic fracturing in the glutenite reservoir.

scholarly journals A multi-perforation staged fracturing experimental study on hydraulic fracture initiation and propagation

2020 ◽  
Vol 38 (6) ◽  
pp. 2466-2484
Author(s):  
Jianguang Wei ◽  
Saipeng Huang ◽  
Guangwei Hao ◽  
Jiangtao Li ◽  
Xiaofeng Zhou ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Oil And Gas ◽  
Fracture Initiation ◽  
Fracture Network ◽  
Hydraulic Fractures ◽  
Breakdown Pressure ◽  
Tight Sandstone ◽  
Heterogeneous Samples ◽  
Initiation And Propagation

Hydraulic fracture initiation and propagation are extremely important on deciding the production capacity and are crucial for oil and gas exploration and development. Based on a self-designed system, multi-perforation cluster-staged fracturing in thick tight sandstone reservoir was simulated in the laboratory. Moreover, the technology of staged fracturing during casing completion was achieved by using a preformed perforated wellbore. Three hydraulic fracturing methods, including single-perforation cluster fracturing, multi-perforation cluster conventional fracturing and multi-perforation cluster staged fracturing, were applied and studied, respectively. The results clearly indicate that the hydraulic fractures resulting from single-perforation cluster fracturing are relatively simple, which is difficult to form fracture network. In contrast, multi-perforation cluster-staged fracturing has more probability to produce complex fractures including major fracture and its branched fractures, especially in heterogeneous samples. Furthermore, the propagation direction of hydraulic fractures tends to change in heterogeneous samples, which is more likely to form a multi-directional hydraulic fracture network. The fracture area is greatly increased when the perforation cluster density increases in multi-perforation cluster conventional fracturing and multi-perforation cluster-staged fracturing. Moreover, higher perforation cluster densities and larger stage numbers are beneficial to hydraulic fracture initiation. The breakdown pressure in homogeneous samples is much higher than that in heterogeneous samples during hydraulic fracturing. In addition, the time of first fracture initiation has the trend that the shorter the initiation time is, the higher the breakdown pressure is. The results of this study provide meaningful suggestions for enhancing the production mechanism of multi-perforation cluster staged fracturing.

The Effects of Perforation Erosion on Practical Hydraulic-Fracturing Applications

SPE Journal ◽  
2017 ◽  
Vol 22 (02) ◽  
pp. 645-659 ◽  
Author(s):  
Gongbo Long ◽  
Guanshui Xu
Keyword(s):  
Hydraulic Fracturing ◽  
Horizontal Wells ◽  
In Situ Stress ◽  
Fluid Distribution ◽  
Fluid Viscosity ◽  
Appropriate Treatment ◽  
Limited Entry ◽  
Successful Design ◽  
Treatment Designs

Summary Predicting perforation erosion and its effects on fracture dimensions, fluid distribution, and pressure drop can be an essential part of successful design of hydraulic-fracturing treatments, especially for massive treatments along the horizontal wells when limited-entry techniques are implemented. Both the perforation diameter D and discharge coefficient Cd increase dynamically as proppant-laden slurries are pumped through perforations, making it necessary to consider the changes of these two variables in terms of time to predict the perforation-erosion effects. In this paper, we conduct a study of the perforation-erosion effects by implementing our new perforation-erosion model derived from experimentally verified abrasion mechanisms to calculate the rate changes of these two variables and the consequent influence on the fracture dimensions, fluid distribution, and downhole pressure during a treatment. The selected parameters affecting the erosion effects in the study include perforation number, perforation-cluster spacing, in-situ stress difference, and fracturing-fluid viscosity. The results demonstrate that our model can predict the perforation-erosion effects on practical hydraulic-fracturing applications in a physically clear and mathematically concise manner under different circumstances by inspecting the simultaneous increases of D and Cd separately, leading to more-appropriate treatment designs, especially with the limited-entry techniques.

scholarly journals Fracture Propagation and Morphology Due to Non-Aqueous Fracturing: Competing Roles between Fluid Characteristics and In Situ Stress State

Minerals ◽  
2020 ◽  
Vol 10 (5) ◽  
pp. 428
Author(s):  
Yunzhong Jia ◽  
Zhaohui Lu ◽  
Hong Liu ◽  
Jiehao Wang ◽  
Yugang Cheng ◽  
...  
Keyword(s):  
Carbon Dioxide ◽  
Hydraulic Fracturing ◽  
Fracture Propagation ◽  
Horizontal Stress ◽  
In Situ Stress ◽  
Fluid Viscosity ◽  
Low Viscosity ◽  
Fracturing Process ◽  
Fluid Characteristics

Non-aqueous or gaseous stimulants are alternative working fluids to water for hydraulic fracturing in shale reservoirs, which offer advantages including conserving water, avoiding clay swelling and decreasing formation damage. Hence, it is crucial to understand fluid-driven fracture propagation and morphology in shale formations. In this research, we conduct fracturing experiments on shale samples with water, liquid carbon dioxide, and supercritical carbon dioxide to explore the effect of fluid characteristics and in situ stress on fracture propagation and morphology. Moreover, a numerical model that couples rock property heterogeneity, micro-scale damage and fluid flow was built to compare with experimental observations. Our results indicate that the competing roles between fluid viscosity and in situ stress determine fluid-driven fracture propagation and morphology during the fracturing process. From the macroscopic aspect, fluid-driven fractures propagate to the direction of maximum horizontal stress direction. From the microscopic aspect, low viscosity fluid easily penetrates into pore throats and creates branches and secondary fractures, which may deflect the main fracture and eventually form the fracture networks. Our results provide a new understanding of fluid-driven fracture propagation, which is beneficial to fracturing fluid selection and fracturing strategy optimization for shale gas hydraulic fracturing operations.

scholarly journals Numerical Investigation of Hydraulic Fracture Propagation in Naturally Fractured Reservoirs Based on Lattice Spring Model

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-18
Author(s):  
Kaikai Zhao ◽  
Pengfei Jiang ◽  
Yanjun Feng ◽  
Xiaodong Sun ◽  
Lixing Cheng ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fractured Reservoirs ◽  
Fracture Propagation ◽  
Maximum Principal Stress ◽  
Injection Rate ◽  
Naturally Fractured Reservoirs ◽  
Fluid Viscosity ◽  
Global Orientation ◽  
Hf Propagation

Hydraulic fracturing has been extensively employed for permeability enhancement in low-permeability reservoirs. The geometry of the hydraulic fracture network (HFN) may have implications for the optimization of hydraulic fracturing operations. Various parameters, including the in situ stress, treatment parameters (injection rate and fluid viscosity), and orientation of natural fractures (NFs), can significantly affect the interactions between hydraulic fracture (HF) and NFs and the final HFN. In this study, a lattice-spring code was employed to determine the impact of various parameters on the geometry of the HFN. The modelling results indicated that with a large stress difference, the global orientation of the fracture propagation was restricted to the direction of maximum principal stress, and the number of fracture branches was reduced. The geometry of the HFN changed from circular to elliptical. In contrast, with an increase in the fluid viscosity/injection rate, the evolution of the geometry of the HFN exhibited the opposite trend. The global orientation of HF propagation tended to remain parallel to the direction of maximum principal stress, regardless of the branching and tortuosity of the fracture. The variations in the ratio of tensile fracture (HF) to shear fracture (shear slip on NF) can be significant, depending on the stress state, treatment parameters, and preexisting NF network, which determine the dominant stimulation mechanism. This study provides insight into the HF propagation in naturally fractured reservoirs.

Investigation of the influence of natural fractures and in situ stress on hydraulic fracture propagation using a distinct-element approach

2015 ◽  
Vol 52 (7) ◽  
pp. 926-946 ◽  
Author(s):  
N. Zangeneh ◽  
E. Eberhardt ◽  
R.M. Bustin
Keyword(s):  
Rock Mass ◽  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Distinct Element ◽  
Fracture Propagation ◽  
In Situ Stress ◽  
Natural Fractures ◽  
Geological Conditions ◽  
Hydraulic Fracture Propagation

Hydraulic fracturing is the primary means for enhancing rock mass permeability and improving well productivity in tight reservoir rocks. Significant advances have been made in hydraulic fracturing theory and the development of design simulators; however, these generally rely on continuum treatments of the rock mass. In situ, the geological conditions are much more complex, complicated by the presence of natural fractures and planes of weakness such as bedding planes, joints, and faults. Further complexity arises from the influence of the in situ stress field, which has its own heterogeneity. Together, these factors may either enhance or diminish the effectiveness of the hydraulic fracturing treatment and subsequent hydrocarbon production. Results are presented here from a series of two-dimensional (2-D) numerical experiments investigating the influence of natural fractures on the modeling of hydraulic fracture propagation. Distinct-element techniques applying a transient, coupled hydromechanical solution are evaluated with respect to their ability to account for both tensile rupture of intact rock in response to fluid injection and shear and dilation along existing joints. A Voronoi tessellation scheme is used to add the necessary degrees of freedom to model the propagation path of a hydraulically driven fracture. The analysis is carried out for several geometrical variants related to hypothetical geological scenarios simulating a naturally fractured shale gas reservoir. The results show that key interactions develop with the natural fractures that influence the size, orientation, and path of the hydraulic fracture as well as the stimulated volume. These interactions may also decrease the size and effectiveness of the stimulation by diverting the injected fluid and proppant and by limiting the extent of the hydraulic fracture.

The effect of gravity on the shape and direction of vertical hydraulic fractures

2020 ◽  
Vol 60 (2) ◽  
pp. 668
Author(s):  
Saeed Salimzadeh
Keyword(s):  
Hydraulic Fracturing ◽  
Shale Gas ◽  
Hydraulic Fracture ◽  
Hydraulic Fractures ◽  
Fluid Viscosity ◽  
Gas Reservoirs ◽  
Unconventional Gas Reservoirs ◽  
Fracture Fluid ◽  
Fracture Opening

Australia has great potential for shale gas development that can reshape the future of energy in the country. Hydraulic fracturing has been proven as an efficient method to improve recovery from unconventional gas reservoirs. Shale gas hydraulic fracturing is a very complex, multi-physics process, and numerical modelling to design and predict the growth of hydraulic fractures is gaining a lot of interest around the world. The initiation and propagation direction of hydraulic fractures are controlled by in-situ rock stresses, local natural fractures and larger faults. In the propagation of vertical hydraulic fractures, the fracture footprint may extend tens to hundreds of metres, over which the in-situ stresses vary due to gravity and the weight of the rock layers. Proppants, which are added to the hydraulic fracturing fluid to retain the fracture opening after depressurisation, add additional complexity to the propagation mechanics. Proppant distribution can affect the hydraulic fracture propagation by altering the hydraulic fracture fluid viscosity and by blocking the hydraulic fracture fluid flow. In this study, the effect of gravitational forces on proppant distribution and fracture footprint in vertically oriented hydraulic fractures are investigated using a robust finite element code and the results are discussed.

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