scholarly journals Numerical Simulation Research on the Interactive Propagation of Hydraulic Fractures and Natural Fractures

2021 ◽  
Vol 292 ◽  
pp. 01007
Author(s):  
Abdullah I Asiri Waleed ◽  
Ma Xiaoming
Keyword(s):  
Tensile Strength ◽  
Principal Stress ◽  
Fracture Network ◽  
In Situ Stress ◽  
Hydraulic Fractures ◽  
Stress Difference ◽  
Natural Fractures ◽  
Approach Angle ◽  
Finite Element Software ◽  
Propagation Behavior

In order to study the fracture propagation behavior after the interaction between hydraulic fractures and natural fractures, the cohensive unit of Abaqus finite element software is used to simulate the influence of natural fractures in the rock on the propagation behavior of hydraulic fractures. The simulation results show that when the approach angle is kept constant, as the in-situ stress difference increases, hydraulic fractures are more likely to penetrate the natural fractures and expand along the direction of the maximum horizontal principal stress; while the stress difference remains the same, as the approach angle increases, hydraulic fractures are easier to penetrate natural fractures and expand along the direction of maximum horizontal principal stress. When the approach angle is kept constant, as the tensile strength of natural fractures increases, hydraulic fractures are more likely to penetrate the natural cracks and expand along the direction of the maximum horizontal principal stress; while the tensile strength of natural cracks remains unchanged, as the approach angle increases, the probability of forming a complex fracture network between hydraulic fractures and natural fractures is reduced, and it is easier to penetrate the natural fractures and expand along the direction of the maximum horizontal principal stress.

scholarly journals Numerical Simulation of the Influence of Natural Fractures on Hydraulic Fracture Propagation

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-12 ◽  
Author(s):  
Song Yaobin ◽  
Lu Weiyong ◽  
He Changchun ◽  
Bai Erhu
Keyword(s):  
Tensile Strength ◽  
Principal Stress ◽  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Stress Difference ◽  
Natural Fractures ◽  
Approach Angle ◽  
Hydraulic Fracture Propagation

According to the theory of plane mechanics involving the interaction of hydraulic and natural fractures, the law of hydraulic fracture propagation under the influence of natural fractures is verified using theoretical analysis and RFPA2D-Flow numerical simulation approaches. The shear and tensile failure mechanisms of rock are simultaneously considered. Furthermore, the effects of the approach angle, principal stress difference, tensile strength and length of the natural fracture, and elastic modulus and Poisson’s ratio of the reservoir on the propagation law of a hydraulic fracture are investigated. The following results are obtained: (1) The numerical results agree with the experimental data, indicating that the RFPA2D-Flow software can be used to examine the hydraulic fracture propagation process under the action of natural fractures. (2) In the case of a low principal stress difference and low approach angle, the hydraulic fracture likely causes shear failure along the tip of the natural fracture. However, under a high stress difference and high approach angle, the hydraulic fracture spreads directly through the natural fracture along the original direction. (3) When natural fractures with a low tensile strength encounter hydraulic fractures, the hydraulic fractures likely deviate and expand along the natural fractures. However, in the case of natural fractures with a high tensile strength, the natural fracture surface is closed, and the hydraulic fracture directly passes through the natural fracture, propagating along the direction of the maximum principal stress. (4) Under the same principal stress difference, a longer natural fracture corresponds to the easier initiation and expansion of a hydraulic fracture from the tip of the natural fracture. However, when the size of the natural fracture is small, the hydraulic fracture tends to propagate directly through the natural fracture. (5) A smaller elastic modulus and larger Poisson’s ratio of the reservoir result in a larger fracture initiation pressure. The presented findings can provide theoretical guidance regarding the hydraulic fracturing of reservoirs with natural fractures.

scholarly journals Numerical simulation on the simultaneous stress interference of parallel multiple hydraulic fractures

2021 ◽  
pp. 014459872110019
Author(s):  
Weiyong Lu ◽  
Changchun He
Keyword(s):  
Principal Stress ◽  
Hydraulic Fracture ◽  
Stress Ratio ◽  
Fracture Network ◽  
Hydraulic Fractures ◽  
Fracture Spacing ◽  
Induced Stress ◽  
Minimum Principal Stress ◽  
Fracturing Process ◽  
Stress Ratios

During horizontal well staged fracturing, there is stress interference between multiple transverse fractures in the same perforation cluster. Theoretical analysis and numerical calculation methods are applied in this study. We analysed the mechanism of induced stress interference in a single fracture under different fracture spacings and principal stress ratios. We also investigated the hydraulic fracture morphology and synchronous expansion process under different fracture spacings and principal stress ratios. The results show that the essence of induced stress is the stress increment in the area around the hydraulic fracture. Induced stress had a dual role in the fracturing process. It created favourable ground stress conditions for the diversion of hydraulic fractures and the formation of complex fracture network systems, inhibited fracture expansion in local areas, stopped hydraulic fractures, and prevented the formation of effective fractures. The curves of the maximum principal stress, minimum principal stress, and induced principal stress difference with distance under different fracture lengths, different fracture spacings, and different principal stress ratios were consistent overall. With a small fracture spacing and a small principal stress ratio, intermediate hydraulic fractures were difficult to initiate or arrest soon after initiation, fractures did not expand easily, and the expansion speed of lateral hydraulic fractures was fast. Moreover, with a smaller fracture spacing and a smaller principal stress ratio, hydraulic fractures were more prone to steering, and even new fractures were produced in the minimum principal stress direction, which was beneficial to the fracture network communication in the reservoir. When the local stress and fracture spacing were appropriate, the intermediate fracture could expand normally, which could effectively increase the reservoir permeability.

scholarly journals Analysis of hydraulic fracture behavior and well pattern optimization in anisotropic coal reservoirs

2020 ◽  
pp. 014459872096083
Author(s):  
Yulong Liu ◽  
Dazhen Tang ◽  
Hao Xu ◽  
Wei Hou ◽  
Xia Yan
Keyword(s):  
Hydraulic Fracture ◽  
Coalbed Methane ◽  
Fracture Network ◽  
Simulation Software ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Well Pattern ◽  
Well Pattern Optimization ◽  
The Impact

Macrolithotypes control the pore-fracture distribution heterogeneity in coal, which impacts stimulation via hydrofracturing and coalbed methane (CBM) production in the reservoir. Here, the hydraulic fracture was evaluated using the microseismic signal behavior for each macrolithotype with microfracture imaging technology, and the impact of the macrolithotype on hydraulic fracture initiation and propagation was investigated systematically. The result showed that the propagation types of hydraulic fractures are controlled by the macrolithotype. Due to the well-developed natural fracture network, the fracture in the bright coal is more likely to form the “complex fracture network”, and the “simple” case often happens in the dull coal. The hydraulic fracture differences are likely to impact the permeability pathways and the well productivity appears to vary when developing different coal macrolithtypes. Thus, considering the difference of hydraulic fracture and permeability, the CBM productivity characteristics controlled by coal petrology were simulated by numerical simulation software, and the rationality of well pattern optimization factors for each coal macrolithotype was demonstrated. The results showed the square well pattern is more suitable for dull coal and semi-dull coal with undeveloped natural fractures, while diamond and rectangular well pattern is more suitable for semi-bright coal and bright coal with more developed natural fractures and more complex fracturing fracture network; the optimum wells spacing of bright coal and semi-bright coal is 300 m and 250 m, while that of semi-dull coal and dull coal is just 200 m.

Impact of the stress state and the natural network of fractures/faults on the efficiency of hydraulic fracturing operations in the Goldwyer Shale Formation

2020 ◽  
Vol 60 (1) ◽  
pp. 163
Author(s):  
Partha Pratim Mandal ◽  
Reza Rezaee ◽  
Joel Sarout
Keyword(s):  
Stress State ◽  
Hydraulic Fracturing ◽  
Pore Pressure ◽  
Cost Effective ◽  
Fracture Network ◽  
Fault Reactivation ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Future Production ◽  
Shale Formation

Cost-effective hydrocarbon production from low-permeability unconventional reservoirs requires multi-stage hydraulic fracturing (HF) operations. Each HF stage aims to generate the most spatially extended fracture network, giving access to the largest volume of reservoir possible (stimulated volume) and allowing hydrocarbons to flow towards the wellbore. The size of the stimulated volume, and therefore, the efficiency of any given HF stage, is governed by the rock’s deformational behaviour and presence of pre-existing natural fractures/faults. Naturally elevated pore pressures at depth not only help to reduce the injection energy required to generate hydraulic fractures but can also induce slip along pre-existing fractures/faults, and therefore, enhance production rates. Here we analyse borehole image, density, resistivity and sonic logs available from a vertical exploration well in the Goldwyer Shale Formation (Canning Basin) to (i) characterise the pre-existing network of natural fractures; and (ii) estimate the in-situ pore pressure and stress state at depth. The aim of such an analysis is to evaluate the possibility of fracture/fault reactivation (slip) during and following HF operations. Based on this analysis, we found that an increase in the formation's pore pressure by only a few MPa (typically ~5–10 MPa) could lead to slip along pre-existing fractures/faults, provided they are favourably oriented with respect to the prevalent stress field for future production. We also found that slip along the horizontal or sub-horizontal bedding of the Goldwyer Formation is unlikely in view of the prevalent strike-slip faulting regime, unless an extremely large overpressure exists within the reservoir.

scholarly journals The Propagation Behavior of Hydraulic Fracture in Rock Mass with Cemented Joints

Geofluids ◽  
2019 ◽  
Vol 2019 ◽  
pp. 1-15 ◽  
Author(s):  
Yongxiang Zheng ◽  
Jianjun Liu ◽  
Yun Lei
Keyword(s):  
Hydraulic Fracturing ◽  
Univariate Analysis ◽  
Fracture Propagation ◽  
Fracture Network ◽  
Parameter Analysis ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Fracture Networks ◽  
Form Complex ◽  
Propagation Behavior

The formation of the fracture network in shale hydraulic fracturing is the key to the successful development of shale gas. In order to analyze the mechanism of hydraulic fracturing fracture propagation in cemented fractured formations, a numerical simulation about fracture behavior in cemented joints was conducted based firstly on the block discrete element. And the critical pressure of three fracture propagation modes under the intersection of hydraulic fracturing fracture and closed natural fracture is derived, and the parameter analysis is carried out by univariate analysis and the response surface method (RSM). The results show that at a low intersecting angle, hydraulic fractures will turn and move forward at the same time, forming intersecting fractures. At medium angles, the cracks only turn. At high angles, the crack will expand directly forward without turning. In conclusion, low-angle intersecting fractures are more likely to form complex fracture networks, followed by medium-angle intersecting fractures, and high-angle intersecting fractures have more difficulty in forming fracture networks. The research results have important theoretical guiding significance for the hydraulic fracturing design.

Predicting Well Performance in Naturally Fractured Reservoir

2013 ◽  
Author(s):  
Yunsuk Hwang ◽  
Jiajing Lin ◽  
David Schechter ◽  
Ding Zhu
Keyword(s):  
Hydraulic Fracture ◽  
Fracture Network ◽  
Darcy Flow ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Well Performance ◽  
Fracture Networks ◽  
Complex Fracture ◽  
Complex Fracture Network

Multiple hydraulic fracture treatments in reservoirs with natural fractures create complex fracture networks. Predicting well performance in such a complex fracture network system is an extreme challenge. The statistical nature of natural fracture networks changes the flow characteristics from that of a single linear fracture. Simply using single linear fracture models for individual fractures, and then summing the flow from each fracture as the total flow rate for the network could introduce significant error. In this paper we present a semi-analytical model by a source method to estimate well performance in a complex fracture network system. The method simulates complex fracture systems in a more reasonable approach. The natural fracture system we used is fractal discrete fracture network model. We then added multiple dominating hydraulic fractures to the natural fracture system. Each of the hydraulic fractures is connected to the horizontal wellbore, and some of the natural fractures are connected to the hydraulic fractures through the network description. Each fracture, natural or hydraulically induced, is treated as a series of slab sources. The analytical solution of superposed slab sources provides the base of the approach, and the overall flow from each fracture and the effect between the fractures are modeled by applying the superposition principle to all of the fractures. The fluid inside the natural fractures flows into the hydraulic fractures, and the fluid of the hydraulic fracture from both the reservoir and the natural fractures flows to the wellbore. This paper also shows that non-Darcy flow effects have an impact on the performance of fractured horizontal wells. In hydraulic fracture calculation, non-Darcy flow can be treated as the reduction of permeability in the fracture to a considerably smaller effective permeability. The reduction is about 2% to 20%, due to non-Darcy flow that can result in a low rate. The semi-analytical solution presented can be used to efficiently calculate the flow rate of multistage-fractured wells. Examples are used to illustrate the application of the model to evaluate well performance in reservoirs that contain complex fracture networks.

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.

scholarly journals Analysis of Initiation Angle for Fracture Propagation Considering Stress Interference

Energies ◽  
2019 ◽  
Vol 12 (10) ◽  
pp. 1841
Author(s):  
Xia Xiao ◽  
Cong Xiao
Keyword(s):  
Fracture Propagation ◽  
Hydraulic Fractures ◽  
Single Fracture ◽  
Natural Fractures ◽  
Intersection Angle ◽  
Propagation Behavior ◽  
Angle Condition ◽  
Real World Applications ◽  
Net Pressure ◽  
Remote Stress

Stress interference of multiplied fractures has significant influences on the propagation behavior of hydraulic fractures in roads, bridges, clay formations, and other forms of engineering. This paper establishes a crossing criterion and initiation angle model with comprehensive consideration of remote stress, stress intensity near the tip of fracture, and stress interference of multiplied fractures. Compared with the existing crossing criterion and initiation angle model, the ability to cross natural fractures decreases. Furthermore, the secondary initiation angle decreases with consideration of multiplied fracture propagation. The length of hydraulic fractures and natural fractures has little influence on the secondary initiation angle. With the increase in fracture space, the stress interference between fractures decreases, and as a result, the initiation angle begins to increase and then decrease. Differing from the propagation behavior of single fracture, the initiation angle basically does not vary with the increasing of net pressure under the high intersection angle between hydraulic fractures and natural fractures. Under a low intersection angle condition, the bigger the net pressure is, the smaller the initiation angle is. These results have great significance when analyzing the propagation behavior of multiplied fractures in real-world applications.

Modeling of Hydraulic Fracture Network Propagation in Shale Gas Reservoirs

2014 ◽  
Author(s):  
Chong Hyun Ahn ◽  
Robert Dilmore ◽  
John Yilin Wang
Keyword(s):  
Shale Gas ◽  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Fracture Network ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Gas Reservoirs ◽  
Complex Fracture ◽  
Shale Gas Reservoirs ◽  
Hydraulic Fracture Network

The most effective method for stimulating shale gas reservoirs is horizontal drilling with successful multi-stage hydraulic fracture treatments. Recent fracture diagnostic technologies have shown that complex fracture networks are commonly created in the field. The interaction between preexisting natural fractures and the propagating hydraulic fracture is a critical factor affecting the complex fracture network. However, many existing numerical models simulate only planar hydraulic fractures without considering the pre-existing fractures in the formation. The shale formations already contain a large number of natural fractures, so an accurate fracture propagation model needs to be developed to optimize the fracturing process. In this paper, we first understood the interaction between hydraulic and natural fractures. We then developed a new, coupled numerical model that integrates dynamic fracture propagation, reservoir flow simulation, and the interactions between hydraulic fractures and pre-existing natural fractures. By using the developed model, we conducted parametric studies to quantify the effects of rock toughness, stress anisotropy, and natural fracture spacing on the geometry and conductivities of the hydraulic fracture network. Lastly, we introduced new parmeters Fracture Network Index (FNI) and Width Anistropy (Wani) which may describe the characteristics of the fracture network in shale gas reservoirs. This new knowledge helps one understand and optimize the stimulation of shale gas reservoirs.

Application of brittleness index to interpret microseismic event distribution in a hydraulically fractured shale formation

2021 ◽  
Vol 9 (1) ◽  
pp. T1-T7
Author(s):  
Dewei Li ◽  
Ruizhao Yang ◽  
Lingbin Meng ◽  
Wang Li
Keyword(s):  
Seismic Data ◽  
In Situ Stress ◽  
Well Logs ◽  
Brittleness Index ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Location Data ◽  
Event Distribution ◽  
Microseismic Events ◽  
Microseismic Event

Many factors can impact the location data of microseismic events, including natural fractures, rock lithology, in situ stress, and hydraulic-fracturing parameters. The distribution of microseismic events generally tends toward highly brittle areas or areas with brittle minerals. Moreover, location data of microseismic events lack effective evaluation methods. Therefore, we have developed a method to use lithologic information and prestack seismic data to explain the distribution of well Tian Xing microseismic events. We have analyzed the brittleness of the target formation through the well logs and core. We inverted the Young’s modulus and Poisson’s ratio based on simultaneous amplitude variation with offset inversion by the prestack seismic data. We then computed the 3D brittleness index (BI) property volume by Grieser and Rickman’s method. In addition, the microseismic event distribution and BI map were then combined to show the internal relationship between the two results. We found that the well logs and core analysis demonstrated that the target formation has high brittleness. Generally, areas with more natural fractures have a higher probability of inducing hydraulic fractures. However, the analysis results show that the BI has an impact on the distribution of hydraulic fractures. Therefore, BI explains the reason for the distribution of almost all events in the northeast of the perforation. These observations also supported the concept that microseismic events preferentially grow toward more brittle areas.

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