scholarly journals Fractal Characterization of Complex Hydraulic Fractures in Oil Shale via Topology

Energies ◽  
2021 ◽  
Vol 14 (4) ◽  
pp. 1123
Author(s):  
Qiang He ◽  
Bo He ◽  
Fengxia Li ◽  
Aiping Shi ◽  
Jiang Chen ◽  
...  
Keyword(s):  
Fractal Dimension ◽  
Stress Ratio ◽  
Fractal Theory ◽  
Horizontal Stress ◽  
Fracture Network ◽  
Hydraulic Fractures ◽  
Fluid Viscosity ◽  
Fracture Networks ◽  
Change Rate ◽  
Complex Fracture

The formation of complex fracture networks through the fracturing technology is a crucial operation used to improve the production capacity of tight gas/oil. In this study, physical simulation experiments of hydraulic fracturing were conducted with a true triaxial test system on cubic shale oil samples from the Yanchang Formation, China. The fractures were scanned by CT both before and after the experiments and then reconstructed in 3D. The complexity of fracture networks was investigated quantitatively by the fractal theory with topology. Finally, the effect of the horizontal stress ratio, fluid viscosity, and natural fractures on the complexity of the fracture networks was discussed. The results indicate that the method based on fractal theory and topology can effectively characterize the complexity of the fracture network. The change rates of the fractal dimension (K) are 0.45–3.64%, and the fractal dimensions (DNH) of the 3D fracture network after fracturing are 1.9522–2.1837, the number of connections per branch after fracturing (CB) are 1.57–2.0. The change rate of the fractal dimension and the horizontal stress ratio are negatively correlated. However, the change rate of the fractal dimension first increases and then decreases under increasing fluid viscosities, and a transition occurs at a fluid viscosity of 5.0 mPa·s. Whether under different horizontal stress ratios or fluid viscosities, the complexity of the fracture networks after fracturing can be divided into four levels according to DNH and CB. Complex fracture networks are more easily formed under a lower horizontal stress ratio and a relatively low fluid viscosity. A fracturing fluid viscosity that is too low or too high limits the formation of a fracture network.

How Effective Is Carbon Dioxide as an Alternative Fracturing Fluid?

SPE Journal ◽  
2018 ◽  
Vol 24 (02) ◽  
pp. 857-876 ◽  
Author(s):  
Sanbai Li ◽  
Dongxiao Zhang
Keyword(s):  
Carbon Dioxide ◽  
Absolute Permeability ◽  
Working Fluid ◽  
Model Parameters ◽  
Hydraulic Fractures ◽  
Fluid Viscosity ◽  
Fracture Networks ◽  
Complex Fracture ◽  
Water Based ◽  
Oil Gas

Summary Massive hydraulic fracturing requires an enormous consumption of water and introduces many potential environmental issues. In addition, water-based fluid tends to be trapped in formations, reducing oil/gas-phase relative permeability, and causes clay-mineral swelling, which lowers absolute permeability. Carbon dioxide (CO2) is seen as a promising alternative working fluid that poses no formation-damage risk, and it can stimulate more-complex and extensive fracture networks. However, very little, if any, extant research has quantitatively analyzed the effectiveness of CO2 fracturing, except for some qualitative fracturing experiments that are based on acoustic emissions. In this study, we systematically examine water and CO2 fracturing, and compare their performance on the basis of a rigorously coupled geomechanics and a fluid-heat-flow model. Parameters investigated include fluid viscosity, compressibility, in-situ stress, and rock permeability, illustrating how they affect breakdown pressure (BP) and leakoff, as well as fracturing effectiveness. It is found that (1) CO2 has the potential to lower BP, benefiting the propagation of fractures; (2) water fracturing tends to create wider and longer tensile fractures compared with CO2 fracturing, thereby facilitating proppant transport and placement; (3) CO2 fracturing could dramatically enhance the complexity of artificial fracture networks even under high-stress-anisotropy conditions; (4) thickened CO2 tends to generate simpler fracture networks than does supercritical CO2 (SC-CO2), but still more-complex fracture networks than fresh water; and (5) the alternative fracturing scheme (i.e., SC-CO2 fracturing followed by thickened-CO2 fracturing) can readily create complex fracture networks and carry proppant to keep hydraulic fractures open. This study reveals that, for intact reservoirs, water-based fracturing can achieve better fracturing performance than CO2 fracturing; however, for naturally fractured reservoirs, CO2 fracturing can constitute an effective way to stimulate tight/shale oil/gas reservoirs, thereby improving oil/gas production.

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 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.

Numerical Simulation of Complex Fracture Network Development by Hydraulic Fracturing in Naturally Fractured Ultratight Formations

2013 ◽  
Author(s):  
Hannes Hofmann ◽  
Tayfun Babadagli ◽  
Günter Zimmermann
Keyword(s):  
Fracture Network ◽  
Natural Fracture ◽  
Fracture Networks ◽  
Network Development ◽  
Complex Fracture ◽  
Fracture Patterns ◽  
Fracture Systems ◽  
Fracture Development ◽  
Complex Fracture Network ◽  
Treatment Designs

The creation of large complex fracture networks by hydraulic fracturing is imperative for enhanced oil recovery from tight sand or shale reservoirs, tight gas extraction, and Hot-Dry-Rock (HDR) geothermal systems to improve the contact area to the rock matrix. Although conventional fracturing treatments may result in bi-wing fractures, there is evidence by microseismic mapping that fracture networks can develop in many unconventional reservoirs, especially when natural fracture systems are present and the differences between the principle stresses are low. However, not much insight is gained about fracture development as well as fluid and proppant transport in naturally fractured tight formations. In order to clarify the relationship between rock and treatment parameters, and resulting fracture properties, numerical simulations were performed using a commercial Discrete Fracture Network (DFN) simulator. A comprehensive sensitivity analysis is presented to identify typical fracture network patterns resulting from massive water fracturing treatments in different geological conditions. It is shown how the treatment parameters influence the fracture development and what type of fracture patterns may result from different treatment designs. The focus of this study is on complex fracture network development in different natural fracture systems. Additionally, the applicability of the DFN simulator for modeling shale gas stimulation and HDR stimulation is critically discussed. The approach stated above gives an insight into the relationships between rock properties (specifically matrix properties and characteristics of natural fracture systems) and the properties of developed fracture networks. Various simulated scenarios show typical conditions under which different complex fracture patterns can develop and prescribe efficient treatment designs to generate these fracture systems. Hydraulic stimulation is essential for the production of oil, gas, or heat from ultratight formations like shales and basement rocks (mainly granite). If natural fracture systems are present, the fracturing process becomes more complex to simulate. Our simulation results reveal valuable information about main parameters influencing fracture network properties, major factors leading to complex fracture network development, and differences between HDR and shale gas/oil shale stimulations.

EFFECT OF FRACTAL FRACTURES ON PERMEABILITY IN THREE-DIMENSIONAL DIGITAL ROCKS

Fractals ◽  
2019 ◽  
Vol 27 (01) ◽  
pp. 1940015 ◽  
Author(s):  
WEIFENG LV ◽  
GUOLIANG YAN ◽  
YONGDONG LIU ◽  
XUEFENG LIU ◽  
DONGXING DU ◽  
...  
Keyword(s):  
Fractal Dimension ◽  
Fractal Theory ◽  
Fractured Reservoirs ◽  
Three Dimensional ◽  
Absolute Permeability ◽  
Fracture Aperture ◽  
Fracture Networks ◽  
Discrete Fracture Networks ◽  
Discrete Fracture ◽  
The Relationship

The fracture has great impact on the flow behavior in fractured reservoirs. Fracture traces are usually self-similar and scale-independent, which makes the fractal theory become a powerful tool to characterize fracture. To obtain three-dimensional (3D) digital rocks reflecting the properties of fractured reservoirs, we first generate discrete fracture networks by stochastic modeling based on the fractal theory. These fracture networks are then added to the existing digital rocks of rock matrixes. We combine two low-permeable cores as rock matrixes with a group of discrete fracture networks with fractal characteristics. Various types of fractured digital rocks are obtained by adjusting different fracture parameters. Pore network models are extracted from the 3D fractured digital rock. Then the permeability is predicted by Darcy law to investigate the impacts of fracture properties to the absolute permeability. The permeability of fractured rock is subject to exponential increases with fracture aperture. The relationship between the permeability and the fractal dimension of fracture centers is exponential, as well as the relationship between permeability and the fractal dimension of fracture lengths.

scholarly journals Transient Pressure Behavior of Complex Fracture Networks in Unconventional Reservoirs

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-11
Author(s):  
Gou Feifei ◽  
Liu Chuanxi ◽  
Ren Zongxiao ◽  
Qu Zhan ◽  
Wang Sukai ◽  
...  
Keyword(s):  
Fracture Network ◽  
Unconventional Reservoirs ◽  
Transitional Flow ◽  
Natural Fractures ◽  
Fracture Networks ◽  
Transient Pressure ◽  
Horizontal Drilling ◽  
Pressure Behavior ◽  
Complex Fracture ◽  
Complex Fracture Network

Unconventional resources have been successfully exploited with technological advancements in horizontal-drilling and multistage hydraulic-fracturing, especially in North America. Due to preexisting natural fractures and the presence of stress isotropy, several complex fracture networks can be generated during fracturing operations in unconventional reservoirs. Using the DVS method, a semianalytical model was created to analyze the transient pressure behavior of a complex fracture network in which hydraulic and natural fractures interconnect with inclined angles. In this model, the complex fracture network can be divided into a proper number of segments. With this approach, we are able to focus on a detailed description of the network properties, such as the complex geometry and varying conductivity of the fracture. The accuracy of the new model was demonstrated by ECLIPSE. Using this method, we defined six flow patterns: linear flow, fracture interference flow, transitional flow, biradial flow, pseudoradial flow, and boundary response flow. A sensitivity analysis was conducted to analyze each of these flow regimes. This work provides a useful tool for reservoir engineers for fracture designing as well as estimating the performance of a complex fracture network.

scholarly journals Clustering, Connectivity and Flow Responses of Deterministic Fractal-Fracture Networks

2020 ◽  
Vol 54 ◽  
pp. 149-156
Author(s):  
Ajay K. Sahu ◽  
Ankur Roy
Keyword(s):  
Fractal Dimension ◽  
Spatial Clustering ◽  
Flow Behavior ◽  
Flow Simulation ◽  
Fractal Dimensions ◽  
Fracture Network ◽  
Natural Fracture ◽  
Fracture Networks ◽  
Fracture Models ◽  
Fractal Fracture

Abstract. It is well known that fracture networks display self-similarity in many cases and the connectivity and flow behavior of such networks are influenced by their respective fractal dimensions. In the past, the concept of lacunarity, a parameter that quantifies spatial clustering, has been implemented by one of the authors in order to demonstrate that a set of seven nested natural fracture maps belonging to a single fractal system, but of different visual appearances, have different clustering attributes. Any scale-dependency in the clustering of fractures will also likely have significant implications for flow processes that depend on fracture connectivity. It is therefore important to address the question as to whether the fractal dimension alone serves as a reasonable proxy for the connectivity of a fractal-fracture network and hence, its flow response or, if it is the lacunarity, a measure of scale-dependent clustering, that may be used instead. The present study attempts to address this issue by exploring possible relationships between the fractal dimension, lacunarity and connectivity of fractal-fracture networks. It also endeavors to study the relationship between lacunarity and fluid flow in such fractal-fracture networks. A set of deterministic fractal-fracture models generated at different iterations and, that have the same theoretical fractal dimension are used for this purpose. The results indicate that such deterministic synthetic fractal-fracture networks with the same theoretical fractal dimension have differences in their connectivity and that the latter is fairly correlated with lacunarity. Additionally, the flow simulation results imply that lacunarity influences flow patterns in fracture networks. Therefore, it may be concluded that at least in synthetic fractal-fracture networks, rather than fractal dimension, it is the lacunarity or scale-dependent clustering attribute that controls the connectivity and hence the flow behavior.

scholarly journals Semianalytical Coupled Model of Transient Pressure Behavior for Horizontal Well with Complex Fracture Networks in Tight Oil Reservoirs

2019 ◽  
Vol 2019 ◽  
pp. 1-12
Author(s):  
Ren Zongxiao ◽  
Du Kun ◽  
Shi Junfeng ◽  
Liu Wenqiang ◽  
Qu Zhan ◽  
...  
Keyword(s):  
Horizontal Well ◽  
Variable Mass ◽  
Fracture Network ◽  
Fracture Networks ◽  
Transient Pressure ◽  
Pressure Behavior ◽  
Complex Fracture ◽  
Complex Fracture Network ◽  
Horizontal Wellbore ◽  
Seepage Model

Due to a large number of natural fractures in tight oil reservoir, many complex fracture networks are generated during fracturing operation. There are five kinds of flow media in the reservoir: “matrix, natural fracture, hydraulic fracture network, perforation hole, and horizontal wellbore”. How to establish the seepage model of liquid in multiscale medium is a challenging problem. Firstly, this paper establishes the dual medium seepage model based on source function theory, principle of superposition, and Laplace transformation and then uses the “star-triangle” transform method to establish the transient pressure behavior model in the complex fracture network. After that, perforating seepage model and variable mass flow in horizontal wellbore were established. Finally, continuous condition was used to couple the seepage model of dual medium seepage model, transient pressure behavior model in the complex fracture network, perforation seepage model, and the variable mass seepage model in horizontal wellbore, to establish a semianalytical coupled seepage model for horizontal well in tight reservoir. This paper provides theoretical basis for field application of horizontal well with complex fracture networks.

A Peridynamics Model for the Propagation of Hydraulic Fractures in Heterogeneous, Naturally Fractured Reservoirs

2015 ◽  
Author(s):  
Hisanao Ouchi ◽  
Amit Katiyar ◽  
John T. Foster ◽  
Mukul M. Sharma
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Two Dimensions ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Fracture Networks ◽  
Complex Fracture ◽  
Nonlocal Continuum Theory

Abstract A novel fully coupled hydraulic fracturing model based on a nonlocal continuum theory of peridynamics is presented and applied to the fracture propagation problem. It is shown that this modeling approach provides an alternative to finite element and finite volume methods for solving poroelastic and fracture propagation problems and offers some clear advantages. In this paper we specifically investigate the interaction between a hydraulic fracture and natural fractures. Current hydraulic fracturing models remain limited in their ability to simulate the formation of non-planar, complex fracture networks. The peridynamics model presented here overcomes most of the limitations of existing models and provides a novel approach to simulate and understand the interaction between hydraulic fractures and natural fractures. The model predictions in two-dimensions have been validated by reproducing published experimental results where the interaction between a hydraulic fracture and a natural fracture is controlled by the principal stress contrast and the approach angle. A detailed parametric study involving poroelasticity and mechanical properties of the rock is performed to understand why a hydraulic fracture gets arrested or crosses a natural fracture. This analysis reveals that the poroelasticity, resulting from high fracture fluid leak-off, has a dominant influence on the interaction between a hydraulic fracture and a natural fracture. In addition, the fracture toughness of the rock, the toughness of the natural fracture, and the shear strength of the natural fracture also affect the interaction between a hydraulic fracture and a natural fracture. Finally, we investigate the interaction of multiple completing fractures with natural fractures in two-dimensions and demonstrate the applicability of the approach to simulate complex fracture networks on a field scale.

Impact of Complex Fracture Networks on Rate Transient Behavior of Wells in Unconventional Reservoirs Based on Embedded Discrete Fracture Model

2021 ◽  
pp. 1-12
Author(s):  
Jiazheng Qin ◽  
Yingjie Xu ◽  
Yong Tang ◽  
Rui Liang ◽  
Qianhu Zhong ◽  
...  
Keyword(s):  
Flow Regimes ◽  
Natural Fracture ◽  
Fracture Model ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Fracture Networks ◽  
Discrete Fracture Model ◽  
Complex Fracture ◽  
Discrete Fracture ◽  
The Impact

Abstract It has recently been demonstrated that complex fracture networks (CFN) especially activated natural fractures (ANF) play an important role in unconventional reservoir development. However, traditional rate transient analysis (RTA) methods barely investigate the impact of CFN or ANF. Furthermore, the influence of CFN on flow regime is still ambiguous. Failure to consider these effects could lead to misdiagnosis of flow regimes and underestimation of original oil in place (OOIP). A novel numerical RTA method is therefore presented herein to improve the quality of reserves assessment. A new methodology is introduced. Propagating hydraulic fractures (HF) can generate different stress perturbations to allow natural fractures (NF) to fail, forming various ANF pattern. An embedded discrete fracture model (EDFM) of ANF is stochastically generated instead of local grid refinement (LGR) method to overcome the time-intensive computation time. These models are coupled with reservoir models using non-neighboring connections (NNCs). Results show that except for simplified models used in previous studies subjected to traditional concept of stimulated reservoir volume (SRV), in our study, the ANF region has been discussed to emphasis the impact of NF on simulation results. Henceforth, ANF could be only concentrated around the near-wellbore region, and it may also cover the whole simulation area. Obvious distinctions could be viewed for different kinds of ANF on diagnostic plots. Instead of SRV-dominated flow mentioned in previous studies, ANF-dominated flow developed in this work is shown to be more reasonable. Also, new flow regimes such as interference flow inside and outside activated natural fracture flow region (ANFR) are found. In summary, better evaluation of reservoir properties and reserves assessment such as OOIP are achieved based on our proposed model compared with conventional models. The novel RTA method considering CFN presented herein is an easy-to-apply numerical RTA technique that can be applied for reservoir and fracture characterization as well as OOIP assessment.

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