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Discrete fracture network: (a) DFN volume; (b) Selected horizontal section; (c) natural fracture apertures
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The characteristics of a natural fracture system (NFs) play an important role in the hydraulic fracturing treatment. Open fractures form intercommunicated channels of high permeability while sealed fractures act as weakness planes and can be activated during the hydraulic fracture treatments. The final geometry of the hydraulic fracture (HF) can be...
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... models (DFM) represent the fracture system's characteristics more accurately and explicitly describe the effect of individual fractures on the mechanical deformation and flow pattern Moinfar et al., 2011;J. A. Rueda Cordero et al., 2019b, 2019aRueda et al., 2020b. These models find a broad range of engineering applications (Gutierrez et al., 2019;J. Rueda Cordero et al., 2019;Rueda et al., 2014) because they can describe the heterogeneities, anisotropy, and fracture distribution of the fracture network. In the finite element method, natural fractures can be represented using zero-thickness interface elements and the extended finite element method (XFEM). The use of interface elements requires a finite element ...
The discovery of carbonate reservoirs in the Brazilian pre-salt field has raised several engineering challenges. These reservoirs are naturally fractured and much stiffer than conventional reservoirs. Thus, the study of fluid flow through natural fractures has received significant attention from the petroleum industry because the production capacity of these fields is associated with the hydraulic behavior of such fractures. However, pressure changes induced by the oil recovery alter the fracture aperture. In turn, changes in the fracture aperture affect the fluid flow inside the fracture channels, increasing or reducing the production capacity of the reservoir. This work investigates the hydromechanical effect of natural fractures on the reservoir behavior at the production unit Tupi pilot of the Brazilian pre-salt. The enhanced dual-porosity/dual permeability model (EDPDP) is adopted to simulate more realistically the hydromechanical behavior of fractured carbonate rock formation. This approach updates the stiffness and permeability tensors considering the fracture orientation and the stress-induced aperture changes. The shape factor is also improved to represent multi-block domains formed by several multiscale fracture sets with different orientations, apertures, and spacing. The hydromechanical formulation of EDPDP implemented in an in-house framework GeMA (Geo Modeling Analysis) is adopted to study the hydromechanical effect of fractures with multiple lengths on the Tupi pilot. The numerical results demonstrate that the complex fracture network is responsible for fluid migration through a preferential pathway. A parametric analysis of the main parameters that affect reservoir behavior was carried out. The parametric study shows higher pore pressure dissipation for smaller dip angles. Then, horizontal fractures are more sensitive to vertical displacements. In addition, smaller spacing and larger fracture aperture enhance permeability, increasing pore pressure dissipation and mechanical deformation. Finally, numerical results were compared against field measurements showing excellent agreement, demonstrating the applicability of the EDPDP model to simulate naturally fractured reservoirs.
... To define that surface, the experiments were divided into six levels of angles of approach, five levels of fracture energy, five levels of friction angle, three levels of minimum stress, and 30 levels of maximum stress with the ratio between the maximum and minimum stress limited between 1 and 4, we simulated all levels combined. Table 2 summarizes the simulation parameters, and Table 3 presents the fixed parameters following Rueda et al. (2019). ...
... A case study verifies the generalization capabilities of the developed neural network. A simulation using the neural network was conducted on the DFN presented by Falcão et al. (2018) and compared with the numerical simulation presented by Rueda et al. (2019). We used the benchmark to validate several reservoir flow simulation methodologies, showing good agreement. ...
... The ANN indicates opening behavior for fractures #1, #2, and #3 and crossing for fractures #4 and #5. Fig. 29b shows the final stimulated results obtained from (Rueda et al., 2019). It can be observed from the results that the type of interaction coincides at four fractures. ...
In recent years, the increasing energy demand has led the oil and gas industry to explore unconventional reservoirs. The hydraulic fracturing technique (fracking) has been adopted in order to increase the reservoir drainage area. Nevertheless, there is an environmental concern about the contamination of aquifers due to this technique. The operation design requires predicting the induced fracture geometry to avoid hazards related to fracking. Hydraulic fracturing changes the state of stress at crack tip leading to more uncertainties in the definition of crack geometry, especially in naturally fractured formations. For such, analytical solutions and numerical simulations have been employed in recent decades. Nevertheless, the numerical models require high computational effort. This paper proposes an artificial neural network (ANN) to predict the interaction between hydraulic fracture and natural fractures. We performed over 800 simulations to build the training database varying the rock mechanical properties and model parameters, such as the approach angle between hydraulic fracture and natural fracture, in-situ stress magnitudes, friction angle, and fracture energy. The ANN results are compared against analytical solutions and numerical models, showing excellent agreement. These results show that the trained neural network can predict fracture interaction accurately. They also suggest that the most sensible parameters were taken into account in the proposed ANN.
... That approach, which is used in this work, allows fracture propagation along complex paths. The methodology has been validated and successfully applied to hydraulic fracturing in naturally fractured media to study the effects of horizontal stress contrast, approach angle, thickness, and friction of NFs on hydraulic fracture propagation [53,54]. ...
... Fig. 7 outlines the fragmentation steps of conventional finite element mesh. The intrinsic cohesive zone model has been successfully applied in hydraulic fracturing in naturally fractured porous media [53,54] and is adopted in this work. ...
Hydraulic fracturing is a technique in which pressurized fluid is pumped into the well to induce fracture propagation in the rock formation. The treatment aims at enhancing permeability and well-reservoir connectivity. However, the presence of natural fractures can impact the hydraulic fracture propagation, increasing the complexity of the hydraulic fracturing treatment, and affect the final configuration of the fracture network. Furthermore, different propagation regimes can develop depending on field conditions, properties of the porous matrix, fractures, the injection fluid, and time. This work introduces a robust fully coupled hydro-mechanical approach to investigate the impacts of natural fractures on hydraulic fracturing in four limiting propagation regimes: toughness-storage, toughness-leak-off, viscosity-storage, and viscosity-leak-off dominated. The proposed approach is based on the finite element method and incorporates the coupling of pore pressure/stress within the permeable rock formation and fracture propagation. An innovative mesh fragmentation technique with an intrinsic pore-cohesive zone approach is implemented in the in-house multi physics framework to simulate fracture propagation with complex crack patterns. Cohesive Zone Model (CZM) represents the initiation and propagation of hydraulic fractures while a contact model with the Mohr-Coulomb criterion is used to represent the normal closure/opening and friction/shear dilation of natural fractures. The results of the new approach are compared against analytical and numerical solutions. Moreover, the influence of parameters such as rock permeability, fluid viscosity, initial stress state, and intercepting angle on the hydraulic and natural fracture is also investigated. The robustness of the presented methodology is demonstrated by simulating crossing with an offset, branching, fracture propagation from the tip of a natural crack, and interaction of multiple cracks. These results can provide guidance for a better understanding of the complex process of hydraulic fracturing.
... This method is a powerful and efficient technique for computational fracture modeling. Complex problems such as hydraulic fracturing and even the interaction between the hydraulic and natural fractures are eligible for modelling with CZM [11,12]. Other techniques are found in literature for modelling fractures as well [13][14][15] This work aims at discussing the effect of the parameters necessary for a numerical simulation of a DFIT. ...
In-situ stresses and permeability of the rock media has a significant role in predicting the production rate of oil and gas reservoirs. Hydraulic fracturing is a widely used technique to increase the rock formation permeability in oil and gas reservoirs. The diagnostic fracture injection test (DFIT) is a commonly used and reliable technique executed prior to a hydraulic fracture stimulation process. Its main objective is to break a small fracture in the rock formation around the wellbore, in order to evaluate the closure of the fracture system. This test provides the parameters necessary for hydraulic fracturing planning, such as minimum horizontal stress, fracture closure pressure, fracture gradient, fluid leak-off coefficient, fluid efficiency, and formation permeability. These parameters play an important role in determining the operation window for stability and planning of secondary recovery operations. This work presents the numerical simulation of a DFIT in a carbonate reservoir of a Brazilian oil field. Coupled hydro-mechanical continuum elements and coupled cohesive interface elements represent the porous media and the hydraulic fracture in the numerical model, respectively. This paper aims at investigating the effect of fracture treatment parameters on the hydraulic fracture geometry before-and after-closure response of the DFIT. The methodology reproduces numerically all stages of a DFIT. Therefore, the comparison of the measured bottom-hole pressure and those obtained numerically show good agreement. The right combination of minimum in-situ stress and permeability estimation was essential to obtain a good closure response after shut-in.
Hydraulic fracturing is essential for assuring production from unconventional reservoirs with ultra-low permeability. The efficiency of hydraulic stimulation is strongly affected by geological discontinuities, such as faults, joints, and natural fractures. This study proposes robust numerical models for fully coupled hydromechanical simulation of the phenomena present in fracture propagation and fluid migration problems in fractured media. A novel mesh fragmentation technique with an intrinsic pore-cohesive zone approach is developed to simulate unrestricted hydraulic fracture propagation. The proposed method allows studying the effect of some primary parameters on hydraulic and natural fracture interaction. In a reservoir simulation, a 3D hydromechanical formulation for an enhanced dual porosity/dual permeability (EDPDP) model is combined with a discrete fracture model (DFM) to represent a fractured porous formation more realistically. The new model allows the study of the impacts of natural fractures with different orientations at multiple scales on the hydromechanical behavior of the reservoir. Finally, this research proposes a new methodology that integrates a robust fluid-driven fracture propagation model and reservoir simulation, improving the evaluation of production performance. We simulate several hydraulic fracturing scenarios for the assessment of cumulative reservoir production. We also study the effects of multiple length fractures on the hydraulically stimulated reservoir integrating EDPDP-DFM. The numerical results show that natural fractures form preferential paths of HF propagation, enhancing well–reservoir connectivity but reducing hydraulic fracture aperture by fluid leak-off. Fluid viscosity and injection rate control fracture opening, pressure, growth, and fluid leak-off. Finally, secondary fractures significantly impact the estimation of fluid drainage and pore pressure dissipation.
Hydraulic stimulation is a technique in which a mixture of viscous fluids is pumped through an injector well in order to initiate and/or propagate fractures in the rock formation to enhance well-reservoir connectivity. Analytical and numerical methods have been proposed in the literature for predicting the evolution of the induced hydraulic fractures. Most of those studies are limited to some assumptions, such as fracture propagation through intact materials that follow a linear elastic behavior. However, those assumptions do not apply in naturally fractured porous media. The presence of geological discontinuities such as faults, joints, and natural fractures increases the complexity of the hydraulic fracturing treatment, affecting the final configuration of the hydraulic fracture network. This work investigates the effect of natural fractures on hydraulic fracture propagation in two limiting propagation regimes: toughness-fracture storage and viscosity-fracture storage dominated.
The model fully couples permeable rock deformation and fluid flow inside and across the fractures. The hydromechanical triple-nodded zero thickness interface element has been combined with a cohesive zone model to simulate hydraulic fracture propagation. Mohr-Coulomb criterion and a contact model represent frictional and closure behavior of natural fractures, respectively. The longitudinal flow within the fracture is governed by Reynold's lubrication theory through smooth narrow parallel plates (i.e., Poiseuille flow). An innovated intrinsic mesh fragmentation technique is used to simulate complex crack patterns during hydraulic crack propagation.
The results of the new approach are compared with analytical solutions. Moreover, the influence of parameters such as rock permeability, fluid viscosity, initial stress state, and natural fracture orientation on the hydraulic fracture propagation is analyzed
Hydraulic fracturing stimulation is a technique in which a mixture of viscous fluids is pumped through an injector well in order to initiate and/or propagate fractures in the rock formation to enhance well-reservoir connectivity. Analytical and numerical methods have been proposed in the literature for predicting the evolution of the induced hydraulic fractures. Most of those studies are limited to some assumptions, such as fracture propagation through intact materials that follow a linear elastic behavior. However, those assumptions do not apply in naturally fractured porous media. The presence of geological discontinuities such as faults, joints, and natural fractures increases the complexity of the hydraulic fracturing treatment, affecting the final configuration of the hydraulic fracture network. This work investigates the effect of natural fractures on hydraulic fracture propagation in two limiting propagation regimes: toughness-fracture storage and viscosity-fracture storage dominated.
The model fully couples permeable rock deformation and fluid flow inside and across the fractures. The hydromechanical triple-nodded zero thickness interface element has been combined with a cohesive zone model to simulate hydraulic fracture propagation. Mohr-Coulomb criterion and a contact model represent frictional and closure behavior of natural fractures, respectively. The longitudinal flow within the fracture is governed by Reynold’s lubrication theory through smooth narrow parallel plates (i.e., Poiseuille flow). An innovative intrinsic mesh fragmentation technique is used to simulate complex crack patterns during hydraulic crack propagation.
The results of the new approach are compared with analytical solutions. Moreover, the influence of parameters such as rock permeability, fluid viscosity, initial stress state, and natural fracture orientation on the hydraulic fracture propagation is analyzed
