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In this work, we construct a new coupled Multiscale/Discrete Fracture Model for compressible flow in a multiporosity shale gas reservoir containing networks of natural and hydraulic fractures. The geological formation is characterized by four distinct length scales and levels of porosity. The window of observation of the finest (nanoscale) portrait...
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... illustrate the performance of the numerical multiscale model proposed herein, we present numerical simulations of gas production in the stimulated region of a shale reservoir. Figure 5 illustrates the idealized reservoir where the reduced domain F ( F ⊂ R) is occupied by a single vertical ...
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... between natural fractures. The hydraulic fracture half length is denoted by x F , the interface with the well lies at y = 0, and the origin of the x-axis aligned with the flow in the natural fractures is also chosen at the well loca- tion. The lengths of the parallel natural fractures and matrix blocks are designated by L f and l b , respectively (Fig. 5). By exploring the symmetry in the simplified arrangement, the natural fracture problem is solved in the half domain [0, L f /2]. In order to validate the pressure continuity in Eq. 43, adopting the input values in Table 1, we obtain the estimate ω = 2.485 × 10 −9 for the dimensionless frac- ture resistance in Eq. 41 thus suggesting a ...
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... By combining the results of core, drilling, and completion analyses, Vasilev et al. (2016) studied the TFB characteristics of a well in NFRs. Rocha et al. (2017) constructed a new coupled discrete-fracture model to simulate gas flow in shale gas formations containing a network of natural and hydraulic fractures. Li et al. (2018) modeled the nonlinear TFB of gas in shale fractures. ...
In this study, a pressure-depleted flow (PDF) experiment on 5 artificially fractured cores was conducted for the first time to simulate physically the transient flow behavior (TFB) in closed high-pressure (HP) gas reservoirs. The experimental method was the same as the matrix core experiment described in Part I. A series of flow rate and pressure curves were drawn, and then matched using regression equations. The nonlinear TFB characteristics were thoroughly analyzed and compared with those of the matrix cores (Part I). The pressure curves between the fractured and matrix cores were similar, but the flow rate curves were different. Particularly, the curves of decline in the flow rate are plotted. It was observed that the decline in flow rate curves reflected the typical inter-porosity flow behavior of dual porosity media, which completely differed from the matrix cores. Additionally, the final recovery factor was calculated using the pressure arithmetic mean method. Finally, the nonlinear TFB characteristics were summarized. The results of this study revealed that the nonlinearity of gas flow through fractured cores was stronger than that through matrix cores. This work can be an excellent reference for investigators to research the nonlinear TFB of fluids in complex porous media.
Article Highlights
The experiment of the flow behavior on fractured cores was first performed and the nonlinear flow characteristics were analyzed.
The inter-porosity flow phenomenon between matrix and fracture media was first discerned from decline rate curves.
The pressure-depleted of experimental results were compared between the fractured and matrix cores.
... Rock mass, therefore, can be regarded as an assemblage of intact rock blocks that are separated by discontinuities. As a consequence, the DFN model is an ideal tool to generate the distribution of natural fractures and express the behavior of fluid flow through fractured rock mass (Hyman et al. 2016, Medici et al. 2019, Rocha et al. 2017. Meanwhile, the DFN model is counted on a statistical characterization of the rock mass. ...
In-situ leaching could be one of the promising mining methods to extract the minerals from deep fractured rock mass. Constrained by the low permeability at depth, however, the performance does not meet the expectation. In fact, the rock mass permeability mainly depends on the pre-existing natural fractures and therefore play a crucial role in in-situ leaching performance. More importantly, fractures have various characteristics, such as aperture, persistence, and density, which have diverse contributions to the promising method. Hence, it is necessary to study the variation of fluid rate versus fracture parameters to enhance in-situ leaching performance. Firstly, the subsurface fractures from the depth of 1500m to 2500m were mapped using the discrete fracture network (DFN) in this paper, and then the numerical model was calibrated at a particular case. On this basis, the fluid flow through fractured rock mass with various fracture characteristics was analyzed. The simulation results showed that with the increase of Fisher’ K value, which determine the fracture orientation, the flow rate firstly decreased and then increased. Subsequently, as another critical factor affecting the fluid flow in natural fractures, the fracture transmissivity has a direct relationship with the flow rate. Sensitive study shows that natural fracture characteristics play a critical role in in situ leaching performance.
... Following the guidelines of our earlier work [28,29] the coupling with flow and deformation in the hydraulic fractures can be pursued within the context of the DFM (discrete fracture model) where the fracture network is treated in a discrete fashion playing the role of interface conditions for flow in the matrix. Alternative more denser networks of natural fractures can also be incorporated in the current framework by exploring the double porosity models for deformable media discussed in [6,9,10,37]. ...
In this work, we consider a new model for flow in a multiporosity shale gas reservoir constructed within the framework of an upscaling procedure where hydraulic fractures are treated as (\(n-1\)) interfaces (\(n=2,3\)). Within this framework, the hydrodynamics is governed by a new pressure equation in the shale matrix which is treated as a homogenized porous medium composed of organic matter (kerogen aggregates with nanopores) and inorganic impermeable solid (clay, calcite, quartz) separated from each other by a network of interparticle pores of micrometer size. The solution of the pressure equation is strongly influenced by the constitutive response of the retardation parameter and effective hydraulic conductivity where the former incorporates gas adsorption/desorption in the nanopores of the kerogen. By focusing our analyses on this nonlinear diffusion equation in the domain occupied by the shale matrix, an optimization strategy seated on the adjoint sensitivity method is developed to minimize a cost functional related to gas production and net present value in a single hydraulic fracture. The gradient of the objective functional computed with the adjoint formulation is explored to update the controlled pressure drop aiming to optimize production in a given window of time. The combination of the direct approach and gradient-based optimization using the adjoint formulation leads to the construction of optimal production scenarios under controlled pressure decline in the well. Numerical simulations illustrate the potential of the methodology proposed herein in optimizing gas production.
Extraction of geothermal energy, oil and gas, and coalbed methane (CBM) are all constrained by the rock’s permeability. To stimulate the production, hydraulic fracturing has become a routine procedure, which is influenced by many factors especially the pre-existing natural fractures. The natural fractures have various characteristics, such as aperture, persistence, and density, which have different effects on the hydraulic performance. Hence, it is necessary to study the dependence of hydraulic fracturing on natural fracture parameters to improve its effectiveness. In this research, the distribution of natural fracture is generated using the discrete fracture network (DFN) to study these relationships. To verify the accuracy, the numerical model is calibrated at a particular case with observed data and then continued to different fragmentation characteristics. Results show that the hydraulically fractured area has an inverse relationship with the natural fracture aperture. However, the increase of pre-existing fracture persistence first causes the fractured zone to increase but increasing persistence of natural fractures further causes the area to decrease. Parametric study shows that pre-existing natural fractures play a critical role in hydraulic fracturing effectiveness, which ultimately affects the production.
Fractures play a crucial role in earth resource engineering, such as geothermal exploitation, coalbed methane (CBM) extraction, and hydraulic fracturing. Breaches, as main channels of fluid flow, have various characteristics, such as aperture, density, and persistence that could affect the transmissivity. Due to the difficulty of distinguishing the contribution of fracture parameters to fluid flow in fractured coal and rock mass, the numerical simulation is necessary to simulate the fluid flow in fractures versus benchmarks to obtain realistic data to study the variation of flow rate with fracture parameters. In this paper, a numerical discrete element method (DEM) was used to rebuild the spatial distribution of DFN and simulate the fluid flow in DFN modeling, and the results were compared to the field test results in Yilgarn area in Western Australia. On this basis, the dependences of the flow rate on fracture parameters were obtained. In DFN modeling, the flow path was considered with a rectangular section, and its geometry was determined by aperture and persistence. As a circular fracture, its persistence is an influential factor of flow lengths. Besides, the flow channels and length in fractured coal and rock mass increased with the increase of fracture density. According to the cubic law, the flow rate has a direct relationship with the fracture opening, and the number of channels, but has an inverse relationship with the flow length, which is consistent with the simulation results. Results showed that the flow rate increased with the fracture aperture. Meanwhile, the increase of flow rate with fracture persistence was non-linear. When the size of the fracture was small, the flow rate increased gradually. However, with the rise of fracture size, the flux increased abruptly. Finally, the flow rate fluctuated with increasing fracture density. This research will enhance the knowledge of earth resource extraction performance such as CBM, geothermal, oil and in-suit leaching through the fractured media.
