ORCID Profile
0000-0002-6043-5749
Current Organisations
University of Nevada Reno
,
Arizona State University
,
China University of Mining and Technology
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Publisher: Institute of Electrical and Electronics Engineers (IEEE)
Date: 11-2022
Publisher: Hindawi Limited
Date: 22-06-2020
DOI: 10.1155/2020/2787903
Abstract: In the process of coalbed methane exploitation, the fracture and pore structure is the key problem that affects the permeability of coalbed. At present, the coupling effect of fracture and pore structure and in situ stress is seldom considered in the study of coal seam permeability. In this paper, the fractal seepage model is coupled with coal deformation, and the adsorption expansion effect is considered. A multifield coupling model considering the influence of matrix and fracture structure is established. Then, the influence of pore structure parameters of main fracture on macropermeability is analyzed, including (1) fractal dimension of fracture length, (2) maximum fracture length, (3) fractal dimension of throat diameter, and (4) fractal dimension of throat bending. At the same time, the simulation results are compared with the results of Darcy’s uniform permeability model. The results show that the permeability calculated by the proposed model is significantly different from that calculated by the traditional cubic model. Under the action of in situ stress, when the porosity and other parameters remain unchanged, the macropermeability of coal is in direct proportion to the fractal dimension of coal fracture length, the fractal dimension of throat diameter, and the maximum fracture length and in inverse proportion to the fractal dimension of coal throat curvature.
Publisher: Hindawi Limited
Date: 16-03-2021
DOI: 10.1155/2021/6616315
Abstract: CO2 injection into coal seam triggers a series of processes that are coupled all together through a permeability model. Previous studies have shown that current permeability models cannot explain experimental data as reported in the literature. This knowledge gap defines the goal of this study. We hypothesize that this failure originates from the assumption that the pore strain is the same as the bulk strain in order to satisfy the Betti-Maxwell reciprocal theorem. This assumption is valid only for the initial state without gas sorption and deformation and for the ultimate state with uniform gas sorption and uniform deformation within the REV (representative elementary volume). In this study, we introduce the pore-bulk strain ratio and interference time to characterize the process of gas sorption and its associated nonuniform deformation from the initial state to the ultimate state. This leads to a new nonequilibrium permeability model. We use the model to fully couple the coal deformation and gas flow. This new coupled model captures the impact of coal local transient behaviors on gas flow. Results of this study clearly show that coal permeability is constrained by the magnitudes of initial and ultimate pore-bulk strain ratios and interference time, that current permeability data in the literature are within these bounds, and that the evolutions of coal permeability all experience similar stages from the initial value to the ultimate one.
Publisher: Hindawi Limited
Date: 2018
DOI: 10.1155/2018/5910437
Abstract: A shale gas reservoir is usually hydraulically fractured to enhance its gas production. When the injection of water-based fracturing fluid is stopped, a two-phase flowback is observed at the wellbore of the shale gas reservoir. So far, how this water production affects the long-term gas recovery of this fractured shale gas reservoir has not been clear. In this paper, a two-phase flowback model is developed with multiscale diffusion mechanisms. First, a fractured gas reservoir is ided into three zones: naturally fractured zone or matrix (zone 1), stimulated reservoir volume (SRV) or fractured zone (zone 2), and hydraulic fractures (zone 3). Second, a dual-porosity model is applied to zones 1 and 2, and the macroscale two-phase flow flowback is formulated in the fracture network in zones 2 and 3. Third, the gas exchange between fractures (fracture network) and matrix in zones 1 and 2 is described by a diffusion process. The interactions between microscale gas diffusion in matrix and macroscale flow in fracture network are incorporated in zones 1 and 2. This model is validated by two sets of field data. Finally, parametric study is conducted to explore key parameters which affect the short-term and long-term gas productions. It is found that the two-phase flowback and the flow consistency between matrix and fracture network have significant influences on cumulative gas production. The multiscale diffusion mechanisms in different zones should be carefully considered in the flowback model.
Publisher: Hindawi Limited
Date: 05-12-2022
DOI: 10.1155/2022/7202972
Abstract: The fluid front motion is an important phenomenon during anisotropic fluid flow in rock engineering. The pore pressure and mechanical responses may be significantly influenced and show an obvious difference near the moving fluid front. However, few studies have been conducted to investigate the front motion of different types of fluids during anisotropic fluid flow. In this work, a numerical model was proposed to detect the front motion of water, nitrogen, and CO2 in anisotropic shale reservoirs. The full coupling effects among mechanical deformation, fluid flow, and moving boundary in anisotropic porous media were considered in the model construction. The impacts of different fluid properties among water, nitrogen, and CO2 on the anisotropic fluid flow have been discussed. Then, the proposed model was applied to study the differences in front motion among different types of fluids in anisotropic shales. The impacts of permeability and mobility on fluid front motion were investigated. The theoretical equations for predicting the fluid front motion of different types of fluids were established by introducing corresponding correction coefficients to the previous formulas. The results showed that the model can well describe the anisotropic fluid permeation process. The fluid front motion increased with the increase of permeability and mobility. At the same permeability or mobility, the nitrogen front motion was the largest and the water front motion was the smallest. The difference in fluid front motion among water, nitrogen, and CO2 was caused by the difference of their viscosity and compressibility. The proposed formulas can fast and accurately predict the evolution of fluid front motion for different types of fluids.
Publisher: Hindawi Limited
Date: 04-03-2019
DOI: 10.1155/2019/7692490
Abstract: Water permeation into a porous medium is a common but important phenomenon in many engineering fields such as hydraulic fracturing. The water permeation front moves with time and may significantly impact the field variable evolution near the water front. Many algorithms have been developed to calculate this water front motion, but few numerical algorithms have been available to calculate the water front motion in anisotropic fluid-solid couplings with high computational efficiency. In this study, a numerical model is proposed to investigate the front motion of water permeation into an anisotropic porous medium. This model fully couples the mechanical deformation, fluid flow, and water front motion. The water front motion is calculated based on a directional Darcy’s flow in the anisotropic porous medium, and a revised formula with a correction coefficient is developed for the estimation of permeation depth. After verification with three sets of experimental data, this model is used to numerically investigate the impacts of permeability, viscosity, permeability anisotropy, and mechanical anisotropy on water front motion. Numerical results show that the proposed model can well describe the anisotropic water permeation process with reasonable accuracy. The permeation depth increases with permeability, mobility, and mechanical anisotropy but decreases with viscosity and permeability anisotropy. The correction coefficient mainly depends on porosity evolution, flow pattern, mobility, permeability anisotropy, and mechanical anisotropy.
No related grants have been discovered for Feng Gao.