Abstract:This paper presents an analytical solution of Buckley-Leverett equation for gas flooding with constant-pressure boundary including the effect of miscibility on the viscosity and relative permeability. First, a relative permeability model and a viscosity model with consideration of miscibility are used to describe the variations of relative permeability and viscosity of oil and gas. Then, based on the fractional-flow theory, the Buckley-Leverett equation for gas flooding with constantpressure boundary including… Show more
“…Hardly any dependence on n s was observed. The results follow an almost linear trend which is typical for fluids with low interfacial tension [53]. Moreover, as both fluids have identical properties (cf.…”
A new homogenization approach for the simulation of multi-phase flows in heterogeneous porous media is presented. It is based on the lattice Boltzmann method and combines the grayscale with the multi-component Shan-Chen method. Thus, it mimics fluid-fluid and solid-fluid interactions also within pores that are smaller than the numerical discretization. The model is successfully tested for a broad variety of single-and two-phase flow problems. Additionally, its application to multi-scale and multi-phase flow problems in porous media is demonstrated using the electrolyte filling process of realistic 3D lithium-ion battery electrode microstructures as an example. The new method shows advantages over comparable methods from literature. The interfacial tension and wetting conditions are independent and not affected by the homogenization. Moreover, all physical properties studied here are continuous even across interfaces of porous media. The method is consistent with the original multi-component Shan-Chen method. It is accurate, efficient, easy to implement, and can be applied to many research fields, especially where multi-phase fluid flow occurs in heterogeneous and multi-scale porous media.
“…Hardly any dependence on n s was observed. The results follow an almost linear trend which is typical for fluids with low interfacial tension [53]. Moreover, as both fluids have identical properties (cf.…”
A new homogenization approach for the simulation of multi-phase flows in heterogeneous porous media is presented. It is based on the lattice Boltzmann method and combines the grayscale with the multi-component Shan-Chen method. Thus, it mimics fluid-fluid and solid-fluid interactions also within pores that are smaller than the numerical discretization. The model is successfully tested for a broad variety of single-and two-phase flow problems. Additionally, its application to multi-scale and multi-phase flow problems in porous media is demonstrated using the electrolyte filling process of realistic 3D lithium-ion battery electrode microstructures as an example. The new method shows advantages over comparable methods from literature. The interfacial tension and wetting conditions are independent and not affected by the homogenization. Moreover, all physical properties studied here are continuous even across interfaces of porous media. The method is consistent with the original multi-component Shan-Chen method. It is accurate, efficient, easy to implement, and can be applied to many research fields, especially where multi-phase fluid flow occurs in heterogeneous and multi-scale porous media.
“… Comparison of simulated value of fractional flow at gas viscosity of 0.035 mPa s three injection pressures of 30, 22, and 14 MPa with the results of Mu et al 43 . …”
Section: Resultsmentioning
confidence: 89%
“… Figure 2 Comparison of the simulated value solution gas-oil ratio, oil formation volume factor, oil density, and relative gas and oil permeability. Figure 3 Comparison of simulated value of fractional flow at gas viscosity of 0.035 mPa s three injection pressures of 30, 22, and 14 MPa with the results of Mu et al 43 . …”
Gas injection is one of the most common enhanced oil recovery techniques in oil reservoirs. In this regard, pure gas, such as carbon dioxide (CO2), nitrogen (N2), and methane (CH4) was employed in EOR process. The performance of pure gases in EOR have been investigated numerically, but till now, numerical simulation of injection of rich gases has been scared. As rich gases are more economical and can result in acceptable oil recovery, numerical study of the performance of rich gases in EOR can be an interesting subject. Accordingly, in the present work the performance of rich gases in the gas injection process was investigated. Methane has been riched in liquefied petroleum gas (LPG), natural gas liquid (NGL), and Naphtha. Afterwards, the process of gas injection was simulated and the effect of injection fluids on the relative permeability, saturation profile of gas, and fractional flow of gas was studied. Our results showed that as naphtha is a heavier gas than the two other ones, IFT of oil-rich gas with naphtha is lower than other two systems. Based our results, gas oil ratio (GOR) and injection pressure did not affect the final performance of injection gas that has been riched in NGL and LPG. However, when GOR was 1.25 MSCF/STB, rich gas with naphtha moved with a higher speed in the domain and the relative permeability of each fluid and fractional flow of gas were affected. The same result was achieved at higher injection pressure. When injection pressure was 2000 psi, movement of gas with higher speed in the domain, alteration of relative permeability and changes in the fractional flow of gas were obvious. Therefore, based on our result, injection of naphtha with low pressure and high GOR was suggested for considered oil.
“…The software also significantly eases the definition of physical models at the frontend and the solving of data at the backend. This comparison method has been implemented in numerous publications, − ,, although such comparisons focus on differences in solution methods rather than physical contrasts; it is, however, an effective way to verify the results. Figure presents the gas saturation profiles during 365 days of the CO 2 injection.…”
Dry-out and salt precipitation (DSP) around the wellbore are potential operational challenges during CO 2 sequestration in saline aquifers. We present an extended Forchheimer−Darcy model for evaluating the impact of high-rate CO 2 storage on the DSP effects close to wellbores in saline aquifers, considering the high-velocity non-Darcy (or Forchheimer) flow, the mutual solubilities of formation fluids, and water evaporation and salt precipitation. We explored the governing parameters�Pećlet number, which determines the contributions of the evaporation regime and advection regime to flow-through drying and salt precipitation, as well as the criteria for transitioning to Forchheimer flow. Sensitivity analyses are also conducted on the critical parameters of the CO 2 -brine displacement and salt saturation to better understand their impact. Results indicate that using Darcy's law to model fluid dynamics and salt deposition for high-velocity gaseous flows leads to inaccuracies. Specifically, it yields imprecise estimations of gas saturation evolution, range, and degree of the DSP effects near the wellbore. The inertial effect is prominent at a high CO 2 injection rate, which leads to a more uniform displacement and results in a moderate decrease in salt saturation by slowing down gas flow. Formations with better petrophysical properties and fluid flow capacity have a larger range of dry-out region without considering the capillary backflow mechanism, where the salt plugging problem may not be severe. Additionally, higher injection rates and a thinner layer thickness moderately reduce salt saturation but significantly increases the extent of the DSP area, which is a more critical aspect of this physical phenomenon. We compared all computational results with Pruess's benchmark Darcy flow model. Moreover, we verified the saturation profiles, especially under non-Darcy flow conditions, displaying excellent agreement between analytical and numerical solutions. Findings of this research provide new insights for future studies on the fluid behavior in formations with similar geological settings, as well as the impact of DSP effects on aquifer injectivity and injection safety.
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