# Browsing by Subject "Fractional flow theory"

Now showing 1 - 3 of 3

- Results Per Page
1 5 10 20 40 60 80 100

- Sort Options
Ascending Descending

Item Displacement theory and numerical simulation of hybrid gas/chemical EOR processes(2021-05-11) Mehrabi, Mehran; Sepehrnoori, Kamy, 1951-; Delshad, Mojdeh; Johnston, Keith P; Okuno, Ryosuke; Farajzadeh, RouhiShow more Hybrid gas/chemical enhanced oil recovery (EOR) techniques comprises gas and chemicals such as surfactant to improve oil recovery by improvement in displacement and/or sweep efficiencies. Design and modeling of these processes are challenging due to the inherent complexities of phenomena that may occur simultaneously. For example, in low-tension gas (LTG) flooding we inject gas and water with at least two types of surfactants, one as a foaming agent and another as a low-IFT agent. In this process, we may have the simultaneous flow of the four phases of water, oil, gas, and microemulsion. The gas phase may flow partly as foam and partly as free gas. Proper modeling of the foam flow, the phase behavior between the oil and gas, the phase behavior between the water, oil, and microemulsion and the interaction between different phases and their rheology and petrophysical properties are among the challenges of understanding and modeling this process. In this study we develop models, techniques and reservoir simulation codes to investigate different aspects of hybrid gas/chemical EOR processes. In this regard, we study the following subjects: 1) estimation of the parameters of foam models and the effect of porosity and permeability on the apparent viscosity of foam in porous media, 2) development of an algorithm for finding classical solutions to Riemann problems of three-phase flow of gas/foam, water, and oil, 3) development of a displacement theory for LTG flooding, and 4) development and implementation of a chemical-compositional model in an implicit pressure explicit concentration (IMPEC) reservoir simulator. The developed models and simulation codes can help engineers and practitioners with both the design and large scale simulation of hybrid gas/chemical processes.Show more Item Experimental studies on CO2-brine-decane relative permeabilities in Berea sandstone with new steady-state and unsteady-state methods(2016-12) Chen, Xiongyu; DiCarlo, David Anthony, 1969-; Pope, Gary A; Mohanty, Kishore K; Prodanovic, Masa; Deinert, Mark RShow more CO2 relative permeability is the key parameter in modeling CO2 geological storage and CO2 enhanced oil recovery. However, the literature CO2 relative permeability data are often inconsistent and smaller than the actual values. This is because the traditional methods only obtain the global values of the three key parameters in relative permeability determinations: pressure drop, saturation and phase flux. These global values are often different from the local values due to capillary effects. This work develops new steady-state and unsteady-state methods to determine relative permeabilities. The new methods obtain the local values of the three key parameters, hence they have the advantage of experimentally avoiding capillary effects, which is crucial for gas and supercritical phase, such as CO2. The new methods give more accurate relative permeability data that are up to 50% higher than the traditional methods. This work uses the new methods to determine two-phase relative permeabilities for CO2-brine in Berea sandstone at different conditions (20-60 °C and 8-12 MPa). Within the scatter of data obtained here, the two-phase CO2 relative permeability data at different temperature and pressure conditions are similar. To ultimately resolve whether two-phase CO2 relative permeability depends on temperature and pressure, experimental relative permeability data with less scatter are needed in future. This work also obtains three-phase CO2 and decane relative permeabilities at 70 °C and 8 MPa when water is immobile. The key findings are: (1) the three-phase relative permeability of CO2 is higher than that of decane by one order of magnitude, which is consistent with CO2 being more non-wetting than decane in water-wet rocks; and (2) the three-phase CO2 relative permeability is lower than the two-phase CO2 relative permeability by another order of magnitude, which is consistent with CO2 becoming less non-wetting and getting similar to decane at high pressure. Thus when modeling water-oil-CO2 three-phase flows, the CO2 relative permeability curve can vary significantly with temperature and pressure since thermodynamics affects wettability and interfacial tension.Show more Item Modeling the fluid flow of carbon dioxide through permeable media(2012-05) Ghanbarnezhad Moghanloo, Rouzbeh; Lake, Larry W.; Sepehrnoori, Kamy; Bryant, Steven L.; DiCarlo, David; Johns, Russell T.Show more This dissertation presents analytical solutions to address several unresolved issues on the modeling of CO₂ flow in permeable media. Analytical solutions are important as numerical simulations do not yield explicit expressions in terms of the model parameters. In addition, simulations that provide the most comprehensive solutions to multiphase flow problems are computationally intensive. Accordingly, we address the following topics in this dissertation. The method of characteristics (MOC) solution of the overall mass conservation equation of CO₂ in two-phase flow through permeable media is derived in the presence of compressibility. The formally developed MOC solutions rely on the incompressible fluid and rock assumptions that are rarely met in practice; hence, the incompressible assumption is relaxed and the first semi-analytic MOC solution for compressible flow is derived. The analytical solution is verified by simulation results. Fractional flow theory is applied to evaluate the CO2 storage capacity of one-dimensional (1D) saline aquifers. Lack of an accurate estimation of the CO₂ storage capacity stands in the way of the fully implementation of CO₂ storage in aquifers. The notion of optimal solvent-water-slug size is incorporated into the graphical solution of combined geochemical front propagation and fractional flow theory to determine the CO₂ storage capacity of aquifers. The analytical solution is verified by simulation results. The limits of the Walsh and Lake (WL) method to predict the performance of CO₂ injection is examined when miscibility is not achieved. The idea of an analogous first-contact miscible flood is implemented into the WL method to study miscibly-degraded simultaneous water and gas (SWAG) displacements. The simulation verifies the WL solutions. For the two-dimensional (2D) displacements, the predicted optimal SWAG ratio is accurate when the permeable medium is fairly homogeneous with a small cross-flow or heterogeneous with a large lateral correlation length (the same size or greater than the interwell spacing). We conclude that the WL solution is accurate when the mixing zone grows linearly with time. We examine decoupling of large and small-scale heterogeneity in multilayered reservoirs. In addition, using an analytical solution derived in this research, the fraction of layers in which the channeling occurs is determined as a function of the Koval factor and input dispersivity. We successfully present a simulation configuration to verify the off-diagonal elements of the numerical dispersion tensor. Numerical dispersion is inevitably introduced into the finite difference approximations of the 2D convection-dispersion equation. We show that the off-diagonal elements of the numerical dispersion tensor double when the flow velocity changes with distance. In addition, the simulation results reveal that the flow becomes more dispersive with distance travelled if there is convective cross-flow. In addition, local mixing increases with the convective cross-flow between layers. A numerical indicator is presented to describe the nature of CO₂ miscible displacements in heterogeneous permeable media. Hence, the quantitative distinction between flow patterns becomes possible despite the traditionally qualitative approach. The correlation coefficient function is adopted to assign numerical values to flow patterns. The simulation results confirm the accuracy of the descriptive flow pattern values. The order-of-one scaling analysis procedure is implemented to provide a unique set of dimensionless scaling groups of 2D SWAG displacements. The order-of-one scaling analysis is a strong mathematical approach to determine approximations that are allowed for a particular transport phenomenon. For the first time, we implement the scaling analysis of miscible displacements while considering effects of water salinity, dissolution of CO₂ in the aqueous phase, and complex configurations of injection and production wells.Show more