Browsing by Subject "Porous Media"

Now showing 1 - 2 of 2

Pore-scale modeling of the impact of surrounding flow behavior on multiphase flow properties
(2009-08) Petersen, Robert Thomas; Balhoff, Matthew T.; Bryant, Steven L.
Accurate predictions of macroscopic multiphase flow properties, such as relative permeability and capillary pressure, are necessary for making key decisions in reservoir engineering. These properties are usually measured experimentally, but pore-scale network modeling has become an efficient alternative for understanding fundamental flow behavior and prediction of macroscopic properties. In many cases network modeling gives excellent agreement with experiment by using models physically representative of real media. Void space within a rock sample can be extracted from high resolution images and converted to a topologically equivalent network of pores and throats. Multiphase fluid transport is then modeled by imposing mass conservation at each pore and implementing the Young-Laplace equation in pore throats; the resulting pressure field and phase distributions are used to extract macroscopic properties. Advancements continue to be made in making network modeling predictive, but one limitation is that artificial (e.g. constant pressure gradient) boundary conditions are usually assumed; they do not reflect the local saturations and pressure distributions that are affected by flow and transport in the surrounding media. In this work we demonstrate that flow behavior at the pore scale, and therefore macroscopic properties, is directly affected by the boundary conditions. Pore-scale drainage is modeled here by direct coupling to other pore-scale models so that the boundary conditions reflect flow behavior in the surrounding media. Saturation couples are used as the mathematical tool to ensure continuity of saturations between adjacent models. Network simulations obtained using the accurate, coupled boundary conditions are compared to traditional approach and the resulting macroscopic petrophysical properties are shown to be largely dependent upon the specified boundary conditions. The predictive ability of network simulations is improved using the novel network coupling scheme. Our results give important insight into upscaling as well as approaches for including pore-scale models directly into reservoir simulators.
A Study of Transport of Micellar Fluids in Porous Media
(1986-05) Delshad, Mojdeh; Lake, Larry W.; Pope, Gary A.
Two- and three-phase relative permeabilities have been measured for a low interfacial tension brineoil- surfactant-alcohol mixture in a Berea sandstone core. The measurements were done at steady-state with a constant nominal capillary number of 10^-2. Residual phase saturation (capillary desaturation curve) and endpoint relative permeability have also been measured for three-phase micellar fluids as a function of capillary number in a Berea core. Continuous and slug displacements of both partitioning and non-partitioning radioactive tracers were run for each steady-state experiment. The experimental effluent tracer data from these experiments were analyzed by a capacitance model. The phase dispersivities and dispersion coefficients estimated from the capacitance analysis as a function of phase saturation and velocity are illustrated. Both excess phases (oil and brine) flowing with the microemulsion showed significant capacitance effects, but the microemulsion did not. The absence of capacitance and higher residual saturation than those of excess phases at the same capillary number indicate that the microemulsion was probably the wetting phase in these low interfacial tension flows, even more wetting than the excess brine phase. The relative permeability of each phase is a function only of its own saturation during three-phase flow. Based on this observation and the trend of experimental data, an exponential function is recommended to model three-phase relative permeability at high capillary number.