Lisitsa, Vadim (Institute of Petroleum Geology and Geophysics SB RAS) | Khachkova, Tatyana (Institute of Petroleum Geology and Geophysics SB RAS) | Kolyukhin, Dmitry (Institute of Petroleum Geology and Geophysics SB RAS) | Gurevich, Boris (Curtin University) | Lebedev, Maxim (Curtin University) | Reshetova, Galina (Institute of Computational Mathematics and Mathematical Geophysics SB RAS) | Tcheverda, Vladimir (Institute of Geophysics)
Typically the resolution of micro-CT scans of the rock samples and the physical size of the studied volume are linearly connected; i.e. improvement in the resolution requires the sample size reduction. In this paper we consider four images of the Bentheimer outcrop sandstone sample acquired with different resolution to determine the effect of the image scale on the geometrical, topological, and transport properties of the digital core sample. To overcome the strict restriction on the sample size and to approach the representative volumes we suggest using statistical modelling of the images using truncated Gaussian simulation method. This approach preserves total porosity of the sample and reciprocal pore-to-core distribution, however it does not preserve advanced geometrical and topological properties of the pore space such as Minkowski functionals values and Betti numbers of the pore spaces. Nevertheless, permeability and tortuosity of the original images are well matched by synthetic images.
Presentation Date: Monday, October 17, 2016
Start Time: 3:45:00 PM
Presentation Type: ORAL
Li, Jun (Center for Integrative Petroleum Research, King Fahd University of Petroleum & Minerals) | Sultan, Abdullah S. (Center for Integrative Petroleum Research & Department of Petroleum Engineering, King Fahd University of Petroleum & Minerals)
The permeability variation of shale gas with pressure is an important input data in the predictions of well performance for optimizing production. We present a novel pore-scale simulation scheme to accurately compute the permeabilities at different pressure conditions by using the Fortran parallel software
Yuan, Yudong (School of Petroleum Engineering, University of New South Wales) | Rahman, Sheik (School of Petroleum Engineering, University of New South Wales) | Wang, Junjian (School of Petroleum Engineering, University of New South Wales) | Doonechaly, Nima Gholizadeh (School of Petroleum Engineering, University of New South Wales)
Characterization of flow processes in multi-scale porous system (nanopores to mesopores) in tight rocks, such as the shales, is challenging because of the coexistence of various flow regimes in the porous media. Although some methods based on dusty gas model (DGM) have been applied to determine the apparent gas permeability of shales (
Sakurai, Keisuke (Tohoku University) | Watanabe, Noriaki (Tohoku University) | Ishibashi, Takuya (Tohoku University) | Tsuchiya, Noriyoshi (Tohoku University) | Ohsaki, Yutaka (JAPEX) | Tamagawa, Tetsuya (JAPEX) | Yagi, Masahiko (JAPEX)
Two-phase flows through fractures in subsurface rocks are of great importance in several domains. Despite this importance few studies have been conducted, and the results presented in the literature seem to be contradictory. So far, two-phase fracture flows are not well understood. In our recent study, it was indicated that relative permeability curves for fractures in rocks under confining pressure may different from the X model, the viscous coupling model, and even the Corey model, due to strong interference between phases by capillarity in the 2-D flow field. However, it was difficult to make a concrete conclusion due to the limited results. In the present study, oil (n-decane)-water relative permeability curves of fractures having different intrinsic permeabilities (i.e., aperture distributions) in granite and limestone under confining pressure has been investigated. First of all, no significant difference was found between fractures in the present granite and limestone. In case of the fracture having the highest intrinsic permeability (4 × 10-10 m2), there was no significant influence of capillarity due to bigger apertures, resulting in X-type relative permeability curves. On the other hand, in case of the fractures having lower intrinsic permeabilities (1 × 10-11 m2 and 4 × 10-11 m2), there was significant influence between phases by capillarity due to smaller apertures, resulting in the Corey-type and V-type (named in the present study) relative permeability curves depending on intrinsic permeability. The V-type relative permeability curves with the strongest interference between phases were found at the smallest intrinsic permeability. It has been revealed that there are three types of relative permeability curves for subsurface fractures depending on their intrinsic permeabilities (i.e., aperture distributions).
Negara, Ardiansyah (King Abdullah University of Science and Technology) | Salama, Amgad (King Abdullah University of Science and Technology) | Sun, Shuyu (King Abdullah University of Science and Technology)
Anisotropy of hydraulic properties of subsurface geologic formations is an essential feature that has been established as a consequence of the different geologic processes that they undergo during the longer geologic time scale. With respect to petroleum reservoirs, in many cases, anisotropy plays significant role in dictating the direction of flow that becomes no longer dependent only on the pressure gradient direction but also on the principal directions of anisotropy. Furthermore, in complex systems involving the flow of multiphase fluids in which the gravity and the capillarity play an important role, anisotropy can also have important influences.
Therefore, there has been great deal of motivation to consider anisotropy when solving the governing conservation laws numerically. Unfortunately, the two-point flux approximation of finite difference approach is not capable of handling full tensor permeability fields. Lately, however, it has been possible to adapt the multipoint flux approximation that can handle anisotropy to the framework of finite difference schemes. In multipoint flux approximation method, the stencil of approximation is more involved, i.e., it requires the involvement of 9-point stencil for the 2-D model and 27-point stencil for the 3-D model. This is apparently challenging and cumbersome when making the global system of equations.
In this work, we apply the equation-type approach, which is the experimenting pressure field approach that enables the solution of the global problem breaks into the solution of multitude of local problems that significantly reduce the complexity without affecting the accuracy of numerical solution. This approach also leads in reducing the computational cost during the simulation.
We have applied this technique to a variety of anisotropy scenarios of 3-D subsurface flow problems and the numerical results demonstrate that the experimenting pressure field technique fits very well with the multipoint flux approximation method. Furthermore, the numerical results explicitly emphasize that anisotropy could not be ignored for the proper model of subsurface flow.
In this paper, a transient incompressible viscous fluid flow is considered, and the ALE (Arbitrary Lagrangian-Eulerian) moving mesh method is applied to simulate the wave generation due to body motion near the free surface. The algorithm consists of three stages in each time step: a) the incompressible Navier-Stokes equations in the ALE frame are solved by finite element method (FEM) over the whole domain, while wave absorption being considered as well; b) the fluid velocities are used for updating the positions of the free surface nodes; c) the interior nodes are moved by solving a pseudo elastic problem so as to minimize mesh distortion. With the numerical method described above, free surface flows around 2D NACA0012 hydrofoil under different Froude numbers, submerged depths and attack angles are systematically investigated, respectively.
El-Amin, M.F. (King Abdullah University of Science and Technology) | Sun, Shuyu (King Abdullah University of Science and Technology) | Salama, Amgad (King Abdullah University of Science and Technology)
Geological storage of anthropogenic CO2 emissions in deep saline aquifers has recently received tremendous attention in the scientific literature. Injected CO2 plume buoyantly accumulates at the top part of the deep aquifer under a sealing cap rock, and some concern that the high-pressure CO2 could breach the seal rock. However, CO2 will diffuse into the brine underneath and generate a slightly denser fluid that may induce instability and convective mixing. Onset times of instability and convective mixing performance depend on the physical properties of the rock and fluids, such as permeability and density contrast. The novel idea is to adding nanoparticles to the injected CO2 to increase density contrast between the CO2-rich brine and the underlying resident brine and, consequently, decrease onset time of instability and increase convective mixing.
As far as it goes, only few works address the issues related to mathematical and numerical modeling aspects of the nanoparticles transport phenomena in CO2 storages. In the current work, we will present mathematical models to describe the nanoparticles transport carried by injected CO2 in porous media. Buoyancy and capillary forces as well as Brownian diffusion are important to be considered in the model. IMplicit Pressure Explicit Saturation-Concentration (IMPESC) scheme is used and a numerical simulator is developed to simulate the nanoparticles transport in CO2 storages.
Kim, F.H. (University of Tennessee) | Penumadu, D. (University of Tennessee) | Gregor, J. (University of Tennessee) | Kardjilov, N. (Helmholtz Center Berlin for Materials and Energy) | Manke, I. (Helmholtz Center Berlin for Materials and Energy) | Schulz, V.P. (Baden-Wuerttemberg Cooperative State University Mannheim) | Wiegmann, A. (Fraunhofer ITWM)
Komai, T. (Research Institute for Geo-resources and Environment) | Sakamoto, Y. (Research Institute for Geo-resources and Environment) | Tanaka, A. (National Institute of Advanced Industrial Science and Technology (AIST))