Wenhui Song

Numerical Simulation of Multiphase Flow in Nanoporous Organic Matter With Application to Coal and Gas Shale Systems: MULTIPHASE FLOW IN NANOORGANIC MATTER

Fluid flow in nanoscale organic pores is known to be affected by fluid transport mechanisms and properties within confined pore space. The flow of gas and water shows notably different characteristics compared with conventional continuum modeling approach. A pore network flow model is developed and implemented in this work. A 3-D organic pore network model is constructed from 3-D image that is reconstructed from 2-D shale SEM image of organic-rich sample. The 3-D pore network model is assumed to be gas-wet and to contain initially gas-filled pores only, and the flow model is concerned with drainage process. Gas flow considers a full range of gas transport mechanisms, including viscous flow, Knudsen diffusion, surface diffusion, ad/desorption, and gas PVT and viscosity using a modified van der Waals’ EoS and a correlation for natural gas, respectively. The influences of slip length, contact angle, and gas adsorption layer on water flow are considered. Surface tension considers the pore size and temperature effects. Invasion percolation is applied to calculate gas-water relative permeability. The results indicate that the influences of pore pressure and temperature on water phase relative permeabilities are negligible while gas phase relative permeabilities are relatively larger in higher temperatures and lower pore pressures. Gas phase relative permeability increases while water phase relative permeability decreases with the shrinkage of pore size. This can be attributed to the fact that gas adsorption layer decreases the effective flow area of the water phase and surface diffusion capacity for adsorbed gas is enhanced in small pore size.

A general method for simulating reactive dissolution in carbonate rocks with arbitrary geometry

The two-scale continuum model is widely used in simulating the reactive dissolution process and predicting the optimum injection rate for carbonate reservoir acidizing treatment. The numerical methods of this model are currently based on structured grids, which are not applicable for complicated geometries. In this study, a general numerical scheme for simulating a reactive flow problem on both structured and unstructured grids is presented based on the finite volume method (FVM). The convection and diffusion terms involved in the reactive flow model are discretized by using the upwind scheme and two-point flux approximation (TPFA), respectively. The location of the centroid node inside each control volume is moved by using an optimization algorithm to make the connections with the surrounding elements as orthogonal as possible, which systematically improves the accuracy of the TPFA scheme. Additionally, in order to avoid the computational complexity resulting from the discretization of the non-linear term, the mass balance equation is only discretized in the spatial domain to get a set of ordinary differential equations (ODEs). These ODEs are coupled with the reaction equations and then solved using the numerical algorithm on ODEs. The accuracy and efficiency of the proposed method are studied by comparing the results obtained from the proposed numerical method with previous experimental and numerical results. This comparison indicates that, compared with the previous methods, the proposed method predicts the wormhole structure more accurately. Finally, the presented method is used to check the effect of the domain geometry, and it is found that the geometry of the flow domain has no effect on the optimum injection velocity, but the radial domain requires a larger breakthrough volume than the linear domain when other parameters are fixed.

Gas flow regimes judgement in nanoporous media by digital core analysis

Abstract A method to judge shale gas flow regimes based on digital core analysis is proposed in this work. Firstly, three-dimensional shale digital cores in an anonymous shale formation in the Sichuan Basin are reconstructed by a Markov Chain Monte Carlo (MCMC) algorithm based on two-dimensional Scanning Electron Microscope (SEM) images. Then a voxel-based method is proposed to calculate the characteristic length of the three-dimensional shale digital core. The Knudsen number for three-dimensional shale digital cores is calculated by the ratio of the molecular mean free path to the characteristic length and is used to judge the flow regimes under different reservoir conditions. The results indicate that shale gas flow regimes are mainly located at the slip flow and transition flow region. Furthermore, adsorption has no obvious influence on the free gas flow regimes. Because adsorption only exists in organic pores, three-dimensional inorganic pores and organic pores in the Haynesville shale formation are reconstructed by a MCMC algorithm based on two-dimensional SEM images. The characteristic lengths of the three-dimensional inorganic pores and three-dimensional organic pores are both calculated and gas flow regimes in organic pores and inorganic pores are judged.