Pore-scale characterization and modeling of two-phase flow in tight gas sandstones

Unconventional natural gas resources, particularly tight gas sands, constitute a significant percentage of the natural gas resource base and offer abundant potential for future reserves and production. The premise of this research is that several unique characteristics of these rocks are the consequence of post depositional diagenetic processes including mechanical compaction, quartz and other mineral cementation, and mineral dissolution. These processes lead to permanent alteration of the initial pore structure causing an increase in the number of isolated and disconnected pores and thus in the tortuosity. The objective of this research is to develop a pore scale model of the geological processes that create tight gas sandstones and to carry out drainage simulations in these models. These models can be used to understand the flow connections between tight gas sandstone matrix and the hydraulic fractures needed for commercial production rates. We model depositional and diagenetic controls on tight gas sandstones pore geometry such as compaction and cementation processes. The model is purely geometric and begins by applying a cooperative rearrangement algorithm to produce dense, random packings of spheres of different sizes. The spheres are idealized sand grains. We simulate the evolution of these model sediments into low-porosity (3% to 10%) sandstone by applying different amount of ductile grains and quartz precipitation. A substantial fraction of the original pore throats in the sediment are closed by the simulated diagenetic alteration. Thus, the pore space in typical tight gas sandstones is poorly connected, and is often close to being completely disconnected, with significant effect on flow properties. The drainage curves for model rocks were computed using invasion percolation in a network taken directly from the grain-scale geometry and topology of the model. The drainage simulations show clear percolation behavior, but experimental data frequently do not. This implies that either network models based on intergranular void space are not a good tool for modeling of tight gas sandstone or the experiments are not correctly done on tight gas samples. In addition to reducing connectivity, the porosity-reducing mechanisms change pore throat size distributions. These combined effects shift the drainage water relative permeability curve toward higher values of water saturation, and gas relative permeability shifts toward smaller values of gas. Comparison of simulations with measured relative permeabilities shows a good match although same network fail to match drainage curves. This could happens because the model gives the right fluid configuration but at the wrong values of curvature and saturation. The significance of this work is that the model correctly predicts the relative permeabilities of tight gas sandstones by considering the microscale heterogeneity. The porosity reduction due to ductile grain deformation is a new contribution and correctly matches with experimental data from literature. The drainage modeling of two-phase flow relative permeabilities shows that the notion of permeability jail, a range of saturations over which both gas and water relative permeabilities are very small, does not occur during drainage.