Multiphase Flow
Ingrain performs the following multiphase flow computations on vRock digital reservoir rocks:
- Two-phase relative permeability: water-oil, gas-oil, and water-gas displacement at different wettability indices and viscosity values
- Irreducible water saturation and residual oil saturation
- Optional two-phase relative permeability in three axes
Ingrain computes multiphase flow at the pore scale in an accurate digital representation of the pore space. Our algorithms can operate at any desired boundary and saturation condition, as well as varying fluid viscosity and wettability contrasts.
Digital simulation of oil displacing water.
Relative permeability curves in oil sand digitally simulated using the multiphase lattice Boltzmann method.
Ingrain's Lattice Boltzmann methods incorporate several technical breakthroughs.
- Ingrain's computations have been designed and developed specifically for low Reynolds number fluid flow in porous media (not strictly gas dynamics) and incorporate:
- Surface Tensions (wetting/ fluid-surface interactions)
- Interfacial Tensions (fluid-fluid interactions)
- Capillary forces
- Several different Lattice Boltzmann schemes are employed for multiphase fluids:
- Chromodynamic model of Rothman and Keller
- Pseudo-potential model of Shan and Chen
- Free energy model of Swift, Osborne, and Yeomans
- Ingrain simulates the experimental processes used in a physical laboratory to measure fluid transport properties in core samples, allowing us to conduct virtual core laboratory experiments:
- Boundary and general fluid flow conditions mimic traditional experimental core measurements
- Dynamic relative permeability – drainage and imbibition processes
- Capillary pressure
- Accurate modeling of the physics exhibited in single-phase and multi-phase fluid flow, such as viscous fingering and capillary-induced “snap-off” behavior
