Reservoirsimulation

Reservoir simulation is the numerical modeling of multiphase fluid flow through porous rock in an oil and gas reservoir to forecast production performance under different development strategies. The goal is to quantify pressure, saturation, and sometimes composition fields over time, given reservoir properties, PVT data, boundary conditions, and production controls.

Governing equations describe mass conservation for each fluid phase and are coupled through Darcy’s law, relative permeability, and capillary pressure. In a typical model, the dependent variables include pressure and phase saturations, with compositions for compositional simulations. The resulting system is nonlinear and solved iteratively, often with Newton-type methods.

Numerical methods used in reservoir simulation include finite-difference, finite-volume, and finite-element discretizations on structured or unstructured grids. Time stepping is usually implicit to maintain stability for stiff, nonlinear problems. Well models integrate with the grid to represent injections and productions, using well indices and constraints such as bottom-hole pressures or production rates.

Model types range from black-oil, which uses simplified fluid behavior, to compositional models that track multiple components and phase behavior. Dual-porosity or dual-permeability formulations are used to represent fractured or dual-structure reservoirs, enabling more accurate flow between fractures and surrounding matrix.

Applications encompass production forecasting, history matching to reproduce past production data, optimization of development plans, and uncertainty analysis to assess risks and alternatives. The field has evolved from early, small-scale black-oil experiments in the 1960s to modern, large-scale, parallel simulations that handle complex geology and fluid behavior. Commercial simulators such as Eclipse and CMG are widely used, alongside research tools and open-source frameworks.