Reservoir simulation models are used by oil and gas companies in the development of new fields. Also, models are used in developed fields where production forecasts are needed to help make investment decisions. As building and maintaining a robust, reliable model of a field is often time-consuming and expensive, models are typically only constructed where large investment decisions are at stake. Improvements in simulation software have lowered the time to develop a model. Also, models can be run on personal computers rather than more expensive workstations.
For new fields, models may help development by identifying the number of wells required, the optimal completion of wells, the present and future needs for artificial lift, and the expected production of oil, water and gas.
For ongoing reservoir management, models may help in improved oil recovery by hydraulic fracturing. Highly deviated or horizontal wells can also be represented. Specialized software may be used in the design of hydraulic fracturing, then the improvements in productivity can be included in the field model. Also, future improvement in oil recovery with pressure maintenance by re-injection of produced gas or by water injection into an aquifer can be evaluated. Water flooding resulting in the improved displacement of oil is commonly evaluated using reservoir simulation.
The application of enhanced oil recovery (EOR) processes requires that the field possesses the necessary characteristics to make application successful. Model studies can assist in this evaluation. EOR processes include miscible displacement by natural gas, CO2, or nitrogen and chemical flooding (polymer, alkaline, surfactant, or a combination of these). Special features in simulation software is needed to represent these processes. In some miscible applications, the "smearing" of the flood front, also called numerical dispersion, may be a problem.
Reservoir simulation is used extensively to identify opportunities to increase oil production in heavy oil deposits. Oil recovery is improved by lowering the oil viscosity by injecting steam or hot water. Typical processes are steam soaks (steam is injected, then oil produced from the same well) and steam flooding (separate steam injectors and oil producers). These processes require simulators with special features to account for heat transfer to the fluids present and the formation, the subsequent property changes and heat losses outside of the formation.
A recent application of reservoir simulation is the modeling of coalbed methane (CBM) production. This application requires a specialized CBM simulator. In addition to the normal fractured (fissured) formation data, CBM simulation requires gas content data values at initial pressure, sorption isotherms, diffusion coefficient, and parameters to estimate the changes in absolute permeability as a function of pore-pressure depletion and gas desorption.
Representation of an underground fault by a structure map generated by Contour map software for an 8500ft deep gas & Oil reservoir in the Erath field, Vermilion Parish, Erath, Louisiana. The left-to-right gap, near the top of the contour map indicates a Fault line. This fault line is between the blue/green contour lines and the purple/red/yellow contour lines. The thin red circular contour line in the middle of the map indicates the top of the oil reservoir. Because gas floats above oil, the thin red contour line marks the gas/oil contact zone.
Traditional finite difference simulators dominate both theoretical and practical work in reservoir simulation. Conventional FD simulation is underpinned by three physical concepts: conservation of mass, isothermal fluid phase behavior, and the Darcy approximation of fluid flow through porous media. Thermal simulators (most commonly used for heavy crude oil applications) add conservation of energy to this list, allowing temperatures to change within the reservoir.
Numerical techniques and approaches that are common in modern simulators:
Most modern FD simulation programs allow for construction of 3-D representations for use in either full-field or single-well models. 2-D approximations are also used in various conceptual models, such as cross-sections and 2-D radial grid models.
Theoretically, finite difference models permit discretization of the reservoir using both structured and more complex unstructured grids to accurately represent the geometry of the reservoir. Local grid refinements (a finer grid embedded inside of a coarse grid) are also a feature provided by many simulators to more accurately represent the near wellbore multi-phase flow effects. This "refined meshing" near wellbores is extremely important when analyzing issues such as water and gas coning in reservoirs. Other types of simulators include finite element and streamline.
Representation of faults and their transmissibilities are advanced features provided in many simulators. In these models, inter-cell flow transmissibilities must be computed for non-adjacent layers outside of conventional neighbor-to-neighbor connections.
Natural fracture simulation (known as dual-porosity and dual-permeability) is an advanced feature which model hydrocarbons in tight matrix blocks. Flow occurs from the tight matrix blocks to the more permeable fracture networks that surround the blocks, and to the wells.
A black oil simulator does not consider changes in composition of the hydrocarbons as the field is produced, beyond the solution or evolution of dissolved gas in oil, or vaporisation or dropout of condensate from gas.
A compositional reservoir simulator calculates the PVT properties of oil and gas phases once they have been fitted to an equation of state (EOS), as a mixture of components. The simulator then uses the fitted EOS equation to dynamically track the movement of both phases and components in field. This is accomplished at increased cost in setup time, compute time, and computer memory.
Correlating relative permeability
The simulation model computes the saturation change of three phases (oil, water and gas)and pressure of each phase in each cell at each time step. As a result of declining pressure as in a reservoir depletion study, gas will be liberated from the oil. If pressures increase as a result of water or gas injection, the gas is re-dissolved into the oil phase.
A simulation project of a developed field, usually requires "history matching" where historical field production and pressures are compared to calculated values. It was realised at an early stage that this was essentially an optimisation process, corresponding to Maximum Likelihood. As such, it can be automated, and there are multiple commercial and software packages designed to accomplish just that. The model's parameters are adjusted until a reasonable match is achieved on a field basis and usually for all wells. Commonly, producing water cuts or water-oil ratios and gas-oil ratios are matched.
Without FD models, recovery estimates and oil rates can also be calculated using numerous analytical techniques which include material balance equations (including Havlena-Odeh and Tarner method), fractional flow curve methods (such as the Buckley-Leverett one-dimensional displacement method, the Deitz method for inclined structures, or coning models), and sweep efficiency estimation techniques for water floods and decline curve analysis. These methods were developed and used prior to traditional or "conventional" simulations tools as computationally inexpensive models based on simple homogeneous reservoir description. Analytical methods generally cannot capture all the details of the given reservoir or process, but are typically numerically fast and at times, sufficiently reliable. In modern reservoir engineering, they are generally used as screening or preliminary evaluation tools. Analytical methods are especially suitable for potential assets evaluation when the data are limited and the time is critical, or for broad studies as a pre-screening tool if a large number of processes and / or technologies are to be evaluated. The analytical methods are often developed and promoted in the academia or in-house, however commercial packages also exist.
Many programs are available for reservoir simulation. The most well known (in alphabetical order) are:
BOAST - Black Oil Applied Simulation Tool (Boast) simulator is a free software package for reservoir simulation available from the U.S. Department of Energy. Boast is an IMPES numerical simulator (finite-difference implicit pressure-explicit saturation) which finds the pressure distribution for a given time step first then calculates the saturation distribution for the same time step isothermal. The last release was in 1986 but it remains as a good simulator for educational purposes.
MRST - The MATLAB Reservoir Simulation Toolbox (MRST) is developed by SINTEF Applied Matemathics as a MATLAB® toolbox. The toolbox consists of two main parts: a core offering basic functionality and single and two-phase solvers, and a set of add-on modules offering more advanced models, viewers and solvers. MRST is mainly intended as a toolbox for rapid prototyping and demonstration of new simulation methods and modeling concepts on unstructured grids. Despite this, many of the tools are quite efficient and can be applied to surprisingly large and complex models.
OPM - The Open Porous Media (OPM) initiative provides a set of open-source tools centered on the simulation of flow and transport of fluids in porous media.
Schlumberger INTERSECT - The high-resolution reservoir simulator that goes beyond the capabilities offered by current-generation simulators. The result is improved accuracy and efficiency in field development planning and risk mitigation — even for the most complex fields. 
Schlumberger ECLIPSE - ECLIPSE The industry-reference reservoir simulator originally developed by ECL (Exploration Consultants Limited) and currently owned, developed, marketed and maintained by SIS (formerly known as GeoQuest), a division of Schlumberger. The name ECLIPSE originally was an acronym for "ECL´s Implicit Program for Simulation Engineering". Simulators include black oil, compositional, thermal finite-volume, and streamline simulation. Add-on options include local grid refinements, coalbed methane, gas field operations, advanced wells, reservoir coupling, and surface networks. 
CMG Suite (IMEX, GEM and STARS) - Computer Modelling Group currently offers three simulators: a black oil simulator, called IMEX, a compositional / unconventional simulator called GEM and a thermal and advanced processes simulator called STARS.
Tempest MORE is a modern, next generation reservoir simulator, offering black oil, compositional and thermal options. 
ExcSim, a fully implicit 3-phase 2D modified black oil reservoir simulator for the Microsoft Excel® platform 
Landmark Nexus - Nexus is an oil and gas reservoir simulator originally developed as 'Falcon' by Amoco, Los Alamos National Laboratory and Cray Research. It is currently owned, developed, marketed and maintained by Landmark Graphics, a product service line of Halliburton. Nexus will gradually replace VIP, or Desktop VIP, Landmark's earlier generation of simulator.
Stochastic Simulation ResAssure - ResAssure is a stochastic simulation software solution, powered by a robust and extremely fast reservoir simulator.
Rock Flow Dynamics tNavigator supports black oil, compositional and thermal compositional simulations for workstations and High Performance Computing clusters 
Plano Research Corporation FlowSim is a fully implicit 3-phase, 3-D, black oil and compositional finite difference reservoir simulator with LGRs, dual porosity dual permeability, and parallel capabilities.
GrailQuest's ReservoirGrail employs a unique patented approach called Time Dynamic Volumetric Balancing  to simulate reservoirs during primary and secondary recovery.