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Fluids exist in reservoirs as mixtures of gas, oil, and water.The major goal of reservoir simulation is to predict future performance of the reservoir and find ways and means of optimizing the recovery of some of the hydrocarbons under various operating conditions.This lack of predictive capability by the EOS can be a result of unsatisfactory compositional data or inexact properties for the heptanes-plus fraction (C7+), inadequate binary interaction parameters, incorrect overall composition, or simply that EOS is not a good enough thermodynamic model.A lot of PVT correlations for calculation of bubble point pressure, formation oil volume factor, and solution gas oil ratio of reservoir oils have been offered in the petroleum engineering literature over the last few years.It is worth mentioning that PVT data to be feed into the black-oil or compositional simulator can be obtained from empirical correlations, laboratory measurement, and EOS fluid characterization.Irrespective of the proportions of these fluid present in a reservoir, obtaining fluid samples and studying their phase behavior in a laboratory are necessary for establishing reservoir type, devising strategies for reservoir management, and estimating expected hydrocarbon recovery.Estimation of reserves, determination of oil reservoir performance, recovery efficiency, production optimization and design of production systems are some of the areas which require precise determination of a fluid's physical properties at different conditions of pressure and temperature.A reservoir PVT behavior can very complicated especially when the composition and PVT properties vary with depth, or when different geological formation produce significantly different fluids from the same field.The importance of collecting representative reservoir fluid samples (preferably early in the life of the reservoir) and having the samples analyzed in a reputable laboratory cannot be over emphasized.PVT (Pressure-Volume-Temperature) represents the behavior of hydrocarbon reservoir fluids (i.e., oil, gas and water) during life of the field, as well as effect of changes in temperature and pressure during fluid transfer from reservoir to surface/processing facilities.In petroleum engineering, the most commonly used EOS's are cubic polynomial in volume.

Fluids exist in reservoirs as mixtures of gas, oil, and water. Some reservoirs may contain only gas and water, only oil and water, or mixtures of gas, oil, and water. Irrespective of the proportions of these fluid present in a reservoir, obtaining fluid samples and studying their phase behavior in a laboratory are necessary for establishing reservoir type, devising strategies for reservoir management, and estimating expected hydrocarbon recovery. The importance of collecting representative reservoir fluid samples (preferably early in the life of the reservoir) and having the samples analyzed in a reputable laboratory cannot be over emphasized. It is one of the essential functions of the engineers working on new or existing reservoirs as an integral part of a comprehensive data collection program.
PVT (Pressure-Volume-Temperature) represents the behavior of hydrocarbon reservoir fluids (i.e., oil, gas and water) during life of the field, as well as effect of changes in temperature and pressure during fluid transfer from reservoir to surface/processing facilities.
PVT properties are important parameters in reservoir engineering. Correlations are used whenever experimentally derived PVT data are not
Available and data from local regions are expected to give better approximation to estimated PVT values.
An accurate knowledge of Pressure-Volume-Temperature (PVT) properties is essential in reservoir and production engineering calculations. Estimation of reserves, determination of oil reservoir performance, recovery efficiency, production optimization and design of production systems are some of the areas which require precise determination of a fluid's physical properties at different conditions of pressure and temperature.
Ideally, the physical properties of the reservoir fluids are determined experimentally in the laboratory. However, due to economical and/or technical reasons, quite often this information cannot be obtained from laboratory measured values. In this case, PVT properties must be estimated from empirically derived correlations.
Because of the availability of a wide range of correlations, it is useful to evaluate them for a given set of PVT data belonging to a certain geological area. Hence, to account for regional characteristics, PVT correlations need to be modified prior to their application. Standing correlations, for bubble point pressure and other fluid properties, need to use production data like solution gas oil ratio, reservoir temperature, crude oil API gravity, and gas gravity. A lot of PVT correlations for calculation of bubble point pressure, formation oil volume factor, and solution gas oil ratio of reservoir oils have been offered in the petroleum engineering literature over the last few years.
A reservoir PVT behavior can very complicated especially when the composition and PVT properties vary with depth, or when different geological formation produce significantly different fluids from the same field. The PVT behavior cannot describe properly by a single set of PVT properties, where composition, saturation pressure, stock tank oil gravity, producing GOR and reservoir temperature may vary. As a result the PVT data are considered to be essential and need to be updated continuously. Thus, understanding, handling and using the resultant data from traditional PVT reports is of great important to the petroleum engineer.
It is worth mentioning that PVT data to be feed into the black-oil or compositional simulator can be obtained from empirical correlations, laboratory measurement, and EOS fluid characterization. It is also important to mention that there are many families of EOS's, suitable for different purpose and substances (e.g., hydrocarbons, electrolytes, solids, and substances). In petroleum engineering, the most commonly used EOS's are cubic polynomial in volume. More complicated EOS's exist, but these are not practical (unaffordable in terms of computer time) for compositional simulator.
The EOS may incorrectly predict the saturation pressure (±10% error), density(±5% error), and composition. This lack of predictive capability by the EOS can be a result of unsatisfactory compositional data or inexact properties for the heptanes-plus fraction (C7+), inadequate binary interaction parameters, incorrect overall composition, or simply that EOS is not a good enough thermodynamic model.
The major goal of reservoir simulation is to predict future performance of the reservoir and find ways and means of optimizing the recovery of some of the hydrocarbons under various operating conditions.