This section presents technical notes explaining thermodynamic phenomena and provides recommendations on which methods and models to use to solve problems within fluid phase behavior.
The PVT Modeling Discipline
PVT modeling of reservoir fluid samples is the link between a PVT lab and the simulation software used in reservoir, flow and process simulation studies. As sketched in Figure 1, the PVT lab measures a series of fluid property data. A PVT model is derived from the PVT data that can be exported to compositional and black oil simulators.
Figure 1 PVT modeling, the link between a PVT lab and reservoir, flow and process simulators.
To make use of a cubic equation of state, each component must be assigned a critical temperature, a critical pressure, an acentric factor, and a volume shift parameter. In addition, each component pair must be assigned a binary interaction parameter. This is done through fluid characterization. The term C7+ characterization is used because the critical properties of the components from C7 and above vary between reservoir fluids. The optimum critical properties of the C7+ components must therefore be found by regression to experimental PVT data. The term common EoS is used when the same EoS model is used for multiple fluid samples. A field wide EoS model is a common EoS model applicable for a whole field.
Figure 2 shows the phase envelope of a heavy gas condensate with quality lines calculated using a cubic equation of state. It illustrates that the application of cubic equations is not limited to single phases. Cubic equations can also be used to calculate the number of phases and the amounts and compositions of each phase. Thermodynamic properties like Joule-Thomson coefficients and sound velocities may also be derived from a cubic equation of state.
Wax may precipitate and deposit in pipelines transporting untreated gas condensates or oils at temperatures below 60 °C. The wax formed from a reservoir fluid consists of heavy paraffins that are kept in solution at the reservoir temperature but may solidify in production wells and subsea pipelines where the temperature is lower.
Production of reservoir fluids containing asphaltenes can be problematic. Asphaltene precipitation can occur in the reservoir when the pressure drops as production takes place or if gas is injected for Enhanced Oil Recovery (EOR) purposes. Figure 3 shows a typical phase diagram for an oil containing asphaltenes. Asphaltene precipitation occurs in a pressure range around the saturation pressure and has its maximum at the saturation pressure.
Figure 3 Asphaltene phase diagram for an oil showing upper asphaltene curve (full drawn line), saturation pressure (dashed line) and lower asphaltene curve (dashed-dotted line). The solid black dots are critical points.
A reservoir fluid composition changes with depth. Gravity segregation causes high molecular weight components seek towards the bottom and lighter components rise to the top. This component segregation is strengthened by a vertical temperature gradient, the effect of which can be described using irreversible thermodynamics. Models for simulating the compositional variation with depth are only applicable to petroleum reservoirs in communication that will allow the molecules to move freely up and down. If a fluid communication study cannot describe the compositional variation with depth, the field will have faults or compartmentalization hindering a free movement of molecules.
Kapexy Aps is specialized in PVT modeling and offers as an additional service to train clients in the EoS modeling discipline. This can be done through regular PVT simulation courses or by engaging customer engineers in EoS modeling projects under Kapexy’s supervision.
Kapexy has expert knowledge on the PVTsim Nova simulator. Contact Kapexy, if you are new to PVTism Nova and need help to get started using the program. An initial consultation is not charged for.
Reservoirs with a Critical Zone
The classical picture of a fluid column with a gas cap on top of an oil zone is one where the shift from oil to gas takes place at a gas-oil contact (GOC) at which the saturation pressure equals the reservoir pressure. This situation is illustrated in Figure 1. Right at the gas-oil contact the situation is the same as it would be in a separator operating at the P & T at the GOC. As is the case with a separator gas and a separator oil, the gas and oil in equilibrium at the GOC have different GOR’s, phase densities, etc., as is illustrated in Figure 2.
Figure 1 Variation in reservoir pressure and saturation pressure in a reservoir with a Gas-Oil-Contact (GOC)
Figure 3 Variation in reservoir pressure and saturation pressure in a reservoir with a critical zone.
As can be seen from Figure 4 the GOR and fluid density develop continuously with depth unlike what is seen in Figure 2 for a reservoir with a GOC.