A multicomponent mixture exhibits an envelope for liquid/vapor phase change in the pressure/temperature diagram, which contains a bubble-point line and a dew-point line, compared with only a phase change line for a pure component. The various reservoir types of oil and gas systems based on the phase behavior of hydrocarbons in the reservoir, in

which the following five types of reservoirs are distinguished:
Typical Phase Diagram of Hydrocarbons
  • Black oils;
  • Volatile oils;
  • Condensate (retrograde gases);
  • Wet gases;
  • Dry gases.

The amount of heavier molecules in the hydrocarbon mixtures varies from large to small in the black oils to the dry gases, respectively.

Black Oils

Black oil is liquid oil and consists of a wide variety of chemical species including large, heavy, and nonvolatile molecules. Typical black oil reservoirs have temperatures below the critical temperature of a hydrocarbon mixture. Point C1 in the same figure shows saturated back oil, which means that the oil contains as much dissolved gas as it can take and that a reduction of system pressure will release gas to form the gas phase. In transport pipelines, black oils are transported in the liquid phase throughout the transport process, whereas in production flowlines, produced hydrocarbon mixtures are usually in thermodynamical equilibrium with gas.

Volatile Oils

Volatile oils contain fewer heavy molecules than black oil, but more ethane through hexane. Reservoir conditions are very close to the critical temperature and pressure. A small reduction in pressure can cause the release of a large amount of gas.


Retrograde gas is the name of a fluid that is gas at reservoir pressure and temperature. However, as pressure and temperature decrease, large quantities of liquids are formed due to retrograde condensation. Retrograde gases are also called retrograde gas condensates, gas condensates, or condensates.
Hydrocarbon Composition of Typical Reservoirs

For a pure substance a decrease in pressure causes a change of phase from liquid to gas at the vapor–pressure line; likewise, in the case of a multicomponent system, a decrease in pressure causes a change of phase from liquid to gas at temperatures below the critical temperature.

Wet Gases

A wet gas exists in a pure gas phase in the reservoir, but becomes a liquid/gas two-phase mixture in a flowline from the well tube to the separator at the topside platform. During the pressure drop in the flowline, liquid condensate appears in the wet gas.

Dry Gases

Dry gas is primarily methane. The hydrocarbon mixture is solely gas under all conditions of pressure and temperature encountered during the production phases from reservoir conditions involving transport and process conditions. In particular, no hydrocarbon-based liquids are formed from the gas although liquid water can condense. Dry gas reservoirs have temperatures above the cricondentherm.

Computer Models

Accurate prediction of physical and thermodynamic properties is a prerequisite to successful pipeline design. Pressure loss, liquid hold up, heat loss, hydrate formation, and wax deposition all require knowledge of the fluid states.

In flow assurance analyses, the following two approaches have been used to simulate hydrocarbon fluids:

  • “Black-oil” model: Defines the oil as a liquid phase that contains dissolved gas, such as hydrocarbons produced from the oil reservoir. The “black oil” accounts for the gas that dissolves (condenses) from oil solution with a parameter of Rs that can be measured from the laboratory. This model predicts fluid properties from the specific gravity of the gas, the oil

gravity, and the volume of gas produced per volume of liquid. Empirical correlations evaluate the phase split and physical property correlations determine the properties of the separate phases.

  • Composition model: For a given mole fraction of a fluid mixture of volatile oils and condensate fluids, a vapor/liquid equilibrium calculation determines the amount of the feed that exists in the vapor and liquid phases and the composition of each phase. It is possible to determine the quality or mass fraction of gas in the mixtures. Once the composition of

each phase is known, it is also possible to calculate the interfacial tension, densities, enthalpies, and viscosities of each phase.

The accuracy of the compositional model is dependent on the accuracy of the compositional data. If good compositional data are available, selection of an appropriate EOS is likely to yield more accurate phase behavior data than the corresponding black-oil model. This is particularly so if the hydrocarbon liquid is a light condensate. In this situation complex phase effects such as retrograde condensation are unlikely to be adequately handled by the black-oil methods. Of prime importance to hydraulic studies is the viscosity of the fluid phases. Both black-oil and compositional techniques can be inaccurate.

Depending on the correlation used, very different calculated pressure losses could result. With the uncertainty associated with viscosity prediction, it is prudent to utilize laboratory-measured values. The gas/oil ratio (GOR) can be defined as the ratio of the measured volumetric flow rates of the gas and oil phases at meter conditions (multiphase meter) or the volume ratio of gas and oil at the standard condition (1 atm, 60 F) in units of scf/STB. When water is also present, the water cut is generally defined as the volume ratio of the water and total liquid at standard conditions. If the water contains salts, the salt concentrations may be contained in the water phase at the standard condition.


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