Naturally occurring hydrocarbon systems found in petroleum reservoirs are mixtures of organic compounds which exhibit multiphase behavior over wide ranges of pressures and temperatures. These hydrocarbon accumulations may occur in the gaseous state, the liquid state, the solid state, or in various combinations of gas, liquid, and solid.
These differences in phase behavior, coupled with the physical properties of reservoir rock that determine the relative ease with which gas and liquid are transmitted or retained, result in many diverse types of hydrocarbon reservoirs with complex behaviors.
CLASSIFICATION OF RESERVOIRS AND RESERVOIR FLUIDS:
Petroleum reservoirs are broadly classified as oil or gas reservoirs. These broad classifications are further subdividded depending on:
The composition of the reservoir hydrocarbon mixture.
Intitial reservoir pressure and temperature.
Pressure and temperature of the surface production.
The conditions under which these phases exist are a matter of considerable practical importance.
That is a typical pressure-temperature diagram of a multicomponent system with a specific overall composition. Although a different hydrocarbon system would have a different phase diagram. These multicomponent pressure-temperature diagrams are essentially used to:
Classify the naturally occurring hydrocarbon systems.
Describe the phase behaviour of the reservoir fluid.
To fully understand the significance of the pressure-temperature diagram, it is necessary to identify and define the following key points on these diagrams:
Cricondentherm (Tct):The Cricondentherm is defined as the maximum temperature above which
liquid cannot be formed regardless of pressure (point E). The corresponding pressure is termed the Cricondentherm pressure Pct.
Cricondenbar (Pch): The Criconderbar is the maximum pressure above which no gas can be formed regardless of temperature (point D). The corresponding temeprature is called the Cricondenbar temperature Tcb.
Critical Point: The critical point for a multicomponent mixture is referred to as the state of pressure and temperature at which all intensive properties of the gas and liquid phases are equal (point C). At the critical point, the corresponding pressure and temperature are called the critical pressure Pc and critical temperature Tc of the mixture.
Phase Envelope (two-phase region): The region enclosed by the bubble-point curve and the dew point curve wherein gas and liquid coexist in equlibrium, is identified as the phase envelope of the hydrocarbon system.
Quality lines: The dashed lines withing the phase diagram are called quality lines. They describe the pressure and temperature conditions for equal volumes of liquids. Note that the quality lines converge at the critical point (point C).
Bubble-Point curve: The bubble-point curve is defined as the line separating the liquid-phase region from the two-phase diagram.
Dew-Point Curve: The Dew-point curve is defined as the line separating the vapor-phase region from the two-phase region.
In general reservoirs are conventiently classified on the basis of the location of the point representing the initial reservoir pressure Pi and temeperature T with respect to the pressure-temperature diagram of the reservoir fluid. Accordingly, reservoirs can be classified into basically two types. These are:
Oil reservoirs: If the reservoir temperature T is less than the critical temperature Tc of the reservoir fluid, the reservoir is classified as an oil reservoir.
Gas reservoirs: If the reservoir temperature is greater than the critical temperature of the hydrocarbon fluid, the reservoir is considered a gas reservoir.
Depending upon initial reservoir pressure Pi, oil reservoirs can be subclassified into the following categories:
Undersaturated oil reservoir. If the initial reservoir pressure Pi, is greater than the bubble-point pressure Pb of the reservoir fluid, the reservoir is labeled an undersaturated oil reservoir.
Saturated oil reservoir. When the initial reservoir pressure is equal to the bubble-point pressure of the reservoir fluid, the reservoir is called a saturated oil reservoir.
Gas-cap reservoir. If the initial reservoir pressure is below the bubble point pressure of the reservoir fluid, the reservoir is termed a gas-cap or two-phase reservoir, in which the gas or vapor phase is underlain by an oil phase. The appropriate quality line gives the ratio of the gas-cap volume to reservoir oil volume.
Crude oils cover a wide range in physical properties and chemical compositions, and it is often important to be able to group them into broad categories of related oils. In general, crude oils are commonly classified into the following types:
ORDINARY BLACK OIL:
A typical pressure-temperature phase diagram for ordinary black oil is shown in the graphic. It should be noted that quality lines which are approximately equally spaced characterize this black oil phase diagram. Following the pressure reduction path as indicated by the vertical line EF on the picture.
LOW SHRINKAGE OIL
A typical pressure-temperature phase diagram for low-shrinkage oil is shown here. The diagram is characterized by quality lines that are closely spaced near the dew-point curve. The liquid-shrinkage curves shows the shrinkage characteristics of this category of crude oils. The other associated properties of this type of crude oil are:
Oil formation volume factor less than 1.2 bbl/STB.
Gas-oil ratio less than 200 scf/STB.
Oil gravity less than 35° API.
- Black or deeply colored.
VOLATILE CRUDE OILS:
It’s also called high-shrinkage, the lines are close together near the bubble-point and are more widely spaced at lower pressures. This type of crude is commonly characterized by a high liquid shrinkage inmediately below the bubble-point. The other characteristic properties of this oil include:
- Oil formation volumen factor less than 2 bbl/STB.
- Gas-oil ratios between 45-55 grados API.
- Lower liquid recovery of separator conditions.
- Greenish to orange in color.