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Phase diagrams for reservoir fluid systems
Real reservoir fluids contain many more than two, three, or four components; therefore, phase-composition data can no longer be represented with two, three or four coordinates. Instead, phase diagrams that give more limited information are used.
Diagramming multicomponent mixtures
Fig. 1 shows a pressure-temperature phase diagram for a multicomponent mixture; it gives the region of temperatures and pressures at which the mixture forms two phases. The analog of Fig. 1 for a binary system can be obtained by taking a slice at constant mole fraction of Component 1 through the diagram in Fig. 3. Also given are contours of liquid-volume fractions, which indicate the fraction of total sample volume occupied by the liquid phase; however, Fig. 1 does not give any compositional information. In general, the compositions of coexisting liquid and vapor will be different at each temperature and pressure.
At temperatures below the critical temperature (point C), a sample of the mixture described in Fig. 1 splits into two phases at the bubblepoint pressure (Fig. 4) when the pressure is reduced from a high level. At temperatures above the critical temperature, dewpoints are observed (Fig. 5). In this multicomponent system, the critical temperature is no longer the maximum temperature at which two phases can exist. The critical point is the temperature and pressure at which the phase compositions and all phase properties are identical.
The bubblepoint, dewpoint, and single-phase regions shown in Fig. 1 are sometimes used to classify reservoirs. At temperatures greater than the cricondentherm, which is the maximum temperature for the formation of two phases, only one phase occurs at any pressure. For instance, if the hydrocarbon mixture in Fig. 1 were to occur in a reservoir at temperature TA and pressure pA (point A), a decline in pressure at approximately constant temperature caused by removal of fluid from the reservoir would not cause the formation of a second phase.
While the fluid in the reservoir remains a single phase, the produced gas splits into two phases as it cools and expands to surface temperature and pressure at point A′. Thus, some condensate would be collected at the surface even though only one phase is present in the formation. The amount of condensate collected depends on the operating conditions of the separator. The lower the temperature at a given pressure, the larger the volume of condensate collected (Fig. 1).
Dewpoint reservoirs are those for which the reservoir temperature lies between the critical temperature and the cricondentherm for the reservoir fluid. Production of fluid from a reservoir starting at point B in Fig. 1 causes liquid to appear in the reservoir when the dewpoint pressure is reached. As the pressure declines further, the saturation of liquid increases because of retrograde condensation. Because the saturation of liquid is low, only the vapor phase flows to producing wells. Thus, the overall composition of the fluid remaining in the reservoir changes continuously.
The phase diagram shown in Fig. 1 is for the original composition only. The preferential removal of light hydrocarbon components in the vapor phase generates new hydrocarbon mixtures, which have a greater fraction of the heavier hydrocarbons. Differential liberation experiments, in which a sample of the reservoir fluid initially at high pressure is expanded through a sequence of pressures, can be used to investigate the magnitude of the effect of pressure reduction on the vapor composition. At each pressure, a portion of the vapor is removed and analyzed. These experiments simulate what happens when condensate is left behind in the reservoir as the pressure declines. See Pedersen, Fredenslund, and Thomassen for more details on pressure/volume/temperature experiments.
As the reservoir fluid becomes heavier, the boundary of the two-phase region in a diagram like Fig. 1 shifts to higher temperatures. Thus, the composition change also acts to drive the system toward higher liquid condensation. Such reservoirs are candidates for pressure maintenance by lean gas injection to limit the retrograde loss of condensate or for gas cycling to vaporize and recover some of the liquid hydrocarbons.
Bubblepoint reservoirs are those in which the temperature is less than the critical temperature of the reservoir fluid (point D in Fig. 1). These reservoirs are sometimes called undersaturated because the fraction of light components present in the oil is too low for a gas phase to form at that temperature and pressure. Isothermal pressure reduction causes the appearance of a vapor phase at the bubblepoint pressure. Because the compressibility of the liquid phase is much lower than that of a vapor, the pressure in the reservoir declines rapidly during production in the single-phase region. The appearance of the much more compressible vapor phase reduces the rate of pressure decline. The volume of vapor present in the reservoir grows rapidly with reduction of reservoir pressure below the bubblepoint.
Because the vapor viscosity is much lower than the liquid viscosity and the gas relative permeability goes up markedly with increasing gas saturation, the vapor phase flows more easily. Hence, the produced gas/oil ratio climbs rapidly. Again, pressure maintenance by waterdrive, water injection, or gas injection can improve oil recovery substantially over the 10 to 20% recovery typical of pressure depletion in these solution-gas-drive reservoirs. As in dewpoint reservoirs, the composition of the reservoir fluid changes continuously once the two-phase region is reached.
Initial reservoir temperature in the two-phase region
There is, of course, no reason why initial reservoir temperatures and pressures cannot lie within the two-phase region. Oil reservoirs with gas caps and gas reservoirs with some liquids present are common. There also can be considerable variation in the initial composition of the reservoir fluid. The discussion of single-phase, dewpoint, and bubblepoint reservoirs is based on a phase diagram for one fluid composition. Even for one fluid, all the types of behavior occur over a range of temperatures. In actual reservoir settings, the composition of the reservoir fluid correlates with depth and temperature. Deeper reservoirs usually contain lighter oils.
Relationship between oil gravity and depth
Fig. 2 shows the relationships between oil gravity and depth for two basins. The higher temperatures of deeper reservoirs alter the original hydrocarbon mixtures to produce lighter hydrocarbons over geologic time. Low oil gravity, low temperature, and relatively small amounts of dissolved gas all combine to produce bubblepoint reservoirs. High oil gravity, high temperatures, and a high concentration of light components produce dewpoint or condensate systems.
- Pedersen, K.S., Fredenslund, A.A., and Thomassen, P. 1989. Properties of Oils and Natural Gases, Contributions in Petroleum Geology and Engineering. Houston, Texas: Gulf Publishing Company.
- Hunt, J.M. 1979. Petroleum Geochemistry and Geology. San Francisco, California: W.H. Freeman and Co.
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