Fluid system in Petroleum industry - Reservoir drill-in
Creators: name: Hadzihafizovic, Dzevad
Publisher: name: Dzevad Hadzihafizovic's Lab
Year: 2024

description: Reservoir fluid system

Dewpoint reservoirs

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[1] 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

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.[2]

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.[2] 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.

References





↑ 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.

↑ Jump up to:2.0 2.1 Hunt, J.M. 1979. Petroleum Geochemistry and Geology. San Francisco, California: W.H. Freeman and Co.