Changes

Because gravity is the dominant force in distributing fluids through geological time, hydrocarbons migrate upward and are trapped against impermeable cap rock. Gas overlies oil which overlies water. However, because the reservoir pores are usually saturated completely by water before hydrocarbon migration and because capillary forces acting to retain water in the smallest pores exceed gravity forces, an initial (connate) water saturation will always be found in hydrocarbon-bearing formations. The connate water saturation may vary from 5 to 50% with the hydrocarbons still having sufficient mobility to produce at economical rates.

Because gravity is the dominant force in distributing fluids through geological time, hydrocarbons migrate upward and are trapped against impermeable cap rock. Gas overlies oil which overlies water. However, because the reservoir pores are usually saturated completely by water before hydrocarbon migration and because capillary forces acting to retain water in the smallest pores exceed gravity forces, an initial (connate) water saturation will always be found in hydrocarbon-bearing formations. The connate water saturation may vary from 5 to 50% with the hydrocarbons still having sufficient mobility to produce at economical rates.

This chapter reviews the physical and thermodynamic properties of gas, oil, and reservoir brine. As commonly done, the phase and volumetric behavior of petroleum reservoir fluids is referred to as ''PVT'' (pressure-volume-temperature). Two important general references on PVT are Katz et al.<ref name=pt10r18>Katz, D. L., 1959, Handbook of Natural Gas Engineering: New York, McGraw-Hill.</ref> and Society of Petroleum Engineers<ref name=pt10r30>Society of Petroleum Engineers, 1981, Phase behavior: Dallas, TX, SPE Reprint Series No. 15.</ref>.

This chapter reviews the physical and thermodynamic properties of gas, oil, and reservoir brine. As commonly done, the phase and volumetric behavior of petroleum reservoir fluids is referred to as ''PVT'' (pressure-volume-temperature). Two important general references on PVT are Katz et al.<ref name=pt10r18>Katz, D. L., 1959, Handbook of Natural Gas Engineering: New York, McGraw-Hill.</ref> and Society of Petroleum Engineers.<ref name=pt10r30>Society of Petroleum Engineers, 1981, Phase behavior: Dallas, TX, SPE Reprint Series No. 15.</ref>

==Property definitions==

==Property definitions==

If a reservoir contains both a gas cap and an oil zone, then both fluids are normally at saturated conditions initially. Initial pressure equals the dewpoint of the gas cap fluid, and it equals the bubblepoint of the underlying oil (Figure 2). The repeat formation tester (RFT) has made the determination of initial [[fluid contacts]] possible in reservoirs with reasonable [[permeability]], that is, >1 md. A saturated gas cap in equilibrium with an underlying saturated oil, for example, will be seen as a sharp discontinuity in RFT pressures at the gas-oil contact.

If a reservoir contains both a gas cap and an oil zone, then both fluids are normally at saturated conditions initially. Initial pressure equals the dewpoint of the gas cap fluid, and it equals the bubblepoint of the underlying oil (Figure 2). The repeat formation tester (RFT) has made the determination of initial [[fluid contacts]] possible in reservoirs with reasonable [[permeability]], that is, >1 md. A saturated gas cap in equilibrium with an underlying saturated oil, for example, will be seen as a sharp discontinuity in RFT pressures at the gas-oil contact.

In the past 20 years, deeper petroleum reservoirs have been discovered and the traditional interpretation of a reservoir containing both gas and oil has changed. An alternative interpretation in some gas-oil reservoirs is that composition varies continuously with depth. Here the fluids at the shallowest elevations are gas condensates, while the fluids at greater depths are oils. Sometimes the initial reservoir pressure may be greater than the saturation pressure of all mixtures in the reservoir, implying that the reservoir is entirely undersarurated even though a gas is at the top and an oil is at the bottom of the reservoir. Reservoirs of this type would not show a sharp contrast in RFT pressures at the depth where the fluid changes from a near-critical gas to a near-critical oil. Instead they would show a continuously increasing pressure gradient (for example, from 0.2 to 0.3 psi/ft).

In the past 20 years, deeper petroleum reservoirs have been discovered and the traditional interpretation of a reservoir containing both gas and oil has changed. An alternative interpretation in some gas-oil reservoirs is that composition varies continuously with depth. Here the fluids at the shallowest elevations are gas condensates, while the fluids at greater depths are oils. Sometimes the initial reservoir pressure may be greater than the saturation pressure of all mixtures in the reservoir, implying that the reservoir is entirely undersaturated even though a gas is at the top and an oil is at the bottom of the reservoir. Reservoirs of this type would not show a sharp contrast in RFT pressures at the depth where the fluid changes from a near-critical gas to a near-critical oil. Instead they would show a continuously increasing pressure gradient (for example, from 0.2 to 0.3 psi/ft).

==Fluid property correlations==

==Fluid property correlations==

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''Equations of state (EOS)'' are now commonly used to calculate phase and volumetric behavior of reservoir mixtures. In particular, EOS are useful for predicting phase behavior of miscible and immiscible displacement processes resulting from the injection of gases such as carbon dioxide, nitrogen, and lean or enriched natural gas in oil and gas condensate reservoirs. EOS do not usually predict phase and volumetric behavior of reservoir mixtures accurately, thereby requiring adjustment of component properties to match experimental PVT data<ref name=pt10r36>Whitson, C. H., Brulé, M. R., 1993, Phase behavior: Society of Petroleum Engineers Monograph Series, in press.</ref>.

''Equations of state (EOS)'' are now commonly used to calculate phase and volumetric behavior of reservoir mixtures. In particular, EOS are useful for predicting phase behavior of miscible and immiscible displacement processes resulting from the injection of gases such as carbon dioxide, nitrogen, and lean or enriched natural gas in oil and gas condensate reservoirs. EOS do not usually predict phase and volumetric behavior of reservoir mixtures accurately, thereby requiring adjustment of component properties to match experimental PVT data.<ref name=pt10r36>Whitson, C. H., Brulé, M. R., 1993, Phase behavior: Society of Petroleum Engineers Monograph Series, in press.</ref>

==Laboratory PVT experiments==

==Laboratory PVT experiments==