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[[file:Geological_time_spiral.png|thumb|400px|The geologic time spiral.<ref name=USGS_2008>United States Geological Survey, 2008, Joseph Graham, William Newman, and John Stacy, [http://pubs.usgs.gov/gip/2008/58/ The geologic time spiral—A path to the past] (ver. 1.1): U.S. Geological Survey General Information Product 58.</ref>]]

[[file:Geological_time_spiral.png|thumb|400px|The geologic time spiral.<ref name=USGS_2008>United States Geological Survey, 2008, Joseph Graham, William Newman, and John Stacy, [http://pubs.usgs.gov/gip/2008/58/ The geologic time spiral—A path to the past] (ver. 1.1): U.S. Geological Survey General Information Product 58.</ref>]]

Petroleum [[reservoir]]s may contain any of the three fluid phases—water (brine), oil, or gas. The initial distribution of phases depends on depth, [[Wikipedia:Temperature|temperature]], [[Wikipedia:Pressure|pressure]], composition, [[migration|historical migration]], type of geological [[trap]], and [[Geological heterogeneities|reservoir heterogeneity]] (that is, varying rock properties). The forces that originally distribute the fluids are [[gravity]], [[Capillary pressure|capillary]], [[molecular diffusion]], [[thermal convection]], and pressure gradients. It is generally assumed that reservoir fluids are in a static state when discovered or, more correctly, that fluids are moving at a very slow rate relative to the time required to extract the fluids (10 to 50 years). Clearly the fluids may still be in a dynamic state in terms of [[:file:Geological_time_spiral.png|geological time]].

[[Petroleum]] [[reservoir]]s may contain any of the three fluid phases—water (brine), oil, or gas. The initial distribution of phases depends on depth, [[Wikipedia:Temperature|temperature]], [[Wikipedia:Pressure|pressure]], composition, [[migration|historical migration]], type of geological [[trap]], and [[Geological heterogeneities|reservoir heterogeneity]] (that is, varying rock properties). The forces that originally distribute the fluids are [[gravity]], [[Capillary pressure|capillary]], [[molecular diffusion]], [[thermal convection]], and pressure gradients. It is generally assumed that reservoir fluids are in a static state when discovered or, more correctly, that fluids are moving at a very slow rate relative to the time required to extract the fluids (10 to 50 years). Clearly the fluids may still be in a dynamic state in terms of [[:file:Geological_time_spiral.png|geological time]].

Because gravity is the dominant force in distributing fluids through geological time, [[hydrocarbon]]s migrate upward and are trapped against impermeable [http://www.oxforddictionaries.com/us/definition/american_english/cap-rock 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, [[hydrocarbon]]s migrate upward and are trapped against impermeable [http://www.oxforddictionaries.com/us/definition/american_english/cap-rock 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.

===Composition or feed===

===Composition or feed===

Quantifies the amount of each component in a reservoir mixture, usually reported in mole fraction. Typical components in petroleum reservoir mixtures include the nonhydrocarbons N₂, CO₂, and H₂S and the hydrocarbons C₁ C₂, C₃ ''i''C₄ ''n''C₄, ''i''C₅, ''n''C₅, C₆, and C₇₊ (C₇₊, or “heptanes-plus,” includes many hundreds of heavier compounds, such as paraffins, napthenes, and aromatics). Asphaltenes are also found in reservoir oils.

Quantifies the amount of each component in a reservoir mixture, usually reported in mole fraction. Typical components in petroleum reservoir mixtures include the nonhydrocarbons N₂, CO₂, and H₂S and the hydrocarbons C₁ C₂, C₃ ''i''C₄ ''n''C₄, ''i''C₅, ''n''C₅, C₆, and C₇₊ (C₇₊, or “heptanes-plus,” includes many hundreds of heavier compounds, such as paraffins, napthenes, and aromatics). [[Asphaltenes]] are also found in reservoir oils.

===Saturated condition===

===Saturated condition===

The water found in petroleum reservoirs is usually a ''brine'' consisting mostly of sodium chloride (NaCl) in quantities from 10 to 350 ppt (‰); seawater has about 35 ppt. Other compounds (electrolytes) found in reservoir brines include calcium (Ca), magnesium (Mg), sulfate (SO₄), bicarbonate (HCO₃), iodide (I), and bromide (Br). Brine specific gravity increases with salinity in units of about 0.075 per 100 ppt.

The water found in petroleum reservoirs is usually a ''brine'' consisting mostly of sodium chloride (NaCl) in quantities from 10 to 350 ppt (‰); seawater has about 35 ppt. Other compounds (electrolytes) found in reservoir brines include calcium (Ca), magnesium (Mg), sulfate (SO₄), bicarbonate (HCO₃), iodide (I), and bromide (Br). Brine specific gravity increases with salinity in units of about 0.075 per 100 ppt.

At reservoir conditions, the brine that is sharing pore space with hydrocarbons always contains a limited amount of [[solution gas]] (mainly methane), from about 10 SCF/STB at 1000 psia to about 35 SCF/STB at 10,000 psia for gas-water systems and slightly less for oil-water systems. Increasing salinity decreases gas in solution. [http://water.usgs.gov/edu/compressibility.html Water compressibility] ranges from 2.5 to 5 × 10^–6 psi^–1, decreasing with increasing salinity. Water [[Wikipedia:Viscosity|viscosity]] ranges from about 0.3 cP at high temperatures (>[[temperature::250&deg;F]]) to about 1 cP at ambient temperatures, increasing with increasing salinity. Finally, reservoir brines exhibit only slight shrinkage (<5%) when produced to the surface.

At reservoir conditions, the brine that is sharing pore space with hydrocarbons always contains a limited amount of [[solution gas]] (mainly methane), from about 10 SCF/STB at 1000 psia to about 35 SCF/STB at 10,000 psia for gas-water systems and slightly less for oil-water systems. Increasing salinity decreases gas in solution. [http://water.usgs.gov/edu/compressibility.html Water compressibility] ranges from 2.5 to 5 × 10^–6 psi^–1, decreasing with increasing salinity. Water [[viscosity]] ranges from about 0.3 cP at high temperatures (>[[temperature::250&deg;F]]) to about 1 cP at ambient temperatures, increasing with increasing salinity. Finally, reservoir brines exhibit only slight shrinkage (<5%) when produced to the surface.

==Petroleum reservoir classifications==

==Petroleum reservoir classifications==

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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., and M. R. Brulé, 1993, Phase behavior: Society of Petroleum Engineers Monograph Series, in press.</ref>

==Laboratory pressure-volume-temperature (PVT) experiments==

==Laboratory pressure-volume-temperature (PVT) experiments==

* [[Conducting a reservoir simulation study: an overview]]

* [[Conducting a reservoir simulation study: an overview]]

* [[Introduction to reservoir engineering methods]]

* [[Introduction to reservoir engineering methods]]

==References==

==References==

[[Category:Reservoir engineering methods]]

[[Category:Reservoir engineering methods]]