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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 reservoirs may contain any of the three fluid phases—water ([[brine]]), [[Oil as an energy source|oil]], or [[natural gas|gas]]. The initial distribution of phases depends on [[depth]], [[temperature]], [[pressure]], [[composition]], [[migration|historical migration]], type of [[geological trap]], and [[reservoir heterogeneity]] (that is, varying rock properties). The forces that originally distribute the fluids are gravity, 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, 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, [[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.

This article, along with the ''See also'' articles, 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 article, along with the ''See also'' articles, 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>

===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===

==Reservoir water==

==Reservoir water==

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. 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 (

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==

* Black oil

* Black oil

The first three of these are gas reservoir fluid types, which are in a gaseous state at virgin reservoir conditions, meaning that the critical temperature of the reservoir fluid is less than the reservoir temperature. Dry gas and wet gas fluids consist mainly of light and intermediate hydrocarbons (N₂, CO₂, H₂S, and C₁ to C₂), in which no liquids will condense in the reservoir rock during pressure depletion. Wet gases produce high API condensate (distillate) at surface conditions in amounts usually less than about 5 STB/MMSCF. The OGR should remain constant throughout the depletion of a wet gas reservoir.

The first three of these are gas reservoir fluid types, which are in a gaseous state at virgin reservoir conditions, meaning that the critical temperature of the reservoir fluid is less than the reservoir temperature. ''Dry gas'' and ''wet gas'' fluids consist mainly of [[Light hydrocarbon|light]] and [[intermediate hydrocarbon]]s (N₂, CO₂, H₂S, and C₁ to C₂), in which no liquids will condense in the reservoir rock during pressure depletion. Wet gases produce high API condensate (distillate) at surface conditions in amounts usually less than about 5 STB/MMSCF. The OGR should remain constant throughout the depletion of a wet gas reservoir.

Gas condensates, in contrast, contain significant amounts of C₅₊ components, and they exhibit the phenomenon of ''retrograde condensation'' at reservoir conditions, in other words, as pressure decreases, increasing amounts of liquid condenses in the reservoir (down to about 2000 psia). This results in a significant loss of ''in situ'' condensate reserves that may only be partially recovered by revalorization at lower pressures. Gas condensate reservoirs exhibit producing gas-oil ratios from 2500 to 50,000 SCF/STB (400 to 10 STB/MMSCF). Gas cycling projects designed to avoid liquid loss from retrograde condensation can usually be justified for fluids with liquid content higher than about 50 to 100 STB/MMSCF. Offshore, the minimum liquid content to justify cycling is about 100 STB/MMSCF.

''Gas condensates'', in contrast, contain significant amounts of C₅₊ components, and they exhibit the phenomenon of ''retrograde condensation'' at reservoir conditions, in other words, as pressure decreases, increasing amounts of liquid condenses in the reservoir (down to about 2000 psia). This results in a significant loss of in situ condensate reserves that may only be partially recovered by revalorization at lower pressures. Gas condensate reservoirs exhibit producing gas-oil ratios from 2500 to 50,000 SCF/STB (400 to 10 STB/MMSCF). Gas cycling projects designed to avoid liquid loss from retrograde condensation can usually be justified for fluids with liquid content higher than about 50 to 100 STB/MMSCF. Offshore, the minimum liquid content to justify cycling is about 100 STB/MMSCF.

Reservoir oils are classified as either black oil or volatile oil, the former being more commonly discovered in the first 50 years of the oil industry. Volatile oil reservoirs have become the “norm” in the past 20 years, mainly because discoveries are at greater depths with higher initial pressures. A clear demarkation between these two oil types is not easily made, although a gas-oil ratio of about 750 SCF/STB is probably a good indicator (black oils have lower GORs). Volatile oils may have GORs up to 2500 SCF/STB and formation volume factors as large as three (meaning that the oil shrinks by a factor of three when produced to the surface). Another characteristic of volatile oil reservoirs is that the reservoir gas that evolves and flows into the wellbore will contain significant quantities of liquids that may eventually contribute the majority of surface oil production at late stages of depletion.

Reservoir oils are classified as either ''black oil'' or ''volatile oil'', the former being more commonly discovered in the first 50 years of the oil industry. Volatile oil reservoirs have become the norm in the past 20 years, mainly because discoveries are at greater depths with higher initial pressures. A clear demarcation between these two oil types is not easily made, although a gas-oil ratio of about 750 SCF/STB is probably a good indicator (black oils have lower GORs). Volatile oils may have GORs up to 2500 SCF/STB and formation volume factors as large as three (meaning that the oil shrinks by a factor of three when produced to the surface). Another characteristic of volatile oil reservoirs is that the reservoir gas that evolves and flows into the wellbore will contain significant quantities of liquids that may eventually contribute the majority of surface oil production at late stages of depletion.

Table 1 gives some typical reservoir fluid compositions and properties. Figure 1 shows a pressure-temperature diagram for a specific reservoir fluid composition. Depending on reservoir temperature, this fluid would be defined as an oil or a gas. An oil exhibits a bubblepoint pressure at saturated conditions, while a gas condensate exhibits a dewpoint pressure at saturated conditions.

Table 1 gives some typical reservoir fluid compositions and properties. Figure 1 shows a pressure-temperature diagram for a specific reservoir fluid composition. Depending on reservoir temperature, this fluid would be defined as an oil or a gas. An oil exhibits a bubblepoint pressure at saturated conditions, while a gas condensate exhibits a dewpoint pressure at saturated conditions.

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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 [[Wireline formation testers|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 [http://www.glossary.oilfield.slb.com/en/Terms.aspx?LookIn=term%20name&filter=gas-oil%20contact 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 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).

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==

Relatively accurate correlations are available for estimating the key fluid properties of reservoir systems (Table 2). Standing<ref name=pt10r32>Standing, M. B., 1977, Volumetric and phase behavior of oil field hydrocarbon systems: Dallas, TX, Society of Petroleum Engineers, AIME.</ref> and McCain<ref name=pt10r23>McCain, W. D., Jr., 1990, Petroleum Fluids, 2nd ed.: Tulsa, OK, Pennwell Books.</ref> give useful reviews of property correlations for oil and gas, and other correlations are available. Note, however, that for specific producing provinces (such as the Gulf Coast or the North Sea) more accurate correlations may exist.

Relatively accurate correlations are available for estimating the key fluid properties of reservoir systems (Table 2). Standing<ref name=pt10r32>Standing, M. B., 1977, Volumetric and phase behavior of oil field hydrocarbon systems: Dallas, TX, Society of Petroleum Engineers, AIME.</ref> and McCain<ref name=pt10r23>McCain, W. D., Jr., 1990, Petroleum Fluids, 2nd ed.: Tulsa, OK, Pennwell Books.</ref> give useful reviews of property correlations for oil and gas, and other correlations are available. Note, however, that for specific producing provinces (such as the [[Gulf Coast]] or the [[North Sea]]) more accurate correlations may exist.

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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 PVT experiments==

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

Experimental PVT measurements are usually obtained for (1) large oil and gas fields, (2) volatile oil and gas condensate reservoirs, and (3) reservoirs where gas injection is a potential EOR ([[enhanced oil recovery]]) method. Two types of fluid samples can be taken during production, or when a well is shut-in:

Experimental PVT measurements are usually obtained for (1) large oil and gas fields, (2) volatile oil and gas condensate reservoirs, and (3) reservoirs where [[gas injection]] is a potential EOR ([[enhanced oil recovery]]) method. Two types of fluid samples can be taken during production, or when a well is shut-in:

* Bottomhole samples, preferred for oils

* Bottomhole samples, preferred for oils

Recombined separator samples are standard for gas condensate fluids, but they may also be used for oil reservoirs. Bottomhole sampling is preferred for oils if the reservoir is undersaturated (that is, the initial pressure is higher than the bubblepoint pressure).

Recombined separator samples are standard for gas condensate fluids, but they may also be used for oil reservoirs. Bottomhole sampling is preferred for oils if the reservoir is undersaturated (that is, the initial pressure is higher than the bubblepoint pressure).

Standard PVT experiments include compositional gas chromatography (GC) analysis through heptanes-plus (C₇₊), constant composition expansion, differential liberation expansion, constant volume depletion, and multistage surface separation. Other PVT measurements include true boiling point (TBP) distillation of the C₇₊ material and multicontact gas injection experiments. Table 3 summarizes these experiments, indicating when they are performed and on what types of reservoir fluids.

Standard PVT experiments include compositional [[gas chromatography]] (GC) analysis through [[heptane]]s-plus (C₇₊), [[constant composition expansion]], [[differential liberation expansion]], [[constant volume depletion]], and multistage surface separation. Other PVT measurements include true boiling point (TBP) distillation of the C₇₊ material and multicontact gas injection experiments. Table 3 summarizes these experiments, indicating when they are performed and on what types of reservoir fluids.

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'''Key:''' * standard, + can be done, – not done

'''Key:''' * standard, + can be done, – not done

Compositional analyses are used to describe the reservoir fluid makeup on a component basis, including calculation of BTU (energy content) of gases, optimization of separator conditions for liquid yield, and characterization of an EOS for compositional simulation. Differential liberation and constant volume depletion experiments are designed to provide quantitative information about the volumetric behavior of oil and gas condensate reservoirs during pressure depletion. The multistage separator test is used together with differential liberation and constant volume depletion data to calculate black oil properties ''R''_s, ''B''_o, ''B''_g, and ''r''_s. Multicontact gas injection experiments provide important volumetric and compositional data that can be used to “tune” an equation of state (or alternative) model for simulation of gas injection processes.

Compositional analyses are used to describe the reservoir fluid makeup on a component basis, including calculation of British thermal unit (BTU) (energy content) of gases, optimization of separator conditions for liquid yield, and characterization of an EOS for compositional simulation. Differential liberation and constant volume depletion experiments are designed to provide quantitative information about the volumetric behavior of oil and gas condensate reservoirs during pressure depletion. The multistage separator test is used together with differential liberation and constant volume depletion data to calculate black oil properties ''R''_s, ''B''_o, ''B''_g, and ''r''_s. Multicontact gas injection experiments provide important volumetric and compositional data that can be used to “tune” an equation of state (or alternative) model for simulation of gas injection processes.

==See also==

==See also==

* [[Reserves estimation]]

* [[Reserves estimation]]

* [[Waterflooding]]

* [[Waterflooding]]

* [[Fundamentals of fluid flow]]

* [[Fluid flow fundamentals]]

* [[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]]