Changes

* 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 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.

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.