Types of reservoir fluids

Quick refresher

The position of the reservoir temperature relative to the phase envelope decides the fluid type. If it lies to the left of the critical point, the fluid is oil: below the bubble point pressure, gas comes out in the reservoir. If it lies between the critical point and the cricondentherm, the fluid is a gas condensate: below the dew point, condensate drops out. If it lies to the right of the cricondentherm, the fluid is a gas, wet or dry.
Black oil gives a lot of liquid and a moderate amount of gas at the surface. Volatile oil gives a lot of gas, and its volume shrinks by roughly half in the separator. Both have a bubble point pressure at reservoir temperature.
A gas condensate is single-phase in the reservoir while the pressure is above the dew point. Below it, liquid drops out in the pores and mostly stays in the reservoir. Wet gas is always single-phase in the reservoir and yields liquid only in the separator. Dry gas yields no liquid even at the surface.
The field signs are the gas–oil ratio, the density and colour of the liquid, and the mole fraction of C7+ in the reservoir mixture. The boundary between oil and gas condensate lies at about 570 m³/m³ (3200 scf/STB) and 12.5 mol% C7+. The boundaries are blurred, so we confirm the type with an experiment in a PVT cell, a laboratory cell in which we study the sample at a given pressure and temperature.
In an accumulation with a gas cap, at the gas–oil contact the oil is at its bubble point pressure and the gas at its dew point pressure. Both phases are saturated.

Key relationships

z_i = \frac{n_g\,y_i + n_o\,x_i}{n_g + n_o},\qquad n_g = \frac{R}{V_m},\qquad n_o = \frac{\rho_o}{M_o}

composition of the reservoir mixture from gas and liquid samples (recombination); the amounts are per 1 m³ of liquid

1\ \text{m}^3/\text{m}^3 = 5.615\ \text{scf/STB}

gas–oil ratio: scf is a standard cubic foot of gas, and STB is a barrel of stock-tank oil. The standard conditions of the gas are the same in both

\text{CGR}\,[\text{cm}^3/\text{m}^3] = \frac{10^6}{R\,[\text{m}^3/\text{m}^3]}

condensate–gas ratio, the reciprocal of the gas–oil ratio

Common pitfalls

Deciding the fluid type from the gas–oil ratio alone. Gas condensates and wet gases overlap in it, and so do volatile and black oils. The deciding sign is whether there is a bubble point or a dew point at reservoir temperature.
Thinking that wet gas is “wet” with water. “Wet” means that the gas yields a hydrocarbon liquid at the surface. Water vapour is present in almost any gas.
Hoping to “vaporise back” the condensate that has dropped out in the reservoir by reducing the pressure quickly. The envelope of the remaining mixture shifts, and mostly the light components vaporise.
Taking a sample of gas condensate or volatile oil when the bottomhole pressure is already below the saturation pressure. The sample will not be representative.
Treating a gas cap and an oil rim as one fluid. They have different phase envelopes and are in equilibrium only at the contact.

After this lesson you can

name the five types of reservoir fluid and explain how their phase envelopes differ relative to the reservoir temperature and the separator conditions
describe what happens in the reservoir and at the surface to each fluid type as the reservoir pressure falls
find the probable fluid type from field data (the gas–oil ratio, the liquid density in degrees API, the colour and the C7+ content), and understand how unreliable these signs are near the boundaries
calculate the share of the C7+ fraction in the reservoir mixture from gas and liquid samples, and convert gas–oil ratios and condensate–gas ratios (the volume of condensate per volume of gas) between units
explain why pressure is maintained in gas-condensate accumulations and what gas cycling is (producing the condensate while the dry gas is injected back), and describe the phase state of an accumulation with a gas cap

Five fluid types and the phase envelope

We usually divide reservoir fluids into five types: black oil, volatile oil, gas condensate (retrograde gas), wet gas and dry gas. The difference between them is not the name of the product. It is the phase behaviour: what happens to the fluid in the reservoir as the pressure falls, and what we get in the separator.

One picture explains all five types (Phase behaviour: pure substances and binary mixtures). Developing an accumulation is an almost isothermal process: the reservoir temperature is constant and the pressure falls. So the change of state of the fluid in the reservoir appears as a vertical line on the pressure–temperature diagram. The path from the bottomhole to the separator is a line along which both pressure and temperature fall. The fluid type depends on where these lines run relative to the phase envelope.

SchematicThe five types of reservoir fluid (schematic). Each panel shows the phase envelope with lines of constant liquid fraction, the critical point

C

, the pressure reduction in the reservoir at reservoir temperature (arrow) and the separator conditions (square). The more heavy components the mixture has, the wider the envelope, and the further to the right it lies relative to the reservoir temperature.

How the five fluid types behave

Type: Black oil
Reservoir temperature: well to the left of the critical point
In the reservoir as pressure falls: gas comes out below the bubble point pressure
In the separator: a lot of liquid, a moderate amount of gas

Type: Volatile oil
Reservoir temperature: slightly to the left of the critical point
In the reservoir as pressure falls: a lot of gas comes out quickly below the bubble point pressure
In the separator: a lot of gas; the liquid is about half of the reservoir volume

Type: Gas condensate
Reservoir temperature: between the critical point and the cricondentherm
In the reservoir as pressure falls: condensate drops out below the dew point
In the separator: gas and a light liquid — condensate

Type: Wet gas
Reservoir temperature: to the right of the cricondentherm
In the reservoir as pressure falls: stays gas
In the separator: gas and a little condensate

Type: Dry gas
Reservoir temperature: to the right of the cricondentherm
In the reservoir as pressure falls: stays gas
In the separator: gas only

Type	Reservoir temperature	In the reservoir as pressure falls	In the separator
Black oil	well to the left of the critical point	gas comes out below the bubble point pressure	a lot of liquid, a moderate amount of gas
Volatile oil	slightly to the left of the critical point	a lot of gas comes out quickly below the bubble point pressure	a lot of gas; the liquid is about half of the reservoir volume
Gas condensate	between the critical point and the cricondentherm	condensate drops out below the dew point	gas and a light liquid — condensate
Wet gas	to the right of the cricondentherm	stays gas	gas and a little condensate
Dry gas	to the right of the cricondentherm	stays gas	gas only

The path from the bottomhole to the separator is not isothermal. The production cools, so the separator point lies to the left of and below the reservoir conditions.

Black oil and volatile oil

For oils, the critical temperature of the mixture is above the reservoir temperature. This means the reservoir temperature lies to the left of the critical point. If the initial pressure is above the bubble point pressure, the oil is undersaturated. As the pressure falls it simply expands, until the pressure reaches the bubble point line. If the initial pressure equals the bubble point pressure, the oil is saturated. Gas comes out at the slightest pressure reduction, and the accumulation usually already has a gas cap (a layer of free gas above the oil).

Black oil is the most common type. It contains many heavy components. The envelope is wide, and the lines of constant liquid fraction are spread fairly evenly across it. So the mixture remains mostly liquid, both in the reservoir below the bubble point pressure and in the separator. The formation volume factor is usually below 2, and the gas–oil ratio is up to 300 m³/m³ or a little more. The stock-tank oil is dark: black, brown, sometimes with a greenish tint. The black oil model works well for it (Black oil model: solution gas–oil ratio and formation volume factors); the model is named after such oils.

Volatile oil contains more light and intermediate components (from ethane to hexane) and fewer heavy ones. Its reservoir temperature is closer to the critical temperature, and the lines of constant liquid fraction crowd together near the bubble point line. Just below the bubble point pressure, a very large amount of gas comes out. Of a cubic metre of reservoir volatile oil, about half or less remains in the stock tank (the tank at the surface); the formation volume factor is greater than 2. The gas–oil ratio is about 300–600 m³/m³. The liquid is brown, orange or greenish, and 40 °API or lighter. Such oils used to be called high-shrinkage oils.

For volatile oil the black oil model is inaccurate. The gas that comes out in the reservoir carries many intermediate components, and these partly condense in the separator. We calculate the properties of volatile oil with a compositional model or with an extended black oil model (see the advanced material).

To keep the oil in the reservoir from degassing, we maintain the pressure above the bubble point pressure, most often by water injection (Why water is injected: pressure maintenance and oil displacement). For volatile oil this is especially important. Below the bubble point pressure the gas quickly becomes mobile and goes to the wells, and it takes the reservoir energy with it.

Gas condensate

Suppose the reservoir temperature lies between the critical point and the cricondentherm. Then the fluid under initial conditions is a gas, or more precisely a single-phase dense mixture (often called the dense phase). Its saturation pressure is the dew point pressure, the pressure at which condensation begins. As long as the reservoir pressure is above it, a gas condensate behaves like an ordinary gas. Below the dew point pressure, retrograde condensation begins in the pores: a liquid rich in heavy components drops out.

CalculatedLiquid fraction of the hydrocarbon pore volume as the reservoir pressure falls, for an assumed gas condensate with a dew point pressure of 36 MPa (the formula is in the advanced material). Below the dew point pressure the liquid builds up quickly. After the maximum it vaporises only partly.

The condensate that drops out in the reservoir is mostly immobile. Its saturation is usually below the level at which a liquid begins to flow (Relative permeability). The gas leaving the reservoir becomes ever “leaner”. The condensate–gas ratio (CGR), the amount of condensate per unit of gas produced, falls, while the most valuable heavy components stay in the reservoir. Condensate builds up most strongly near the bottomhole, where the pressure is lowest. This is condensate banking. It reduces the productivity of the well even when the average reservoir pressure is still above the dew point. Near the critical point the interfacial tension (the pull at the surface between gas and liquid) is low, and condensate can move at lower saturations than ordinary oil. We take this into account in modelling.

Typical signs of a gas condensate are a gas–oil ratio above about 570 m³/m³ (3200 scf/STB), a pale condensate of 40–60 °API (from colourless to straw and light brown), and a C7+ fraction of less than about 12.5 mol% in the reservoir mixture. In Russian-language practice, we express the richness of a gas in condensate as the condensate–gas ratio, in cubic centimetres of stable (degassed) condensate per cubic metre of gas, or as the condensate content, in grams per cubic metre.

To keep condensate from being lost in the reservoir, we maintain the pressure above the dew point. Water injection suits this poorly, because behind the front the water traps a noticeable part of the gas together with the heavy components dissolved in it. More often we use gas cycling. We separate the produced gas from the condensate, extract the heavy components from it, and inject the dry gas back into the reservoir. The dry gas mixes with the reservoir gas and gradually pushes it towards the producing wells, while we sell the condensate. Part of the volume leaves the reservoir together with the condensate. So for full pressure maintenance we need more gas than remains after the condensate is separated, and we add it from outside. When the injected gas breaks through to the producing wells, we produce the rest of the accumulation by depletion, like an ordinary gas accumulation.

Wet gas and dry gas

For gases the whole envelope lies to the left of the reservoir temperature, because the cricondentherm is below it. As the reservoir pressure falls, the fluid stays a single-phase gas, and no liquid drops out in the reservoir.

Wet gas contains enough heavy hydrocarbons for some of them to condense when the gas cools in the well and in the separator. The separator conditions lie inside the envelope. The liquid we get is a light, colourless or faintly coloured condensate of up to 70 °API. The English word “wet” refers to this hydrocarbon liquid, not to water. The gas–oil ratio of a wet gas is thousands of cubic metres of gas per cubic metre of condensate. It hardly changes during development, because no liquid drops out in the reservoir and the composition of the produced mixture stays the same.

Dry gas is almost pure methane with a small admixture of ethane and non-hydrocarbon gases. No liquid forms, either in the reservoir or in the separator: both the reservoir path and the separator conditions lie outside the envelope. We call such gas “dry” because it has no hydrocarbon liquid. It may still be saturated with water vapour. On cooling under pressure, water comes out of it, and gas hydrates (ice-like solids) may form. That is why we dehydrate gas at the field (Gas processing and compression).

The boundary between wet and dry gas is conventional, because it depends on the pressure and temperature at which the separator operates. A gas that stays dry in an ordinary separator can yield condensate in a low-temperature separation plant (a plant that cools the gas strongly).

How to recognise the fluid type from field data

We cannot see the phase envelope of a reservoir fluid in the field. We get it in the laboratory or calculate it from the composition. But we can draw the first conclusions about the fluid type from well test results: from the gas–oil ratio and from the density and colour of the liquid. These signs are connected with one another because they all reflect the same thing: the share of heavy components in the mixture (Composition of reservoir fluids).

Field signs of the fluid types (approximate)

Type: Black oil
Initial gas–oil ratio, m³/m³: up to 310
Liquid, °API: below 45
C7+, mol%: above 20
Saturation at $T_{\text{res}}$: bubble point

Type: Volatile oil
Initial gas–oil ratio, m³/m³: 310–570
Liquid, °API: above 40
C7+, mol%: 12.5–20
Saturation at $T_{\text{res}}$: bubble point

Type: Gas condensate
Initial gas–oil ratio, m³/m³: above 570
Liquid, °API: 40–60
C7+, mol%: below 12.5
Saturation at $T_{\text{res}}$: dew point

Type: Wet gas
Initial gas–oil ratio, m³/m³: above 2700
Liquid, °API: up to 70
C7+, mol%: usually below 4
Saturation at $T_{\text{res}}$: none (in the reservoir)

Type: Dry gas
Initial gas–oil ratio, m³/m³: above 18,000
Liquid, °API: almost no liquid
C7+, mol%: about 0
Saturation at $T_{\text{res}}$: none

Type	Initial gas–oil ratio, m³/m³	Liquid, °API	C7+, mol%	Saturation at $T_{\text{res}}$
Black oil	up to 310	below 45	above 20	bubble point
Volatile oil	310–570	above 40	12.5–20	bubble point
Gas condensate	above 570	40–60	below 12.5	dew point
Wet gas	above 2700	up to 70	usually below 4	none (in the reservoir)
Dry gas	above 18,000	almost no liquid	about 0	none

These are approximate boundaries that summarise field statistics. In oilfield units, 310 m³/m³ ≈ 1750 scf/STB, 570 ≈ 3200, 2700 ≈ 15,000 and 18,000 ≈ 100,000 scf/STB. The gas–oil ratio here is all the gas per 1 m³ of stock-tank liquid under initial conditions, with both volumes at standard conditions. The signs overlap: we cannot tell gas condensates from wet gases by the gas–oil ratio. We confirm the type with an experiment in a PVT cell: at reservoir temperature we find a bubble point for an oil and a dew point for a gas condensate. $T_{\text{res}}$ is the reservoir temperature.

How the gas–oil ratio changes during development also tells us a lot:

For an oil, the gas–oil ratio is constant above the bubble point pressure. Below it, the ratio may at first fall slightly. Then it rises as the free gas becomes mobile.
For a gas condensate, the gas–oil ratio is constant while the pressure is above the dew point, and it rises below it. The condensate stays in the reservoir, and the produced gas becomes leaner.
For wet and dry gas, the gas–oil ratio hardly changes during development.

Worked exampleFluid type from the tests of three wells

Given (assumed data)

Well 1: gas–oil ratio 85 m³/m³; liquid 876 kg/m³, dark brown
Well 2: gas–oil ratio 520 m³/m³; liquid 800 kg/m³, orange-brown
Well 3: gas–oil ratio 2400 m³/m³; liquid 752 kg/m³, straw yellow
Conditions: liquid densities are at 15.6 °C; the density of water is 999.0 kg/m³

Solution

Gas–oil ratios in oilfield units: $85\cdot 5.615 = 477$ , $520\cdot 5.615 = 2920$ and $2400\cdot 5.615 = 13{,}476$ scf/STB.
Liquid density in degrees API: $141.5/(876/999) - 131.5 = 29.9$ ; likewise 45.2 and 56.5 °API.
For well 3, the condensate–gas ratio: $10^6/2400 = 417$ cm³/m³, or $417\cdot 0.752 = 313$ g/m³.
Compare with the table of field signs.

Answer: Well 1 is a black oil (477 scf/STB, 29.9 °API); well 2 is probably a volatile oil (2920 scf/STB, 45.2 °API); well 3 is a gas condensate (13,476 scf/STB, condensate of 56.5 °API, about 420 cm³ per cubic metre of gas).

What it means. For wells 1 and 3 all the signs agree. Well 2 is close to the boundary between volatile oil and gas condensate (570 m³/m³). We cannot establish its type reliably from field data. We need a representative sample and an experiment in a PVT cell, to see whether there is a bubble point or a dew point at reservoir temperature. The development scheme depends on the answer. We usually waterflood a volatile oil, and we produce a gas condensate by depletion or with gas injection (cycling). The data in this example are assumed for illustration.

The mole fraction of the C7+ fraction in the reservoir mixture is more reliable than the gas–oil ratio. According to field statistics, the boundary between oils and gas condensates lies at about 12.5 mol%. We get it by recombination: we recalculate the compositions of the gas and liquid taken at the surface to the reservoir mixture, using the gas–oil ratio (Reservoir fluid sampling).

Composition of the reservoir mixture from gas and liquid samples (recombination)

z_i = \frac{n_g\,y_i + n_o\,x_i}{n_g + n_o},\qquad n_g = \frac{R}{V_m},\qquad n_o = \frac{\rho_o}{M_o}

where:

$z_i$ mole fraction of component $i$ in the reservoir mixture, —
$y_i,\ x_i$ mole fractions of the component in the gas and in the liquid, —
$n_g,\ n_o$ amounts of gas and liquid per 1 m³ of liquid, kmol
$R$ gas–oil ratio: the standard volume of gas per 1 m³ of liquid, m³/m³
$V_m$ molar volume of an ideal gas at standard conditions: 24.06 m³/kmol at 0.101325 MPa and 20 °C (23.64 at 15 °C), m³/kmol
$\rho_o,\ M_o$ density and molar mass of the liquid at the conditions to which the gas–oil ratio refers, kg/m³, kg/kmol

Units: mole fractions as fractions of one; the gas volume is at standard conditions

Holds when

The gas and liquid were taken at the same time, at steady flow, with the bottomhole pressure above the bubble point pressure. Otherwise the flow at the surface does not match the reservoir mixture.
The gas–oil ratio and the liquid properties refer to the same liquid. This is either the separator liquid or the stock-tank oil. In the second case the gas is all the gas of the separator and the tank, and its composition is the average over both streams.
We treat the gas at standard conditions as ideal. The error is less than 1%.

The reservoir mixture is the sum of the moles of gas and liquid that came from the reservoir together. The gas gives many moles but little mass, and the liquid does the opposite. So even 10–15 mol% C7+ in the reservoir mixture means a large yield of liquid at the surface.

Worked exampleWhat is the C7+ share in the reservoir mixture: oil or gas condensate?

Given (assumed data)

Gas–oil ratio: 480 m³/m³: all the separator and tank gas per 1 m³ of stock-tank oil, 20 °C
Stock-tank oil: 800 kg/m³, molar mass 180 kg/kmol, C7+ fraction 75 mol%
Gas: C7+ fraction 0.4 mol%
Molar volume of the gas: 24.06 m³/kmol (0.101325 MPa and 20 °C)

Solution

Gas per 1 m³ of oil: $n_g = 480/24.06 = 19.95$ kmol; oil: $n_o = 800/180 = 4.44$ kmol.
The amount of C7+ in them: $19.95\cdot 0.004 + 4.44\cdot 0.75 = 3.41$ kmol.
The total amount of substance is $19.95 + 4.44 = 24.40$ kmol. The share of C7+ is $z_{7+} = 3.41/24.40 = 0.140$ , that is, 14.0 mol%.
The share of gas in the reservoir mixture by moles is $19.95/24.40 = 0.82$ . The gas–oil ratio in oilfield units is 2695 scf/STB.

Answer: The reservoir mixture contains about 14.0 mol% of the C7+ fraction, which is more than 12.5%. The gas–oil ratio of 2695 scf/STB is below 3200. Both signs point to a volatile oil.

What it means. More than 81% of the moles of the reservoir mixture arrive at the surface as gas. Even so, the mixture holds enough heavy fraction that it most probably has a bubble point at reservoir temperature. Both signs, however, are not far from the boundary, so we confirm the type with an experiment in a PVT cell. The same calculation over all the components gives the full composition of the reservoir mixture, which is the input data for the equation of state. The data in this example are assumed for illustration.

CalculatedAssumed composition of the five types of reservoir fluid in mole percent (the table is in the lesson on fluid composition). The share of the C7+ fraction grows from dry gas to black oil.

Accumulations with a gas cap

If an accumulation contains both gas and oil, these are two different fluids in equilibrium. At the gas–oil contact they touch at the same pressure and temperature. So the oil there is at its bubble point pressure, and the gas is at its dew point pressure. Both phases are saturated.

Each fluid has its own phase envelope. The envelope of the oil passes through the point of reservoir conditions at the contact with its bubble point line, and the envelope of the gas passes through it with its dew point line. Suppose we mix the gas and oil in the proportion in which they are present in the accumulation. For this mixture, the reservoir conditions lie inside its envelope, on the line of constant liquid fraction that equals the share of oil in the volume of the accumulation.

A gas cap can be dry gas, wet gas or gas condensate, depending on its composition and temperature. Beneath a gas-condensate cap there may be an oil rim, a thin oil-bearing part of the accumulation. Such accumulations are especially difficult to develop. When we produce oil, the gas of the cap breaks through to the wells. When we produce gas, the pressure in the cap falls, and the oil of the rim moves into the gas-saturated part of the reservoir and is partly left behind there.

Terms and symbols

Black oil: An oil with a wide phase envelope and a moderate gas–oil ratio (up to ~310 m³/m³). The formation volume factor is usually below 2.
Volatile oil: An oil with a high content of light and intermediate components. The gas–oil ratio is ~310–570 m³/m³, the formation volume factor is above 2, and the reservoir temperature is close to the critical temperature.
Gas condensate: A reservoir mixture whose reservoir temperature lies between the critical temperature and the cricondentherm. Below the dew point, condensate drops out in the reservoir.
Wet gas: A gas that stays single-phase in the reservoir but yields a hydrocarbon liquid in the separator.
Dry gas: A gas that forms no hydrocarbon liquid, either in the reservoir or in the separator.
Condensate–gas ratio (CGR): The amount of stable condensate per unit of gas produced, in cm³/m³. We also express the condensate content in g/m³.
Gas cycling: Injecting dry gas, separated from the condensate, back into a gas-condensate reservoir to keep the pressure above the dew point.
Oil rim: The thin oil part of an accumulation beneath a gas cap, often a gas-condensate cap.

Common mistakes and misconceptions

Wrong

“A gas–oil ratio of 400 m³/m³ means it is a gas condensate.”

In fact

400 m³/m³ (about 2250 scf/STB) is a typical value for a volatile oil. The position of the reservoir temperature relative to the envelope decides the type. The field signs only point to it.

Wrong

“A gas-condensate accumulation can be developed as a gas one: the condensate will vaporise later as the pressure falls.”

In fact

Below the dew point, the liquid that has dropped out mostly stays in the pores. The envelope of the remaining mixture shifts to the right, and as the pressure falls further only the light components vaporise. We prevent condensate losses by maintaining the pressure.

Wrong

“Wet gas is a gas with a lot of water.”

In fact

Wet gas is a gas that yields hydrocarbon condensate in the separator. Water vapour is present in almost any reservoir gas, and we remove it by dehydration.

Wrong

“Under a gas cap the oil is undersaturated: the gas has already separated.”

In fact

It is the other way round. At the contact with gas, the oil is saturated: it is at the bubble point pressure. Undersaturated oil is found in accumulations without a gas cap.

Wrong

“Dry gas means there will never be liquid at the field.”

In fact

“Dryness” depends on the separation conditions. In low-temperature separation, condensate can come out of the same gas, and on cooling under pressure, water and hydrates can come out of it.

In depth: advanced detail

Near-critical fluids and the change of composition with depth

When the reservoir temperature is close to the critical temperature of the mixture, the boundary between volatile oil and gas condensate loses its practical meaning. With a small change in composition, a bubble point gives way to a dew point. The densities and compositions of the phases are close, and the interfacial tension is low. Such near-critical fluids need particularly careful sampling and calculations with an equation of state (Cubic equations of state).

In tall accumulations the composition of the fluid can change in a regular way with depth. Under gravity, the heavy components concentrate at the bottom. The gas–oil ratio falls with depth, and the saturation pressure changes. In a near-critical system, a gas condensate at the top can pass smoothly, with no distinct contact, into a volatile oil at the base. So a sample from one well does not always describe the whole accumulation (Pressure gradients, fluid contacts and capillary equilibrium).

Which fluid model is needed for calculations

Fluid type and the model for calculations

Fluid type: Black oil
Usually enough: black oil model: $R_s$ , $B_o$ , $B_g$ as functions of pressure
When more is needed: gas injection, mixing of oils from different reservoirs

Fluid type: Volatile oil
Usually enough: extended black oil model
When more is needed: gas injection, near-critical conditions — a compositional model

Fluid type: Gas condensate
Usually enough: extended model: accounts for the liquid dissolved in the gas
When more is needed: cycling, gas injection — a compositional model

Fluid type: Wet gas
Usually enough: gas properties from the composition of the whole produced mixture; the condensate is converted to equivalent gas
When more is needed: design of gas treatment — a calculation from the composition

Fluid type: Dry gas
Usually enough: gas properties: gas deviation factor, $B_g$
When more is needed: —

Fluid type	Usually enough	When more is needed
Black oil	black oil model: $R_s$ , $B_o$ , $B_g$ as functions of pressure	gas injection, mixing of oils from different reservoirs
Volatile oil	extended black oil model	gas injection, near-critical conditions — a compositional model
Gas condensate	extended model: accounts for the liquid dissolved in the gas	cycling, gas injection — a compositional model
Wet gas	gas properties from the composition of the whole produced mixture; the condensate is converted to equivalent gas	design of gas treatment — a calculation from the composition
Dry gas	gas properties: gas deviation factor, $B_g$	—

The extended black oil model accounts not only for the gas dissolved in the oil but also for the liquid hydrocarbons dissolved in the gas (their content per unit volume of gas). Types of reservoir simulation model covers the types of models, and Gas formation volume factor, compressibility and viscosity covers the properties of gas.

Assumed condensate dropout curve

We calculated the curve in the plot of the section on gas condensate from a simple approximation for an imaginary gas condensate:

Assumed approximation of condensate dropout

S_L(p) = S_{\max}\,\frac{\Delta p}{\Delta p_m}\,\e^{\,1 - \Delta p/\Delta p_m},\qquad \Delta p = p_d - p \ge 0

where:

$S_L$ liquid fraction of the hydrocarbon pore volume, %
$S_{\max}$ maximum liquid fraction; taken as 12%, %
$p_d$ dew point pressure; taken as 36 MPa, MPa
$\Delta p_m$ pressure reduction below the dew point at which the dropout is greatest; taken as 16 MPa (the maximum is at 20 MPa), MPa

Units: MPa, %

Holds when

This is an approximation for one imaginary fluid, not a correlation. We chose the shape of the function to reproduce the typical form of laboratory curves: rapid growth below the dew point, a maximum and slow re-vaporisation.
Above the dew point $S_L = 0$ . Real curves come from the laboratory, from a constant volume depletion experiment (a test in which gas is withdrawn from a cell of constant volume as the pressure falls) (Laboratory PVT tests).

The maximum liquid fraction and its position depend on the composition. Lean gas condensates (low in heavy components) drop out a few per cent of liquid, and rich ones several times more.

Worked exampleHow much liquid drops out in the reservoir of the assumed gas condensate

Given (assumed data)

Curve parameters: $p_d = 36$ MPa, $S_{\max} = 12$ %, $\Delta p_m = 16$ MPa

Solution

At 30 MPa: $\Delta p/\Delta p_m = 6/16 = 0.375$ ; $S_L = 12\cdot 0.375\cdot \e^{0.625} = 8.4$ %.
At 20 MPa: $\Delta p/\Delta p_m = 1$ ; $S_L = S_{\max} = 12.0$ %.
At 5 MPa: $\Delta p/\Delta p_m = 31/16 = 1.9375$ ; $S_L = 9.1$ %, that is, 76% of the maximum amount.

Answer: Already 6 MPa below the dew point, the liquid that has dropped out takes up 8.4% of the hydrocarbon pore volume. By 5 MPa only about a quarter of the maximum amount of liquid has vaporised.

What it means. If the liquid that has dropped out is immobile, almost all of it stays in the reservoir. A pressure reduction returns only a small part of it to the gas, the lightest part. The data are assumed for illustration.

Connections to other topics

Phase behaviour: pure substances and binary mixtures — the phase envelope, critical point, cricondentherm and retrograde condensation.
Composition of reservoir fluids — what fluids of different types consist of; the C7+ fraction.
Black oil model: solution gas–oil ratio and formation volume factors — solution gas–oil ratio and formation volume factors — the model in which black oil is described.
Reservoir fluid sampling — how to take a representative sample of oil and gas condensate.
Laboratory PVT tests — the experiments that measure the saturation pressure, the dew point and condensate dropout.
Retrograde condensation, wax, asphaltenes and high-pressure fluids — retrograde condensation in the reservoir, paraffins, asphaltenes and high-pressure fluids.
Reservoir drive mechanisms — drive mechanisms of accumulations with a gas cap, solution gas and water drive.

Check yourself

1
The reservoir temperature lies between the critical temperature of the mixture and the cricondentherm. What kind of fluid is it?
1. A.Gas condensate
2. B.Dry gas
3. C.Volatile oil
4. D.Black oil
Show the answer
Correct answer: A. Gas condensate
To the right of the critical point, the fluid in the reservoir is a gas. While the temperature is to the left of the cricondentherm, the isotherm (the line of constant temperature) crosses the dew point line, so condensate drops out in the reservoir as the pressure falls. This is a gas condensate.
2
How does wet gas differ from dry gas?
1. A.It does not differ, they are synonyms
2. B.Wet gas contains a lot of water vapour
3. C.Wet gas releases liquid in the reservoir as the pressure falls
4. D.For wet gas the separator conditions lie inside the phase envelope, and condensate comes out at the surface
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Correct answer: D. For wet gas the separator conditions lie inside the phase envelope, and condensate comes out at the surface
Both gases are single-phase in the reservoir at any pressure. Wet gas contains enough heavy hydrocarbons for them to condense when it cools in the separator. For dry gas, the separator also lies outside the envelope. “Wet” refers to the hydrocarbon liquid, not to water.
3
The initial gas–oil ratio of a well is 1500 m³/m³, and the liquid is pale, 55 °API. What is the probable fluid type, and how can we confirm it?
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1500 m³/m³ ≈ 8400 scf/STB. This is above the boundary of about 570 m³/m³ (3200 scf/STB), and a pale liquid of 55 °API is typical of a condensate. So the fluid is probably a gas condensate. We confirm it with an experiment in a PVT cell on a representative sample: at reservoir temperature we should see a dew point, not a bubble point.
4
Why is dry-gas injection (cycling) usually preferred to waterflooding for a gas-condensate accumulation, although it is more expensive?
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The aim is to keep the pressure above the dew point, so that condensate does not drop out in the reservoir. Water traps part of the gas behind the front, together with the heavy components dissolved in it. Dry gas, on the other hand, mixes with the reservoir gas and pushes it towards the wells. The drawbacks of cycling are that the sale of gas is postponed, compressors are needed, and the injected gas may break through early to the producing wells.
5
The reservoir pressure of a gas-condensate accumulation has fallen below the dew point. How will the condensate–gas ratio change?
1. A.First fall to zero, then rise
2. B.Fall: the condensate stays in the reservoir and the produced gas becomes leaner
3. C.Rise: more liquid drops out
4. D.It will not change
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Correct answer: B. Fall: the condensate stays in the reservoir and the produced gas becomes leaner
The liquid that has dropped out in the reservoir is mostly immobile, the heavy components stay in the pores, and an ever leaner gas flows to the well. The gas–oil ratio rises, and the condensate–gas ratio, its reciprocal, falls.
6
An accumulation has a gas cap. What can be said about the oil at the gas–oil contact and about the gas of the cap?
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Both phases are saturated. At the contact the oil is at its bubble point pressure and the gas is at its dew point pressure, because they are in equilibrium at the same pressure and temperature. Any pressure reduction will release gas from the oil. If the cap is a gas condensate, condensate will also drop out of the gas.

Updated: 19 October 2026