Phase Behavior of Mixed Petroleum Fluids

I came across this phase diagram recently and like to explain what I see. What is this fluid, what are the likely properties, and what geological processes may have created it? I posted on LinkedIn as a question and had many good suggestions that I have incorporated in the explanation below. 

1) It is obviously a gas (vapor) reservoir by definition (reservoir temperature > critical temperature), and a retrograde one (reservoir temperature < cricondentherm), definitely not an oil. See definitions of fluid types in the blog post just below. 

2) It is not a normal retrograde condensate. First, the critical point is at -92 °C, that is colder than pure methane (perhaps some nitrogen may be mixed in there)! So it is a lean gas. The actual C6+ is only about 2 mol% - so it is actually very dry.

3) The cricondentherm (the highest temperature on the curve) for a normal dry gas should be near 0 or negative, but this one is at 380 °C! That is a cricondentherm for a black oil. High cricondentherm means it takes very high temperature to vaporize the liquid in this fluid - so it must be fairly heavy hydrocarbons. 

4) The dew point pressure is abnormally high at ~8000 psi. High Psat gas means either it has a lot of liquid (rich), and/or the liquid fraction in fluid is hard to dissolve in the gas.

5) We can rule out rich liquid case because the critical temperature is too low for that a rich condensate. 8000 psi is also too high for that too. So it is likely a mixture of a lean/dry gas with a liquid that is much heavier than normal condensate. 

6) In this particular case, it is a dry gas sourced from a coal mixed with small amount of lacustrine oils. The "condensate" is around 35 API gravity! 

7) Very high saturation pressure (some times > 12,000 psi) is a good indicator of a mixed fluid that came from very different sources. We see this in the GOM deep water, and the Mediterranean Sea, where we have mixes of biogenic gas and some normal oil. We also find these on both side of Atlantic margins, and some deep basins in China. It is one of the clues for some of the fluids offshore Guyana/Suriname.

8) This could also be a result of a dry gas with oil based mud contamination , as proposed by Brian Moffat in the LinkedIn comments section. So be careful.  

The figure below explains the effects on phase diagram when a dry/lean gas is mixed with a normal oil. 

Fig. 2. Effects of mixing dry gas with normal oil on phase diagram. Dry gas has a very low critical temperature and cricondentherm. Black oil has very high critical temperature and cricondentherm. The mixed fluid inherits the low critical temperature from the gas, but the high cricondentherm from the oil. The saturation pressure increases dramatically as the two fluids are not compatible. It takes higher pressure for them to dissolve each other.  

Petroleum Reservoir Fluid Types

The five main type of reservoir fluids, black oil, volatile oil, retrograde gas, wet gas and dry gas, are used mainly by engineers for designing production facilities based on what is expected to happen to the fluid during production. It is often confusing to geologists as we tend to focus on the range of properties of each fluid type, such as API gravity, GOR and color etc. offered in literature tables like this one: 

However, the classification does not actually depend on these properties, instead it depends on the fluid's phase behavior and initial reservoir PT conditions. The same exact fluid can be a retrograde gas, or a volatile oil simply due to a few degrees difference in reservoir temperature. A fluid may be retrograde gas at a given reservoir temperature, but a wet gas if the reservoir temperature is higher. These typical ranges of properties are only a guide. In nature some gas fields have heavy condensates (<40 API gravity), whereas some black oils are colorless and very light (55 API). I hope this essay can help the PSA community in their petroleum system evaluation and communicate with engineers and managers better.

Fig. 1. The standard fluid types are determined by the position of the initial reservoir PT condition relative to the fluid's critical point, cricondentherm and separator conditions. The color circles on each line is the critical point. The large blue dot is the initial reservoir pressure and temperature. The blue line indicates how reservoir pressure decreases during production. Tc -  critical temperature, Tct - cricondentherm, Pd -- dew point pressure, Pb -- bubble point pressure.

The standard fluid types are determined by the position of the initial reservoir PT condition relative to the fluid's critical point, cricondentherm and separator conditions (Fig. 1). If reservoir temperature is lower than the critical temperature of the fluid it is oil (liquid), and when pressure drops it will cross the bubble point and thus also called a bubble point fluid. If the reservoir temperature is higher than the critical temperature, it is a gas (vapor), and also called a dew point fluid. Black oil and volatile oils are separated by the shrinkage factor (FVF) ; Among the gas types, it is called retrograde gas if condensate can form in the reservoir (Tc < T < Tct). If condensate cannot form in the reservoir (T>Tcc), but can in the separator, it is called wet gas. It is dry gas if no liquid drops out at the separator or surface. 

Black Oil is a bubble point fluid whose critical temperature is much higher than the reservoir temperature (Tc>>T).  It is "low shrinkage" - with FVF (or Bo) less than 2 due to low GOR. It is usually black hence the name. 

Volatile Oil is also a bubble point fluid (Tc>T). But the critical temperature is closer to reservoir temperature. It is high shrinkage (FVF > 2.0) due to higher  GOR and volatile because it has higher content of C2-C6 hydrocarbons.

Retrograde Gas (or Gas Condensate) is a dew point with critical temperature less than reservoir temperature (Tc<T) but because cricondentherm is higher than reservoir temperature (Tct>T)  condensate can form in reservoir when pressure drops below dew point and cause production problems. However, condensate volume decreases again (retrograde) when pressure is further reduced.   

Wet Gas has a dew point as well, but because reservoir temperature is higher than the cricondentherm (T>Tct), condensate cannot form in the reservoir when pressure decreases. However, because the separator PT condition falls within the phase envelope, condensate will form in the separator and has to be dealt with. 

Dry gas has so little C7+ that the condensate will not drop out in the separator or even at surface. 

Exceptions and odd fluid properties

The properties of fluids within each type can be outside or typical ranges given in the table above. There can be a black oil with no color, and 55 API gravity. Some gases may have a low gravity and dark colored condensate.  

The boundary between black oil and volatile oil is not so clear cut with parameters. GOR for volatile oils can be as low as 1000 scf/bbl, and black oil up to 2000 scf/bbl, depending to a large degree on the concentration of C2-C5 hydrocarbons vs methane.  The solution gas for black oil stays in gas phase in the separator, and simple mass balance equations (black oil models) are adequate. Solution gas from volatile oils drops condensate in the separator, and requires more sophisticated EOS models. 

Fig. 2. Normal relationship between API gravity and GOR. Fluids outside of the normal trend are likely formed under certain geological conditions, that may not happen to most fluids.

Certain geological processes can create unusual fluids. For example, when a gas condensate migrates into a low pressure reservoir, the light gravity condensate drops out and forms an "oil" rim. If the trap then leaks off the gas cap, or if the oil rim migrates into another trap, we can end up with a low GOR black oil but very light (something like 300 scf/bbl & 55 API). Water washing can cause a gas condensate to lose most of its gas and form a black oil as well. These “black” oils are light colored or colorless. The laminaria fields (fig.2) are black oils interpreted as formed by water washing of an originally gas condensate fluid. 

The opposite can happen when mixing very different fluids. We are now drilling much deeper (higher pressure) than before.  A migrating undersaturated gas may dissolves a small amount of normal or even heavy oil during migration, either from background organic matter, or small oil accumulations. The result can be a gas reservoir with a condensate API gravity in the black oil range. Such fluids have abnormally high dew point pressure and cricondentherm, so they likely fit the definition of retrograde condensate, but GOR can be in the dry gas range. 

Abnormal fluid properties can be clues to the geological processes, and the interpretation can be useful in petroleum system analysis and prospect evaluation. 

Other names

Gas condensate often has the same meaning as retrograde gas, but also a more generic term that include all gases because all natural gases have some amount of condensate, however little it may be. Sometimes is is also called condensate gas.

Rich gas condensate is one that contains more condensate. At a GOR of 5000 scf/bbl, a million cubic feet of gas yields 200 barrels of oil (condensate from the gas). The mass fraction of the two are about same (50% each), but both dollar and calorific/BTU value of the condensate are more than that of the gas. Even at the GOR of 20,000 scf/bbl, the 50 barrels of condensate at $70/bbl, is worth more than 1 mmcf of gas at $3/mcf. For us geologists, we need to be aware that rich gas condensate can only be found at deep enough reservoirs. 

Super critical fluid, is gas condensate (but typically refer to liquid rich ones) when reservoir pressure and temperature are higher than critical point. These have properties between gas and oil and some times called dense fluid. Near critical fluid can also include volatile oil.  

References:

William McCain, The Properties of Petroleum Fluids, 2nd Ed., 1990