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PVT and Flow course - Lab PVT Tests CVD

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Lab PVT Tests CVD (20160225 Part 1)

The Constant Volume Depletion test. This test is mainly conducted on gas condensates, that's reservoir fluids with a dew point. And it can in a few cases be used for what we'll call very volatile or sometimes we refer to it as near critical oils - oils with high GOR (>2500 scf/STB or 500 Sm3/Sm3).

The key data being measured is how the the the gas composition changes as the pressure drops below the saturation pressure. Ee're particularly talking about C5+, yhay is is what you want to look at, because those are the components that make up this thing that we call oil that we sell.
The reason that's important is because the economic value of a gas condensate reservoir will almost always be primarily from the condensate that's sold or the oil that's sold at the surface and not the gas. You're going to make more money off of the oil being sold then you all are going to be selling the gas. So if the amount of oil that you get out of a certain reservoir volume of gas produced - if that amount of oil starts dropping (which it will as you go below the dew point) - that will have a big impact on the economy of the field.

As the pressure drops the gas is able to keep in solution less oil. So as the pressure drops below the dew point oil comes out of solution, the oil has no mobility, it sticks to the rock - you don't get that oil.

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Lab PVT Tests CVD (20160225 Part 2)

The Constant Volume Depletion experiment is conducted at reservoir temperature only, you would never do this experiment it at other temperatures. It starts at the saturation pressure, there's typically five probably at the minimum to as many as eight depletion stages, the higher the saturation pressure the more stages.
For a gas condensate fluid the CVD test itself is very similar - if not almost equal - to the expected depletion performance of really any reservoir containing the gas condensate mixture that we're studying in the CVD test.

The CVD test starts at the dew point so you it you wouldn't necessarily have the points above the dew point but obviously the composition is not going to change if you're in the single phase. As the average reservoir pressure drops below the dew point liquid will condense out. You drop below the dew point pressure and you get liquid drops coming out of the gas, it sticks to the rock doesn't flow. So what you see at the surface, what we're producing, OGR (or the mole fraction of C5+) will start going down probably monotonically down as far as you drop the pressure. If you went to really low pressures you might see the producing oil gas ratio go up again, probably not - it is possible and it does happen but it's not common.
OGR vs. P, CVD test

Our surface process - and is simplified but that kind of reasonably accurate representation - as surface gas is basically equal to all of the components produced out of the reservoir that's ighter then or equal to C4 and the surface oil is C5 and heavier components. Depending on the actual process it might this might be a good representation or if it's a less efficient process then it might be something like up to C5 is gas and C6+ is oil. It's an approximation but it's not a bad one, it just makes things a lot simpler: you can take the molar composition of what comes out of the reservoir or what comes out of the PVT cell, you can take that composition and say well everything lighter than C5 is going to be produced as the surface gas and everything heavier than C5 including C5 is produced as oil.
And if you do that then what you can find is that the if the producing well stream composition we call that Zwi well stream. That's capital Z for a mole fraction, w for well stream and i for component. We can translate that into an oil gas ratio in a very simple form:

OGR = Zw5+ / (1 - Zw5+) * [(M/ρ)5+/ R*Tsc/Psc]
R*Tsc/Psc - converts moles to volume in your favorite unit 
(M/ρ)5+ - molecular weight divided by the density at standard conditions of that C5+ material  - convert moles of the surface oil to a volume

[(M/ρ)5+/ R*Tsc/Psc] is more or less constant during depletion, so if you can just find that initial number you can use it.

So it ends up that the composition at average reservoir pressure, we look at the producing well stream that composition that we would actually be processing at the surface, is actually quite close to the CVD composition at the CVD pressure. It is a very good approximation (2-5% accuracy). That gives us a reasonable estimate of our well stream producing composition at the same pressure, we can convert the compositions to barrels per million, or whatever unit you want to use, and using the CVD solution oil-gas ratio will be a little bit optimistic but not too bad.

Why is the condensate trapped in the reservoir? The maximum oil volume over the (oil plus gas) volume from the CVD test which is basically the oil volume over the initial volume at the initial saturation pressure, the max value of this is around 45%
The oil saturation is equal to that value times 1 minus water saturation: So = Vro_cvd * (1-Sw)
Sw in average ~ 20%
So, So = 0.45*(1-0.2) = 0.36
And the residual saturation to oil in general or the Critical saturation for oil to flow, where KR o is greater than zero, is typically around 20 to 30%.
So what you see is that in the most extreme case you have your oil just above the oil saturation needed to flow.
So gas mobility is going to be so much higher than the oil mobility even if there is some finite mobility to the condensate the gas is just going to outrun it. You might get a little bit of oil trickling in but it's not going to be a lot.

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Other lectures from the PVT and Flow course

Class notes developed during lectures are available as PDF files, named with the format yyyymmdd.pdf located on:

See also

PVT tests
Curtis Whitson Petroleum Engineering Videos

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