# PVT and Flow course - Lab PVT Tests CCE

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The constant composition or constant mass expansion test.

**1.** CCE for oils, and in particular oils that a little bit lower gas flow ratio they're not so compressible, we could call it **slightly compressible oils**. If you took the the reservoir oil to the surface and flashed it down to stock tank conditions you'd get somewhere less than around thousand standard cubic feet per stock tank barrel or around 200 standard cubic meters gas per standard cubic meter of flash oil. For these systems we can use a blind PVT cell. There
are many different types of this blind, so basically you have a piston pump and that will inject some kind of a working fluid. You have a working fluid, that would be maybe water, and then that water would push a piston up and down making the cell volume which is the total volume would be whatever happens to be gas and whatever happens to be oil we don't know what's gas and we don't know what's oil because it's a blind cell, but whatever the total volume is we would be able to measure that as a function of pressure by gauging the exact amount of liquid that's been pushed into the cell or out. So you measure the pressure and you get the volume and that's all you know. So for a slightly compressible oil the volume change with pressure will have this discontinuity. We start at some very high pressure in the cell that's probably going to be greater than or equal to the what you think is the initial pressure. The experiments conducted typically at a constant temperature and that temperature 98% of the time is at reservoir conditions. So, basically we expand the volume, measure the pressure, we expand the volume again, measure the pressure and so forth. The max cell volume is typically around four times the initial volume that you start.

If the function volume of pressure is a linear trend then it's approximately a constant compressibility, it won't be constant, it'll be kind of constant. The slope would probably start changing a little bit more as you go to lower pressures. So, if it stayed as a liquid you would expect it to to just stay on that trend, but then all of a sudden you get a point that very nonlinear highly increasing and it's due to the gas basically. And where it intersects this linear trend that's going to be the bubble point. Below that pressure we get a little bit of gas coming out of solution, its compressibility is probably 10 times at least the oil compressibility so that one PSI pressure drop gives a lot more volume increase than if it was just an oil.

The uncertainty increases as it becomes more compressible as this discontinuity becomes smaller so might be as much as a hundred and fifty psi by the time it gets that big you should not be using this kind of equipment (but sometimes they do).

From this experiment for a traditional oil you get the density above the bubble point and you get total relative volume as a function of pressure. And of course, you get the bubble point pressure estimate. An example of the report can be found in the notes for this lecture.

**2.** CCE for oils and gas condensates.

Here we use a windowed PVT cell. What we're doing here, again, we just charge the cell with a certain amount of massive material, keep it at a fixed temperature; we change the pressure and we measure the volume of oil and the volume of gas and the total volume. We start with the pressure greater than or equal to the initial reservoir pressure, you'd come down to the point where you find the saturation pressure, it's either going to be a bubble point or a dew point and then we'll go down to some low minimum pressure where the total volume is approximately 4 times the volume of the saturation pressure.

What's reported is typically the total volume over the saturation volume. And then we get the oil volume in one of two ways presented: 1) the most common way would be oil volume as a function of total volume or relative to total volume and/or 2) oil volume relative to the saturation volume. For reservoir oils you'll also get the oil density above the bubble point and for reservoir gases they'll typically give you the Z factor and / or the gas formation volume factor. These will be given at and above the saturation pressure where it's single-phase.

How how do we establish this saturation pressure? This has for sure some uncertainty probably here at the best 10 psi and it might be into the hundreds of psi uncertainty. Basically what they do is they use a graphical plot an oil volume (Vo) versus pressure, in both cases boils and gases. So this you do kind of a trend analysis and where these intersect, is what you're going to call the bubble point.

The accuracy depends on:

- how many and how close you have pressures near by the bubble point.
- make sure that you you bring all points to equilibrium. Because you can have this super saturation effect that if you just lower the pressure or maybe the gas doesn't come out of solution, if you shake it the gas comes out of solution, so if you don't shake it enough you might get partial gas out of solution. Basically there's a requirement of physical agitation over a certain amount of time to bring the system to a true equilibrium. And if you don't do that because time is money and labs like to make money, then some of these points may not really be where they should be and that makes it more uncertain.

Reservoir gas. At first we don't see any oil and then, because there's not very much of it may be hard to call it may be hard to quantify, but they see fog or they see liquid droplets but they can't quantify how much. So what they'll do is that they'll basically put a number like they might put it up to zero and they'll say that these two pressures we saw what they call a trace. It's it's definitely liquid appearing but they can't measure the amount. And then they get the first measurable amount. It'll max out and then maybe it'll drop down. And then they have to do some kind of interpretation of where is the dew point.

The curve on the plot is what we refer to as the liquid dropout curve because liquid is dropping out of the gas. We have retrograde condensation and below the maximum you have kind of a revaporization - the condensed liquid is revoporized back into the gas.

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## Other lectures from the PVT and Flow course

- Blog:PVT and Flow course - Gas or Oil Reservoir?
- Blog:PVT and Flow course - Single Component Vapor Pressure.
- Blog:PVT and Flow course - Two-Component Phase Behavior
- Blog:PVT and Flow course - Multi-Component Phase Diagrams
- Blog:PVT and Flow course - K Values
- Blog:PVT and Flow course - Flash Calculations
- Blog:PVT and Flow_course - Surface Separation Processing
- Blog:PVT and Flow course - Sampling
- Blog:PVT and Flow course - PVT Lab Tests
- Blog:PVT and Flow course - OBM Decontamination
- Blog:PVT and Flow course - Lab PVT Tests CCE
- Blog:PVT and Flow course - LAB PVT Tests Multistage SEP
- Blog:PVT and Flow course - Lab PVT Tests DLE
- Blog:PVT and Flow course - Lab PVT Tests CVD
- Blog:PVT and Flow course - Black-Oil PVT
- Blog:PVT and Flow course - Rate Equation (Darcy) Intro

Class notes developed during lectures are available as PDF files, named with the format yyyymmdd.pdf located on: http://www.ipt.ntnu.no/~curtis/courses/PVT-Flow/2016-TPG4145/ClassNotes/

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