PVT and Flow course - Black-Oil PVT

Black-Oil PVT (20160301 Part 1)

Traditional black oil pvt is kind of what we talked about before, where you take the different Liberation tests data together with the multi-state separator test data, you could also include the constant composition expansion data above the bubble point to kind of get a a set of black oil PVT properties for the oil phase. And then the gas phase is treated in a very simple way, the gas phase is assumed not to contain any oil forming components in solution. It's kind of like having assuming that you have dry air and no matter how much you cool the windows that you'll never see condensation on the Windows, that's the assumption. That is not really almost ever the case but sometimes it's a reasonable assumption that the amount of condensate or surface oil that is dissolved in the reservoir gas can be neglected. that's the traditional black oil formulation.
And then the modified is just simply where we say that no, the reservoir gas does contain components. When you bring it to the surface and you process it you're going to make more money because you get some of these components form a surface oil or what we call it a surface condensate.

Some of the characteristics of a black oil pvt formulation:

• we only have two what we're going to call pseudo compcomponents. Normal components are like methane, ethane, propane, decane and so forth, but in this formulation there's basically just two components. And these are what we've been calling surface gas and surface oil.
• instead of using moles of the components, keeping track of the moles, of the components or even the mass of the components, we keep track of volumes which is different. So we quantify amounts in volume and because they're both by definition surface components, we're going to say these volumes at surface condition. So that's one atmosphere and 60° Fahrenheit.
• we need to describe gas and oil phases at some pressure and temperature. We want to know the gas and oil densities and viscosities. You need the composition of the gas, and that is Oil-Gas-Ratio or Gas-Oil-Ratio.
• we need formation volume factor.

What is black oil table?
So, we're going to have pressure, viscosity of oil, B_O (oil formation volume factor), R_s (Gas-Oil-Ratio). These columns of numbers constitute the oil phase black oil table. It's half of the table, for the oil phase. Of course there's some temperature: you'll have one table for a given temperature. Second half of the table is for the gas phase, for the gas phase we have the gas viscosity, the B_G (gas formation volume factor), and the r_s (Oil-Gas-Ratio). So there's two parts here.
And then there's another two parts: each the oil phase has two parts and the gas phase has two parts.

Black-Oil PVT (20160301 Part 2)

Saturated oil phase: Bo and Rs

• Downward trend in Bo(p) is due to gas coming out of solition.
• The larger the deviation below the straight line or the linear trend of Bo-Pressure plot, it becomes more and more of a volatile oil. That means gas coming out of solution faster, for every bar below the bubble point you get more gas out of solution than if you follow the linear trend.
• The volume shrinkage is kind of directly proportional with how much gas comes out of solution.
• The shape of the Rs curve the shape is identical to the shape of the Bo. That means Rs - Bo plot is a straight line.

Saturated oil phase: viscosity

How do we get oil density?

Calculate from Rs and Bo.

Undersaturated oil phase

If the local pressure is greater than the oil's bubble point then it's undersaturated.

• You need to know what is the oil bubble point (or what is the oil Rs value).
• At all pressures greater than that bubble point the composition of the oil remains the same.

Black-Oil PVT (20160303 Part 1)

Discussion of saturated black oil table

Black oil PVT table is probably the most commonly used pvt model for describing oil and gas in petroleum engineering. So it's important to try to get a kind of handle on what it is. We started by talking about the black oil PVT properties for an oil phase at some pressure and temperature in the production system. This could be in the reservoir (in which case it's at the reservoir temperature) or it could be as the production is going up through the production pipe to the surface in which the temperature and the pressure could be changing. Or it could actually be describing the oil and gas flowing in a pipeline system where the pressure and temperature are quite a bit lower, traditionally lower, but both pressure and temperature are changing along the the flow lines, the gathering lines at the surface for the gas and the oil. So it's used in all of the these types of engineering calculations: Reservoir, Production, Transportation.
And the idea is that um you have an oil and gas either by itself, which it probably is undersaturated or if it's together gas and oil together in any point in the system then the gas and oil are saturated. So if gas and oil together they're saturated if gas is by itself somewhere in the system system it's very likely undersaturated although it could be at its dew point. If an oil is by itself then likely it's undersaturated, but it could be at its bubble point in which case we would formally define it as being saturated.

What are the black oil properties of the oil phase as a function of pressure? For the saturated system, in other words if the oil is saturated, that is the pressure by definition is at its Bubble Point. So if I say the saturated Bo is two okay at 4,000 PSI and some temperature, what is the bubble point of that oil? And then you're going to say: "ah he said it was saturated oil therefore the pressure 4,000 PSI must be its bubble point pressure". So if it's saturated then the pressure we're talking about in the table that you have is a function of pressure that means that the oil formation volume factor or the oil viscosity is the property at that particular oil's bubble point. The point is that in that saturated table the one thing you know for sure is that the pressure given in the table is the bubble point of that oil. And each of these saturated tables is going to have a maximum pressure (Pbi) and that maximum pressure will be the expected maximum bubble point you have for that for that system.
The composition of the oil is given by Rs. What is composition? It's the surface gas amount and the surface oil amount, and we deal in volumes. And if you know the ratio, then you kind of know the amount of each.
Then, the property Bo and viscosity are given. The change in BO and and viscosity is being caused by two things, as you lower the pressure in this table two things are changing: the pressure is changing and the composition of the oil is changing. Now, why did the viscosity increase as we lowered the pressure? Because you're losing this light component (methane and ethane and so on) and the light components when put into an oil will tend to lower its density and lower its viscosity. So the viscosity is going to be increasing because the oil is becoming heavier. The oil Formation Volume Factor (Bo) will be decreasing.

Discussion of undersaturated black oil table

If an oil is undersaturated is you have to know the pressure and you have to know its bubble point to understand that it's undersaturated.
If you have undersaturated then the first thing you know is the RS.
For each oil we need to have properties Bo and viscosity (for a specified RS value, for a specified bubble point) at pressures above its bubble point - that's the saturated table.

Black Oil plots

Rs vs. TVD

Many reservoirs have an initial vertical variation of Rs versus true vertical depth. Solution gas or ratio decreases, just because methane being lighter tends to go up and the heavy components C30+ tend to go down.
So in reality, for every saturated oil we have in the original table, we need the undersaturated set of properties. The undersaturated tables is kind of a set of tables.

Black-Oil PVT (20160303 Part 2)

Gas PVT properties

Let's just say that we're at a temperature, of course we have to keep that constant, and let's just say that this gas that we're looking at used to be together with this oil. Let's say that they were in equilibrium but we basically took away the oil and now, all that we are left with is this gas at pressure that's at the dew point. We take that gas to the surface through a surface process (whatever surface process you want to use - two-stage separator, three-stage separator, single stage separator).

The gas formation volume factor is going to be defined as the gas volume at temperature and pressure divided by what we end up with as gas at the surface.

And then while the gas is down here at temperature and pressure we can measure its viscosity (or calculate it). That pressure where we can measure or calculate gas viscosity would be at any pressure greater than or equal to the dew point.

If we went to a pressure below the dew point what would happen? It wouldn't be a gas in an oil and you can't really measure the viscosity of this gas and the oil together. So, we're going to restrict our viscosity to pressures that are greater than or equal to the the dew point.
And what is the dew point of the gas? It's the pressure where it used to be together with the oil.

So there are 3 properties in the Gas PVT table: OGR, Gas Forming Volume Factor, and Viscosity - all of them versus Pressure. And these three properties can be calculated at any pressure greater than or equal to the dew point of that gas.

Black-Oil PVT (20160303 Part 3)

Saturated gas phase black oil pvt

The undersaturated table is going to be a subset of tables for each particular saturated gas, it's going to have a set of undersaturated values, just like the oil.

How to create the saturated Gases and Saturated Oils?

• start with a sample, composition Z.
• fix the temperature.
• deplete, that means lower the pressure in stages that gives two phases - gas and oil - equilibrium.
• we create one point in the saturated table (measure Oil and gas properties).
• then we deplete this some way or another down to a new pressure - that can be from CCE, CVD or DLE all of those three methods would give us two phases at a lower pressure. We've got some amount of oil and some amount of gas, the amount doesn't really matter, because all we take out of this is the composition of the gas at that second pressure and the composition of the oil at the second pressure. Measure Oil and gas properties. Again we get saturated Bo pvt and at second P saturation and we get undersaturated Black oil pvt for pressures greater than this second saturation pressure.
• and then we just keep repeating this process until you get to whatever low pressure you want to get to (the lowest pressure you expect your system to be in at that temperature).

Phase densities

This is kind of important, because we don't really have a table of phase densities. We have to use this equation:


We going to assume a single surface oil density and a single surface gas density. Even though we actually calculate for each stage of the process and each temperature it would be different, but the models force you to pick a single number. This can lead to inaccuracies, the inaccuracy can be a half percent it might be 5%.

See also

Curtis Whitson Petroleum Engineering Videos

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/