In the next series of modules, we are going to look at how we can apply what we have learned so far to perform vapor/liquid equilibria calculations.
- First of all, we are going to review engineering systems and how the phenomenon of VLE is related to them,
- Then we will proceed by looking at how to describe the problem itself,
- We then will discuss the formulation the problem,
- And finally, we will discuss solution strategies.
These are the four main topics that we will look at in this module. As far as VLE is concerned, we can list a number of systems that are at the heart of petroleum fluid production that involve this phenomenon:
- LNG Processing
- NGL Processing
- Oil and LNG Tankers.
Vapor/liquid equilibrium pertains to all aspects of petroleum production with which we are concerned. It is no wonder, then, that we devote a new module to the subject itself.
Consider the case of a typical transmission pipeline. As gas is injected at the inlet, the pressure will drop continuously along the length of the pipeline, due to friction. Even though we usually think of liquid as forming with increasing pressure — i.e., upon compression — we have to recall that the phenomena of retrograde condensation (discussed in Module 4) takes place in hydrocarbon mixtures. Therefore, contrary to expectations, most single-phase natural gasses yield liquid upon expansion. Therefore, as pressure drops in the pipeline, liquid may drop out as the thermodynamic path crosses the dew point line and enters the phase envelope. In this case, what started as a single phase flow became two-phase flow within the system.
We also encounter this phenomenon in gas condensate reservoirs. Your initial reservoir conditions may be outside the phase envelope, but as you deplete the reservoir, your production path may take the system inside the two-phase region. In these previous two examples, the single-most important property with which you are concerned is the dew point. You want to know dew point, since you would like to know at which point of the pipeline or at which stage of production liquid may start to form.
We also may have an oil reservoir, where the initial pressure and temperature conditions place us in the single-phase liquid region. As you produce, you deplete the reservoir and enter the two-phase region by crossing the bubble point curve. At this point, we would like to know the bubble point of the system so that we may anticipate the appearance of a gas phase within an originally-all-liquid reservoir.
In all these cases, by taking a sample of the fluid to the lab, we may be able to find the composition of the fluid. Hence, in these kinds of problems, composition is usually known, and so are temperature and pressure. Your unknowns are the dew point or bubble point condition.
Suppose we are not interested in what is happening in the reservoir, but rather in what is happening at the surface. You would then like to know how much liquid or gas you will have in your separators. In this case, you are no longer interested in bubble points or dew points, but rather the extent of the phases: how much liquid and how much gas the reservoir will be able to deliver at the surface. In this case, the composition of what is coming to your separator may be known, and the pressure and temperature of operation of each separation stage may be specified. We would want to know the quality and the quantity of what is coming out; that is, we need the compositions of the gas and oil that leave the separators and the flow rates of gas (MSCF/D) and oil (STB/D).