Q913 rfp w3 lec 12, Separators and Phase envelope calculations

Reservoir Fluid Properties Course (1st Ed.)

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http://www.about.me/AlamiNia

1. PT-Flash Process

2. Equilibrium Ratios

3. PT-Flash Calculations

4. Mixture Saturation Points

2013 H. AlamiNia Reservoir Fluid Properties Course: Separators and Phase Envelope Calculations 2

1. Mixture Saturation Points Calculation

2. Surface Separation

3. Phase Envelope

4. Phase Identification


Bubble Point Pressure Calculations


Dew Point Temperature Calculation


Bubble and Dew Points

Bubble and dew points may also be calculated for a specified pressure in which case the temperature is the unknown parameter to be determined.

Though in principle simpler than PT-flash calculations, bubble and dew point calculations are complicated by the fact that it is not generally known in advance whether the mixture considered really has a bubble or a dew point at the specified P or T.


Reality vs. Calculations

In next slide, the bubble point line ends in the critical point (CP) at a temperature of around − 60 ° C. A bubble point calculation for a higher temperature

should therefore give the answer that no bubble point can be located.It can however be quite hard to distinguish cases with

no saturation point from cases for which the saturation point calculation is causing numerical problems. Figure also reveals that the natural gas considered has

two dew point pressures in a temperature interval above the critical temperature. This may cause convergence problems in a saturation point

calculation, and either the upper or lower dew point will be located, at best.


Separator Calculations

The manner in which the hydrocarbon phases are separated at the surface influences the stock tank oil recovery.The principal means of surface separation of gas and oil

is the conventional stage separation. Stage separation is a process in which gaseous and liquid hydrocarbons are flashed (separated) into vapor and liquid phases by two or more separators. These separators are usually operated in series at

consecutively lower pressure. Each condition of pressure and temperature at which hydrocarbon phases are flashed is called a stage of separation. Traditionally, the stock-tank is normally considered a separate stage of separation.


A Schematic Illustration of 2 & 3 Stage Separation Processes


Types of Gas-Oil Separation

Mechanically, there are two types of gas-oil separation:''Differential'' separation

''Flash'' or ''equilibrium" separation

To explain the various separation processes, it is convenient to define the composition of a hydrocarbon mixture by three groups of components:The very volatile components ("lights''), such as nitrogen,

methane, and ethane.

The components of intermediate volatility, i.e., intermediate, such as propane through hexane.

The components of less volatility, or the ''heavies," such as heptane and heavier components.


Differential Separation in Reality

In the differential separation, the liberated gas (which is composed mainly of lighter components) is removed from contact with the oil as the pressure on the oil is reduced.

When the gas is separated in this manner, the maximum amount of heavy and intermediate components will remain in the liquid, there will be minimum shrinkage of the oil and, therefore, greater stock-tank oil recovery will occur.

This is due to the fact that the gas liberated earlier at higher pressures is not present at lower pressures to attract the intermediate and heavy components and pull them into the gas phase.


Flash Separation in Reality

In the flash (equilibrium) separation, the liberated gas remains in contact with oil until its instantaneous removal at the final separation pressure.

A maximum proportion of intermediate and heavy components are attracted into the gas phase by this process and this results in a maximum oil shrinkage and, thus, a lower oil recovery.


Stage Separation

In practice, the differential process is introduced first in field separation when gas or liquid is removed from the primary separator.

In each subsequent stage of separation, the liquid initially undergoes a flash liberation followed by a differential process as actual separation occurs.

As the number of stages increases, the differential aspect of the overall separation becomes greater. The purpose of stage separation then is to reduce the

pressure on the produced oil in steps so that more stock-tank oil recovery will result.


Separator Calculations Goals

Separator calculations are basically performed to determine: Optimum separation conditions: separator pressure and

temperature

Compositions of the separated gas and oil phases

Oil formation volume factor

Producing gas-oil ratio

API gravity of the stock-tank oil


High and Low Separator Pressure

If the separator pressure is high, large amounts of light components will remain in the liquid phase at the separator and be lost along with other valuable components to the gas phase at the stock-tank.

On the other hand, if the pressure is too low, large amounts of light components will be separated from the liquid and they will attract substantial quantities of intermediate and heavier components.


Optimum Separator Pressure

An intermediate pressure, called ''optimum separator pressure," should be selected to maximize the oil volume accumulation in the stock-tank. This optimum pressure will also yield:

A maximum in the stock-tank API gravity

A minimum in the oil formation volume factor (i.e., less oil shrinkage)

A minimum in the gas-oil ratio


Effect of the Separator Pressure on API, Bo, and Gor


Phase Envelope of Natural Gas


Stability Analysis

A flash calculation presents the problem that the number of phases is generally not known in advance.

An important element of a flash calculation is therefore determination of the number of phases present.This may be accomplished by carrying out a stability

analysis. (Using Gibbs free energy concept)

The stability analysis may be extended to test for the possible presence of three or more phases


Phase Envelope Calculations

A phase envelope may in principle be calculated by performing a series of saturation point calculations, but if the complete phase envelope is needed, this method is not to be recommended.

It is both time consuming and likely to cause convergence problems at higher pressures and near the critical point.

The procedure outlined by Michelsen (1980) may be used instead.


Michelsen’s Technique

Michelsen’s technique for construction of phase envelopes is not limited to dew and bubble point lines.

It may also be used to construct inner lines in a phase envelope, i.e., the PT values for which the vapor mole fraction equals a specified value.



Phase Envelope of Oil Mixture Calculated Using SRK EoS

It is seen that the dew and bubble point lines as well as the inner lines

meet in the critical point at which the gas and liquid phases are

indistinguishable and the vapor mole fraction β may therefore be

assigned any value between 0 and 1.

Note about Critical Point

Next slide shows the results of phase envelope calculations performed for the gas condensate mixture calculated using PR equation of state.

No critical point is located.

The mixture considered forms three phases in a PT region at low temperatures. The critical point would have been located near this region, had the mixture only formed two phases.

This example illustrates the fact that a hydrocarbon mixture will not always have a critical point.


Phase Envelope of Gas Condensate Mixture


Two Phase Identification

For water-free mixtures, liquid–liquid splits are rarely seen for temperatures above 15°C.

If a PT flash calculation for an oil or gas mixture shows presence of two phases, The one with lower density is usually assumed to be gas

or vapor, and

The one with higher density is assumed to be liquid or oil.


One Phase Identification

In the case of a single-phase solution, it is less obvious whether to consider this single phase to be a gas or a liquid. There exists no generally accepted definition to

distinguish a gas from a liquid.

Because the terms gas and oil are very much used in the oil industry, it is however of interest to try to establish a reasonable criterion for distinguishing between the two types of phases.


One Phase Identification

Next slide shows the phase envelope of a volatile oil. Four single-phase conditions are marked on the figure (points 1 to 4). Point 1 is just outside the two-phase region on the bubble

point side. Therefore, it is natural to classify the mixture at these conditions as being a liquid.

Point 4 is also just outside the two-phase region, but on the dew point side, suggesting that the mixture is gaseous at these conditions.

At the conditions of points 2 and 3, it is less obvious whether the mixture is to be considered a gas or a liquid.

Point 2 is located at a temperature lower than the critical temperature. This could suggest that the mixture in point 2 is a liquid.

Similarly, point 3 is at a temperature higher than the critical temperature, suggesting that the fluid in point 3 is a gas.


Phase Identification of Single-Phase Mixtures


Liquid Phase Identification Criterion

This leads to the following suggestion for a phase identification criterion

Liquid 1. If the pressure is lower than the critical pressure and

the temperature lower than the bubble point temperature.

2. If the pressure is higher than the critical pressure and the temperature lower than the critical temperature.


Gas Phase Identification Criterion

Gas1. If the pressure is lower than the critical pressure and

the temperature higher than the dew point temperature.

2. If the pressure is higher than the critical pressure and the temperature higher than the critical temperature.


Possible Phase Identification Criterion


1. Pedersen, K.S., Christensen, P.L., and Azeem, S.J. (2006). Phase behavior of petroleum reservoir fluids (CRC Press). Ch6.


1. The Estimation of Physical Properties

2. EoS Applications

3. Thermodynamic Properties


Q913 rfp w3 lec 12, Separators and Phase envelope calculations

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