5. Bubble Point Pressure Calculations
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Reservoir Fluid Properties Course: Separators and Phase Envelope Calculations
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6. Dew Point Temperature Calculation
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Reservoir Fluid Properties Course: Separators and Phase Envelope Calculations
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7. 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.
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Reservoir Fluid Properties Course: Separators and Phase Envelope Calculations
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8. 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.
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Reservoir Fluid Properties Course: Separators and Phase Envelope Calculations
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9.
10. 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.
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Reservoir Fluid Properties Course: Separators and Phase Envelope Calculations
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11. A Schematic Illustration of
2 & 3 Stage Separation Processes
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12. 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.
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Reservoir Fluid Properties Course: Separators and Phase Envelope Calculations
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13. 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.
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14. 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.
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Reservoir Fluid Properties Course: Separators and Phase Envelope Calculations
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15. 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 stocktank oil recovery will result.
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Reservoir Fluid Properties Course: Separators and Phase Envelope Calculations
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16. 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
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Reservoir Fluid Properties Course: Separators and Phase Envelope Calculations
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17. 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.
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Reservoir Fluid Properties Course: Separators and Phase Envelope Calculations
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18. Optimum Separator Pressure
An intermediate pressure, called ''optimum
separator pressure," should be selected to
maximize the oil volume accumulation in the stocktank. 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
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Reservoir Fluid Properties Course: Separators and Phase Envelope Calculations
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19. Effect of the Separator Pressure on
API, Bo, and Gor
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20.
21.
22. Phase Envelope of Natural Gas
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Reservoir Fluid Properties Course: Separators and Phase Envelope Calculations
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23. 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
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Reservoir Fluid Properties Course: Separators and Phase Envelope Calculations
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24. 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.
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Reservoir Fluid Properties Course: Separators and Phase Envelope Calculations
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25. 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.
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26. 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.
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Reservoir Fluid Properties Course: Separators and Phase Envelope Calculations
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27. 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.
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Reservoir Fluid Properties Course: Separators and Phase Envelope Calculations
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28. Phase Envelope of
Gas Condensate Mixture
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29.
30. 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.
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Reservoir Fluid Properties Course: Separators and Phase Envelope Calculations
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31. 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.
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32. 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.
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34. 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.
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Reservoir Fluid Properties Course: Separators and Phase Envelope Calculations
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35. Gas Phase Identification Criterion
Gas
1. 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.
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Reservoir Fluid Properties Course: Separators and Phase Envelope Calculations
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