Process Gasoline Stripping

PROCESS
GASOLINE STRIPPING
TRAINING MANUAL
COURSE EXP-PR-PR170
Revision 0.1
Exploration & Production
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Gasoline Stripping
LE PROCESS
GASOLINE STRIPPING
CONTENTS
1. OBJECTIVES ..................................................................................................................4
2. FUNCTION OF GASOLINE STRIPPING.........................................................................5
2.1. WHAT IS GASOLINE STRIPPING USED FOR? ......................................................5
2.2. FINISHED PRODUCT...............................................................................................7
2.2.1. Composition of natural gas................................................................................7
2.2.2. Source of the condensates................................................................................8
2.2.2.1. The family of paraffins or alcanes ................................................................8
2.2.2.2. Normal trade names of light natural gas hydrocarbons..............................10
2.2.3. Reminder on interpreting the phase envelope.................................................11
2.2.4. Specifications required for Commercial Gas ...................................................14
2.2.5. Gas transport specifications ............................................................................16
2.2.6. Specifications required for the Condensates removed from NG......................18
2.2.7. Effect of the components of a gas on its behaviour.........................................19
2.3. EXAMPLE ...............................................................................................................20
3. DIFFERENT TYPES ......................................................................................................22
3.1. COOLING BY ISENTHALPIC EXPANSION (EXPANSION THROUGH A VALVE).23
3.1.1. General............................................................................................................23
3.1.2. General description .........................................................................................23
3.2. COOLING BY POLYTROPIC EXPANSION (EXPANSION TURBINE) ...................26
3.3. COOLING BY A COOLER ......................................................................................28
3.3.1. General............................................................................................................28
3.3.2. Cooler operation..............................................................................................28
3.3.3. External refrigeration loop operating principle .................................................30
3.4. CONDENSATE EXTRACTION PROCESS BY ABSORPTION...............................32
4. ADVANTAGES AND DISADVANTAGES OF THE DIFFERENT PROCESSES ............34
4.1. PROCESS USING THE JOULE-THOMSON VALVE..............................................34
4.1.1. Advantages .....................................................................................................34
4.1.2. Disadvantages.................................................................................................34
4.1.3. Function...........................................................................................................35
4.2. ISENTROPIC EXPANSION ....................................................................................35
4.2.1. Advantages .....................................................................................................35
4.2.2. Disadvantages.................................................................................................36
4.2.3. Function...........................................................................................................36
4.3. REFRIGERATION BY A COOLER..........................................................................36
4.3.1. Advantages .....................................................................................................37
4.3.2. Disadvantages.................................................................................................37
5. PROCESS LOCATION ..................................................................................................38
6. REPRESENTATION ......................................................................................................40
6.1. PROCESS FLOW DIAGRAM..................................................................................40
6.2. Typical example: External refrigeration loop at the Peciko gas production field......42
6.2.1. General............................................................................................................42
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6.2.2. Description of the primary separation ..............................................................42
7. HOW DOES IT WORK?.................................................................................................55
7.1. Description of a simple refrigeration loop ................................................................55
8. CONDENSATE EXTRACTION UNIT OPERATION ......................................................57
8.1. OPERATING PARAMETERS .................................................................................57
8.1.1. Operating parameters of a unit with external refrigeration loop .......................57
8.1.2. Operating parameters of a unit with Joule-Thomson valves............................58
9. TROUBLESHOOTING...................................................................................................59
9.1. Extraction unit with Joule-Thomson valves .............................................................59
9.2. Extraction unit with external refrigeration loop.........................................................59
10. EXERCISES ................................................................................................................62
11. LIST OF FIGURES ......................................................................................................64
12. LIST OF TABLES ........................................................................................................65
13. CORRECTIONS FOR THE EXERCISES ....................................................................66
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1. OBJECTIVES
After studying the Gasoline stripping module the operator must know:
The reasons why it is necessary to extract Condensates from Natural Gases
The principle resulting in the extraction of these Condensates
The three most commonly-used processes for Condensate extraction
How to describe a standard Condensate extraction unit
How to describe the different parts of the external refrigeration loop
The main operating parameters to be respected
The common problems which may arise in this type of unit
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2. FUNCTION OF GASOLINE STRIPPING
2.1. WHAT IS GASOLINE STRIPPING USED FOR?
When extracting natural gas, the expansion for example at the wellhead, reduces the
temperature thus condensing the C5 to C8 hydrocarbons which were in the gas state in the
reservoir conditions.
The recovered liquids, called natural gas "condensates", correspond to an extremely light
oil with a very high value (giving gasoline and naptha).
All the rest (C1 to C4 hydrocarbons, CO2, H2S and He) are in the gas state at ambient
temperature and transported by gas pipeline to a gas treatment plant. There must
therefore be two collection systems, one for the gas and one for the condensates.
Réinjection
Gas lift
Puits
producteurs
Traitement
sur champ
pour
transport
par pipeline
Traitement
pour
liquéfaction
Pipeline
ou réseau de
consommation
Méthaniers
G.N.L.
Constituants
indésirables
Gisement
de gaz naturel
Constituants
indésirables
Gaz associé
C1+C2+C3+C4
Traitement
sur champ
pour
transport
par bateau ou
pipeline
Gisement
de pétrole brut
Traitement
pour livraison
à un réseau de
consommation
Pipeline
ou bateau
Pétrole brut
stabilisé,
déshydraté et
dessalé
Constituants
indésirables
Figure 1: Simplified diagram of the treatment operations to be carried out on the
production field
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So why do we have to remove the condensates from natural gas?
To allow the gas to be recompressed for export we must get rid of the condensates
likely to seriously damage the recompression units.
The heavy components in the gas (C5+) can condense in the transport lines and
reduce the cross sectional area of the gas lines and therefore increase the pressure
drops and the unscheduled production shutdowns. It is thus essential that the
commercial gas standards and specifications are respected.
Danger: For the consumers (a gas burner must not be fed with liquid otherwise the
flame goes out and there is a risk that the gas cloud formed will explode...
Finally, as we saw previously, these condensates correspond to an extremely light
oil. This high added value product will be used in the refineries or reintroduced into
the crudes
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2.2. FINISHED PRODUCT
In this chapter we will look at the composition of natural gases, the source of the
condensates and finally we will give a few reminders about interpreting the phase
envelope to gain a good understanding of the condensation phenomenon.
Finally, as the title of this chapter indicates, we will look at the specifications required for a
commercial natural gas according to the European Consortium, and the specifications
required for the condensates.
2.2.1. Composition of natural gas
Each natural gas, even although it mainly consists of methane, has a composition which
varies from one gas field to another. The following table shows the compositions of the
natural gas effluents.
San Salvo
Cupelio
Reserve 2
Frigg
Hassi
R'Mel
0.01
-
21.62
-
0.40
-
5.84
0.19
-
-
0.06
-
-
9.30
-
0.89
8.40
0.30
0.21
C1
69.00
73.60
81.30
60.18
95.59
83.72
C2
3.00
10.20
2.85
5.49
3.60
6.76
C3
0.90
7.60
0.37
2.78
0.04
2.09
C4
0.50
5.00
0.14
0.94
0.01
0.82
C5
C6+
0.20
0.30
1.70
1.90
0.04
0.05
0.33
0.20
0.06
0.22
0.15
Composition
(% volume)
Deep
Lacq
N2
He
1.50
-
-
H2S
15.30
CO2
Parentis Groningue
Table 1: Examples of natural gas compositions
As we have just seen, the natural gas fields can have very different compositions.
Therefore they are classified into different categories according to their composition: dry
gas, wet gas or even condensate gas.
The following diagram shows the risks liquid in the gas on the different types of gas fields.
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P
B
300
A
C
PC
200
Cheminement en P et T
S
S
0
TCC 100
T (° C)
Figure 2: Characterisation of a gas field
A = Dry gas (never liquids)
B = Wet gas (liquids on the surface)
C = Gas Condensates (can deposit liquids in the reservoir) => downgrading
2.2.2. Source of the condensates
They are part of the family of paraffins (waxes) with an atomic number greater than four
(C5+).
Reminders: What are paraffins?
2.2.2.1. The family of paraffins or alcanes
These are "saturated" hydrocarbons since their structure only contains single bonds.
Chemical formula: Cn H2n + 2 (indicates that each carbon atom is combined with 2n + 2
atoms of hydrogen. e.g.: CH4, C2H6, C3H8).
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There are two types of alcanes which have the same formula but different structures:
in a straight chain for the normal-paraffins,
in a straight chain with straight branches for the iso-paraffins.
Paraffins with number of carbon atoms limited to four
These are the main components of the gases supplied to the gas distribution networks.
These include: methane C1, ethane C2, propane C3 and the butanes C4 (normal+iso).
They are in the gas state at normal atmospheric pressure and temperature (15 °C) and
and are called "light" hydrocarbons.
Paraffins with over 4 carbon atoms
They are liquid at normal atmospheric pressure and temperature (15 °C) and are called
"heavy" hydrocarbons.
They are grouped under the designation "C5+", they are the basic components of
condensates or natural gasolines and of crude oils.
They are stored at atmospheric pressure and transported by pipeline or ship.
It is these which we will cover in this course.
Paraffins with over fifteen carbon atoms
They are solid at atmospheric pressure and temperature (15 °C).
They are highly viscous and tend to jell in normal storage and transport conditions for high
concentrations and thus specific treatment measures are required.
They are called "paraffin-based" hydrocarbons.
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2.2.2.2. Normal trade names of light natural gas hydrocarbons
Méthane
C1
GNL
LNG
Ethane
Propanes
Butanes
Pentanes
C2
C3
C4
C5
Hexanes
Benzène
C6
Heptanes
Toluène
C7+
LGN
NGL
GPL
LPG
PROPANE
BUTANE
CONDENSATS, GASOLINE
Table 2: Normal trade names of light natural gas hydrocarbons
LNG: Liquefied Natural Gas
NGL: Natural Gas Liquids
LPG: Liquefied Petroleum Gas
Note: LNG sometimes also contains LPGs or even other light natural gas hydrocarbons.
They are left in it since the fractionation phase takes place at the final customer's (dashed
arrow in Table 2).
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2.2.3. Reminder on interpreting the phase envelope
When we are dealing with a hydrocarbon, we can guess its behaviour according to P and
T on a phase envelope diagram as shown below.
CB
Pcb
Liquide
P
Courbe
de Bulle
Point de Bulle
Liquide
+
Vapeur
0%
Vaporisé
Domaine Critique
CT
Point de Rosée
Courbe
de Rosée
Vapeur
100 %
Vaporisé
tb
tr tCT
T
Figure 3: Phase envelope (reminders)
Reminders and definitions of the phase envelope environment.
Bubble temperature (BP) of a liquid which is heated at constant pressure: temperature
at which the first vapour bubble appears.
Bubble pressure (P) of a liquid which is expanded at constant temperature: pressure at
which the first vapour bubble appears.
Dew point temperature (DP) of a gas which is cooled at constant pressure:
temperature at which the first liquid bubble appears.
Dew point curve: all the dew points.
Bubble point curve: all the bubble points.
Critical point C: point common to the two curves (corresponds to the critical
pressure Pc and to the critical temperature Tc - see figure 4).
Phase envelope: all the bubble point and dew point curves.
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Although little used, it is designated by:
Cricondenbar (CB): the phase envelope point which has the highest pressure Pcb.
Cricondentherm (CT): the phase envelope point which has the highest
temperature tCT.
Reminders of the condensation phenomenon of a hydrocarbon mixture with respect to the
phase envelope:
Pc
Tc
Figure 4: Phase envelope
From this diagram we can see:
a. A constant pressure when we start from point A, and by reducing the temperature, liquid
begins to appear when we reach B.
b. A constant temperature when we start from point A’, and by reducing the pressure,
liquid also begins to appear when we reach B’.
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c. When we start from point X, and by reducing the temperature and pressure, liquid
begins to appear when we reach X’. This is the case, for example, for the production when
we go from reservoir conditions to surface conditions. Similarly, it is also the case when we
go from the wellhead to storage for example.
During production (from bottom hole to the surface), the pressure falls (due to the flow and
the variation in level) and when this is accompanied by a temperature drop (linked with the
expansion of the gases and, if this is the case, the partial vaporisation of the liquid)
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2.2.4. Specifications required for Commercial Gas
The extraction of the Condensates is the main consequence of the specifications imposed
for a natural gas to be marketable.
The following table gives the specifications required for commercial gas.
Table 3: Specifications for commercial gas
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Comments from the previous table giving the specifications of commercial gas:
H2S content: Generally from 1.5 to 4 ppm by vol. maximum
Its high toxicity means that specific treatments are required to reduce its level
according to the transport or commercial specifications.
Toxicity risks, in addition to the ignition hazard linked with natural gas, when it is
permanently or accidentally vented to atmosphere.
Total sulphur and other contaminants: Maximum levels of sulphur compounds:
from 50 to 150 mg/Sm3 maximum
The following are also considered to be impurities: the sulphur compounds which
are the most problematic but also oxygen, nitrogen and even metal atoms such as
nickel and vanadium.
Note: oxygen is not a natural contaminant of the produced gas but it often appears
in the analyses.
Its appearance is due to the air ingress into the low pressure installations. It may be
corrosive and in certain proportions also form an explosive mixture with the gas.
CO2 content: From 2 to 3 molar % maximum
The CO2 reduces the heating value of the natural gas since it does not supply any
combustion heat.
It is thus extracted, generally when it is removed at the same time as the H2S in
different processes.
It must be removed when the gas has to be cooled in certain temperature domains
(mainly in the case of liquefaction –LNG).
(crystallisation ⇒ blockages).
Dew point
o Water dew point: of the order of – 15 °C at 70 bar.
o Hydrocarbon dew point: of the order of – 2 °C at 70 bar.
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Heating value
o Net Heating Value: It is the amount of heat given off by the complete
combustion at constant pressure (1.01325 bar), of 1 kg of liquid fuel or of
1 m3 of gas (normal conditions).
The combustion products are reduced to a temperature of 0°C and the water
from the water-saturated fuel is assumed to remain in vapour state at this
temperature.
o Gross Heating Value: Same definition as for the Net Heating Value but the
water is assumed to be completely condensed at 0°C.
2.2.5. Gas transport specifications
Water dew point
It is expressed in °C for a given pressure (e.g.: - 15°C at 70 bar a).
E.g.: the gas exported by pipeline from the Frigg field imposes - 5°C at 140 bar a.
which corresponds to imposing a maximum water content in the gas.
The transport problems linked with the presence of water in the gas are the
following:
-
the water in liquid state is responsible for most forms of corrosion when it is
associated with acid gases (H2S and CO2) or with salts (calcium carbonates),
-
risk of hydrate formation.
The hydrate formation phenomenon is a major problem in natural gas
production and transport.
It causes pipes and equipment to become blocked and therefore
production stops and risks of overpressure for the installations.
-
formation of water slugs.
The water deposits due to condensation in the pipes or the
entrainments of free reservoir water can create large pressure drops
with risks of erosion and water hammer due to liquid slugs.
Liquid H. C. content
The condensate level is expressed in g/Sm3.
Equivalent to the hydrocarbon dew point in °C.
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E.g.: the transport of produced gas by pipeline on the Frigg field imposes a
maximum of 5 g/Sm3.
Which corresponds to a hydrocarbon dew point of 7 °C at 50 bar a.
When a condensate natural gas is present we can have deposition of liquid
condensates in the pipes.
The heavy hydrocarbons in the gas (C5+) can condense in the transport lines
reducing the cross sectional area of the gas lines and therefore increase the
pressure drops and the unscheduled production shutdowns.
Definition of the Wobbe index:
This index is used in domestic gas applications to determine the supply pressures to be
applied to an injector to conserve the power for variable pressures.
It is defined as the ratio of the Gross Heating Value (GHV) of the gas (kWh/m3) over the
square root of the density of the fluid concerned:
W = PcS / d0.5
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2.2.6. Specifications required for the Condensates removed from NG
For various safety reasons, for transport, handling and use there are also specifications to
be respected for the characteristics of the removed Condensates.
These specifications are indicated in the following table:
Table 4: Specifications for condensates
RVP: Reid Vapour Pressure
The Reid Vapour Pressure is the pressure developed by the vapours of an oil product
contained in a standardised aerosol can at a temperature of 37.8°C. This test particularly
applies to automotive fuels.
The Reid Vapour Pressure directly depends on the content of volatile components in the
product at high vapour pressure.
The RVP is also used to characterise a fuel's ability to vaporise.
Not to be confused with the true vapour pressure. It is directly linked to its composition and
the more volatile compounds the product contains, the higher it is. Limiting a product's
vapour pressure is thus equivalent to limiting the quantity of light products it can contain.
This limitation is obviously directly related to the storage characteristics and concerns their
pressure resistance.
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2.2.7. Effect of the components of a gas on its behaviour
The composition of the gas has a large impact on its behaviour and on the shape of its
phase envelope on a pressure - temperature representation. The following graph
"Example of the shape of a gas envelope according to its composition" shows this effect.
The wider the "volatility" range of the hydrocarbons composing the mixture, the larger the
phase envelope (and the higher the cricondenbar).
These scales increase with the number of carbon atoms (also called the carbon number)
in the heaviest component.
Figure 5: Example of the envelopes for a gas and its composition in molar %
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2.3. EXAMPLE
As we have just seen, when the fluid flows between the reservoir and the primary
separator its pressure drops.
In the well production tubing (weight of column + pressure drops)
In the collection line (pressure drops + difference in level).
This pressure drop is also accompanied by a large fall in temperature which results in the
formation of liquid water and sometimes condensates.
If we represent the change in pressure and temperature in a gas treatment installation in
the phase envelope diagram (following diagram), we note:
the first drop of condensed hydrocarbon takes place at point A. In this example,
point A is located on the dew point curve quite simply because the gas arriving
here is from a separator (primary separator) where the condensates already
generated upstream have been removed.
the phase envelope changes as the heavy hydrocarbons condense, until a phase
envelope is obtained which guarantees that there is no longer any condensation
in the installation downstream of the treatment.
Figure 6: Example of cooling
In this example we start from point A.
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Segments AB and BC which are two exchangers in series (gas cooling). The
pressure remains almost constant (low pressure drops) and the temperature
rapidly decreases. If we enter the phase envelope this causes the heavy
hydrocarbons to condense. These will be drawn off in the separators at points B
and C.
Segment CD represents an expansion of the HP gas through a valve. This
expansion cools the gas (Joule – Thomson effect) and a new heavy hydrocarbon
extraction is carried out downstream of the expansion valve (point D).
Segment DE represents a recompression of the gas which also increases its
temperature.
Segment EF represents the pressure drops at ambient temperature in the
system.
We note that our objective is reached since the aim of the operation is to prevent
condensation in the FE system. Point E is located outside the new gas phase envelope.
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3. DIFFERENT TYPES
The C5+ are extracted mainly by cooling the gas. This cooling condenses the heaviest
hydrocarbons and the recovery rate basically depends on the temperature drop achieved.
The following condensate extraction processes are used:
cooling by isenthalpic expansion (expansion through a valve),
cooling by polytropic expansion (expansion turbine),
cooling by a cooler (cooling by external mechanical cycle).
The following diagram shows the effect of the different condensate extraction processes
by cooling on the natural gas phase envelope at the primary separation outlet.
Pression
Ps
A
B
C
D
(2)
(1)
(2)
(2)
Ts
Température °C
Figure 7: Representation of the effect of the different gasoline stripping processes by
cooling on the natural gas phase envelope at the primary separation outlet
AB: treatment by external cooling.
AC: treatment by expansion turbine.
AD: treatment by expansion through a valve.
The purpose of condensate removal is to condense the heaviest hydrocarbons. This
amounts to modifying the phase envelope which flattens towards the left of the diagram
and the hydrocarbon liquid recovery rate basically depends on the temperature reached.
In this chapter we will describe the different condensate extraction processes described
briefly above and we will also cover condensate extraction by absorption.
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3.1. COOLING BY ISENTHALPIC EXPANSION (EXPANSION THROUGH A
VALVE)
3.1.1. General
Also called "Cold frac", the expansion of a high pressure gas through a valve cools the gas
by Joule-Thomson effect (approximately 0.5 °C per bar).
This simple process requires a DEG or MEG injection upstream of the valve, if there is no
dehydration step upstream, to prevent hydrate formation. For information, we often avoid
using MeOH since there are high losses in the gas.
The condensates (mostly C5+) are recovered at a ow rate in an LTS cold separator (Low
Temperature Separator).
If necessary, the gas can then be recompressed (this will depend on the initial pressure
and the export pressure).
3.1.2. General description
The gas leaving the primary separator is:
precooled through a Separation Gas (rich) / Lean Gas exchanger (Gas-Gas
Exchanger in Figure 2)
cooled by isenthalpic expansion in the J-T valve(s) where part of the HCs are
condensed, then recovered in liquid form in the Cold Separator. Their Vapour
Pressure can then be stabilised in a stabilisation column
the cold Lean Gas leaving the Cold Separator is reheated through the Separation
Gas (rich) / Lean Gas exchanger where it recovers the calories from the Rich Gas.
This gas can then undergo other operations depending on its planned use, like for
example, fractionation to extract the LPGs (see the extraction of the C2 for a polyethylene
manufacturing base as at the Karstoe site in Norway) then Recompression of the C2 and
(C1) components and export by pipeline at the other end of which it can be liquefied into
LNG or distributed in a Natural Gas (NG) network.
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JT Valve
Figure 8: Principle of extracting Condensates from NG by isenthalpic expansion through a Joule-Thomson
valve
Note: the temperature drop through a Joule-Thomson valve is of the order of 0.5°C /
1Bar).
The following phase diagram for the condensate recovery using a Joule-Thomson valve
shows the phase envelope for the rich natural gas leaving the gas treatment plant primary
separator respectively in Alwyn (UK) and Heimdal (Norway). (The primary separator is the
first separator downstream of the wellhead).
Figure 9: Phase diagram for condensate recovery using a Joule-Thomson valve
The point of the first arrow shows the temperature reduction through the Rich Gas / Lean
Gas exchanger.
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The head of the second arrow on the lean gas phase envelope corresponds to the cold
separator conditions, whereas the origin of the second arrow (or the head of the first
arrow) corresponds to the conditions upstream of the Joule-Thomson valve.
Generally, the exiting gas must be recompressed to the export pipeline admission
pressure if it was expanded to a lower pressure.
Thus the Joule-Thomson process is very useful when the gas exiting the wellhead is
produced at a very high pressure and can be expanded (by the J-T process) to the export
line pressure without being recompressed.
If the gas must be recompressed, the J-T process is penalise by the compulsory
recompression.
The Rich and Lean gas composition table shows that the C5+ content of the gas has fallen.
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3.2. COOLING BY POLYTROPIC EXPANSION (EXPANSION TURBINE)
This process is based of the use of
an expansion turbine (expander)
through which the gas expands and
cools.
Figure 10: Turbo-expander at the
Lacq plant (France)
The work done by the gas energy is
recovered on the turbine shaft which
is coupled to a compressor.
By comparison with the J-T valve, the expansion in a turbine reduces the temperature
much faster (1°/bar of pressure drop for the J-T valve and approximately twice that for the
expansion turbine). Since we benefit from the Joule-Thomson effect + the fact that the gas
performs work (rotates the turbine) which makes it lose energy (hence a second reason for
reducing the temperature !!!)
The use of an expansion turbine means that the gas must be dehydrated upstream of the
turbine (molecular sieves or TEG absorption).
Déshydratation
au glycol
ou tamis
moléculaire
Gaz aux
spécifications
Expansion
Compression
Liquide
Figure 11: Diagram of polytropic expansion (expansion turbine)
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Figure 12: Diagram of the Turboexpander at the Lacq plant
Courbe de bulle
4’
Courbe de rosée
Figure 13: Expansion by turboexpander - Expansion through a valve
Expansion by expander → Closer to the bubble curve → increased recovery of
condensates
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3.3. COOLING BY A COOLER
3.3.1. General
This is the most conventional type of treatment. It is used when a good recovery rate is
required.
The equipment necessary is well known and a wide range of temperatures and pressures
can be used.
Injection
glycol
Gaz ou
spécification
Compression (option)
Réfrigération
externe
Glycol vers régénération
Liquide
Figure 14: Diagram of the condensate extraction process using an external refrigeration
loop
3.3.2. Cooler operation
The refrigerant goes through a conventional cycle consisting of compression,
condensation and expansion, and is then vaporised by thermal exchange with the gas to
be cooled (supply of latent heat) which flows through the tube cores.
The refrigerant is then sent to the compressor for a new cycle.
The main refrigerants used are:
propane (to condense LPGs),
ammonia (to condense LPGs),
freon (LTS temperature > -10°C),
propane (often used since it is produced on-site but has the disadvantage of being
combustible),
methane (very low temperatures).
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Condenseur
Q1
C
B
WM
Vanne
Compresseur K
Q2
D
A
Évaporateur
Q1
Pression
Liquide
C
HP
B
Gaz
BP
A
D
Q2
WM
Enthalpie
Figure 15: Cooling cycle diagram
Key:
CD :
DA :
AB :
BC :
Q1 :
Q2 :
Wm :
isenthalpic expansion in the valve
refrigerant evaporator exchanger (cooling of the treated gas Q2)
isentropic compression
cooling by water or air (Q1) and refrigerant condensation
heat released at the condenser
thermal exchange with the gas to be cooled
energy necessary for recompression
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3.3.3. External refrigeration loop operating principle
The gas/gas exchanger recovers the additional cooling from the Lean Gas leaving the cold
separator and uses it in the reverse direction to the warm inlet gas, as shown in the
following diagram. This phase precools the process gas before it enters the exchanger
(chiller) cooled by the external refrigeration loop.
Figure 16: Diagram showing the principle of an external refrigeration loop
The temperature of the cold lean gas leaving this exchanger is close to that of the warm
rich gas entering this same exchanger.
The refrigerant liquid cools the process gas in a "chiller" which is typically a shell heat
exchanger consisting of a set of tubes contained in a cylindrical body.
The process gas flowing through the chiller tubes gives its calories to the liquid refrigerant
surrounding the tubes.
The refrigerant boils and exits the chillers vapour zone mainly in the form of saturated
vapour.
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Figure 17: Phase diagram for condensate recovery using an external refrigeration loop
The rich gas composition table shows that the C5+ content of the gas has fallen.
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3.4. CONDENSATE EXTRACTION PROCESS BY ABSORPTION
In the lean oil absorption process the "lean oil" which is of the kerosene type (a mixture of
nonane, decane and heavier) is used to recover the butane and part the propane present
in the rich gas.
The inlet gas is normally cooled by a heat exchanger in which the outlet gas from the
absorption column flows in the reverse direction.
A cooler is then located upstream of the absorbent inlet to finish the gas cooling.
The absorption is performed in an absorption column, the "lean oil" and "rich gas" come
into contact via plates or packing.
The gas is fed into the bottom of the column and exits at the top. The "lean absorption oil"
reaches the top of the column and slowly flows downwards over plates or packing
depending on the type of column internals used. Since the gas descends in the opposite
direction to the gases in an absorption column, it is absorbed by the liquid oil and recovers
the volatile fractions.
Figure 18: Simplified diagram of a heavy condensate absorption unit
The "lean absorption oil" which has become rich in light hydrocarbons, leaves through the
bottom of the column, and supplies the de-ethaniser to eliminate the light components
such as the methane and the ethane.
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In most oil installations the Rich Oil De-ethaniser (ROD) unit recovers the methane and the
ethane at the same time, since very little ethane is recovered by the "lean oil".
If only the methane was rejected by the ROD unit, then it may be necessary to install a deethaniser column downstream to produce ethane and thus to prevent the ethane
contaminating the other products produced by the plant. (Contamination due to the
increase in the vapour pressure of the other liquid products).
The ROD is similar to a cold stabilisation tower for the rich oil.
Heat is added at the bottom of the column to drive off almost all the methane (and most
likely the ethane) from the bottom product by exchanging heat with the warm lean oil
coming from the still.
A reflux is provided by a stream of cold lean oil injected at the top of the ROD column.
The gas exiting the top of the column is used as fuel for the plant.
The amount of intermediate components flashed off with the gas can be controlled by
adjusting the reflux rate.
The absorber oil is sent to the still where it is heated to a fairly high temperature to
evacuate the propane, butane, pentanes and other natural gas liquids via the top of this
column.
This column is similar to a crude oil stabilisation column with reflux.
The closer the bottom temperature is to the lean oil reboiling temperature, the purer the
lean oil recirculated to the absorbent and thus the better the absorption.
The temperature control reduces to the maximum the lean oil losses to the top of the
column.
Thus the lean oil completes a cycle by which it successively recovered the light and
intermediate components from the gas before being regenerated.
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4. ADVANTAGES AND DISADVANTAGES OF THE DIFFERENT
PROCESSES
4.1. PROCESS USING THE JOULE-THOMSON VALVE
Figure 19: Diagram of the process using a Joule-Thomson valve
4.1.1. Advantages
•
simple process (no rotating machines)
•
not sensitive to variations in the gas flow to be treated
•
low investment cost
•
allows the gas to be dehydrated at the same time.
4.1.2. Disadvantages
•
low liquid recovery rate (basically limited to the C5+),
•
sensitive to the pressure variations in the gas to be treated (the recovery rate
depends on this),
•
requires a high upstream pressure,
•
requires inhibiter to be injected to prevent the formation of hydrates,
•
gas pressure is considerably reduced.
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4.1.3. Function
It is particularly adapted to operations where the gas is not commercialised, which is
becoming less and less frequent.
Where the gas is commercialised, the cost of the recompression installation (generally
necessary since the gas field pressure is not high enough) means that other solutions are
preferred to it.
Internal consumption: reaching the HC dew point for the gas turbines.
Used in parallel with the turboexpanders (for "better than nothing" start-up and standby).
4.2. ISENTROPIC EXPANSION
Figure 20: Diagram of the isentropic expansion process
4.2.1. Advantages
•
process adapted to ethane recovery,
•
the yield from isentropic expansion is very good,
•
process well-adapted to the additional recovery of ethane from a gas already
treated by an external mechanical cycle.
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4.2.2. Disadvantages
the use of an expansion turbine means that the gas must be perfectly dehydrated
upstream by a glycol unit or molecular sieve,
process highly dependent on the pressure of the gas to be treated,
ƒ
requires a sufficiently high upstream pressure
ƒ
the machine is very sensitive to upstream pressure variations (problem in case of
depletion, etc.)
requires cold make-up by an external mechanical cycle, to achieve high ethane
recovery rates,
sensitive to the molar mass variations of the gas to be treated,
presence of rotating machines (more complex to operate, to maintain, etc.). High
cost.
4.2.3. Function
Used to achieve very low hydrocarbon dew points and/or for ethane recovery.
4.3. REFRIGERATION BY A COOLER
Figure 21: Diagram of the cooling process by a cooler
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4.3.1. Advantages
process gives a very good LPG recovery rate,
process independent of the gas to be treated (preserves the gas pressure),
uses pure refrigerants with perfectly known thermodynamic performance,
process can be installed upstream or downstream of any other cooling system
without disrupting its operation,
process can be used both for gasoline stripping and gas dehydration.
4.3.2. Disadvantages
process little adapted to ethane recovery when pure refrigerants are used,
practical cooling limit around - 40°C,
process expensive due to equipment complexity,
process little adapted to gasoline stripping or LPG extraction from high pressure
gases (> 80 b).
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5. PROCESS LOCATION
The following block diagram clearly shows the location of the main condensate extraction
section (Gasoline in the diagram) and the additional part which may be outside the
fractionation section where it exists.
Figure 22: Example of an assembly producing gasoline and LPGs from a natural gas
The following diagrams show the location and environment of each cooling and
condensate extraction process.
20
50
50
100
Gaz
Transportable
Injection de
GLYCOL
S
Détente
J.T.
Compression
GLYCOL vers Régénération
Liquide
Figure 23: Diagram of the Joule-Thomson system and its environment
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40
30
50
Déshydratation
au GLYCOL
100
Gaz
Transportable
50
Expansion
Compression
30
S
Liquide
Figure 24: Diagram of the Turboexpander and its environment
50
50
100
Gaz
Transportable
Injection de
GLYCOL
S
Réfrigération
Externe
Compression
GLYCOL vers Régénération
Liquide
Figure 25: Diagram of an external cooling system and its environment
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6. REPRESENTATION
In this chapter we will describe how a condensate recovery system is represented in the
main documents made available to the operator and particularly the Joule-Thomson
system.
6.1. PROCESS FLOW DIAGRAM
Process Flow Diagram (PFD): this document which is issued during the project phase
shows the main process lines and tanks and their main operating parameters in a
simplified format.
The following PFD (Process Flow Diagram) example shows a natural gas condensate
extraction unit using a Joule-Thomson valve.
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Figure 26: PFD of a natural gas condensate extraction unit using a Joule-Thomson valve
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6.2. Typical example: External refrigeration loop at the Peciko gas
production field
6.2.1. General
The Peciko gas production field is located offshore, 26Km from the coast and consists of
around 12 wells (under development) connected to two platforms linked to the onshore
production unit by two 24" pipelines.
These two pipelines end up at a 30" manifold which serves a bank of slug catchers where
there is an initial recovery of the C5+ condensates.
The outlet gas is then sent into two identical treatment trains each comprising:
An exchanger: Raw Gas tubes / Shell: cold Lean gas
A "warm" separator (26°C)
An exchanger (Chiller) (application of the external refrigeration loop principle)
A cold separator (12°C)
A Tri Ethylene Glycol injection performed upstream of each exchanger.
The gasoline thus recovered in each train is sent into an MP separator then into an LP
separator from where it is pumped to a stabilisation unit (special storage facilities, sold at a
light crude price and maritime transport possible in tanks at Patm).
The treated gas is metered in a conventional four-tube Metering station and sent by
pipeline to NG liquefaction units located around 100 Km away.
6.2.2. Description of the primary separation
Upstream of the section itself an initial part of the Condensates is recovered in the Slug
Catchers. From there they are sent into two WKOs (one for each train).
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Figure 27: Screen view of the Peciko condensate Treatment section
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They undergo an initial degasing and a free water separation.
They are then sent into a V 4500 MP Separator (36 Barg and 38°C), then into a V 4510 LP
Separator (7 Barg). (Figure 27 - 33 - 34)
From there they are taken by three pumps (P4540 A B & C normally two in service, the
third on standby) to undergo Stabilisation in a Condensate Stabilisation Unit (CSU).
This CSU unit consists of a distillation assembly with a train of raw product / stabilised
gasoline exchangers, a reboiler and a column.
The following are extracted at this unit:
The stabilised Condensates leaving the base of the column and sent to their
allocated storage tank
Water vapour in the last third of the water column then condensed and sent to the
water treatment (Oily Water)
The low pressure top gas is recompressed to be used in the fuel gas.
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Figure 28: DCS view of the Condensate stabilisation unit (CSU)
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Detailed description of the Condensate Recovery section by external refrigeration
loop
Following the Primary separation in the Slug Catchers and WKO an additional recovery
step by an external refrigeration loop was installed to recover the major part of the
Condensates. These are stored in a tank then sold separately from the crude, but at an
equivalent price, which represents an excellent commercial upgrade. This condensate
extraction also avoids build-ups at the inevitable low points in the pipeline.
The following description is associated with the following isometric diagram which gives a
better indication of the layout of the different equipment on site.
Gaz
dé
li é
TEG Riche
Figure 29: Isometric diagram produced at the Peciko field representing the condensate
recovery section by external refrigeration loop
The gas exiting the slug catchers at a pressure of 84 Barg passes through the two parallel
treatment trains on the route indicated below:
It is first precooled from 50°C to 26°C by passing through the tube part of a
horizontal exchanger (E 4310), the refrigerant exiting the refrigeration loop passes
through the exchanger's shell.
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TEG is continuously injected upstream of E 4310 to prevent hydrate formation in the
exchanger (Possible risk zone: HP and 26°C).
Following this initial cooling, part of the condensates are condensed. They are
recovered in a "warm" separator (V 4320) and sent with level control into the MP
separator V 4500 already used for the identical condensates exiting the WKOs.
The gas leaving the V 4320 again undergoes a continuous TEG injection to prevent
hydrate formation (Highest risk zone: HP and 10 to 12°C) when it passes into the
next exchanger which is the Chiller.
It enters the tubes of Chiller E 4350 which forms the "process" part of the external
refrigeration loop (described separately later), the gas temperature is lowered to
12°C (variable) and is thus well below the dew point of the Condensates.
At the chiller outlet an FCV (FV 4360) controls the gas flow rate but particularly
plays the role of a J-T valve during the refrigeration loop starting phase.
The Condensates are recovered in a cold separator (V 4360 at 12°C).
They are then sent with level control to the MP separator V 4500 (36 Barg 48°C).
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Figure 30: DCS view of the precooling and warm separator section
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Figure 31: DCS view of the Cold separator and Chiller section
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Then again degassed in the LP separator (V 4510) and finally pumped to the
Vapour Pressure Stabilisation Unit (CSU) by P 4540 pumps A, B and C (two in
service during normal production and the third on standby).
The Condensates (Natural Gasoline) are then stabilised in the Condensate
Stabilisation Unit (CSU), then cooled by an air cooler and sent to the tank
reserved for them.
Gas circuit
The gas which has been inhibited against hydrates by TEG injections upstream of the
exchanger leaves the cold exchanger at 10 / 12°C which is incompatible with the pipeline
transport conditions (temperature differences too great with the 25 / 35°C environment). It
must thus be heated, which corresponds to the cooling requirement of the gas to be
gasoline stripped; the exchange takes place in the first E 4310 exchanger (figure 29 & 30).
This exchange takes place with temperature control by two TCVs installed in the cold gas
pipeline which is divided into two sections on the shell side of the inlet of exchanger
E 4310:
TCV 4310 1 installed on the section which passes through the exchanger
TCV 4310 2 installed on the section which bypasses the exchanger
(the TIC is placed at the outlet of precooler E 4310 on the treated gas on the tube side).
The gas is thus heated to 39°C and sent to the metering station consisting of four tubes
equipped with ∆P orifices. It then continues along the pipeline via a pig trap to the LNG
site which is around 50 Km away.
Treatment of the TEG injected upstream of the exchangers
The injected TEG becomes hydrated (absorbs water) in contact with the wet gas. The
Condensates are separated from it in the boots of the two "Warm" (V 4320) and "Cold"
(V 4360) separators (figure 30 & 31) from where it is sent with level control to the
conventional regeneration unit with reboiler and stripping column with stripping gas.
The regenerated TEG is injected upstream of the exchangers by positive displacement
pumps with a high backpressure (the gas pressure in the two trains is 84 Barg).
External refrigeration loop
The refrigerant used in the loop is a product meeting the environmental requirements, it is
Forane 134 (Tetra Fluoro Ethane) with chemical formula CF3-CH2-F, with boiling point of
–26.4°C and a vapour pressure of 6.6 Barg at 25°C. Thus its cooling characteristics are far
superior to those required to recover all the condensates (≈ 10° / 12°C).
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Figure 32: DCS view of the External Refrigeration Loop section
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The loop consists of:
A storage tank (V 492 A) for the Forane (the coolant) which is also used as a
centrifugal compressor suction drum (there is one compressor per gas treatment
train and one on standby which can supply either of the two loops)
A bank of air coolers (four A 492 F cells)
A receiver (V 492 G) for the condensed Forane
An intercooler exchanger (V 492 E) in which part of the liquid leaving the V 492 G
with level control (LIC) is vaporised and will supply the compressor's intermediate
suction stage.
The other part of the heated liquid leaving the intercooler goes into another exchanger
(Re-evaporator) E492 B by dividing into two streams:
The first stream is reflux-subcooled with the liquid Forane from the liquid Forane
manifold and at its outlet goes to Chiller E 4350 (figure 31) where it condenses the
process gas's C5+ components.
The second stream goes into the V 492 A suction drum with level control where it
rejoins the partially vaporised Forane coming from Chiller E 4350.
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Figure 33: DCS view of the condensate LP separator section
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Figure 34: DCS view of the condensate MP separator section
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7. HOW DOES IT WORK?
In this chapter we will look in more detail at the operating principle of an external
refrigeration loop.
We will then cover the location and environment of the different extraction processes
described in the previous chapter.
7.1. Description of a simple refrigeration loop
The refrigerant is stored in a suction drum where the refrigerant can be topped up from
containers with a capacity of a few m3. The refrigerant is obviously in a two-phase state:
•
Liquid / Vapour state at atmospheric pressure Patm and at – 40°C (Propane)
When the compressor is running it draws the vapour phase from the tank at 0.098Barg
and compresses it to 17BarA (i.e. 16 Barg); because of the compression, the vapour is at
a higher temperature than that of the suction side.
It is therefore cooled and partially condensed by the air cooler and recovered as a mixed
phase downstream in the tank at 49°C and 15.7 Barg (thus at a temperature less than the
C3 critical temperature, hence it can be liquefied)
The liquid phase is sent from the receiver to the Evaporator exchanger, with level control,
through an LCV which subcools the liquid due to the ∆P it creates.
In contact with the warm Separation Gas flowing through the tubes the liquid propane is
partially vaporised and returns to the suction drum as a mixed liquid / vapour phase.
The separation gas is cooled below the dew point of the condensates with the result that
they are condensed and recovered downstream in a separator which is commonly called
the Cold Separator.
The refrigerant's thermodynamic cycle is described in the graph following the refrigeration
loop diagram.
The cycle graph is represented by a trapezium CDAB whose four sides represent the
transformations which the refrigerant undergoes during the cycles.
We start at point C: in the suction drum conditions at Pc and Td.
From point C to point D the vapour phase is compressed to pressure Pd.
Then cooled in the air cooler to its dew point (TA) at constant pressure (with a very small
pressure drop in the air cooler).
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The cooling continues from the point on the dew point curve to point A on the bubble point
curve by expansion in the LCV valve and is at pressure PB = PC in the suction drum. The
enthalpy variation ∆h of the cycle is represented by segment B C.
Ballon du Fluide
Réfrigerant
Figure 35: Diagram of a refrigeration loop using propane and description of the
thermodynamic cycle
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8. CONDENSATE EXTRACTION UNIT OPERATION
8.1. OPERATING PARAMETERS
In the condensate extraction process which uses different cooling methods it is obvious
that the basic parameter to be followed in these units is the temperature at all the steps in
the process.
8.1.1. Operating parameters of a unit with external refrigeration loop
For example, for the unit previously described in detail, in chapter 3.4, the first temperature
which is controlled is that which we must have at precooler E-4310 inlet since the
upstream gas temperature varies according to the total flow rate of the wells in service
(more wells generate more flow and thus a higher temperature on arrival in the two
production trains).
And as the "warm" separator (V 4320) inlet temperature must be 26°C,
A TIC installed at the outlet of E-4310 acts on two TCVs (one in the section
containing the cold gas entering the precooler (E-4310), the other in the section
containing the cold gas bypassing it) to regulate the temperature to the dry gas
setpoint.
The second temperature to be controlled is that at the gas outlet of the chiller (E4350) which must be 12°C, it depends on the flow rate and temperature of the
refrigerant (in this case the Forane) at the chiller inlet (shell side). It is the flow rate
which is controlled by FIC on the compressor recycling.
The condensate levels in the two separators (V-4320 and V-4360).
The following must be monitored in the refrigeration loop:
The compressor delivery pressure
The air cooler outlet temperature
The temperature and liquid level in the suction drum.
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8.1.2. Operating parameters of a unit with Joule-Thomson valves
There are generally two valves in parallel, the parameters to be monitored more closely
are:
Pressure, at the valve inlet(s)
Temperature at the valve inlet(s)
Temperature at the valve outlet(s)
Valve adjustment parameters to obtain a high stability to prevent temperature
variations downstream in the cold separator
Hydrate inhibitor circulation and regeneration loop parameters
More generally, the parameters to be adjusted are:
Gasoline level in the cold separator
Temperature of the gasoline-free gas at the cold separator outlet
If a recompression compressor with raw gas / cold gas exchanger is present upstream of
the compressor:
Operating parameters of the compressor(s) and of the gas turbines (where they
exist).
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9. TROUBLESHOOTING
The process safety systems normally installed on a condensate extraction section with a
Joule-Thomson valve process are the following:
On the Cold Separator:
An LSHH & an LSLL
A PSLL on the cold lean gas outlet
PSLL upstream of the J-T valve
A TSHH downstream of the valve
9.1. Extraction unit with Joule-Thomson valves
If a Joule-Thomson valve is subject to surge causing flow / temperature oscillations:
Set the valve to "manual" position
Examine the possible causes coming either from the valve itself or fluctuations in
the upstream flow.
When surge appears in the recompression compressor (present in most cases), if the antisurge system does not react:
Set its loop FCV / PCV to "Manual" and slowly open until the phenomenon stops,
If the surge persists, shut down the compressor; this will inevitably result in the
shutdown of the train concerned due to PSHH on the suction side and the closure
of the LP wells.
9.2. Extraction unit with external refrigeration loop
The process safety systems normally installed on a condensate extraction section with
external refrigeration loop are in the Peciko unit, for example:
On the Warm separator:
An LSHH & an LSLL
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On the Cold Separator:
An LSHH & an LSLL
A PSLL on the cold lean gas outlet
In the evaporator (Chiller):
an LSHH and a PSHH on the refrigerant side
At the compressors:
A PSHH & TSHH on the delivery side
A PSLL on the suction side
In this type of unit a malfunction on the Process Gas side is basically of two origins.
Either due to a malfunction of the two TCVs installed in the Lean Gas line entering
or bypassing the precooler exchanger, the result produces temperature variations at
the warm separator inlet which reduce the Condensate recovery in this separator
This is not too serious since, in any case, with a temperature of 12°C at the chiller
outlet, all the gasoline will be recovered in the cold separator.
To solve this problem the two TCVs must be moved to "Manual" position one after
the other to determine which is causing the problem. When this valve has been
found, leave it in manual mode at the opening value it had before it began to
malfunction.
Call in the instrument technician to re-establish its normal operation.
Or the formation of a hydrate in the Chiller due to an insufficient amount of hydrate
inhibiter upstream of the two exchangers, or a refrigerant flow rate which is too high.
Reduce the refrigerant flow rate on the refrigeration loop side by adjusting the compressor
recycling.
Then apply the same general procedure as for the identical problem in the turboexpander:
Send part of this train's flow into the other train within the design limit, close some wells or
temporarily flare the remaining flow until the hydrate inhibiter problem is solved.
The inhibitor's regeneration section must therefore be checked (generally one of three
types of glycol, it may be methanol), reboiling temperatures, stripping gas, etc.
Then when the inhibitor quality has been re-established, increase its injection flow rate to
speed up the hydrate breakdown.
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Then bypass the precooler a little more using the bypass TCV to move away from the
critical hydrate zone at the Chiller inlet.
Slowly re-establish the process gas flow rate in the train.
Slowly return all the parameters to their normal values.
On the refrigeration loop side, a mechanical problem may arise on the compressor in
service.
However, it is extremely rare to get surge (during normal operation) on centrifugal
compressors operating in closed loops since the suction flow is practically constant.
Start the compressor in standby mode with reflux. Then when it is operating satisfactorily
configure it in a proportional arrangement with the other compressor and then stop the
other compressor.
One of the two air coolers downstream of the compressor may also stop unexpectedly, we
then just have to start the standby air cooler.
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10. EXERCISES
1. Give the reasons for removing the Condensates from a gas
2. There are two basic principles allowing the condensates of a gaseous fluid to be stored
at atmospheric pressure, what are they?
3. Which one of the two is used to store Natural Gas Condensates?
4. What are the three cooling processes most currently used for removing the
Condensates from Natural Gas?
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5. In a condensate extraction section, what are the basic parameters which must be
maintained? Why?
6. In a condensate extraction installation with external refrigeration loop the temperatures
at the precooler exchanger outlet and of the lean gas begin to oscillate. What is the
most usual cause of this? What must we do to restabilise these temperatures?
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11. LIST OF FIGURES
Figure 1: Simplified diagram of the treatment operations to be carried out on the
production field .............................................................................................................5
Figure 2: Characterisation of a gas field ..............................................................................8
Figure 3: Phase envelope (reminders)...............................................................................11
Figure 4: Phase envelope ..................................................................................................12
Figure 5: Example of the envelopes for a gas and its composition in molar % ..................19
Figure 6: Example of cooling .............................................................................................20
Figure 7: Representation of the effect of the different gasoline stripping processes by
cooling on the natural gas phase envelope at the primary separation outlet ..............22
Figure 8: Principle of extracting Condensates from NG by isenthalpic expansion through a
Joule-Thomson valve..................................................................................................24
Figure 9: Phase diagram for condensate recovery using a Joule-Thomson valve.............24
Figure 10: Turbo-expander at the Lacq plant (France) ......................................................26
Figure 11: Diagram of polytropic expansion (expansion turbine) .......................................26
Figure 12: Diagram of the Turboexpander at the Lacq plant..............................................27
Figure 13: Expansion by turboexpander - Expansion through a valve...............................27
Figure 14: Diagram of the condensate extraction process using an external refrigeration
loop.............................................................................................................................28
Figure 15: Cooling cycle diagram ......................................................................................29
Figure 16: Diagram showing the principle of an external refrigeration loop .......................30
Figure 17: Phase diagram for condensate recovery using an external refrigeration loop ..31
Figure 18: Simplified diagram of a heavy condensate absorption unit...............................32
Figure 19: Diagram of the process using a Joule-Thomson valve .....................................34
Figure 20: Diagram of the isentropic expansion process ...................................................35
Figure 21: Diagram of the cooling process by a cooler ......................................................36
Figure 22: Example of an assembly producing gasoline and LPGs from a natural gas .....38
Figure 23: Diagram of the Joule-Thomson system and its environment ............................38
Figure 24: Diagram of the Turboexpander and its environment.........................................39
Figure 25: Diagram of an external cooling system and its environment.............................39
Figure 26: PFD of a natural gas condensate extraction unit using a Joule-Thomson valve
...................................................................................................................................41
Figure 27: Screen view of the Peciko condensate Treatment section ...............................43
Figure 28: DCS view of the Condensate stabilisation unit (CSU) ......................................45
Figure 29: Isometric diagram produced at the Peciko field representing the condensate
recovery section by external refrigeration loop ...........................................................46
Figure 30: DCS view of the precooling and warm separator section .................................48
Figure 31: DCS view of the Cold separator and Chiller section .........................................49
Figure 32: DCS view of the External Refrigeration Loop section .......................................51
Figure 33: DCS view of the condensate LP separator section...........................................53
Figure 34: DCS view of the condensate MP separator section..........................................54
Figure 35: Diagram of a refrigeration loop using propane and description of the
thermodynamic cycle ..................................................................................................56
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12. LIST OF TABLES
Table 1: Examples of natural gas compositions...................................................................7
Table 2: Normal trade names of light natural gas hydrocarbons........................................10
Table 3: Specifications for commercial gas........................................................................14
Table 4: Specifications for condensates ............................................................................18
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13. CORRECTIONS FOR THE EXERCISES
1. Give the reasons for removing the Condensates from a gas
¾ To remove them from the Gas to obtain a gas with commercial specifications.
¾ To upgrade the condensates to light crude in the refineries by reintroducing them
into the Crudes (excellent added value)
¾ To be able to change to downstream operations such as fractionation to recover
the LPGs.
2. There are two basic principles allowing the condensates of a gaseous fluid to be stored
at atmospheric pressure, what are they?
1 ) Compress the gas on condition that it is kept under the fluid's Critical
Temperature.
2 ) Reduce the temperature of the gaseous fluid to below its dew point.
3. Which one of the two is used to store Natural Gas Condensates?
It is the second principle: lowering the temperature since it allows the C5+
condensates to be stored at atmospheric pressure, e.g. the boiling point of nC5 is
36°C and that of iC5 is 26°C. Thus in most regions they are often both present in the
NG and can be stored in floating roof tanks. They are also mixed with the other
components in the refineries to produce gasolines.
4. What are the three cooling processes most currently used for removing the
Condensates from Natural Gas?
1 ) Isenthalpic expansion in Joule-Thomson valves.
2 ) Polytropic expansion in turboexpanders.
3 ) NG cooling by a refrigerant flowing through an exchanger by means of a
compressor and coolers. In this case, the whole assembly is known as an external
refrigeration loop.
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5. In a condensate extraction section, what are the basic parameters which must be
maintained? Why?
In the case of the refrigeration loop, they are the Gas temperatures at the exchanger
outlets.
The Gas temperature downstream of the Joule-Thomson valves.
6. In a condensate extraction installation with external refrigeration loop the temperatures
at the precooler exchanger outlet and of the lean gas begin to oscillate. What is the
most usual cause of this? What must we do to restabilise these temperatures?
The usual cause is a surge at the two TCVs installed on the lean gas at the precooler
inlet and bypass.
The two TCVs must be placed in "Manual" position to re-establish the
temperatures by referring to the open position they had in "Automatic" mode.
Then return each TCV successively to "Automatic" mode to determine the valve
creating the problem. Then return the incriminated TCV valve to "Manual" and call in
the instrument technician.
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