Part 3. Introduction to Gas Refining Processes

Part 3. Introduction to Gas Refining Processes
1 Gas Industries:
• Gas Production
• Gas Refining
• Gas Transportation
Some Iran Gas Refineries:
•
•
•
•
Bid Boland Gas Refinery
Khangiran Gas Refinery
Kangang (Fajr Jam) Gas Refinery
Assaluyeh Gas Complex (containing a number of
refineries)
2 Typical Processes:
Reciption Facilities (Slug catcher)
Gas treatment:
Acid gas removal
Dehydration
Dew-point unit
Mercaptan removal (Sulfrex)
Dry gas compression to pipe pressure
Condensate stabilization
Sulfur recovery
Utilities
3 Units Configuration
specifications
Reception Facility
Condensate
Stabilization
Acid gas removal
To remove H2S
Dehydration Unit
To remove Water
Dew point unit
To remove heavy HC
C4 < 1%mol
To remove Mercaptans
RSH < 15mg/Nm3
H2S < 3 ppm
Water dew point at 44 barg max -10 C.
Butane cut
Sulfrex unit
٤
4 Reciption Facilities
The Reception Facilities are designed to receive the multi-phase flow (gas/ condensate and
glycolated water) from piplines originating from the wellhead.
The purpose of the Reception Facilities is to remove liquid slugs that occur in the pipelines and
to route the raw gas to the downstream gas treatment units.
The major part of Reception Facilities is Slug Catcher.
The Slug Catcher is finger type with co-current gas / liquid flow (Figure 1). The co-current
arrangement is selected in order to minimize the risk of carry-over compared to counter current
arrangement.
The equipment is designed in order to separate gas, condensate and glycolated water. The gas
stream is sent to the Gas Treatment section for further processing.
Gas-liquid separation section
The gas / liquid separation is achieved in the first zone of fingers. In order to achieve the highest
separation efficiency an adequate length is provided upstream the gas outlet header.
Slug Receiving Section
An enough storage capacity shall be achieved through a sufficient fingers length, since liquid
will not necessarily arrive at the slug catcher at a steady rate (hundreds of meters).
Gas disengagement from the storage section is connected to the main gas outlet header of the
separation section.
Liquid / liquid separation
5 Liquids from the fingers are collected in the Slug Receiving Section and are routed via a
horizontal liquid header known as Liquid Bottle. There is enough time in this part to separate the
glycolated water and condensate.
The outlet gas from Slug Catcher is routed to gas treatment units, while the liquids are sent to
condensate stabilization unit.
Pig Receiver
Gas
Slug receiving section
5 fingers
Condensate
MEG
١٠
Figure 1. A five finger Slug Catcher
6 GAS SWEETENING
The gas is a mixture of hydrocarbon components, which can be produced from a reservoir
rock (original natural gas designation) or from a crude production (associated gas).
Natural gas or associated gas produced with crude oil-contain acid components, mainly
carbon dioxide (CO2) and hydrogen sulfide (H2S) and sometimes traces of other compounds:
Carbonyl sulfide (COS) carbon disulfide (CS2) and mercaptans.
Gas or oil produced from a well that contains hydrogen sulfide (H2S) or other obnoxious
sulfur compounds is called “sour” gas or oil.
The process used to remove the H2S or sulfur compounds is called “Sweetening”.
H2S must be removed from the gas before it can be used for fuel. It is highly corrosive, and
deadly toxic. The products formed when it burns are also highly toxic.
Other sulfur compounds are also corrosive and toxic, but not to the degree of H2S.
CO2 must be removed if its concentration is high. It is not toxic but it is corrosive and it can case
pipeline plugging due to hydrate formation.
7 Table 1. TOXICITY OF HYDROGEN SULFIDE
H2S CONCENTRATIONS
(ppm, in air)
4-6
EFFECTS OBSERVED
Easily detected, moderate odor
Unpleasant odor. Possible eye irritation.
10-20
Threshold Limit Value (TLV) fixed at 8 hours for 10 ppm.
Loss of sense of smell after about 15 minutes exposure.
50-100
Irritation of throat and eyes.
100-200
200-500
Loss of sense of smell within seconds, with irritation of throat and eyes.
Haemorrhage and death beyond 8 hours exposure.
Loss of balance and consciousness within 30 minutes and paralysis of the
respiratory system. Artificial respiration must be applied immediately.
Hemorrhage and death after 2 to 4 hours exposure.
Loss of consciousness within 15 minutes of exposure.
500-700
Respiration stops and death is inevitable after 15 to 30 minutes exposure if
the victim is not immediately treated.
Immediate loss of consciousness.
700-1,000
Brain damage or death if first aid is not immediately applied. Inevitable
death after 15 minutes exposure.
1,000-1,500
Immediate collapse and death after 2 minutes exposure.
Above 1,500
Immediate death
8 Table 2. COMPOSITIONAL ANALYSIS OF NATURAL GASES
Field
Kangan
Nar
Khangiran
Assaluyeh
Sarkhon
Components
Mole%
Mole%
Mole%
Mole%
Mole%
N2
5.95
4.61
0.55
3.474
4.89
CO2
1.83
1.46
6.41
1.860
0.65
H2S
681 ppm
59.6 ppm
3.85
0.555
0.02
COS
---
---
17 ppm
3.1 ppm
---
C1
85.29
87.98
88.35
85.086
87.76
C2
4.14
3.65
0.56
5.448
3.75
C3
1.32
1.09
0.09
1.991
1.39
IC4
0.29
0.24
0.02
0.379
0.32
NC4
0.40
0.32
0.03
0.573
0.48
IC5
0.20
0.16
0.02
0.178
0.19
NC5
0.14
0.11
0.02
0.159
0.15
C6+
0.44
0.38
0.01
0.273
0.21
RSH
59.6 ppm
17.1 ppm
---
159.4 ppm
---
9 GAS SWEETENING PROCESSES
Numerous processes are available:
•
•
•
•
•
•
•
CHEMICAL ABSORPTION
PHYSICAL ABSORPTION
PHYSICO- CHEMICAL ABSORPTION
PHYSICAL ADSORPTION
CRYOGENIC PROCESS (CO2 Removal only)
MEMBRANES
Direct Conversion To SULPHUR
Chemical absorption processes are the most utilized in industries and we will explain it in more
detail.
Chemical Absorption
In this type of process, the chemical solvent absorbs the acid components present in the feed
gas by chemical reaction and releases them by heating at low pressure.
A chemical reaction processes mixes a chemical with the gas stream in order to neutralize
hydrogen sulfide, or “sweeten” the gas.
The most common of these processes is called “amine sweetening”. Alkanolamines (or
simply, amines) are substances which are weak bases. They react chemically with acid gases
like hydrogen sulfide to form salt complexes.
These salt complexes can be broken down so the amines are relieved of acid gases and can be
recycled.
An acid gas is a gas that forms an acid when combined with water. Examples of acid gases
include hydrogen sulfide and carbon dioxide.
10 The main chemical solvents are:
. MEA (Monoethanolamine)
. DEA (Diethanolamine)
. TEA (Triethanolamine)
. MDEA (Methyldiethanolamine)
11 Figure 1. CHEMICAL STRUCTURAL FORMULAS FOR ALKANOLAMINES
Alkanolamines cannot be used pure for different reasons:
12 •
•
Close to solid state at ambient conditions
Low stability at high temperature (heating is needed to extract the absorbed acid gases)
with generation of highly corrosive products by decomposition.
Therefore these products are utilized in aqueous solutions with the following concentrations:
•
MEA
15 to 20 % weight
•
DEA
25 to 35 % weight
•
MDEA 30 to 50 % weight
Advantages of MDEA
•
Selective to H2S:
Lower loading of Sulphur Recovery Units
•
Low Corrosive:
-Higher concentration can be used (normally 45%)
-Lower flow rate is required
•
Lower Degradation
13 Process description (Figure 2)
The process is actually quite simple. Sour gas (or natural gas with acid gas in it), is subjected to a
stream of amines, which absorbs the acid gas, leaving sweet gas (or natural gas without acid in
it).
The amine solution containing the acid gas then goes through a process of distillation to remove
the acid gas. The lean amine is then reused.
H2S gas becomes concentrated during the distillation process. Typically, it is burned in a flare
stack. If the volume of H2S is very large, then the H2S must be converted to sulfur and recovered
for environmental reasons. The recovered sulfur can be sold to help offset operating costs.
Figure 2. Simple schematic of chemical absorption process
14 Figure 3 is a process flow diagram (PFD) that shows typical process in more detais.
The feed gas enters the bottom of the absorber column and flows upwards in intimate counter
current contact with the lean MEA solution (“lean” meaning low content of acid gases).
During these contacts the MEA solution flowing downward absorbs the acid gases by a complex
chemical reaction.
Absorber column (contactor) could be either a tray column (15 to 25 tray) or a packed column
operating at the feed gas pressure. The aim is to obtain a good contact between the feed gas and
the amine solution.
The temperature of the lean solution entering the top of the absorber shall be 6ºC higher than that
of the feed gas of feed gas to avoid hydrocarbon condensation and related foaming problems.
The treated gas leaving the column is at the lean solution temperature. The installation of a mist
eliminator pad on the top of the column will reduce amine losses by carry-over.
Antifoam is injected continiously to prevent foaming.
Sweetened (i.e. on specification) gas leaves the top of the absorber and is routed to downstream
section (dehydration, compression or other).
The heat of the chemical reaction increases the temperature of the gas which will be water
saturated when leaving the absorber.
Rich amine solution (“Rich “meaning high content of acid gases) is then generally flashed in a
degassing drum at a lower pressure and then routed to the Lean-Rich heat exchanger.
Gas leaves the top ot Flash drum can be used as a fuel gas after washing with amine in a small
packed tower at the top of Flash drum.
15 The purpose of the stripper is to remove the acid gas contained in the rich solution.
In an amine type sweetening plant, the stripper usually contains 18 to 24 trays. The feed enters
the vessel 2 to 4 trays below the top tray. As the solution flows down the tower, it is contacted
with stripping steam from the reboiler, which flows up the tower.
As the up flowing steam bubbles through the solution on each tray, it strips the acid gas from the
solution so that the gas vaporizes and passes out the top of the tower. The amount of acid gas
removed from the solution will increase as the amount of steam passing up the tower increases.
The vapor leaving the top of the stripper is a mixture of steam and acid gas. It passes through a
condenser, where the steam is condensed to water. The condenser can be a shell and tube
exchanger using cooling water inside the tubes or it can be air cooler with the vapor stream
flowing through the tubes.
The lean solution from the bottom of the regenerator releases its heat to the rich solution through
an heat exchanger (this lowers the steam requirements for reboiling) and is collected in a surgetank.
The lean solution is then pumped and routed to the absorber, after water or air-cooling, at a
temperature slightly higher than temperature of the feed gas.
A reclaimer operating on 1 to 3% of the solution circulation rate is used to maintain the purity of
the lean solution.
Reclaimer is nessesory for the processes imploying MEA, but it is not required for DEA or
MDEA systems.
16 Figure 3. AMINE TYPE SWEETENING PLANT
17 18 DEHYDRATION PROCESSES
Dehydration is the operation whereby water is removed from the gas. Gas contains water: not
liquid water of course but water vapor exactly like atmospheric air.
What happens when the weather becomes cooler? Generally it rains.
The risks of water condensation in the pipeline are great if care is not taken to dehydrate. This
is exactly what we want to avoid in gas pipelines.
We do not want the water vapor to be condensed. Therefore, water condensation is to be
avoided in the pipe because:
1- It will enhance corrosion
2- It will decrease the capacity of the pipe by the creation of liquid slugs in
the lower parts and therefore increase the pressure drop.
3- It may form hydrates.
1- It will enhance corrosion
2- It will decrease the capacity of the pipe by the creation of liquid slugs in the lower parts
and therefore increase the pressure drop.
3- It may form hydrates.
Hydrates are white crystalline solids composed of water and hydrocarbons. They are very hard
and can plug the pipeline and block the valves and the relief system (Figure 4). For this
reason they are very dangerous, everything must be done to avoid their formation.
19 Figure 4. Hydrate in a pipline
20 Figures (5a) and (5b) show hydrate formation.
Figure 5a. Hydrate formation and deposition
21 Figure 5.b. Damage of a pipline by hydrate
22 Four possibilities are at our disposal to prevent this:
1- Increase the temperature of the gas:
It is impossible because the temperature of the gas in the pipe is more or less
equal to the temperature of the atmospheric air. We do not have any possibility
to control this unfortunately.
2- Decrease the pressure of the gas in the pipe:
It is impossible too if the pressure of the gas is decreased the capacity of the
pipe will be decreased too. This is not realistic
3- Remove the water:
If the water is taken out of the gas no risks of condensation are to be expected
without increasing the temperature or decreasing the pressure. It is the best
solution to avoid operating problems.
4- Anti-hydrate injection to pipeline.
That is the reason why dehydration is necessary.
The temperature at which the first droplet of water appears is called WATER DEW POINT.
The working temperature of the pipeline must be higher than the water dew point
temperature.
Dehydration Methods:
1. Absorption by TEG.
2. Adsorption by fixed bed.
23 Absorption by TEG
The principle is based on the absorption of water by something, which strongly attracts water
but does not attract too many hydrocarbons.
It must be a selective absorber of water.
Although there are several methods for removing water from gas, the most commonly used
dehydration method utilized a substance known as glycols.
These have the advantages of being fairly unreactive chemically, dissolving water readily,
being thermally stable and having a high boiling point. There are three kinds of glycol in
general use.
Of these three types triethylene glycol is the most frequently used for dehydration purposes. It
is accepted that triethylene glycol is the most satisfactory agent for general use, because:
- It has a high affinity for water.
- It is practically non-corrosive.
- It is a stable substance.
24 - Regeneration is continuous and simple.
- The vapor pressure is low at operating temperatures.
- It has low solubility for natural gases.
- By comparison, it has low foaming or emulsifying tendencies.
- The boiling point is much higher than other glycols.
Process description
The process is again quite simple (Figure 6).
Wet gas (or natural gas with water in it), is subjected to a stream of TEG, which absorbs the
water, leaving dry gas (or natural gas without water in it).
The TEG solution containing the water then goes through a process of distillation to remove the
water. The lean TEG is then reused.
Figure 7 shows the process in more detail.
dehydration plant are:
The major pieces of equipment in a glycol
The contactor
The flash tank
The filters
The regenerator
25 Figure 6. Simple schematic of TEG absorption process 26 Figure 7. TEG TYPE DDEHYDRATION PLANT
Contactors will normally contain trays although some manufactures prefer packed type.
Good contactor design with respect to tray spacing, tray liquid levels etc. is imperative for
efficient operation. Trays provide a high degree of gas to liquid contact. The wet gas stream
flows upwards through the vessel “contacting” the glycol solution traveling downwards.
Water present in the gas is absorbed by the glycol. As gas passes upward through each
succeeding tray it becomes driver.
Before leaving the contactor, the dry gas passes through a mist extractor to remove any glycol
that may be in vapor form. As the glycol particles collect and become heavier in the mist
extractor, they drop back into the top tray and rejoin the glycol stream.
Dry gas passes out of the top of the contactor through a heat exchanger. The gas cools the
incoming hot glycol stream, which in turn increases its absorption efficiency.
27 The flash tank (Figure 7) is present in the process to recover gas dissolved in the glycol. The
rich glycol solution enters the flash tank, which operates usually in a pressure range of 3-5
bar. The operating pressure is kept as low as possible to promote flash.
Since the contactor will normally operate at about 60 bara pressure drop is induced and thus
dissolved gas is released. The gas produced is used directly as a fuel source since it will be
wet and quite probably corrosive.
If the wet gas stream contains some liquid hydrocarbons they collect in the bottom of the
contactor and pass to the flash tank with the rich glycol stream. Liquid hydrocarbon will then
separate in a layer above the rich glycol in the flash tank and may be removed under level
control.
Rich glycol from the flash tank flows through a coil (heat exchanger) in the upper portion of
the stripper section of the regenerator. Cool wet glycol flowing through the tubes causes the
water and hydrocarbon to cool and the purer glycol to condense to the reboiler section. The
rich glycol then flows to the filters.
Glycol filters are used to remove solid impurities present or created in the process. Solids
cause fouling and foaming and are best removed by filters placed in the rich glycol stream.
In the regenerator the water absorbed by the glycol is removed by boiling. The regenerator
unit is made up of the following components, which can be seen in Fig. 7.
A stripper
A reboiler
A heat exchanger (reflux coil)
A surge tank and circulating pump.
Rich glycol from the filter passes to a heat exchanger in which heat is transferred from hot
lean glycol to the rich feed in the stripper section. It is important to maximize heat transfer at
this point to reduce the amount of heat required to operate the reboiler. The temperature of the
lean glycol leaving the heat exchanger will normally be in the range of 85-105°C.
28 Rich glycol entering the upper zone of the stripper flows downward is heated by hot glycol
vapors from the reboiler.
The water present in the rich glycol is converted to steam and passes out the top of the
stripper. A portion of the vapor is condensed by the reflux coil as described earlier.
Reboiler is indirectly fired using combustion gas hot oil or steam as heat sources.
The temperature of the glycol in the reboiler is maintained in the range 200-205°C.
The lean glycol passes to a heat exchanger (previously discussed) and then to a surge tank
prior to recirculation back to the contactor.
Adsorption by fixed bed
Adsorption is the process of removing impurities, most frequently water, from a fluid stream
by means of a solid material called an adsorbent that has a special attraction for the impurities.
For example, water vapor can be removed from a gas in an adsorption plant using solid
material such as alumina or silica gel when water is the impurity; the adsorbent is referred to
as a desiccant. The desiccant has an attraction for water vapor that is greater than for other
components, so it will remove the moisture from the gas.
An absorption process can also be used to remove the same impurities. In the absorption
process, the impurities dissolve in a liquid solution that is in contact with the fluid.
In this section, we are concerned with the adsorption process, which uses a solid material to
remove impurities from a gas or liquid.
The vessel containing the adsorbent is called an adsorber. The impurities the adsorbent
removes are called the adsorbates.
29 There are four types of adsorbents widely used in the gas processing industry.
They are: activated alumina, activated charcoal or carbon, molecular sieves, and silica gel. In
the case of the alumina and charcoal, the term activated refers to some treatment that improves
the capacity of efficiency of the adsorbent.
All of these materials have several common characteristics. They are all strong, dense, solid
particles.
Although they do not look like it, they all have a physical structure that is filled with cavities,
or pores, like a sponge. These pores are so small they cannot be seen even with a strong
microscope. But, they are large enough so that gas, and the contaminants it carries, can enter.
Once inside the particle of adsorbent, the contaminants condense and cling to the surface of
the inner cambers, and the purified gas passes out.
The amount of surface area available in many adsorbents is so great that if you could unfold it
and spread it out there would be enough from a spoonful of adsorbent to cover a football field.
This unseen surface is what makes the adsorbents differ from beads or rock particles they
resemble. It provides so much surface area for adsorption that some of the grades of silica gel,
for example, can adsorb as much as 330 liters of water per cubic meter of adsorbent.
When the silica gel holds this much water it does not change in appearance. It does not look
wet. All of the water is adsorbed in the pores, where it is condensed and held on the inner
surface.
In addition to having tremendous surface area where adsorption can take place, the adsorbents
have attractive forces on their surfaces.
These forces act like magnets to condense and hold material on the surfaces even when the
system temperature and pressure are not near the condensation point.
30 At high temperature, however, the vapor pressure of the adsorbed liquid can become so great
that it can overcome the adsorptive forces. When this happens, the liquid that was adsorbed
will vaporize and return to the surrounding gas. In this way the adsorbed material can be
recovered, and the adsorbent can be emptied and made ready to adsorb again.
Figure 8 shows three common adsorbents.
For dehydration, the alumina, silica gels or molecular sieves can be used.
The choice of desiccant will depend on the operating temperature, the outlet dew point
required, and the composition of the stream.
Figure Activated carbon is not shown because it has very little water capacity, so is not used
as desiccant.
Figure 8: Three common adsorbents
31 Process description
Most adsorber towers are vertical cylindrical vessels as shown in figure 9. There are instance
horizontal adsorbers are used, rather than vertical towers, but they are not common.
The adsorption process is a batch type operation. The inlet fluid flows through a adsorber
tower until the adsorbent is saturated with the contaminant it is removing from the fluid. At
that point, flow is switched to a tower containing freshly regenerated adsorbent, and the
original tower is regenerated (figure 9).
A switching valve arrangement is required to divert the flow of process fluid from one tower
to the other, and at the same time, start flow of regeneration gas to the tower which has been
in adsorption service.
A typical piping manifold for a 2-tower adsorber plant is shown in figure 9. In this illustration,
the main gas stream is flowing into the top of tower 1 and leaving at the bottom of the tower.
Regeneration gas is flowing to tower 2. Regeneration flow is usually the opposite direction of
adsorption.
Plants with 3 or more towers may operate with one tower in cooling service while another
tower is in heating service. This requires another pair of switching valves for each tower at
shown in figure 10.
32 Figure 9. Plants with 2 towers
Figure10. Plants with 3 towers
33 Condensate Stabilization Unit
High vapor pressure values of condensate are due to the pressure of dissolved volatile
hydrocarbons called "light ends" such as methane, ethane, propane, butanes.
To store safely crude oil in tanks at atmospheric conditions or to transport safely crude oil in
pipelines at defined operating pressure, condensate vapor pressure value must be controlled or
adjusted to meet pipeline, storage, or tanker Reid vapor pressure (RVP) specifications.
This control or adjustment is carried out by removal of the light end components dissolved in
a condensate stabilization unit. Condensate stabilization unit performance is characterized by
the Reid vapor pressure value of stabilized condensate produced.
Reid vapor pressure value to be performed is fixed by negotiation between seller and buyer
and varies from case to case. Typical value for storage or oil tanker transport: 12 psi (80 kPa)
maximum.
Figure 11 shows some liquid hydrocarbons associated with or produced from Natural gas. As
can be see “condensate” has very similar structure to gasoline. As results, condensate is a very
valuable product. It depend on its specification, however its price is usually higher than Crude
oil.
Purposes of this unit are:
•
•
Adjust RVP of Condensate:
ƒ Summer: 10 Psig
ƒ Winter: 12 Psig
Remove Condensate Impurities:
ƒ MEG
ƒ Water
ƒ Inhibitors…
34 Process Desctiption
The unit contains four main sections (Figure 12):
•
Raw Condensate Preflash drum and Desalting drum
•
Condensate Stabilisation tower
•
Offgas Compression Section
•
Stabilised Condensate to Storage.
Figure11. Liquid hydrocarbons associated with or produced from Natural gas
35 Preflash Drum
The raw condensate from the slug catchers is preheated then flashed before going through a
desalter. The Preflash Drum a three-phase separator: (Figure 12)
•
Due to pressure reduction, some lighter components evaporate. This light components
(Flash gas) is sent to a Compressor Suction Drum. Excess gas, if any, is sent to the flare
under pressure control.
•
Glycolated water is sent to the MEG regeneration and injection unit.
•
The main part, Hydrocarbon liquid is pumped by to the Condensate Desalter.
Desalter
There is still some dissolved water in condensate which must be removed before condensate
sends to stabilization tower. (Figure 12)
The duty of this equipment is to remove the free aqueous phase, which can be salted or not,
from the hydrocarbon phase.
The desalter uses the electrostatic effect to perform a very good phase separation.
Also Demulsifying chemicals are injected if required.
Operating temperature in the desalter is held at about 70 degrees to ensure an efficient
separation of glycolated water from condensate. This is achieved by heating the fluid by
exchange with stabilised condensate in the Condensate Desalter Preheater.
36 Condensate Stabilization Tower (Stabiliser)
Raw condensate from desalter is treated in the Condensate Stabiliser (a tray tower).
The condensate light components are then removed in the condensate stabiliser These light
components are removed as vapor overhead product with the condensed liquid serving as
reflux. (Figure 12)
The column is equipped with:
•
Reboiler, heated by high pressure steam.
•
Partial reflux condenser in which the vapour leaving the top of the column is cooled down.
•
Three phase separator reflux drum.
Offgas Compression
Preflash drum Overhead vapor and also Stabiliser overhead vapor is compressed by a
compressor with cooling and vapour-liquid separation at the interstage. (Figure 12)
Gas is compressed by compressor and is mixed with the gas sent to the Gas Treatment Plant
for further processing.
If the compressor is not operating, or if more gas is being produced than the compressor can
handle, the excess gas is vented to the flare system
Stabilized Condensate Conditioning and Storage
The stabilised condensate from the stabiliser bottom column is cooled in a step-wise fashion.
The air cooler is designed in order to maintain an export temperature equal 5°C below the
bubble temperature of mixed condensates at atmospheric pressure. This temperature margin
has been considered to prevent condensate flashing at atmospheric pressure.
The Condensate Degassing Drum is installed as a precaution in case of temporary
maloperation of the stabilisation unit (upset condensate vapour pressure).
37 Stabilized condensate is then sent to the stabilised condensate storage tanks and ultimately
shipped out.
38 70barg
PV
PV
Raw
Condensate
Feed
HP
separator
2nd
PV
1st
PV
Flare
9 barg
68 C
8 barg
Stabilizer
LDV
LV
SH
To sour water
stripper
19
FV
27 barg
34 barg
70 C
TV
PDV
SH
FC
FV
E
Preflash drum
Fresh Water
Condensate desalter
FV
E
LDV
LDV
TV
F
Sour Water
F
189 C
9.5 barg
LV
0 barg
PDV
Cond Degassing Drum
136 C
LV
Waste Water
Stabilization unit
Off spec cond.
To Storage
TK
LV
Stab. cond
To Storage
TK
Figure 12. Condensate Stabilization Unit
39 Cond from
Dehexaniser
٢٥
Hydrocarbon Dew Point Control Unit
This unit sometimes called NGL (natural gas liquid) unit. The objectives are:
1. To produce a transportable gas stream,
2. To maximize natural gas liquid production.
Condensate (heavy components) may or may not be recovered prior to pipeline transport.
If the hydrocarbon dew temperature value of the transported gas is lower at any pressure
value than the lowest expected temperature in the pipeline, then no processing to remove
NGL is required.
At the opposite if this hydrocarbon dew temperature value is higher at any pressure value
than the lowest expected temperature in the pipeline a condensate removal must be done to
prevent to prevent liquid formation in pipeline.
After H2S removal and dehydration of gas, the dry sweet gas is routed to the Dewpointing
control, where the gas is processed to cope with the following main specifications:
•
HC dew point of - 10 °C +/- 5°C at 55 barg
•
Mercaptans 15 mg/Nm3 max
These specifications require that the heavier hydrocarbons and the major part of the
mercaptans be removed from the gas prior to export.
Light mercaptans (Methyl and Ethyl-mercaptans) are separated with iC4/nC4 whereas Propylmercaptans and heavier mercaptans are separated with C5+.
40 -28 C
PV
24 C
39.6 C
Compression unit
-30 C
34 C
Cold oil
Contactor
29 C
-30 C
Cold box
Dehydration unit
28.6 C C3 From/to
FV
LV
6.3 C
55 C
PV
Partial Condenser
10.8 C
PC
C3
C6 7%
C7 37 %
C8 42 %
C9 14 %
Recycle
Compressor
33 C
C1 50%
C2 20%
C3 28%
Reflux
Suction
Drum
93.1 C
23 C
Reflux Drum
C4 5 %
iC5 31 %
C5 29 %
C6 26 %
61 C
Reflux Drum
Depropaniser
Dehexaniser
FV
Condenser
SH
Condensate
Stabilization
Unit
SH
LV
147 C
LV
SH
Debutaniser
RSH
C4 35,3%
C4 59,3%
C3
164 C
C4 to Mercaptan
removal
٣٨
LV
163 C
Figure 13. Hydrocarbon Dew Point Control Unit
41 Cold Box
Dry gas from the Dehydration Unit is divided into two flows. The major part flows through
the Cold Box where it is cooled down to -30 °C (Figure 13).
At this temperature a major portion of the propane and heavier components are condensed.
The liquid phase also contains significant amounts of methane and ethane, which must be
removed.
Cold oil contactor
The two-phase stream from the Cold Box enters the Cold Oil Contactor which is a stripperabsorber tray column that produces sales gas as an overhead and a wide-range liquid as a
bottom product (Figure 13).
To minimize the amount of light component in the liquid, a stripping action is provided by
bypassing some of the warm dry gas around the Cold Box and injecting it into the Cold Oil
Contactor below the bottom tray.
The base of the Cold Oil Contactor operates at 5 °C. Light components are stripped out of the
liquid phase between the bottom tray and the feed tray, and heavy components are absorbed
from the gas phase between the top tray and the feed tray.
42 Depropanizer
Cold Oil Contactor bottoms liquid is sent to the Depropanizer (Figure 13).
The function of this column is to remove propane and lighter as an overhead vapour stream
and to yield a bottom product containing all the butanes and heavier components.
The overhead of the Depropanizer is chilled in the Depropanizer Condenser and mixed phase
is routed to the Depropanizer Reflux Drum.
After separation in the Depropanizer Reflux Drum, the liquid is pumped and returned to the
top tray of the Depropanizer as reflux.
The Depropanizer column is equipped with a Depropanizer Reboiler which uses HP saturated
steam as heating medium.
The vapour from the Depropanizer Reflux Drum is routed to the Recycle Compressor it is
recompressed by the reciprocating Recycle Compressor. The gas is then injected with 'lean
oil', cooled, chilled, and returned to the Cold Oil Contactor as contacting liquid.
Debutanizer
The Depropanizer bottom liquid is sent to the Debutaniser. The Debutaniser operates at 8
bara and is equipped with both overhead condenser and Reboiler (Figure 13).
The overhead gas of the Debutaniser column is air-cooled and totally condensed at about 56
°C in the Debutaniser Condenser. The liquid butane product is then routed to the Debutanizer
Reflux Drum.
This butane cut contains the majority of the Methyl and Ethyl-mercaptans removed from gas.
The liquid is pumped from the Debutaniser Reflux Drum to the top tray of the Debutaniser as
reflux. The other part is cooled and sent to the LPG Treatment Unit where the Methyl and
Ethyl-mercaptans will be removed.
43 Dehexanizer
The Debutaniser bottom liquid is sent to the Dehexanizer. The Dehexanizer operates at 4 bara
and is equipped with both condenser and Reboiler. (Figure 13)
The liquid (C5-C6) product is then routed to the Dehexanizer reflux Drum from which it is
pumped by the Dehexanizer Reflux Pump. At the pump discharge, part of the liquid is
returned under flow control, to the top tray of the Dehexanizer as reflux. The other part is sent
to the Stabilisation Unit to be mixed with stabilised condensates.
The Dehexanizer Reboiler uses HP saturated steam as heating medium. The Dehexanizer
bottom temperature is of approximately 164 °C.
Apart of Dehexanizer bottom liquid is pumped as lean oil to the Cold Oil Contactor. The
other part, C7+, is sent to the Stabilisation Unit after mixing with the C5 /C6 from the
Dehexanizer Reflux Drum.
44