Study of natural gas liquids recovery from associated gas

1. Ferdowsi University of Mashhad.
Faculty of Engineering.
Chemical engineering department
Study of NGLs recovery plant
Name of supervisor : Dr. B. Aminshahidy
Name of student : Mohammed Al-isawi

2. Contents:
1- Introduction
2- NGL recovery processes
2-1 Recovery processes
2-2 Refrigeration Processes
2-2-1 Mechanical Refrigeration
2-2-2 Self-Refrigeration
2-2-3 Cryogenic Refrigeration
2-3 Lean Oil Absorption
2-4 Solid Bed Adsorption
2-5 Membrane Separation Process
2-6 Twister Supersonic Separation
2-7 Selection of NGL Recovery Processes
3-NGL FRACTIONATION
4-LIQUIDS PROCESSING
4-1Sweetening
4-2 NGLs stabilization

3. 1-Introduction:
Most natural gas is processed to remove the heavier hydrocarbon liquids from the natural gas stream.
These heavier hydrocarbon liquids, commonly referred to as natural gas liquids (NGLs), include ethane,
propane, butanes, and natural gasoline.
• Recovery of NGL components in gas required for:
1- Hydrocarbon dew point control in a natural gas stream (to avoid the unsafe formation of a liquid phase during transport).
2- A source of revenue, as NGLs normally have significantly greater value as separate marketable products than as part of the natural gas stream.

4. Natural Gas: Any reservoir classified as natural gas reservoir
if the temperature of this reservoir above the critical
temperature of hydrocarbon system. The composition of
natural gas varies considerably from lean non-associated gas
to rich associated gas containing a significant intermediate
components (C2 –C6).
Associates Gas: Associated gas is produced from oil
reservoirs. This gas is dissolved in oil or exists in free gas
phase. Associated gas is produced in association with oil.
Non-Associated Gas: reservoirs that contain only natural gas
and no oil.
The gas reservoirs are classified as:
A. Gas-condensate reservoir
B. Wet gas reservoir
C. Dry gas reservoir

5. Gas-condensate reservoir:
•Retrograde Gas-condensate
Reservoir temperature lies between the critical temperature
and cricondentherm temperature. This category of gas
reservoir is a unique type of hydrocarbon accumulation in
that the special thermodynamic behavior of the reservoir
fluid is the controlling factor in the development and the
depletion process of the reservoir.
The associated physical characteristics.
1- Gas-oil ratios between 8,000 to 70,000 scf/STB.
2- Condensate gravity above 50o API.
3- Stock-tank liquid is usually water-white or slightly colored.

6. •Near Critical Gas-Condensate
The gas reservoir temperature is near critical temperature.
The volumetric behavior described through the isothermal
pressure declines and by corresponding liquid drop-out
curve.

7. Wet gas reservoir:
Reservoir temperature is above the cricondentherm of the
hydrocarbon mixture. Because the reservoir temperature
exceeds the cricondentherm of the hydrocarbon system the
reservoir fluid will always remain in the vapor phase region.
Wet gas reservoirs properties:
1- Gas-oil ratios between 60,000 to 100,000 scf/STB.
2- Stock-tank oil gravity above 60o API.
3- Liquid is water-white in color.
4- Separator conditions (pressure and temperature) lie
within the two phase region.
Dry gas reservoir:
The hydrocarbon mixture exists as a gas both in the
reservoir and the surface facilities. The only liquid associated
with gas from a dry gas reservoir is water. Usually a system
having a gas-oil ratio greater than 100,000 scf/STB is
considered to be a dry gas.

8. 2- NGL recovery process
2-2 Refrigeration Processes:
2-2-1 Mechanical Refrigeration:
Is a simple process used widely in gas conditioning
applications (e.g., hydrocarbon dew point controlling), but it is
also used in NGL recovery applications as the primary
refrigeration option or in conjunction with another
refrigeration option.
source of refrigeration when inlet pressure is low.
is supplied by a vapor-compression refrigeration cycle that
usually uses propane as the refrigerant and reciprocating or
centrifugal types of compressors to move the refrigerants
from the low- to high-pressure operating conditions.
A mechanical refrigeration process is adopted when sizeable
amounts of condensate are expected.
Propane is by far the most popular refrigerant in the gas
processing applications. It is readily available (often
manufactured on-site), is inexpensive, and has a “good” vapor
pressure curve. It is flammable, but this is not a significant
problem if proper consideration is given to the design and
operation of the facility

9. A-Cascade Refrigeration:
Cascade refrigeration refers to two refrigeration circuits thermally connected by a cascade condenser, which is the condenser of the low-
temperature circuit and the evaporator of the high-temperature circuit. A cascade system utilizes one refrigerant to condense the other primary
refrigerant, which is operating at the desired evaporator temperature. This approach is usually used for temperature levels below –90 F, when
light hydrocarbon gases or other low boiling gases and vapors are being cooled. To obtain the highest overall efficiency for the system, the
refrigerants for the two superimposed systems are different. Cascade refrigeration systems are not common in gas processing.
B-Mixed Refrigerants:
An alternative to cascade refrigeration is to use a mixed refrigerant. A mixed refrigerant is a mixture of two or more components. The light
components lower the evaporation temperature, and the heavier components allow condensation at ambient temperature. The evaporation
process takes place over a temperature range rather than at a constant temperature as with pure component refrigerants. The mixed refrigerant
is blended so that its evaporation curve matches the cooling curve for the process fluid. Heat transfer occurs in a countercurrent exchanger,
probably aluminum plate-fin, rather than a kettle-type chiller. Mixed refrigerants have the advantage of better thermal efficiency because
refrigeration is always being provided at the warmest possible temperature. The amount of equipment is also reduced to a cascade system.
Disadvantages include a more complex design and the tendency for the heavier components to concentrate in the chiller unless the refrigerant is
totally vaporized.
Advantages and drawbacks:
1. Mechanical refrigeration is a simple and flexible process, adopted when sizeable amounts of condensate are expected.
2. this process occupies a large area, and the equipment involved in such systems is heavy with respect to other NGL recovery alternatives such
as the Turbo expansion process.
3. requires a high maintenance cost and a high utility requirement.
4. If the feed gas contains a large amount of inert components, the efficiency of process will be reduced due to the interference of the inert.
5. Propane refrigeration becomes inappropriate for feed throughputs of less than 25 million standard cubic feet per day (MMSCFD).
6. the amount of C02 in the feed must be as low as temperatures of the process can cause freezing of C02

10. 2-2-2 Self-Refrigeration:
in the self-refrigeration process the inlet gas is cooled by
isenthalpic expansion (i.e., Joule–Thomson expansion)
This process is usually used in hydrocarbon dew point controlling
applications, but is also used in NGL recovery applications. If the
objective is to recover ethane or more propane than obtainable
by mechanical refrigeration, a good process can be self
refrigeration, which is particularly applicable for smaller gas
volumes of 5–10 MMcfd.
Advantages and drawbacks:
1. The advantages of this process are simplicity and low cost.
2. The primary drawback is the pressure Drop that occurs
across the valve, which often ranges from 500 to 1,000 psia.
3. This process may be attractive when the plant inlet pressure
is sufficiently high to eliminate the need for compression.
4. Due to this chilling, the self-refrigeration process achieves
high ethane recoveries; typical ethane recoveries are about
70%.

11. 2-2-3 Cryogenic Refrigeration:
processes are commonly used for deep NGL recovery, with minimum
temperatures below –150 F achieved routinely. In the cryogenic or
turbo-expander plant, the chiller or Joule–Thomson ( JT) valve used in
the two previous processes is replaced by an expansion turbine. As
the entering gas expands, it supplies work to the turbine shaft, thus
reducing the gas enthalpy. This decrease in enthalpy causes a much
larger temperature drop than that found in the simple JT (constant
enthalpy) process.
Cryogenic processes can be applied only if the gas pressure after
expansion is sufficiently high for condensation of the heavier
components to take place.
Cryogenic refrigeration processes are also used for hydrocarbon dew
point controlling applications in which the required pressure drop
across the expander is substantially less than that required across a JT
valve, resulting in lower compression costs over the life of the field.
The cryogenic refrigeration process is generally the most technically
advanced type of NGL recovery used today. This combines high
recovery levels (typically allowing full recovery of all of the propane
and heavier NGLs and recovery of 50% to more than 90% of the
ethane) with low capital cost and easy operation . This is less
attractive on very rich gas streams or where the light NGL product (C2
andC3) are not marketable, whereas for gases very rich in NGL,
simple refrigeration is probably the best choice.
.

12. Modern NGL Recovery Processes:
Modern NGL recovery processes are based on turbo expanders
using various reflux configurations. There are many patented
processes that can be used to improve NGL recovery, either for
propane recovery or ethane recovery.
A-Dual-Column Reflux Process The dual-column process.
the first column acts as an absorber recovering the bulk of the NGL
components and the second column serves as deethanizer during
propane recovery and demethanizer during ethane recovery.
refluxes to the dual-column design process was originally
configured for high propane recovery. The process is very efficient
and can achieve over 99% propane recovery.
B-Ortloff's Gas Sub cooled Process.
Increasing ethane recovery beyond the 80% achievable with the
conventional Design requires that a source of reflux must be
developed for the demethanizer.
Ortloff’s Gas Subcooled Process (GSP) was developed to overcome
this problem and others encountered with the conventional
expander scheme. GSP configuration allows recovering ethane
from around 50% to 99%, with propane recovery at 99%.

13. C- Ortloff SCORE The SCORE (single-column overhead recycle
process).
The SCORE process is designed to recover over 99% propane
from the feed gas in a single-column configuration.
This process recovers the C3+ hydrocarbons from the feed gas
and produces a lean residual gas for sales. Alternatively, the
residue gas can be
sent to the natural gas liquefaction plant.
D-Residue Gas Recycle
When high ethane recovery is required, additional cooling is
required by recycling a portion of the residue gas as reflux to the
absorber.

14. E-Fluor Twin-Column High Absorption Process.
When the sales gas must be compressed to the pipeline pressure, it is
desirable to operate the demethanizer at as high a pressure as
possible.
Fluor has developed the twincolumn high absorption process (TCHAP)
using a dual-column approach. The first column operates as an
absorber at 600 psig or higher pressure and is designed for bulk
absorption. The second column, which serves as a demethanizer or
deethanizer, operates at a lower pressure at about 450 psig. To
improve NGL recovery, the overhead vapor from the second column is
recycled using a small overhead compressor. The recycle gas is chilled
using the absorber overhead vapor and used as a cold reflux to the
absorber.
F-Fluor Twin-Reflux Absorption Process.
NGL recovery units are frequently required to operate in ethane
rejection mode when the profit margin of the ethane product is low.
During these periods, the NGL recovery units are required to reject
their ethane content to the sales gas Pipeline.
When operated in ethane rejection mode, some propane is lost with
the rejected ethane, resulting in a loss of liquid revenue.
The process can be operated on ethane recovery and can also operate
in ethane rejection while maintaining high propane recovery.

15. Advantages and drawbacks:
1. The turbo expander is compact with a low weight and low space requirement compared with absorption equipment or external refrigeration
systems.
2. The operational as well as capital costs are relatively low.
3. Another disadvantage of this process is the height required for the de-methanizer tower.
4. The installation of an elevated tower is extremely difficult on offshore plants and could also present operational problems due to the
common strong winds in the sea .
5. Another drawback is the lack of tolerance to wet gas in the feed since it can damage the mechanical system. Nevertheless, a certain amount
of liquid can be managed in the exit of the equipment.
6. Another important limitation of the turbo expander is the elevated maintenance cost.
7. the operation of this equipment represents a major issue in terms of safety.

16. 2-3 Lean Oil Absorption:
Lean oil absorption is the oldest and least efficient process to
recover NGLs. In this process the gas to be processed is
contacted in a packed or tray absorption column (typically
operated at the ambient temperature and a pressure close to
the sales gas pressure) with an absorption oil. which absorbs
preferentially the most heavy hydrocarbons (C3,C7+) from
natural gas.
Note that the oil absorption plant cannot recover ethane and
propane effectively when it requires circulating large amounts of
absorption oil, demands attendant maintenance, and consumes
too much fuel.
oil absorption plant can be modified to improve its propane
recovery by adding a propane refrigeration cycle for cooling. The
refrigerated lean oil absorption process improves the recovery
of propane to the 90% level, and depending on the gas
composition, up to 40% of ethane may be recovered.
Lean oil absorption plants are not as popular as they once were
and are rarely They are expensive and more complex to operate,
and it is difficult to predict their efficiency at removing liquids
from the gas as the lean oil deteriorates with time.

17. Advantages and drawbacks:
1. This process is selective to propane, and a low ethane recovery is achieved.
2. Inert gases in the feed gas do not interfere with the process of the absorption of the hydrocarbon and pre-treatment of the gas is not
needed. This is also true for feed gas with water.
3. For the case of associate gas treatment, this process is rarely used.
4. There are also the possible environmental impacts of chemical use including spills, storage of virgin/waste oil, etc.
5. For feed pressures below 2,800 kPa absorption systems operate well, but for higher pressures a dual pressure absorber column with high and
low pressure sections is required. Above 8,500 kPa the efficiency of the absorption system will be reduced.
6. The efficiency of the absorption process is improved with rich gases.
7. The absorption systems also suffer from the high-energy costs needed to run solvent circulating pumps and also regeneration of oil.

18. 2-4 Solid Bed Adsorption:
The solid bed adsorption method uses adsorbents that have the
capability to adsorb heavy hydrocarbons from natural gas. The
adsorbent may be silica gel or activated charcoal, activated
alumina cannot be used .
This process is appropriate for relatively low concentrations of
heavy hydrocarbons. It can be also appropriate if the gas is at a
high pressure, close to the cricondenbar. In this case, refrigeration
processes become ineffective and separation by adsorption may
offer the only way to obtain the required specifications.
Advantages and drawbacks:
1. An adsorption process requires enormous amount of energy
due to the regeneration process.
2. the equipment involved is heavy and expensive.
3. Safety is a considerable issue for this process since the high
temperature with the hydrocarbon solids could produce a fire
or related accident.

19. 2-5 Membrane Separation Process:
The membrane separation process offers a simple and low-cost
solution for removal and recovery of heavy hydrocarbons from
natural gas.
The separation process is based on a high-flux membrane that
selectively permeates heavy hydrocarbons compared to methane.
These hydrocarbons permeate the membrane and are recovered as
a liquid after recompression and condensation. The residue stream
from the membrane is partially depleted of heavy hydrocarbons
and is then sent to the sales gas stream.
Gas permeation membranes are usually made with vitreous
polymers that exhibit good diffusional selectivity. However, for
separation to be effective, the membrane must be very permeable
with respect to the contamination to be separated, which passes
through the membrane driven by pressure difference, and it must
be relatively impermeable to methane.
Membrane systems are very versatile and are designed to process a
wide range of feed conditions. With very compact footprint and
low weight, these systems are well suited for offshore applications.
Membranes could potentially remove water and heavier
hydrocarbons simultaneously, thus making these systems an
attractive alternative to replace the conventional dehydration and
hydrocarbon dew pointing design.

20. Advantages and drawbacks:
1. membranes are operationally simple and do not require additional separation agents
2. membrane is the flexibility of its operations. This means production conditions can be modified, and the membrane process can be easily
adapted to it.
3. The membranes are arranged in modules, which can be orientated in horizontal or vertical positions.
4. the membrane separation technologies are appropriate for small to medium production
5. Membranes typically have lower installation, operation, and maintenance costs compared with other technologies.

21. 2-6 Twister Supersonic Separation:
Twister supersonic technology uses the concept that feed gas passing
through a nozzle accelerates to supersonic speed, suffering a pressure
and temperature drop, where the temperature drop causes condensation
of the heavier hydrocarbons.
Condensation and separation at supersonic velocity are key to achieving a
significant reduction in both capital and operating costs.
Twister supersonic technology shares similar benefits of simplicity,
robustness, and ease of operation as the LTS ( JT valve). Two studies
showed that Twister can recover more hydrocarbons than the JT valve for
the same pressure drop.
Therefore, it could potentially be operated at a reduced pressure drop for
the same performance as a JT valve. This reduces the sales gas
compression power and cost. It can be particularly interesting for
debottlenecking or upgrading existing gas plants. An additional benefit of
Twister is the ability to remove water and hydrocarbons simultaneously
in its tubes. Twister technology also offers environmentally friendly,
chemical-free operation within a small footprint.

22. Advantages and drawbacks:
1. Twister supersonic technology shares similar benefits of simplicity, robustness, and ease of operation as the LTS (JT valve). Two studies
showed that Twister can recover more hydrocarbons than the JT valve for the same pressure drop. Therefore, it could potentially be operated
at a reduced pressure drop for the same performance as a JT valve. This reduces the sales gas compression power and cost.
2. Twister is the ability to remove water and hydrocarbons simultaneously in its tubes.
3. Twister technology also offers environmentally friendly.
4. Twister BV introduced the Twister SWIRL valve, which improves HC dew pointing performance of existing LTS plants by improving the
separation of two-phase flow across a pressure reduction valve, such as a choke valve, JT valve, or control valve.
in turn, significantly improves the liquid separation efficiency of downstream separators. This improved separation can be used to either increase
flow capacity of existing LTS plants or to reduce the pressure drop required for JT cooling or to lower the HC dew point and also reduce glycol
carryover.

23. 2-7 Selection of NGL Recovery Processes:
The case Recovery process
sufficiently high inlet pressure. the self-refrigeration process requires the lowest capital
investment.
the feed gas pressure is close to the treated gas pressure,
over a large pressure drop range.
more economical to employ a cryogenic refrigeration
process.
When the feed gas pressure is clearly below the required
pipeline pressure.
most economical to apply mechanical refrigeration.
When the feed gas pressure is equal to or lower than the
required pipeline pressure,.
solid bed adsorption seems a good option.

24. 3-NGL FRACTIONATION
Once NGLs have been removed from the natural gas stream, they must be fractionated into their base components, which can be sold as high-
purity products. Fractionation of the NGLs may take place in the gas plant but may also be performed downstream, usually in a regional NGL
fractionation center.

25. 4-LIQUIDS PROCESSING
Hydrocarbon condensate recovered from natural gas must be treated to make it safe and environmentally acceptable for storage, processing, and
export. Therefore, removing water and salt is mandatory to avoid corrosion. Separation of any dissolved gases, which belong to the light
hydrocarbon components (methane and ethane in particular), along with hydrogen sulfide, mercaptans, and other sulfur compounds, will make
condensate safe and environmentally acceptable to handle.
4-1 Sweetening
If acidic and sulfur compounds are present in the feed gas and have not been removed before NGL recovery, then they will end up in the NGL
products. The distribution of the contaminants for the various NGL products
A. Caustic Processes
A number of caustic processes, both regenerative and non-regenerative, can be used to remove sulfur compounds from hydrocarbon liquids. The
simplest process is the use of a non-regenerative solid potassium hydroxide (KOH) bed, which is effective for removal of H2S but not for other
sulfur compounds. One of the common processes for treating hydrocarbon liquids is the use of regenerative caustic wash with sodium hydroxide
(NaOH).
B. Adsorption
Molecular sieve technology is commonly used for treating NGLs. Molecular sieves can be used for removal of sulfur compounds (H2S, COS, and
mercaptans) either in the gas or liquid phase. There are advantages and disadvantages for either option. The adsorber efficiency is higher in the
gas phase since the mass transfer rate of sulfur compounds is much faster in the gas phase.
C. Amine Treating
Amine treating is an attractive alternative, especially when an amine gas sweetening unit is already on-site. In such cases, the liquid treating unit
can often be operated using a slipstream of amine from the main sweetening unit. Amine treating is often used upstream of caustic treaters to
minimize caustic consumption caused by irreversible reactions with CO2.

26. 4-2 NGLs stabilization
Process separation of the very light hydrocarbon (methane
and ethane) from the heavier components. Increasing the
amount of intermediate (C3 to C5) and heavy component.
This process is performed primarily in order to reduce the
vapor pressure of the condensate liquids so that a vapor
phase is not produced upon flashing the liquid to
atmospheric storage tanks.
Flash vaporization:
Is a simple operation employing only two or three flash
tanks this process is similar to stage separation utilizing the
equilibrium principles between the vapor and condensate
phases. Equilibrium vaporization occurs when the vapor and
condensate phases are in equilibrium at the temperature
and pressure of separation.
Fractionation:
Stabilization by fractionation is a detailed process, very
popular in the industry and precise enough to produce
liquids of suitable vapor pressure. During the operation, the
undesirable components (low boiling-point hydrocarbons
and hydrogen-sulfide gas) are removed.

27. NGLs market:
The global natural gas liquids market size is expected to
reach 11,468 kilo barrels/day by 2022 from 7,306 kilo
barrels/day in 2015 with a CAGR of 6.67% from 2016 to
2022.
The global natural gas liquids market is segmented based on
product type and geography. According to product type, the
market is categorized into ethane, propane, isobutene, and
others, which include normal butane, pentane, and pentane
plus. Geographically, the market is analyzed across North
America, Europe, Asia-Pacific, and LAMEA.

29. Thank you