This document summarizes a student project to design a natural gas purification process. The process involves removing impurities from raw natural gas through amine sweetening to remove hydrogen sulfide and carbon dioxide, and glycol dehydration to remove water. The purified natural gas is then used in a steam power cycle to generate electricity. A cost analysis was performed to estimate the costs of the required equipment and determine if the process would be economically feasible.

1. Purification of Natural Gas
David Luong, Jassim Alajmi, Jesse Reyes, Siwanet
Ratanasiripornchai
Fantastic Four
Chemical Engineering Design, ChE 470, Sec 01 5111
Chemical Engineering Department
California State University, Long Beach
Table of Contents
1. Abstract
2. Introduction
A. Problem Statement
B. Related Work and Market Analysis
3. Process Design/Methodology/Approach
4. Components Description and Process
5. Cost Analysis
6. Results
7. Summary/Conclusion
8. Future Work
9. References
10. Appendix
Abstract
As the population of the world continues to increase, there is an
increase in energy demand. Though there are many ways to
produce energy, it is important that the energy can be easily
obtained and produce less pollution than methods used in the
past. One solution that has emerged and is currently continuing
to grow today is natural gas. Burning natural gas for energy

2. produces less pollution than other methods and can be easily
extracted from underground. However, natural gas directly
extracted from the earth has impurities such as hydrogen
sulfide, carbon dioxide, and water that needs to be removed.
Thus, to remove carbon dioxide and hydrogen sulfide, a process
called amine sweetening is performed. Natural gas will also go
through a process called glycol dehydration to remove water
contaminates out of the stream. If the natural gas is shipped
overseas then the natural gas will also go through a process
called natural gas liquefaction. Our goal is to purify natural gas
and sell it for a lower price than our competitors by burning
some of our natural gas and using water and a steam turbine to
capture the energy in a steam power cycle. Our process will not
include the liquefication of natural gas as we will be shipping
natural gas only nationally and countries nearby but not
overseas.
Liquefied Natural Gas (LNG) processes started in the 1960s;
the product can be used as a fuel for vehicles or residential
needs and some industrial consumption. basically the liquified
natural gas process is essentially is a natural gas mixture that
has been cooled down to a liquid for several purposes like
storage and transport. Liquified natural gas can be profitable for
energy consumption and transportation over other methods. One
of the reasons liquifying would be beneficial to companies is
that when gases are liquified, they take only a fraction of the
volume that it would require to transport gases, making it
possible to transport a larger volume after the gases have been
liquified.
Introduction
When drilling for petroleum or crude oil, there is a release of
natural gases from the ground.These gases are a mixture of
hydrocarbons such as methane, ethane and propane, hydrogen
sulfide, water, carbon dioxide and nitrogen.
Previously, these gases were burned off or flared during the
drilling process because there was no marketable uses for them.

3. Additionally, since they could not be stored or transported very
far, the only way that natural gas could be utilized was if it was
used near where it was collected and pumped and used as it was
pumped. Since this was not previously economically feasible,
these gases would be released and not a viable energy source.
However, due to advancements in the processing of gases, the
market for natural gas improved and the use of it worldwide
increased. The next issue facing the reliability of natural gas as
an energy source was the volume it occupies when in its
gaseous state. The large volumes at atmospheric pressure are
not practical to store or transport, however, when the purified
gases are liquified, they take up a fraction of the volume
(1/600th) and are easier to transport and store. When the gas is
taken where it is to be sold or it is needed for energy peaks, it
can be regasified and sent through pipes as natural gas to meet
energy needs without having to be close to the source of where
it was collected or used when immediately when it is pumped.
Based on the information, liquified natural gas is a profitable
market that is feasible as long as the gases can be purified and
then liquified for storage and transportation.
There is a need for additional energy sources that can reliably
provide energy to people across the world. The world
population is expected to grow to 8.6 billion people by the year
2030. By 2050, the population is expected to reach 9.7 billion
people and will approach around 11 billion by the year 2100
(cite the UN population data). With this growth in the
population over the course of the century, coupled with the fact
that even today nearly a billion people struggle to have reliable
or any electricity at all shows the need for growth in the energy
sector (cite World Bank data). This search for additional
resources comes as governments, including large markets such
as China and the European Union, have been setting tighter
restrictions on carbon dioxide emissions and have set laws in
place that are more favorable towards natural gas as opposed to
coal. With these factors in mind, the market for natural gases
and the liquefaction of natural gas for storage and transportation

4. appear to be favorable. In 2011, the United States Congress
deemed it necessary to export liquified natural gas to other,
international markets for businesses to net higher profits, so
long as the countries had free trade agreements with the United
States. However, with demand high enough, the Department of
Energy received applications to export to nearly 50 countries
with which the United States did not have free trade
agreements, showing the growing need and demand worldwide
for liquified natural gas (cite US Congress). The market outlook
of liquified natural gas is expected to grow rapidly until at least
2035, with nearly 250 billion dollars of investment into
liquified natural gas plants and transportation over the course of
the next two decades. Additionally, market growth and reliance
on natural gas is expected to rise from large markets such as
China and plants and infrastructure is expected to grow in
places such as Africa, China and Russia (cite global gas and
LNG market). With these factors combined, the profitability of
liquified natural gas and the demand for natural gas in a global
market looks feasible and regions such as Africa, Asia and
Europe should be expected buyers with high demand.
Related work in this field includes other liquified natural gas
plants, the transportation of liquified natural gas and the selling
of natural gas when it is transported to where it will be used.
The liquified natural gas plants receive raw material, gases
mostly containing methane and ethane, and work to purify and
remove impurities such as carbon dioxide, hydrogen sulfide,
water and helium. These impurities would damage piping if the
gases were pumped without being purified. After the
purification process, the gas is liquified for storage and
transportation. From here, the transportation of natural gas to
the areas it will be used at occur and liquified natural gas is
carried by sea to a station where it will be regassed and pumped
to customers or stored for later use during energy spikes. Areas
of focus for those interested in the liquified natural gas market
are designing and running liquified natural gas plants capable of
purifying and freezing the gas, vessels capable of carrying large

5. volumes of purified natural gas and facilities in areas with large
demand for natural gas that will handle the regasification
process and distribute natural gas to customers or use it during
energy spikes in communities.
Process Design
Amine Sweetening
For this project, the focus was the collection of natural gases
that come from the ground and purifying it by removing
impurities that would damage the piping when the natural gas is
transported. After natural gas is extracted from underground, it
will first go through a process called amine sweetening. Natural
gas will enter gas absorption column from the bottom and
diethanolamine (DEA) mixed with water will be fed in from the
top of the column. Diethanolamine is mixed with water so that
the amine feed is about 5.41 mole percent DEA since
diethanolamine is corrosive. There is also a small amount of
carbon dioxide (CO2) and hydrogen sulfide (H2S) in the amine
feed stream which will be explained later. In the gas absorption
column diethanolamine reacts with carbon dioxide from the
natural gas in an acid base reaction that is shown in figure
below. A similar reaction occurs with hydrogen sulfide causing
both CO2 and H2S to leave the natural gas stream and flow out
the bottom of the column with diethanolamine. The natural gas
stream is now said to be sweetened since the gas aborsption
column removed the acid gases, CO2 and H2S, from the natural
gas. It is usually aimed that the amount of H2S in the natural
gas stream to be 5.5 mg per meter cubed to prevent damages to
the pipes. In our system the natural gas contains 1.60 mg per
meter cubed of H2S in the final product. After being sweetened
the natural gas is now able to continue to the next part of the
process, the amine stream mixed with water and now acid gases
cannot be reused unless it is cleaned. In order to make the cost
of removing acid gases cheaper, it is necessary to bring the
amine stream outlet back to its original conditions such as

6. temperature, pressure, and composition so it can be reused in a
continuous process. This means the acid gases need to be first
removed out of the solvent followed by a pressure and
temperature change. After leaving the gas absorption column,
the amine feed will go through a throttle valve to reduce its
pressure and a heat exchanger that increases the temperature. It
will now be fed into a distillation column where most of the
acid gases and some of the water will be removed. Not all the
acid gases can be remove out of the amine stream or else the
distillation column would require more energy. This stream can
now go through two more heat exchangers to cool down and
have water added back into it to make up the water lost in the
distillation column. Finally the stream can go through a pump to
increase the pressure and bring the recycle stream back to its
original compositions and operating conditions. As mentioned
before our system uses DEA to remove acid gases, however
there are other possible amines that are better at removing acid
gases. These amines however will use more energy in the
distillation column to remove the acid gases, thus DEA was
chosen.
Glycol Dehydration
In the next process, sweetened natural gas will go through a
process called glycol dehydration. Natural gas will be fed into a
gas absorption column from the bottom and a triethylene glycol
(TEG) and water mixture will enter from the top. Triethylene
glycol and water are both polar molecules thus the triethylene
glycol stream is comprised of only polar molecules. The
triethylene glycol stream will attract other polar molecules such
as water from the natural gas stream. Natural gas also contains
hydrocarbons that are nonpolar and will not be attracted to the
polar molecules. Thus only water will leave from the natural gas
stream and the purification process of natural gas will be
complete. The natural gas stream is now ready to be sold
directly or used as a source of energy. The amount of water in
natural gas after glycol dehydration is usually under 65 mg per

7. meter cubed. Our system has our final natural gas product has
the amount of water to be about 40.45 mg per meter cubed. Just
like the amine processes before, we want to the process to be as
efficient as possible to reduce costs. Thus we wish to remove
most of the water out of the triethylene glycol stream leaving
the gas absorption column and bring it back to its original
operating conditions. The stream of triethylene glycol leaving
the gas absorption column will first go through a throttle valve
to reduce its pressure and then go through a flash drum. The
flash drum will remove some of the water so that when it enters
the next unit, a distillation column, it will use less energy. The
distillation column will remove most of the water and also some
of the triethylene glycol. The recycle stream will go through a
heat exchanger to bring down the temperature and a pump to
increase the pressure and mixed with a stream of triethylene
glycol to make up for the lost triethylene glycol.
Steam Power Cycle
In order to use the energy stored inside natural gas, the natural
gas must first come down in pressure. This is achieved by
taking some of the natural gas product and running it through a
series of throttling valves. If too large of a pressure drop occurs
pipes and valves can freeze over, thus to avoid this problem it is
done in several steps. Next natural gas and air will be mixed
together to combust and release energy since it is an exothermic
reaction. The combustion reaction for methane, ethane and
propane is as follows:
It is necessary to mix air in a ratio close to the relationships
above however excess air is mixed with the natural gas stream
to ensure complete combustion of the fuel. In our simulation an
excess amount of air was added so that the combustion products
would have 5 mole percent of air. The heat released will be
extracted by high pressure water in a heat exchanger, turning
the water to superheated steam. This superheated steam will
now go through a steam turbine to generate electricity by

8. turning a shaft. What leaves the turbine is slightly superheated
steam and not saturated vapor to ensure that no water condenses
in the turbine to prevent any damage to the turbine. After the
steam leaves the turbine, it will be cooled down to water by
cold water that comes from a cooling tower in a condenser. The
water will go into a pump to bring its pressure back to its
original operating pressure so it can extract heat that is
produced from natural gas again.
Cost Estimation:
After researching the process of how to make this natural gas
plant, the next step was to approximate as closely as possible
what costs would this carry, whether it would be financially
feasible to run this plant and what investment up front would be
required from companies or other interested parties.
The cost estimation employed for this project occurred in two
steps: the first step was to calculate the cost of the equipment
that this system would use and the second step was to use the
Lang factors method to determine the other costs associated
with other aspects such as piping and delivery of the
components ordered.
For the first step, research was conducted into what units were
available through catalogs and websites, however, with many of
these units costing well over $10,000 each, many companies
that produce these units do not list their prices and instead ask
interested parties to call for a quote and for prices. Since that
was not a viable option for such large units, some of the units
were sized and scaled up to the approximate size that would be
necessary for the requirements of production based on the six-
tenths rule. For other units, there were general costs that were
listed from sources and these numbers were used from the time
they were published and then a cost index was used to calculate
the cost to what it would cost in the year 2019. Finally, some
units did not have reliable enough costs or resources available
to get an estimate for the cost of the unit. In these instances,
this design utilized graphs and tables from a few sources (cite
textbook and report from eas) that provide a general cost line

9. and based on the characteristics of the unit, prices could be
interpolated from the data available. Since these graphs and
tables are from published data 10 or more years ago, a cost
index was utilized again to find the current cost that these units
would cost today, however this is not the most accurate way to
price these units but for some units this was the only viable
option without simply guessing a value for the unit.
For the second step, once the value of all equipment was
estimated, the other costs associated with the delivery,
installation and more were calculated based on Lang factors, a
method developed by an engineer to simplify the overall cost
estimation for plant creation and a method used to understand
the magnitude of costs associated with designing, building and
running a plant based on what sort of equipment it needs and
what products it produces. While this method is not a useful
method for final design and detailed estimate analysis, for the
purposes of providing a study estimate with a genuine effort to
look for costs associated with things such as utilities, legal fees
and labor costs, this method provides enough detail and
allocates an approximate cost to each category that would go
into later stages of design. Assuming that the plant appears to
be economically feasible from this study estimate, interested
parties would be able to take the different cost categories
looked into in this report and do more accurate calculations
with actual quotes and prices based on location and size needed.
For the cooling tower, research was conducted into the size and
cost needed for the purposes of this project. Based on the
PRO/II design and heat transfer specifications, the results
section shows that the unit would need to handle close to 5000
lb-mol/hr of water in order to cool the exit stream to the
appropriate temperature. This means that the feed rate of water
into the system would be equal to approximately 1800 gallons
per minute and that the cooling tower for this plant would need
to be able to handle that. To ensure a properly sized unit and to

10. have some room for error in case of the need for slightly greater
rates of water to fulfill the needs of heat transfer, the unit
needed was assumed to handle 1900 gallons per minute. An
average cost of $300,000 for a 1000 gallon per minute cooling
tower was found from a company that repairs and maintains
cooling towers and this combined with the size necessary for
this project’s unit allowed an approximate unit cost to be
calculated using the six-tenths rule. Based on the slightly higher
specification of 1900 gallons per minute and assuming a cost of
$300,000 for a similar unit capable of 1000 gallons per minute,
the cooling tower for this project has an expected cost of about
$440,933.82.
This project required two flash drums in its operation, one large
and one relatively small. For the large flash drum, it was
necessary to separate a liquid from a combination of gases that
would require removal from the system. The incoming stream
was overwhelming composed of water, both by volume and
composition, so for the simplification of calculations, it was
assumed that the flash drum would need to handle a volume
slightly greater than the incoming volume of water. This drum
would be at around ambient pressure, so the pressure drop in the
drum was not assumed to be significant and there was a smaller
requirement for what pressures the vessel needed to be capable
of. When calculating for volume, the unit was very large so it is
assumed to be a large horizontal drum and this is what was
available for the cost estimation. Based on a resource published
the US Department of Energy, the cost of the drum was
approximated using a cost curve from 2002 that correlated cost
to the capacity of the drum. The volume of water coming into
the system was approximately 17,286 gallons per hour and to
safely account for the relatively small volume of gases in the
system, the drum size needed was assumed to be a horizontal
drum capable of 20,000 gallons per hour. From the cost curve, it
was approximated that a 20,000 gallons per hour drum would
cost $40,000 in 2002. Using the Nelson-Farrar cost index, it was

11. approximated that a 20,000 gallons per hour flash drum would
cost about $61,005 in 2019.
For the second flash drum, the volume is much smaller than
the first so the capacity that the drum will need to handle is also
smaller. For this drum the liquid volume is made up mostly of
glycol and water and there is an even smaller composition of
vapor in the flash drum. Due to this fact, the calculations were
simplified by using the volumetric flow rate of glycol and water
as the basis for capacity and then scaled up to account for the
vapor in the system. To calculate the cost, a vertical drum was
used to approximate the cost of the flash drum capable of 1800
gallons per hour. The cost curve and Nelson-Farrar cost index
were both utilized and it was found that for a flash drum
capable of at least 1598.8 gallons per hour, it would cost about
$22,873.00 in 2019.
This system utilizes two mixers, one large and one relatively
small. The large mixer relies on a system that can handle
approximately 2000 gallons of material to mix at all times. The
mixing rate was assumed to be around 4 minutes for complete
heat and mass transfer assuming high efficiency from the
agitator and based on the flow rates, a 2000 gallon drum would
be necessary. In order to assume high efficiency mixing, the
ratio between the diameter of the impeller and the diameter of
the mixing drum should be as close to ⅓ as possible (cite
mixing data). If the diameter of the drum is too large, the
impeller will be too small to generate an appropriate flow and
proper mixing between materials will not occur. If the diameter
of the impeller is too large, the drum will be too small and there
will not be enough space on the sides of the impeller to allow
for proper mixing between the fluids above and underneath the
rotors of the impeller. With this in mind, an impeller with an
appropriate diameter was selected after the size of the drum was
calculated. The D/t ratio was calculated to confirm these parts
would work well together and it was estimated that the cost of a

12. large mixer would be about $66,065.89.
The smaller mixer was sized similarly to the large mixer.
Based on the flow rates coming into the mixer, it was assumed
that a 100 gallon drum would be necessary to ensure the system
could meet both the mixing requirements and the volume
coming into the system at any time. Based on a stainless steel
100 gallon drum, it was found to have a diameter of 36 inches.
Because of the D/t ratio, an impeller of 14 inches was selected
and the approximate cost for the unit was $8,849.73.
For the absorber column that intakes the gases when they are
first collected, the column is a 5 tray system that does not have
an attached reboiler or condenser. The unit is expected to have
an efficiency of 25%, meaning that compared to the PRO/II
design, the actual unit will need four times as many trays. To
size the column, a heat factor of the system was used to find the
diameter of the sieve trays needed for the system. Based on
these calculations and the data collected from PRO/II, the
diameter was projected to need to be around 2.9 feet. From
here, graphs from the textbook were used to find the cost of a
column made of stainless steel material per tray used. Since the
cost per tray was estimated to be $6,000, the total system was
expected to run about $120,000 in 2002. Using the Nelson-
Farrar cost index, the cost of a similar system in 2019 was about
$182,984.10.
For this regenerator column, it consists of 5 sieve trays and a
reboiler. For the sake of getting an estimate for cost analysis
purposes, the reboiler was treated as another tray, as the area of
a reboiler would have to be very large in order for it to be more
expensive than the cost assumed per tray. Again, the column
was expected to have an efficiency of 25%, so the actual
number of trays for the system is 24 and the diameter was
estimated using heat duty data from PRO/II. The diameter was
found to be approximately 2.78 feet and the cost per tray in this

13. case was about $5,500 per tray, bringing the cost of this unit in
2002 to about $132,000. In 2019, a cost index was used to find
that the expected value would be about $201,282.36 for this
unit.
For the second absorber column in the system, it had four
trays and no reboiler or condenser on the column. The flow rate
into the system was less than the first column but for cost
analysis purposes, the diameter was assumed to be the same as
the others to ensure proper function. The efficiency of this
particular system is estimated to be around 30%, so the final
system would be around 14 trays. With 14 trays and an assumed
cost of $5,500 per tray in the column, the column needed would
cost about $77,000 in 2002. Using the Nelson-Farrar cost index,
this unit would cost about $117,414.71 in 2019.
For the second regenerator unit, it consisted of two internal
trays and a reboiler and condenser unit attached to the column,
however, based on the assumption that trays will cost more than
condensers or reboilers, both of these auxiliary units were
treated as trays for the purpose of cost analysis. The unit has
four trays and based on the assumption of 50% efficiency, the
system will actually have 8 trays that are sized at around 2.78
feet in diameter and this puts the total price at $44,000 in 2002.
By utilizing the Nelson-Farrar cost index, the unit can be
expected to cost approximately $67,094.12 in the year 2019.
The LNG heat exchanger in the system is utilized to handle
large quantities of heat and return products back to other
streams for resuage. The cost of an LNG heat exchanger is
difficult to locate because of the size and expense associated
with the unit and because of this, the price of the unit needed
was estimated using a smaller heat exchanger assuming large
amount of heat transfer between the different feeds coming into
the unit. For a much smaller unit, the price was found online
from a manufacturer and the condition was assumed that this

14. unit operated closely enough that the six-tenths rule could be
used. Based on the heat transfer necessary compared to the heat
transfer rate associated with the unit found, the estimated cost
of the unit is $414,255.03.
The cost of heat exchangers was based on the cost of a unit
found from a website that produces shell and tube heat
exchangers. Assuming that similar rates of heat transfer would
be possible in actual units used in the design of a liquified
natural gas plant, the cost analysis of the four heat exchanger
units used in the design were estimated using the six-tenths
rule. Based on the PRO/II design and results section, the heat
duty associated with each heat exchanger was found and from
there, the size of the units and the cost for each one was found.
In the example above, the heat exchanger needs to be capable of
transferring 2,230,000 British Thermal Units per hour. On the
basis of what the unit found is capable of, the cost of the unit
needed would be about $26,846.49. The same method and unit
found were utilized for the three other units to give estimated
costs of $12,587, $67,541.83 and $125,512.73.
For the conversion reactor, the cost analysis led to few
results about the price of an actual conversion reactor as it
functions in the PRO/II model. With some more research, the
assumption was made that for cost analysis purposes, the
conversion reactor could be treated as a packed bed reactor
(PBR) or a continuous stirred tank reactor (CSTR) and that
sizing the unit would be roughly equivalent to what the
conversion reactor would require. The flow rates into the
conversion reactor are so large that although it is simulated as a
single unit, it was more appropriate to size the unit as multiple
units to allow for proper function. Based on the cost found of an
8,000 gallon tank reactor, it was calculated that approximately 6
units would be needed to handle the amount of material flowing
into the system. Based on this assumption and along with
treating the unit as 6 different units rather than one very large

15. unit, the estimated cost for a conversion reactor is $1,680,000.
A computer is a necessary part of any process. While
calculating the costs associated with larger control panels and
other electrical equipment that would be necessary is difficult
and therefore lumped with the second step of the cost
estimation, at least one powerful computer is necessary to run
calculations or simulations. For these reasons, the costs of a
computer capable of handling advanced business and simulation
tasks was chosen. An upgraded solid state drive was also
selected for ease of use and for extra storage. Software that this
computer might need was not calculated for directly but can
also be lumped with the costs found in the second step of the
cost estimation. This unit will cost about $1,615.41.
An expander is utilized in the third stage of this plant and has
a very large estimated power output requirement. The cost
analysis of this unit was completed by assuming the cost of an
expander and the cost of a similarly powerful steam turbine
would result in a similar price tag. The plant results showed that
with an expected 80% efficiency, the maximum power output
would be 137,167 horsepower. Additionally, the unit was
selected based on the inlet temperature and pressure
requirements. Using these inlet parameters and power output, a
unit online was found and the estimated cost for the unit was
$2,700,000.00.
Pumps are useful pieces of equipment to change the pressure
of the materials in the pipes of the system. There are three
pumping stations in the plant design and based on data provided
by the simulation of the design, the pumps were estimated to
need 250 hp. One pump did require greater pumping power but
it may be better to pressurize fluids and gases in stages rather
than rapidly to avoid rapid changes in temperature so the unit
was simulated with 4 pumps. A unit capable of similar flow
rates were found but the horsepower was sized and then the cost

16. of 6 of these units were calculated. Based on these estimations,
the pumps in the plant are expected to cost a total of
$157,182.22.
When calculating for depreciation, all units were assumed to
last 10 years before reaching a salvage value of 20% of the
value it was purchased at. Although some units were expected
to last longer and have less physical wear, 10 years seemed to
be a safe estimate so as not to overestimate the service life of
the unit. Based on these assumptions, the total depreciation per
year is about $509,203.47 for the first 10 years of plant
operation and the expected salvage value at the end of those 10
years should be about $1,273,008.67.
Results
Conclusion
Future Works
Our process design uses a commonly used method to remove
CO2 and H2S to regenerate the amine stream, using a
distillation column along with heat exchangers and pumps.
There are many other methods used such as matrix, flashing
feed, and internal exchange that can be used since some are
more energy efficient. The same goes for our process for glycol
regeneration, there are many other methods such as the DRIZO
method. More research can be done on various methods to find a
method which suits best for the natural gas composition. To also
make our process cheaper for glycol dehydration would be to
get rid of the make-up glycol. This can only be done if the
system does not lose any glycol but it would also leave more
water inside the glycol stream. Thus a more optimal solution for
our glycol dehydration can be found. Using different
temperature, pressure, and flow rates of all the streams in the

17. process can also lead to a better performing process. It is
however important to meet the specifications of the amount of
H2S and water allowed in the natural gas. Another possible
room for improvement for our process was in the steam power
cycle. By reheating the steam coming out the turbine and adding
another steam turbine can increase the amount of electricity
produced. Our plant was able to only able to 25 percent of the
heat released from combustion of natural gas as electricity. by
adding an additional turbine it would increase the amount of
electricity produced to about 32 percent. Another method would
be to send the hot gases that comes from the combustion
chamber to a turbine. Using a combination of the hot gas
turbine and steam turbine would be the most optimal solution
and yield 50 percent of the energy released from combustion as
electricity.
One of the biggest improvements for our process design is to
add the liquefaction of natural gas process. By liquefying gases
it will take less room and will be easier to store and transport,
opening an overseas market. There are many processes used to
perform liquefaction of natural gases such as C3MR, DMR,
SMR, and cascade. Many of the most popular methods are made
by Air and Gas Products since they invest large amounts of
money into researching alternative methods of liquefying
natural gas. There is also lots of research of improving the
current processes mentioned above by changing temperature,
pressure, and using different mixtures and amounts of
refrigerant .

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United Nations, Department of Economic and Social Affairs,
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World Bank, Sustainable Energy for All (SE4ALL) database
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World Bank, International Energy Agency, and the Energy
Sector Management Assistance Program.
United States. Congress. Senate. Committee on Energy and
Natural Resources. Liquefied natural gas. Washington : U.S.
G.P.O., 2012
https://www.mckinsey.com/industries/oil-and-gas/our-
insights/global-gas-and-lng-outlook-to-2035
https://www.sightline.org/research_item/what-goes-on-at-an-
lng-facility/
CO2 and DEA reaction
https://www.degruyter.com/downloadpdf/j/eces.2012.19.issue-
1/v10216-011-0006-y/v10216-011-0006-y.pdf
Natural gas specifications
https://www.naesb.org/pdf2/wgq_bps100605w2.pdf

19. Natural gas used for electricity
http://naturalgas.org/overview/uses-electrical/
Mixing info
https://www.mixerdirect.com/blogs/mixer-direct-blog/mixer-
basics-step-4-tank-to-impeller-ratios