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Hydrotreating and Acidic Gas Removal for Natural Gas Pretreatment
Razan Anwar Hamdan, Burcu Okmen Altas, Gursel Abbas, Guliz Topcu, Cansu Goktas, Sabiha G. Yavas, Emre Kirac, and
Ozge Yuksel Orhan, Hacettepe University, Department of Chemical Engineering, Ankara, Turkey
© 2024 Elsevier Inc. All rights are reserved, including those for text and data mining, AI training, and similar technologies.
Introduction 2
Natural Gas Sweetening 2
Natural Gas Definition 2
Formation of Natural Gas 2
Classification of Natural Gas 2
Natural Gas Processing (Treatment) 3
Phase Separation 3
Acid Gas Removal 3
Mercury Removal 4
Dehydration 4
Hydrocarbon Dewpoint Control Unit 5
Natural Gas Transportation 5
Hydrotreating 6
The Importance of Hydrogen 7
Understanding the Different Types of Hydrogen: Toward a Sustainable Energy Future 7
Acid Gases in Natural Gas 8
Hydrodesulfurization 10
Catalyst for Desulfurization 10
Future Challenges for Commercial Hydrodesulphurization 11
CO
2
Removal From Natural Gas 12
Physical Carbon Dioxide Removal Processes 12
Chemical Absorption Processes (CA-LNG) 13
Future Implications 15
Conclusion 15
Acknowledgment 15
References 15
Key Points
•The natural gas treatment process encompasses the elimination of impurities and contaminants to guarantee its quality and
safety.
•Acidic gases like hydrogen sulfide (H
2
S) and carbon dioxide (CO
2
) are prevalent impurities in natural gas necessitating
specific elimination methods.
•Widely adopted, hydrodesulfurization is a common method for sulfur eradication in natural gas, leveraging catalysts for
efficient desulfurization.
•The removal of CO
2
from natural gas can be accomplished through physical methodologies (e.g., Rectisol, Selexol, and
Fluor) and chemical absorption processes using solvents such as potassium carbonate and amines.
Abstract
Natural gas has become a vital energy source due to its abundant availability and relatively low carbon emissions. However,
the presence of impurities, such as sulfur compounds, nitrogen compounds, and acidic gases, poses significant challenges in
both efficiently using natural gas and addressing its environmental impact. This chapter provides a comprehensive overview
of hydrotreating techniques and methods for removing acidic gases during the pretreatment of natural gas. Hydrotreating
involves catalytic processes like hydrodesulfurization (HDS) and hydrodenitrogenation (HDN), aimed at converting
harmful compounds into less detrimental forms. Within this chapter, detailed discussions cover reaction mechanisms,
various catalyst types, and the impact of process conditions on the efficacy of hydrotreating. Furthermore, the chapter
explores multiple technologies utilized for eliminating acidic gases, such as carbon dioxide (CO
2
) and hydrogen sulfide
(H
2
S), from natural gas streams. These methods include absorption, adsorption, and membrane separation. Offering
Reference Collection in Chemistry, Molecular Sciences and Chemical Engineering https://doi.org/10.1016/B978-0-443-15740-0.00047-1 1
significant insights, this chapter serves as a valuable resource for researchers and industry professionals involved in advancing
cleaner and more efficient processes for natural gas pretreatment.
Introduction
This chapter addresses the critical role of natural gas pretreatment in ensuring its purity and suitability for energy use. Key to meeting
stringent quality standards and facilitating smooth downstream operations, natural gas pretreatment involves removing impurities
such as sulfur and nitrogen compounds, acidic gases, mercury, and water. This process is essential for converting sour gas into a form
that complies with environmental and quality regulations. The chapter also explores various pretreatment methods like hydrotreat-
ing and acidic gas removal, vital for eliminating these impurities which otherwise can affect gas quality, infrastructure, health, and
the environment. Aimed at professionals in the field, this comprehensive chapter focuses on advanced techniques, challenges, and
opportunities in natural gas pretreatment, contributing to cleaner and more efficient utilization. Section Natural Gas Sweetening
delves into the concept of natural gas sweetening, outlining its formation and the stages of its processing, including phase separa-
tion, acid gas removal, and more, emphasizing the importance of pretreatment. Section Hydrotreating shifts focus to hydrotreating,
discussing its mechanisms, catalyst types, and process conditions crucial for removing sulfur and nitrogen compounds effectively. In
Section Acid Gases in Natural Gas, the emphasis is on acidic gas removal from natural gas streams, exploring methods for sulfur
and CO
2
removal, including various absorption and separation technologies, and concluding with nitrogen and oxygen removal
strategies.
Natural Gas Sweetening
Natural Gas Definition
Natural gas is one of the most important energy sources, utilized in both domestic and industrial sectors. Natural gas is an ideal fuel
for power generation due to its low capital cost and good heat ratio. According to research done by the US Energy Information
Administration (EIA), due to these factors renewable energy will be one of the fastest growing components of global energy
consumption by 2050. However, it is undeniable that petroleum and natural gas will continue to dominate due to their high
efficiency.
Natural gas streams typically contain high concentrations of methane (CH
4
) and lower concentrations of harmful acidic gases
such as carbon dioxide (CO
2
) and hydrogen sulfide (H
2
S), as well as higher molecular weight hydrocarbons (Abd et al., 2020). The
amount of CO
2
in natural gas varies between 5% and 50%, depending on its source. Therefore, the high concentration of CO
2
in
fossil fuels like natural gas emerges as one of the fundamental causes of global climate change. Natural gas is favored over other
sources such as oil and coal due to its exceptional qualities, particularly its safety, non-toxic nature, and environmental friendliness.
Formation of Natural Gas
The formation of conventional natural gas is a multifaceted process influenced by geological and chemical variables. It hinges on the
presence of reservoir rocks, storing the gas, and impermeable rock layers that inhibit its escape (Speight, 2015). Natural gas orig-
inates from onshore and offshore locales and is formed primarily via the biogenic mechanism, involving methane production
by microorganisms in shallow sediments, and the thermogenic mechanism, resulting from thermal decomposition of buried
organic matter (Keogh et al., 2022). Furthermore, biogenic method, facilitated by methanogenic organisms near the Earth’s surface,
yields natural gas characterized by lower methane content and is linked to relatively recent geological formations (Gutsalo, 1982).
The thermogenic process, on the other hand, occurs deep below the Earth’s crust and involves the thermal decomposition of organic
materials over millions of years, resulting in natural gas with a higher methane concentration and linked with older geological
formations (Li and Horita, 2022;Moore et al., 2018). Understanding natural gas formation is critical for resource exploration,
enabling insights into distribution, abundance, and quality reserves by studying geological conditions, organic matter composition,
and thermodynamic processes. This knowledge is essential for efficient extraction and utilization, contributing to energy security
and sustainability.
Classification of Natural Gas
Classification of natural gas is based on its origin, which may be categorized as either conventional or unconventional gas. Conven-
tional gas can be classified as either associated gas, which is found in conjunction with crude oil, or non-associated gas, which is
found with little or no crude oil. Unconventional gas refers to coal-bed methane, shale gas, deep aquifer gas, and gas hydrates
(found with crude oil). Recently, substantial unconventional gas reserves have been verified. Natural gas can also be classified based
on its chemical composition as well. The gas can exhibit either dryness or wetness, depending on its hydrocarbon composition, or it
might possess a sour or sweet quality, based on its sulfur level.
2Hydrotreating and Acidic Gas Removal for Natural Gas Pretreatment
Non-associated Gas
The classification of natural gas into non-associated and associated gas is important in the exploration and production of hydro-
carbon resources. Non-associated gas refers to natural gas that is found without any accompanying crude oil within the reservoir
rock. It is characterized by the absence of significant oil deposits in the same geological formation. When extracted, non-
associated gas may have its own condensate, which is the liquid hydrocarbon that can be separated from the gas. Non-
associated gas typically has a higher concentration of methane and lower quantities of higher-molecular-weight hydrocarbons
(Abd et al., 2020;Speight, 2015).
Associated Gas
Associated gas is natural gas that occurs in direct contact with crude oil within the same reservoir rock. Associated gas generally has
a lower methane content and higher concentrations of paraffinic hydrocarbons compared to non-associated gas (Abd et al., 2020;
Speight, 2015). It can exist in two different forms. In the first form, it can be dissolved within the oil, meaning the gas is trapped and
dispersed throughout the oil phase. In the second form, it can be separated from the oil and form a gas cap above the oil within the
reservoir. The existence of associated gas alongside crude oil can have ramifications for the oil and gas industry’s production tech-
niques and economic concerns. Fig. 1 provides a visual representation of this concept.
Natural Gas Processing (Treatment)
Natural gas extraction requires specialized drilling machines that penetrate deep into the Earth’s crust to access the reservoir rock.
The pressure differentials cause the natural gas to flow toward the surface. Once captured, the natural gas is transported to pretreat-
ment facilities for further processing before its final utilization (Abd et al., 2020).
Phase Separation
Phase separation is an important first stage in natural gas pretreatment because it assures the gas’s compatibility for following proce-
dures. The feed is gravity separated at this process to separate the natural gas from accompanying liquids such as water and gas
condensate. Separation is achieved based on the density differences of the fluids, and horizontal or vertical phase separators are
commonly used for the primary extraction of natural gas (Alcheikhhamdon and Hoorfar, 2016).
Acid Gas Removal
After the primary phase separation, it is essential to purify natural gas by removing acidic components to reduce toxicity and corro-
siveness. This process, known as “The Sweetening of Natural Gas,”involves the removal of H
2
S and CO
2
compounds. Acid gas
removal can be accomplished through absorption techniques using amine solutions or adsorption techniques utilizing molecular
sieves (Chew et al., 2022;Qayyum et al., 2020).
Utilizing aqueous amine solvents inside absorber-stripper processes, which are often referred to as contactor-regenerator
processes, has been the most common method of acid gas removal over the course of history. Extensive research and development
efforts have been put into aqueous amine technologies, which have been employed in the natural gas industry for more than eight
decades and have been put to commercial use. In order to extract impurities from the product stream that is sought, aqueous amine
solvents make use of chemical processes that are reversible and involves an acid gas and an amine. In spite of the fact that aqueous
amine solutions are highly efficient and dependable in terms of removing acid gases to the low levels that are necessary to fulfill
industrial specifications, they are energy intensive because water evaporates during the process of solvent regeneration (Rochelle,
2009).
New types of solvents have been developed in order to address the removal of CO
2
,H
2
S, SO
2
, and other “acid”gases that are
typically found in processes that produce hydrocarbon fuels or generate electricity from coal or natural gas. This is because the
massive chemical engineering and chemistry challenges that are associated with the generation and production of clean energy
in the early 21st century have prompted the development of these new formulations (Kidnay et al., 2019).
Ionic liquids (ILs) have been proposed as an alternative solvent platform to aqueous amine solvents for applications such as the
removal of carbon dioxide and sulfur dioxide from the flue gas of coal-fired power plants and the removal of carbon dioxide and/or
hydrogen sulfide from natural gas, which is typically referred to as “sweetening.”This is due to the drawbacks that are associated
with conventional aqueous amine solvents. The fact that ILs do not evaporate at temperatures of up to 120 C, which are frequently
Natural gas
Non-associated
Higher methane
content
Associated
Lower methane
content
Gas Cap
Free gas above the crude oil
Dissolved Gas
Dissolved inside crude oil
Fig. 1 Natural gas classification in terms of occurrence relative to crude oil.
Hydrotreating and Acidic Gas Removal for Natural Gas Pretreatment 3
used in solvent regeneration, may allow for greater energy efficiency within a process that has been tuned (Shannon and Bara,
2012). Because of their adjustable structures and relatively low viscosities, imidazolium-based ILs have been researched to a greater
extent than other types of ILs. According to the findings that have been obtained up to this point, the majority of ILs do not possess
the high acid gas capacities that are shown by aqueous amine solutions. This is particularly true in applications where the acid gas
partial pressures are low, such as post-combustion CO
2
capture (Shannon and Bara, 2012). In high pressure acid gas removal appli-
cations, where organic solvents like methanol and oligomers of poly(ethylene glycol) find commercial use in the Rectisol and
Selexol processes, respectively, it may be more prudent to investigate the use of ILs as alternative solvents.
The development of ILs that is capable of directly interacting with CO
2
or creating reversible ILs from neutral molecules that react
with carbon dioxide (or other acid gases). This is the area in which energy efficiency can be increased the most significantly in
comparison to the processes that are now in place, hence the focus will be on performance in low partial pressure applications
such as post-combustion carbon dioxide collection. The elimination of H
2
S, SO
2
, and CS
2
is the subject of more instances that
will include reactive and reversible ILs (Shannon and Bara, 2012).
Mercury Removal
Mercury is an element that is naturally present in the crust of the earth. It is released into the environment as a pollutant that is
harmful via a variety of cycles that are both natural and caused by human activity. Each and every form of mercury, including
elemental mercury, oxidized mercury, Hg(I), and Hg(II), is inherently hazardous to human health (Abai et al., 2015). Mercury
is one of the most significant contributors to environmental pollution, and it is produced by fossil fuels, namely via the burning
of coal or by the emission of natural gas. Many natural gas sources include mercury that was liberated from ores that contained
mercury as a result of secondary geothermal processes. In natural gas fields, mercury is often found in either elemental or mixtures
of elemental and organometallic forms. The quantities of mercury in these fields may vary from less than 0.1 to 5000 mgm
3
,
depending on the geology and geographical location of the reservoir. For a typical gas processing plant that processes 250 MMSCFD
(million standard cubic feet per day ¼28300 m
3
d
1
) of natural gas, the cumulative quantities can be significant and can lead to
problems through accumulation through condensation and amalgamation.
Through liquid metal embrittlement, mercury may be exceedingly corrosive, causing severe damage to process equipment, espe-
cially aluminum heat exchangers. Mercury can also cause damage to stainless steel. For instance, in 1973, an explosion occurred at
the Skikda liquefied natural gas facility in Algeria, which resulted in the deaths of 27 people and a loss of one billion dollars in
financial resources. This was caused by the catastrophic collapse of an aluminum heat exchanger, which occurred as a result of a reac-
tion with mercury contamination (Wilhelm, 2009).
Control and treatment of mercury throughout the oil and gas supply chain are becoming more recognized as being critical. This
is for two reasons: first, to protect employees as well as machinery from exposure to mercury that might be harmful, and second, to
ensure compliance with discharge laws that are becoming increasingly strict. In the context of natural gas processing, mercury
control often refers to the use of fixed-bed scrubbers that are equipped with a solid adsorbent. These scrubbers have the capability
to collect mercury vapor by adsorption, amalgamation, or oxidation followed by adsorption strategies.
Extensive removal of mercury is necessary to prevent corrosion in aluminum-containing exchangers. Currently, the adsorption
process using solid desiccants is the only commercially available technology for mercury removal (Liu et al., 2023;Onaizi, 2022).
Within the gas sector, sulfur-impregnated activated carbons are likely the adsorbents that are used the most often for the purpose
of controlling mercury levels. Some of the slow kinetics of the reactions that are associated with the interaction of mercury with
elemental sulfur under ambient circumstances may be circumvented by the process of impregnating activated carbons with sulfur.
It has been suggested that this phenomenon might be attributed to the presence of sulfur allotropes that include a larger amount of
reactive end groups. Activated carbons, on the other hand, are not as mechanically strong as oxide supports like alumina or silica. As
a result, they are susceptible to attrition, which means that their operational life-times are reduced. Mercury capture from gas has
been examined utilizing copper(II) chloride impregnated on carbon as a “chloride”source. However, the mercury(II) chloride that
was produced as a consequence of this process was only partially collected and leached under high pressure circumstances (Wang
et al., 2020).
Additionally, ionic liquids have been investigated for the purpose of liquid-liquid partitioning of mercury, in the form of
mercury(II), from water. Initially, hydrophobic ionic liquids that included pendant sulfur ligands were used for this purpose. In
further research, it was shown that mercury(II) is capable of partitioning into hydrophobic ionic liquids that are not functionalized
(Papaiconomou et al., 2008).
As a result of the effective involatility of the majority of ionic liquids, it is possible to explore gaseliquid contacting situations
without the risk of polluting process gas streams. Ionic liquids have been shown to be effective in capturing elemental and oxidized
mercury from combustion flue gases. This was accomplished by mixing the ionic liquid with permanganate(VII) as an oxidant
(Abai et al., 2015).
Dehydration
The produced natural gas is often saturated with water vapor, and it may even transport a certain quantity of liquid water depending
on the circumstances. The presence of water in natural gas has the potential to produce a whole host of catastrophic events. As an
example, the presence of water vapor in natural gas that contains carbon dioxide and hydrogen sulfide may result in the formation
of acid, which can cause pipes and equipment to corrode. Within certain circumstances, it has the potential to create gas hydrates
that may block valves, pipelines, and process equipment. This can result in a reduction in the transmission capacity of the pipeline,
4Hydrotreating and Acidic Gas Removal for Natural Gas Pretreatment
an excessive amount of power consumption, and therefore an increase in the extra economic losses. For the purpose of satisfying the
requirements of the pipeline standards, it is necessary to remove water from all natural gas before it is sent to the pipeline. As a result,
the dehydration of natural gas is essential, which is advantageous for the efficient production and exploitation of natural gas.
Absorption with conventional solvents, adsorption with solid desiccants, condensation, membrane separation, and supersonic
separation are the primary ways that are used in the process of dehydrating natural gas in today’s world. Within the realm of indus-
trial production, the process of absorption with standard solvents has been used extensively, among other methods. Triethylene
glycol, known as TEG, is used rather frequently. The process of dehydration using TEG is comprised of two primary stages: the first
stage involves the absorption of water from wet gas by means of an absorption column, and the second stage involves the desorp-
tion of water from the water-loaded solvent used in the regenerator (Bahadori and Vuthaluru, 2009). Due to the fact that the
amount of water present in the recycled TEG would directly influence the quality of the gas product, the regeneration of TEG is
a highly important phase in the whole process. Operating factors, such as the temperature and pressure at which the regeneration
process takes place, have the potential to have an effect on the quality of the TEG that is regenerated. The purity of the TEG that has
been regenerated will grow as the temperature of the regeneration process increases, whereas it will decrease as the pressure of the
regeneration process increases. Because of this, the ideal circumstances for operation are when the temperature is high and the pres-
sure is low. On the other hand, the temperature of the regeneration process has to be maintained at around 208 C, at which point
TEG begins to break down (Netusil and Ditl, 2011). Despite the fact that TEG has a saturated vapor pressure that is relatively low,
there are still a significant number of losses that occur as a result of vaporization. These losses cannot be prevented throughout the
regeneration process. The high running costs are a direct consequence of the high energy consumption as well as the comparatively
significant loss of TEG content. In addition, the TEG dehydration process frequently experiences the phenomenon of foaming,
particularly when hydrocarbons, wax, sand, drilling mud, and other impurities are present. This can result in severe foaming, flood-
ing, higher glycol losses, and poor efficiency, as well as an increase in the cost of maintenance in the absorption column. It is essen-
tial to investigate a more acceptable, efficient, and alternative absorbent to replace TEG for the dehydration of natural gas in order to
avoid the downsides (Yu et al., 2017).
ILs have garnered attention as novel green solvents due to their unique physicochemical properties. However, there has been no
research on IL foaming problems. In many chemical engineering processes these substances have become intriguing green alterna-
tives because of their favorable features. They have the potential to replace standard organic solvents. As a result of the fact that many
ILs are very hygroscopic and have a high solubility for water, it is known that the affinity of ILs for water vapor is even greater than
that of TEG. Moreover, the process of ILs regeneration may be simplified because to the advantage of insignificant vapor pressure,
and practically pure ILs can be produced by merely using a flash tank. In the meanwhile, it is possible to prevent the loss of solvents
due to volatilization. In theory, ILs have the potential to be used as a kind of gas dehydration agents and as an alternate absorbent to
TEG (Yu et al., 2017).
Dehydration is crucial before transporting natural gas to remove dissolved water molecules present in the reservoir. Failure to
remove water can lead to issues such as pressure drop, corrosion, and the formation of slug flow regimes in the pipeline. Various
methods can be employed for dehydration, including absorption using glycol solvents, adsorption using silica gel or molecular
sieves, and the use of refrigeration units (Alcheikhhamdon and Hoorfar, 2016).
Hydrocarbon Dewpoint Control Unit
Extracted natural gas becomes saturated with high molecular weight hydrocarbons due to direct contact with oil in reservoirs. These
hydrocarbons pose transportation risks as they can condense in processing pipes, leading to two-phase flow regimes caused by their
higher dew point. To address this, natural gas is purified by removing heavy hydrocarbons and lowering its dew point. Two
common methods for achieving this are:
i. Refrigeration Units: These units reduce the temperature of rich natural gas to a level at which high dew point hydrocarbons
(heavy hydrocarbons) condense and separate from the main natural gas stream.
ii. Gas Cooling by Expansion: This method involves using a throttling valve to decrease the gas pressure, causing a temperature
drop that leads to the condensation and removal of heavy hydrocarbons from the natural gas (Alcheikhhamdon and Hoorfar,
2016).
At the end of this stage, several separation processes transform the rich natural gas into lean natural gas, which predominantly
consists of methane with only trace amounts of heavy hydrocarbons. Additionally, Natural Gas Liquids (NGLs), including
C2-C4 alkanes and natural gasoline, are obtained (Speight, 2015).
Natural Gas Transportation
The primary method of transporting natural gas is through pipeline infrastructure, which consists of extensive networks on land.
These pipelines connect the gas from production facilities to processing facilities and end consumers. The pipeline system spans
long distances, often hundreds to thousands of kilometers, and includes compression stations along the way to maintain the
gas pressure during transportation (Chebouba et al., 2009;Ma et al., 2019).
In cases where delivering natural gas via pipelines is not feasible, liquefaction of the gas allows for offshore transportation. Lique-
fied Natural Gas (LNG) shipping is favored for long-distance transportation, especially for international shipments as it is more
economical in comparison with laying pipelines across the oceans (Aseel et al., 2021). Liquefying natural gas involves cryogenic
Hydrotreating and Acidic Gas Removal for Natural Gas Pretreatment 5
processes due to methane’s low dew point and gaseous nature, which requires significant refrigeration and is thus costly. To reduce
expenses, the gas is pre-cooled using coolants like water or air, lowering the refrigeration demands. The resulting liquefied natural
gas (LNG) is stored in insulated containers to maintain the low temperatures. At the destination, specialized evaporators re-gasify
the LNG for final use (Alcheikhhamdon and Hoorfar, 2016).
Compressed Natural Gas (CNG) provides an alternative method for natural gas transportation. It involves compressing the gas
to a volume that is less than 1% of its original volume at standard atmospheric pressure. CNG has the advantage of clean combus-
tion emissions and can be stored in cylindrical rigid metallic containers at pressures of 200e248 bar (Khan et al., 2015).
Hydrotreating
The historical development of hydrotreating dates back to the early 20th century, with contemporary advancements shaping its
modern form. Initially focused on sulfur removal, the process has expanded to address a wider range of impurities, including
nitrogen and metals (Navalikhina and Krylov, 1998). This evolution has been driven by both technological advancements and
changing regulatory landscapes. Recent developments in hydrotreating technology have centered on improving the efficiency
and effectiveness of catalysts. Proper catalyst design allows more targeted removal of specific impurities, leading to the production
of cleaner fuels with a lower environmental impact (Speight, 2006). In addition, integrating hydrotreating with other refining
processes, such as hydrocracking, is being explored to optimize overall refining efficiency (Gary et al., 2007). Such environmental
concerns have also prompted research into new catalysts that operate effectively at lower temperatures, thus reducing energy
consumption. These developments are important in the context of escalating environmental regulations and the global push toward
sustainable energy practices (Choi et al., 2021).
In refineries worldwide, crude oil is processed to produce value-added products. Moreover, refineries are required to comply with
environmental policies, laws, and regulations, which increasingly impose limits on sulfur and impurities in fuels. To meet these
requirements, refining processes like hydrotreating are employed to remove sulfur content. Generally, the elemental composition
of crude oil consists of carbon (83%e87%), hydrogen (11%e15%), and trace amounts of sulfur, oxygen, and nitrogen (Barker,
1985). Hydrotreating is a crucial process among various refining processes, aimed at removing impurities such as sulfur and
nitrogen from petroleum products. The selection of an appropriate catalyst depends on the level of hydrotreating required and
the specific impurities present. Cobalt and molybdenum oxides on an alumina matrix are commonly used catalysts (Fahim
et al., 2010).
The challenges faced in hydrotreating are multifaceted. One of the primary challenges is the deactivation of catalysts due to the
accumulation of impurities and regeneration. Another challenge is adapting the process to handle crudes with higher levels of impu-
rities. This adaptation requires ongoing research and development to design catalysts and process conditions that can efficiently
handle such variability. Despite these factors, hydrotreating remains a fundamental process in refining operations. Its development
aimed to meet both industrial demands and environmental standards (Palos et al., 2019).
As a result of the many benefits that they provide in comparison to other kinds of reactors, fixed-bed reactors are the ones that are
used for HDT the most often. However, the most significant drawback that occurs during the HDT of heavy oils is catalyst deacti-
vation as a result of the deposition of metals and coke. This deactivation is most pronounced when the reaction severity is high and
the time-on-stream is extended. During the initial few hours of the stream, the formation of coke occurs at a very quick pace, whereas
the deposition of metals takes place over an extended period. The majority of asphaltene molecules are transformed into coke
during hydrotreating processes that take place at high temperatures. Coke, along with metals, is deposited on the catalyst as the
reaction progresses.
The investigation of catalyst deactivation during the hydrotreating of heavy oil fractions is one of the most essential elements to
consider in order to enhance the catalytic performance of the processes involved in the refining of petroleum. There are three prop-
erties that are used to identify a suitable commercial catalyst. These features include activity, selectivity, and stability.
When it comes to the use of industrial catalytic processes, one of the most significant and ongoing concerns is the gradual decline
in catalytic activity and/or selectivity that occurs over time. The degree of catalyst deactivation is mostly determined by the charac-
teristics of the feed and the circumstances under which the process is carried out. This is because the performance of catalysts
declines with time for the reasons that have previously been mentioned; hence, in order to keep product yields and/or quality
constant, it is necessary to compensate for the loss of catalytic activity by increasing the temperature of the reaction at regular inter-
vals. Each year, the costs that are incurred by industry for the replacement of catalysts and the stoppage of processes amount to
billions of dollars. However, it is unavoidable that the activity of any catalyst will eventually decrease.
There is a clear connection between the examination of catalyst deactivation in the hydrotreating of heavy oil fractions and the
kinetic studies that are essential for the selection and optimization of catalysts in industrial catalytic processes. The results of kinetic
studies give essential information that is included in the database that is used for comparing and selecting catalysts, as well as for
matching the kind of catalyst with the reactor and feed. The characteristics that are established via these kinds of research serve as the
foundation for the construction of kinetic and deactivation models. These models may be used for evaluating the reactivity of heavy
feeds, selecting catalysts, and improving the functioning of catalytic systems.
The demand for petroleum products with a high value, such as middle distillate, gasoline, and lubricating oil, is growing, but the
demand for goods with a low value, such as fuel oil and products based on residue, is dropping. In light of this, refiners should
immediately focus their attention on optimizing the production of liquid products from the different processes and enhancing
6Hydrotreating and Acidic Gas Removal for Natural Gas Pretreatment
the value of the residues collected. Additionally, the fluctuating pricing of crude oils, in addition to the growing production of heavy
and extra-heavy crude oils, have prompted an increase in the amount of research and development that is aimed at improving the
technological capabilities of such heavy materials. The relevance of operations like hydrotreating and hydrocracking, which trans-
form heavy oil fractions into lighter and more valuable clean products, has been brought to light as a result of these developments.
The Importance of Hydrogen
Hydrogen is gaining recognition as a key element in addressing climate change and advancing toward clean, sustainable energy
systems. Its value lies in its ability to decarbonize multiple sectors, offer energy storage solutions, improve energy efficiency, and
support a sustainable and secure energy future (Ajanovic et al., 2022).
Hydrogen plays a crucial role in various sectors and holds significant importance for several reasons:
•Clean Energy Source: Hydrogen, a clean and versatile energy carrier, can be produced from renewable sources like solar, wind, and
hydro power using electrolysis. In fuel cells, it generates electricity with water vapor as its only byproduct, making it crucial for
sustainable energy systems (Pareek et al., 2020).
•Decarbonization: Hydrogen can aid in decarbonization by substituting fossil fuels in different sectors. It serves as a zero-emission
fuel for transportation modes like cars, buses, trains, and ships. It is also useful in industrial processes, heating systems, and
power generation, helping to cut greenhouse gas emissions (Guilbert and Vitale, 2021).
•Energy Storage: Hydrogen can store energy on a large scale, addressing the intermittent nature of renewable energy sources. Excess
electricity generated from renewables can be used to produce hydrogen through electrolysis, which can be stored and later used
for power generation or other applications when renewable energy supply is low or demand is high (Yue et al., 2021).
•Energy Conversion Efficiency: Fuel cells, which use hydrogen as a fuel, have high energy conversion efficiency compared to
traditional combustion-based systems. Fuel cells can convert the chemical energy stored in hydrogen directly into electricity and
heat, offering a more efficient and cleaner alternative to internal combustion engines (Yue et al., 2021).
•Versatility and Flexibility: Hydrogen can be utilized in various sectors and applications. It can be used as a fuel for vehicles, a heat
source for industrial processes, a backup power supply, and even as a feedstock for the production of chemicals, fertilizers, and
other valuable products. Its versatility makes it a valuable resource in enabling the transition to a low-carbon economy
(Bhandari and Shah, 2021).
•Energy Independence and Security: Hydrogen can be produced domestically from local renewable resources, reducing dependence
on imported fossil fuels. This enhances energy security and diversifies energy sources, leading to more resilient and self-
sustaining energy systems (Jasi
unas et al., 2021).
•Air Quality Improvement: Hydrogen-fueled vehicles produce zero emissions at the point of use, resulting in improved air quality
by reducing pollutants that contribute to smog and harmful health effects. Shifting to hydrogen as a transportation fuel can help
mitigate air pollution and improve urban air quality (Mac Kinnon et al., 2016).
Understanding the Different Types of Hydrogen: Toward a Sustainable Energy Future
Hydrogen, a clean and versatile energy carrier, is gaining increasing attention as a key component of a sustainable energy system. It
has the potential to play a crucial role in decarbonizing various sectors and mitigating climate change (Abdin et al., 2023). Different
types of hydrogen have emerged, each with its own production methods and environmental impact (Fig. 2). Green hydrogen is
produced through electrolysis using renewable energy sources, while blue hydrogen involves carbon capture and storage to reduce
emissions. Gray hydrogen, the most common form, is produced from fossil fuels without carbon capture. Other types include
turquoise hydrogen with carbon capture and utilization, brown hydrogen from coal, and purple hydrogen using nuclear power.
Understanding these distinctions is vital in assessing the environmental sustainability of hydrogen production methods (George
et al., 2022).
Green Hydrogen: Green hydrogen is produced through a process called electrolysis, where water is split into hydrogen and oxygen
using electricity, typically sourced from renewable energy sources such as solar or wind power. This method of hydrogen production
is considered environmentally friendly and sustainable since it does not emit CO
2
during production (Muller et al., 2023).
Blue Hydrogen: Blue hydrogen is produced through a similar process as green hydrogen, specifically electrolysis. However, in blue
hydrogen production, the carbon emissions generated during the process are captured and stored, preventing them from being
released into the atmosphere. This carbon capture and storage (CCS) technology reduces the environmental impact of hydrogen
production, although some critics argue that it still relies on fossil fuels for the initial hydrogen production (AlHumaidan et al.,
2023;Novotny, 2023).
Gray Hydrogen: It is considered the least environmentally friendly and the most common form of hydrogen production. It is typi-
cally produced from fossil fuels, primarily natural gas or coal, through a process called steam methane reforming or coal gasifica-
tion. However, gray hydrogen production does not involve carbon capture and storage, resulting in CO
2
emissions being released
into the atmosphere (Park et al., 2022).
Hydrotreating and Acidic Gas Removal for Natural Gas Pretreatment 7
Turquoise Hydrogen: This concept revolves around producing hydrogen from natural gas while incorporating carbon capture
and utilization (CCU) technologies. The goal is to lessen carbon emissions from gray hydrogen production by capturing and repur-
posing the carbon by-products (Tran et al., 2021).
Brown Hydrogen: It is produced from coal through coal gasification, similar to gray hydrogen. However, unlike gray hydrogen,
brown hydrogen does not aim to capture and store carbon emissions, resulting in significant CO
2
emissions (Ibrahim et al., 2021).
Purple Hydrogen: Purple hydrogen is a term used to describe hydrogen produced through the electrolysis process using electricity
generated from nuclear power. It is an emission-free method of hydrogen production but comes with considerations regarding the
safety and long-term storage of nuclear waste.
It’s important to note that the categorization of hydrogen into these different types helps distinguish their environmental impact
and the methods used for their production. Green and blue hydrogen are considered more environmentally friendly and sustainable
compared to gray, brown, or purple hydrogen due to their lower carbon footprint.
Acid Gases in Natural Gas
Natural gas often contains primary contaminants like H
2
S and CO
2
, as well as other acidic compounds such as mercaptans, carbon
sulfide, and carbonyl sulfide. H2S, a colorless but highly toxic and corrosive gas with a rotten egg smell, is common in many natural
gas deposits and crude oil (Bhide et al., 1998). Its concentration varies across reservoirs, posing safety hazards to oil and gas workers
and causing corrosion to equipment, pipelines, and infrastructure (Ma et al., 2021).
CO
2
is a non-toxic, odorless gas that is also commonly found in natural gas. It is a byproduct of the combustion of fossil fuel
burning and is naturally present in reservoirs along with hydrocarbons. Besides, CO
2
is a greenhouse gas and contributes to global
warming. Its presence in natural gas can impact the energy content and quality of the gas, reducing its usability and market value
(Kittel et al., 2012).
Natural gas is a complex mixture of hydrocarbon compounds that can vary in composition depending on the source and loca-
tion of extraction. The terms “sweet”and “sour”gas are commonly used to describe natural gas based on the presence or absence of
acidic components, primarily H
2
S and CO
2
(Onaizi, 2022).
Sweet gas is a type of natural gas with low levels of acidic components like H
2
S and CO
2
.It’s named as “sweet”due to the lack of
the rotten egg odor characteristic of H
2
S. It’s high-quality, less corrosive, and has a higher energy content. Predominantly composed
of methane (over 90%), it also contains ethane, propane, butane, and traces of other hydrocarbons. The low concentration of H
2
S
and CO
2
in sweet gas, meeting regulatory standards, makes it suitable for various uses without extensive treatment (Ghasem, 2020).
Sour gas is another type of natural with high level of acidic components, primarily H
2
S and CO
2
. The concentration of these
acidic components in sour gas can vary significantly depending on the gas reservoir. The presence of these acidic gases in sour
gas can have several implications for safety, equipment integrity, and environmental impact. The corrosive nature of H
2
S can
also cause damage to pipelines, equipment, and infrastructure if not properly managed (Rubaiee, 2023;Taifan and Baltrusaitis,
2017).
Fig. 2 Brief of hydrogen manufacturing and color (Ajanovic et al., 2022).
8Hydrotreating and Acidic Gas Removal for Natural Gas Pretreatment
The presence of acid gases, particularly H
2
S and CO
2
, in natural gas has several significant implications (Nourmohamadi Tae-
meh et al., 2018):
•Safety Risks: H
2
S is extremely toxic, even in small amounts, posing serious health risks like respiratory issues, eye irritation, and
potentially fatal outcomes. Implementing safety measures such as detection systems, personal protective equipment, and gas
monitoring is important to protect employees in areas where H
2
S is present.
•Corrosion: H
2
S is also highly corrosive and can cause damage to pipelines, equipment, and infrastructure. The presence of H
2
Sin
natural gas requires careful consideration and appropriate corrosion-resistant materials to prevent equipment failure, leaks, and
accidents.
•Environmental Impact: The release of CO
2
into the atmosphere during the production, processing, and utilization of natural gas
adds to the overall carbon footprint of the energy industry. Minimizing CO
2
emissions and implementing carbon capture and
storage (CCS) technologies are crucial for mitigating the environmental impact.
•Gas Quality and Usability: High concentrations of CO
2
reduce the heating value of the gas, impacting its usability in various
applications, including power generation and industrial processes. Therefore, it is essential to remove acid gases to ensure the
desired quality and marketability of natural gas.
The process of removing acid gases from natural gas is commonly referred to as gas sweetening or amine sweetening. Gas sweetening
units are employed for this purpose. The selection of an appropriate process depends on various factors, including the type and
concentration of impurities in the sour gas, desired specifications for the treated gas, hydrocarbon composition of the sour gas,
required selectivity for gas removal, and the volume of gas to be treated. These considerations are crucial in determining the
most suitable method for removing acid gases from natural gas (Mokhatab et al., 2015).
In Fig. 3, the gas sweetening process flow diagram is presented. The process primarily consists of an adsorber and a stripper
column. The sour gas is introduced at the bottom of the absorber. Within the adsorber, hydrocarbons and acid gases undergo
condensation in a rich amine solution, while the sweet gas is separated and exits from the top of the column. The solution, carrying
absorbed components, exits the absorber and enters a flash tank separator, where liquid hydrocarbons are removed. The remaining
rich solvent is then heated and directed to the stripper column.
In the stripper column, acid gases are dissolved in the solvent through countercurrent flow. The acid gases exit the top of the
column. At the bottom of the stripper column, the collected lean solvent is condensed in an accumulator and returned to the system.
Additionally, a portion of the lean solvent is heated, filtered, and cooled before being fed back to the absorber (Mokhatab et al.,
2015).
Fig. 3 Gas sweetening plant (Mokhatab et al., 2015).
Hydrotreating and Acidic Gas Removal for Natural Gas Pretreatment 9
Hydrodesulfurization
Sulfur compounds present in hydrocarbons can lead to environmental issues, such as the formation of sulfur dioxide, a major
contributor to acid rain. European countries have established standards for natural gas, as outlined in Table 1, based on the latest
EU regulations.
There are several methods available for removing sulfur content from fuels, including hydrodesulfurization, oxidative desulfur-
ization (ODS), adsorbent desulfurization (ADS), and biodesulfurization (BDS). Among these methods, HDS is the most widely
used process for sulfur reduction and was first reported by Paul Nahin and Raymond Fleck in 1950 (Kadhum and Albayati,
2022). The HDS process involves reacting the hydrocarbon feedstock with hydrogen gas in the presence of a high-temperature
and high-pressure catalyst.
During HDS, the organic sulfur-containing compounds in the hydrocarbon feedstock are converted into H
2
S gas and sulfur-free
hydrocarbons (Jumina et al., 2021). The H
2
S gas is then separated from the reactor and can be further processed to recover sulfur or
converted into more useful chemicals. Typically, the catalyst used in the HDS process is a metal such as molybdenum or nickel. The
operating conditions for hydrotreating typically range from 200 to 425 C and 1 to 18 MPa, although these conditions can be opti-
mized based on the desired level of sulfur removal (Javadli and de Klerk, 2012).
In the HDS process, sulfur-containing compounds are first heated and pressurized to the required conditions. The reaction takes
place in a fixed-bed reactor containing a hydrogenation catalyst. The hydrocarbon feedstock reacts with hydrogen gas in the reactor,
resulting in the formation of H
2
S gas and hydrocarbons with reduced sulfur content. The hydrogen gas is then cooled, recycled, and
returned to the reactor for further use. Simultaneously, the H
2
S gas is sent to a sulfur recovery unit for subsequent processing as a by-
product. The hydrocarbon stream, now with lower sulfur content, is directed to other operations for additional processing (Shafiq
et al., 2022). Fig. 4 provides a process flow chart illustrating these steps.
In summary, the HDS process is typically conducted in two stages. The first stage removes the majority of sulfur, while the second
stage further reduces the remaining sulfur to very low levels. Reaction conditions such as temperature, pressure, and catalyst compo-
sition are carefully controlled to maximize sulfur removal while minimizing the formation of undesirable by-products (Kadhum
and Albayati, 2022).
The HDS process involves two main reactions: hydrogenolysis and hydrogenation. Hydrogenolysis is the process of directly
breaking the CeS bond in sulfur-containing molecules without affecting the hydrocarbon portion. Hydrogenation, on the other
hand, involves the saturation of unsaturated hydrocarbons (C¼C) followed by CeS bond cleavage (Jumina et al., 2021).
In general, the HDS mechanism comprises several steps. First, the sulfur-containing feedstock molecules are adsorbed onto the
surface of the HDS catalyst. Then, the adsorbed molecules undergo activation, where the sulfur-oxygen bond is dissociated, resulting
in the formation of surface sulfur atoms. The sulfur atoms are then hydrogenated by H
2
, forming H
2
S on the catalyst surface. Finally,
the H
2
S desorbs from the catalyst surface, completing the reaction the overall HDS reaction for different compounds can be found in
Table 2 (Wilson et al., 1957). In the table, R-S represents the sulfur-containing molecule, and RH represents the desulfurized
product molecule (Jumina et al., 2021).
Catalyst for Desulfurization
HDS, or hydrodesulfurization, is a process that removes sulfur compounds from hydrocarbon fuels using heterogeneous catalysts.
Developed in Germany in the 1920s and 1930s, it primarily utilizes tungsten and molybdenum catalysts with cobalt or nickel
promoters. NiMo/Al
2
O
3
and CoMo/Al
2
O
3
are common catalysts in HDS, efficiently converting organosulfur compounds to H2S
(Bae, 2017).
Table 1 European standards for natural gas (Yang et al., 2021).
Nation
European Association for
rationalization of gas
energy exchange European Union Germany DVGW USA AGA
US
Department of
oil and gas of
Changtan
Russian
industry
standards
Total sulfur mass
concentration/(mg.m
3
)
30 20 (odorant-free)
30 (containing odorant)
6
8 (containing odorant)
11.5e460 17 e
Mass concentration of
hydrogen sulfide/(mg.m
3
)
5(H
2
SþCOS) 5(H
2
SþCOS) 5(H
2
SþCOS) 5.7e23 5.75 20
Mass concentration of
mercaptan/(mg.m
3
)
666 4.6e46 6.9 36
10 Hydrotreating and Acidic Gas Removal for Natural Gas Pretreatment
The catalyst type depends on the specific application of the HDS process. CoMo catalysts are better for hydrogenolysis, while
NiMo catalysts are more effective for hydrogenating tough sulfur compounds found in heavy oils such as benzonaphthothiophene
(BNT), 4-methyldibenzothiophene (4-MDBT), dibenzothiophene (DBT), and 4,6-dimethyldibenzothiophene (4,6-DMDBT)
(Tanimu et al., 2019). NiMo catalysts suit extensive hydrogenation needs, whereas CoMo catalysts are used for unsaturated hydro-
carbon streams like in fluid catalytic cracking. For batch reactors, CoMo catalysts are preferred, while NiMo catalysts are chosen for
flow reactors with limited contact time. Operating conditions for hydrotreating typically range from 1 to 18 MPa and 200 to 425 C
(Javadli and de Klerk, 2012).
Future Challenges for Commercial Hydrodesulphurization
Crude oil remains an essential energy source for transportation, electricity generation, and chemical processes. However, sulfur
compounds present in aromatic and aliphatic organosulfur compounds pose significant challenges. Crude oil is a flammable liquid
with a black-brown color, derived from the remains of dead plants and animals. The sulfur content in crude oil contributes to critical
environmental problems. During the exothermic combustion process, hydrogen and carbon elements serve as the primary energy
sources, while sulfur elements generate toxic SOx gases and sulfate particulate matter emissions, which are harmful to human health
and the environment. Hydrodesulphurization is a catalytic process that utilizes hydrogen gas to remove sulfur from crude oil.
However, there are several limitations and challenges associated with this method. The hydrodesulphurization process can be
costly, as it requires high-pressure and high-temperature trickle-bed reactors, resulting in relatively high initial setup costs (Kadhum
and Albayati, 2022).
Refineries employ various desulfurization technologies, such as alkylation, biological desulfurization, oxidative desulfurization,
and adsorption, to reduce the sulfur content in crude oil. While there are opportunities for innovation and the development of
advanced desulfurization technologies, researchers worldwide are still working to design, optimize, and overcome the limitations
of the hydrodesulfurization process (Kadhum and Albayati, 2022).
Fig. 4 Hydrodesulfurization process flow diagram (Shafiq et al., 2022).
Table 2 Hydrotreating pathways of organic sulfur compounds.
Types of organic sulfur
compound Reaction mechanism
Mercaptans H2þRSH /RHþH2S
Sulfides 2H2þRSR0/RHþR0HþH2S
Disulfides 3H2þRSSR0/RHþR0Hþ
2H2S
Hydrotreating and Acidic Gas Removal for Natural Gas Pretreatment 11
CO
2
Removal From Natural Gas
Nnatural gas, as a fossil fuel, is seen as a promising energy source for achieving carbon emission reductions (Nocito and Dibene-
detto, 2020). With advancements in carbon capture, utilization, and storage (CCUS) technology, natural gas can potentially achieve
near-zero carbon emissions, making it an attractive option (Nocito and Dibenedetto, 2020).
When natural gas from fossil fuels is liquefied for storage and transportation, it becomes liquefied natural gas (LNG). LNG due to
the low temperature occupies only about 1/600th of the volume of standard-state natural gas. CO
2
is a common impurity found in
natural gas, with nearly 50% of gas reservoirs containing more than 2% CO
2
. Therefore, it is crucial to remove impurities, especially
CO
2
, from natural gas before it is transported or used, particularly prior to liquefaction. The high concentration of CO
2
in the envi-
ronment poses economic, environmental, and safety risks (Tao et al., 2019). Various gas sweetening technologies, such as physical
absorption, chemical absorption, adsorption, membrane separation, cryogenic separation, and hybrid separation, are employed for
CO
2
removal.
Physical Carbon Dioxide Removal Processes
Physical solvents offer several advantages, including strong selectivity for CO
2
, high loading capacity at high acid gas partial pres-
sures, solvent stability, and low energy requirements since most of the solvent can be regenerated by a simple pressure drop. The
performance of physical solvents can be easily predicted. These processes work more efficiently as gas pressure increases because the
solubility of a compound in the solvent is directly proportional to its partial pressure in the gas phase. Physical solvent processes can
achieve high hydrogen sulfide/carbon dioxide selectivities and high levels of carbon dioxide recovery (Shreve and Austin, 1984).
Table 3 presents various carbon dioxide removal processes along with their corresponding trade names. The processes include Meth-
anol, marketed as Rectisol, Poly(ethylene)glycol dimethyl ether, sold under the trade name Selexol, and Propylene carbonate,
commercially available as Fluor. This table provides an overview of different methods and reagents used for carbon dioxide
removal.
Rectisol Process
The Rectisol process, a physical solvent method using chilled methanol, due to high vapor pressure of methanol, is employed for
CO
2
removal at very low temperatures (as low as 75 C) (Speight, 2019). This process involves a two-stage absorption column
where methanol selectively absorbs CO
2
and sulfur compounds are removed, followed by CO
2
separation in a steam-heated regen-
erator. After cooling and refrigeration, the CO
2
is then extracted, and the methanol is recycled (Ghasem, 2020).
Rectisol has several advantages: it’s more selective for CO
2
and doesn’t foam or corrode. It is also thermally and chemically stable
without degradation or the need for a reboiler. However, it’s less capable than other processes and it requires complex and costly
equipment. Additionally, it demands careful handling due to methanol’sflammability and toxicity (Speight, 2019).
Selexol Process
The Selexol process is commonly used for the removal of water, aromatic chemicals, CO
2
, and sulfur compounds. It employs
a solvent called Selexol, derived from polyethylene glycol dimethyl ethers (Speight, 2019). In this process, the feed gas enters
the absorption column from the bottom, while the solvent enters from the top. As they flow counter currently inside the column,
the solvent comes into contact with the feed gas. The CO
2
-rich solvent exits from the bottom of the absorption column and
undergoes flashing. The resulting vapor stream is then recycled back to the absorption column. Unlike the Rectisol process, this
process requires minimal energy for solvent regeneration and can be operated without refrigeration (Speight, 2019).
Fluor Process
The Fluor process utilizes propylene carbonate as a physical solvent to remove CO
2
and H
2
S from natural gas. Propylene carbonate
can also remove water, COS, SO
2
, and C3þhydrocarbons from the natural gas stream. This process is particularly suitable for bulk
CO
2
removal when the CO
2
concentration is above 3% (Ghasem, 2020).
In the Fluor process, the feed gas is first dehydrated and cooled. A series of flash drums are used to regenerate CO
2
, and the
remaining gas is desorbed in a vacuum flash. The solvent is then recycled back to the absorption column. The Fluor solvent offers
advantages such as high solubility for CO
2
, low vapor pressure, low viscosity, and chemical inertness toward all natural gas compo-
nents. Consequently, the system requires low heat and pump requirements, and there is minimal solvent loss. However, the oper-
ation cost is high due to the high solvent circulation rate and the cost of the Fluor solvent itself XXUSMAN.
Table 3 Carbon dioxide removal processes.
Process or reagent Trade name
Methanol Rectisol
Poly(ethylene)glycol dimethyl ether Selexol
Propylene carbonate Fluor
12 Hydrotreating and Acidic Gas Removal for Natural Gas Pretreatment
Chemical Absorption Processes (CA-LNG)
Chemical absorption processes, specifically for liquefied natural gas (LNG), are advantageous due to their lower cost and higher
purification efficiency compared to other gas sweetening methods. When it comes to purifying natural gas for LNG production,
the CO
2
concentration must be reduced to less than 50 ppm. This level of purification cannot be achieved through physical absorp-
tion, adsorption, or membrane separation techniques alone (Wijayanta et al., 2019). There are two main categories of chemical
absorption processes based on the solvents used: Potassium Carbonate-Based Solvent and Amine-Based Solvent processes. These
processes are commonly employed in LNG production to achieve the desired CO
2
removal and purification levels (Wijayanta
et al., 2019).
Potassium Carbonate-Based Solvent
This process is applied for CO
2
removal and it presents multiple benefits: using easily available chemicals, low operating expenses,
minimal solvent degradation, and reduced steam needs. However, it also has downsides, including potential corrosion and stress on
materials, interaction with anti-corrosion agents, foaming issues, and increased wear on pump impellers. Fig. 5 describes the
process, highlighting the steps for effectively purifying natural gas (Ghasem, 2020).
In this process, the overall reaction is influenced by the concentration of potassium bicarbonate. When 1 mol of potassium
carbonate reacts, it produces 2 mol of potassium bicarbonate (Eq. 1). The overall reaction between CO
2
and potassium carbonate
can be represented by the combination of Eqs. (2) and (3):
K2CO2þCO2þH2O42KHCO3(1)
The main reaction occurs in two parts: the hydrolysis of potassium carbonate (Eq. 2) and the carbon dioxide reacts with potas-
sium hydroxide to generate potassium bicarbonate (KHCO
3
)(Eq. 3):
K2CO2þH2O4KOH þKHCO3(2)
KOH þCO2þH2O4KHCO3(3)
Amine-Based Solvent
Amine-based solvents are widely used in natural gas sweetening processes due to their high absorption rates, high CO
2
loading
capacity, low solvent degradation, low corrosion, and low energy consumption. Primary and secondary amines, such as monoetha-
nolamine (MEA) and diethanolamine (DEA), are commonly employed due to their fast reaction rates with CO
2
and cost-
effectiveness (Orhan et al., 2020).
Methyldiethanolamine (MDEA) is currently the most commonly used solvent in gas sweetening operations. It offers advantages
such as strong chemical stability, low solvent degradation, and low energy requirements. However, a significant drawback of MDEA
Fig. 5 Process of the chemical absorption with potassium carbonate solvent (Ghasem, 2020).
Hydrotreating and Acidic Gas Removal for Natural Gas Pretreatment 13
is its slow reaction rate with CO
2
, which limits its application in cases of high CO
2
concentrations or large-scale capacities (Ghasem,
2020).
The reaction between MDEA and CO
2
can be represented as follows:
CO2þMDEA þH2O4HCO
3þMDEAþ(4)
In the case of MEA, carbonate, bicarbonate, and carbamate are formed during the reaction with CO
2
:
Carbonate Reaction:
2RNH2þH2OþCO24ðRNH3Þ2CO3(5)
Bicarbonate Reaction:
ðRNH3Þ2CO3þH2OþCO242RNH3HCO3(6)
Carbamate Reaction:
2RNH2þCO24RNHCOONH3R (7)
These reactions are reversible, moving to the right at low temperatures (adsorption) and to the left (stripping) at high temper-
atures (reverse reaction). The cooling effect in the absorber reduces temperature, increasing CO
2
solubility and increasing CO
2
removal. Fig. 6 illustrates a typical acid gas treatment process flowchart.
Membrane Separation Method
The membrane separation method utilizes selective permeation to separate gases using semipermeable components. The process
relies on pressure differentials, where the undesired gas diffuses from the high-pressure side to the low-pressure side of the
membrane. A higher partial pressure gradient results in a stronger driving force (Naquash et al., 2023).
The gas feed is initially purified by passing it through various filters to remove debris such as sand. It is then cooled to remove
heavier hydrocarbons. To eliminate heavy hydrocarbons or condensable liquids, the stream is further chilled. The hot gas stream is
introduced into the membrane separator. The CO
2
-rich stream and the residue, known as the retentate (the high-pressure
hydrocarbon-rich stream), are separated from the gas stream. Membranes can be arranged in modules, reducing installation costs.
As membranes do not have moving components, operational and maintenance costs are minimal. Moreover, they do not require
instrument air or water. However, there may be hydrocarbon losses with the permeate, and if released into the atmosphere, these
losses can impact greenhouse gas emissions (Jangam et al., 2021;Naquash et al., 2023).
Cryogenic Process
The cryogenic process involves the separation and liquefaction of CO
2
from natural gas streams at very low temperatures. The gas is
cooled to a temperature where CO
2
becomes a liquid, and then separation is achieved through distillation. The main advantage of
cryogenic distillation is the production of readily transportable liquid CO
2
. However, this process requires a significant amount of
power to operate the refrigeration unit and necessitates pre-treatment of the feed gas to prevent freezing issues (Naquash et al.,
2023).
Fig. 6 Process of amine-based solvent sweetening (Ghasem, 2020).
14 Hydrotreating and Acidic Gas Removal for Natural Gas Pretreatment
Hybrid Separation Processes
Physical and chemical solvents are used in hybrid separation procedures. A hybrid separation approach is illustrated by the sulfinol
process. To make the sulfinol process solvent, a physical solvent (sulfolane), water, and a chemical solvent such as MDEA and/or
diisopropanolamine (DIPA) are used. Sulfinol is a highly efficient CO
2
capture solvent due to its unique combination of chemical
and physical solvents.
The sulfone solvent enters into contact with the gas feed in the absorption column. The regenerated solvent is then injected into
the absorber’s top. The rich solvent exiting the contactor is heated in a heat exchanger with the regenerated solvent before being
routed to a stripper. The rich solvent is heated further in the regenerator, causing the acid gas component of the rich stream to
be released. As reflux after being cooled by surplus steam, the CO
2
emitted by the regenerator unit is condensed and partially intro-
duced (Ghasem, 2020).
Future Implications
The field of hydrotreating and acidic gas removal in natural gas pretreatment is ripe for future advancements. Key areas include:
•Emerging Technologies and Innovations focus is on new catalysts and adsorbents, advanced reactor designs, integrating renewable
energy, and using modeling and simulation for optimization.
•Research on Environmental and Sustainability Considerations is aimed at greener solvents, sustainable extraction methods, and
carbon capture to minimize emissions, alongside developing closed-loop systems for better resource and waste management.
•Market Trends and Industrial Applications are important for assessing the economic feasibility and scalability of these technologies
for industrial use, their integration with existing networks, and potential markets and regions for significant impact.
•Research Challenges and Open Questions involve understanding reaction mechanisms and kinetics, the impact of impurities on
catalysts, process intensification, and assessing long-term durability and maintenance of systems.
Conclusion
This chapter covers the essential hydrotreating and acidic gas removal techniques for natural gas pretreatment. Acidic gases like CO
2
and hydrogen sulfide, varying widely in concentrations, make natural gas corrosive and toxic. Their presence lowers the gas’s heating
value and complicates cryogenic processes. Addressing these gases is crucial for safety, environment protection, and to avoid high
costs due to corrosion-resistant materials. Effective control of these gases is key in early gas treatment stages to ensure economic
feasibility.
The chapter provides insights into the mechanisms, catalyst types, and process conditions vital for efficient hydrotreating. It
serves as a valuable resource for professionals in natural gas pretreatment, aiming to enhance cleaner and more efficient gas utili-
zation while reducing greenhouse gas emissions and promoting sustainability. Overall, mastering hydrotreating and acidic gas
removal is fundamental for maintaining gas quality and ensuring the sustainability of natural gas usage.
Acknowledgment
AI and technologies aided by AI are employed to enhance the clarity and linguistic quality of the writing process.
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