RU2596764C2 - Natural gas liquefaction method - Google Patents

Abstract

FIELD: gas industry.

SUBSTANCE: gas plant for liquefying the flow of initial natural gas is proposed. Plant includes gas separation unit, having at least one fractioning reservoir. Adsorption layers for adsorption kinetic separation are used in the separation unit. Adsorption layers release methane-rich flow of initial gas. Plant also includes refrigeration system with expander cycle of high pressure. Refrigeration system compresses the methane-rich gas flow to absolute pressure making more than approximately 1,000 pounds per square inch (6895 kPa). Refrigerating system also cools down the flow of methane-rich initial gas in one or more refrigerators and then extends the flow of cooled natural gas, forming a flow of liquefied product. Methods of initial natural gas flow liquefaction using AKP and refrigerating system with expander cycle of high pressure are also proposed in this invention.

EFFECT: these methods make it possible to produce LNG using plant with smaller weight than traditional ones.

26 cl, 9 dwg, 4 tbl

Description

Cross reference to related application

This application claims the priority of provisional patent application US No. 61/521657, filed August 9, 2011 and entitled "Method of liquefying natural gas", which in its entirety is incorporated herein by reference.

BACKGROUND OF THE INVENTION

This section is intended to present a variety of technical aspects that may be associated with exemplary embodiments of the present invention. This discussion is considered to be helpful in creating the basis for a better understanding of specific aspects of the present invention. Accordingly, it should be understood that this section is best viewed in this light and not necessarily as achievements of the prior art.

FIELD OF THE INVENTION

The present invention relates to the processing of gaseous fluids. More specifically, the present invention relates to the liquefaction of natural gas, in particular gaseous hydrocarbons produced in remote locations.

Technology talk

As demand for fossil fuels grows around the world, energy companies are forced to explore hydrocarbon resources located in more remote and disadvantaged areas of the world, including on the coast and on the high seas. This includes natural gas exploration.

Due to its clean combustion quality, natural gas has become widely used in recent years. However, many sources of natural gas are located in geographic areas that are vast distances from commodity markets. In some cases, a pipeline is already in place or may be constructed to transport the produced natural gas to the commodity market. However, when there is no pipeline for transportation, the produced natural gas is often transported by ocean vessels.

To minimize the volume of transported gas, often the gas is subjected to a liquefaction process. Liquefied natural gas (LNG) is obtained by cooling very light hydrocarbons, for example, gases containing methane, to about -160 ° C. Liquefied gas can be stored at ambient pressure in special cryogenic tanks installed on large vessels. Alternatively, LNG can be liquefied at elevated pressure and elevated temperature, i.e. above -160 ° C, and in this case, the well-known term "compressed LNG" (LNG) is used. For the purposes of the present invention, LNG and LNG may be referred to by the single general term “LNG”.

According to recent developments, the gas is subjected to a liquefaction process in the closest place to its production point. This means that it is necessary to build large production and liquefaction centers in producing countries. Alternatively, the liquefaction process can be carried out using an offshore platform or system, such as a floating production, storage and shipping system (PSHO). Currently, large liquefaction plants have Qatar, Russia (Sakhalin Island), Indonesia and other countries. Several major LNG terminals are under construction or are currently planned for Australia.

After the natural gas is cooled to a liquid state, the hydrocarbon product is loaded onto marine transport vessels. Such vessels are known as LNG tankers. The cooling of natural gas to a liquefied state ensures the transport of a significantly larger mass of gas.

When designing an LNG plant, one of the most important issues is how to convert the feed stream of natural gas to LNG. Currently, the most common liquefaction methods using some form of refrigeration system. Although many refrigeration cycles are used to liquefy natural gas, there are three types of refrigeration systems most commonly used in LNG plants.

A system of the first type is known as a cascade cycle. In a cascade cycle, many one-component refrigerants are used in series-mounted heat exchangers to reduce the gas temperature to the liquefaction temperature. The refrigeration system of the second type is a “multi-component refrigeration cycle”. This system uses a multi-component refrigerant in specially designed heat exchangers. The third type of system is an “expander cycle”. The expander cycle system expands the gas, decreasing its pressure from the original to low pressure and producing a corresponding decrease in temperature according to Boyle's law. Most natural gas liquefaction cycles use variations or combinations of these three main types.

The modern version of the expander cycle is a high pressure expander cycle. In this system, a liquefaction process is carried out, which is more efficient and compact than the cycles described above. As a result, it is an attractive option for use in remote or offshore installations.

Limiting the use of any liquefaction system is the presence of contaminants in the natural gas stream. Unrefined natural gas produced from underground formations typically contains components that are undesirable in the LNG process. Such components include water, carbon dioxide and hydrogen sulfide. Water and CO ₂ should be separated because they freeze at liquefaction temperatures and clog the liquefaction equipment. H ₂ S should be separated as it may cause an adverse safety effect or may adversely affect the characteristics of the LNG product. Thus, the produced natural gas is typically treated before liquefaction to separate undesired components or contaminants.

When H ₂ S and CO ₂ are produced as part of a gaseous hydrocarbon stream (such as methane or ethane), the crude gas stream is sometimes referred to as the “sulfur containing gas” term. H ₂ S and CO ₂ are often referred to by the generic term acidic gases. Methods have been developed for separating acid gases from a crude natural gas stream. In some cases, cryogenic gas processing is used. It involves cooling the gas stream in a large cryogenic tank so that the components of CO ₂ and H ₂ S precipitate as solid precipitation. Hydrocarbon components are distilled from the tank. For this method, as a rule, it is necessary that the crude gas stream is dehydrated before cryogenic separation.

Alternatively, the gaseous hydrocarbon stream may be treated with a solvent. Solvents may include chemical solvents such as amines. Examples of amines used in the treatment of a sulfur-containing gas include monoethanolamine (MEA), diethanolamine (DEA) and methyldiethanolamine (MDEA). Instead of amine solvents, physical solvents are sometimes used. Examples of physical solvents include Selexol® and Rectisol ™. In some cases, hybrid solvents are used, i.e. mixtures of physical and chemical solvents. An example is Sulfinol®. However, the most common is the use of amine-based solvents to separate acid gases. In any case, solvent extraction is usually carried out using a large thick-walled countercurrent contact column.

In a solvent extraction method, an aqueous solvent is used to absorb unwanted substances. For this reason, water is stored in the treated gas, which must be separated to prevent freezing and clogging of the fluidizing equipment.

Regardless of whether water is removed before or after acid gas separation, the water removal process is typically carried out in several stages to fulfill the requirements of an extremely low water content in the gas to be liquefied. A process is being developed based on a dehydration system using glycols to separate bulk water, followed by several layers of molecular sieves as stages of final purification. Thus, for the solvent extraction step, several items of large and heavy equipment that are moisture sensitive are required. Such equipment is unattractive for offshore installations where volume and mass matter, and wave movement is inevitable.

In addition to water, nitrogen can also be removed from the gas stream. Nitrogen should be removed because it does not have a calorific value and, accordingly, adversely affects the quality of the fuel. Nitrogen is typically removed after acid gas separation and liquefaction are carried out. Nitrogen is removed using a distillation column known as a nitrogen removal unit (ASU). ASA is sensitive to the movement of waves. In addition, ASA, as a rule, includes several large and heavy items of heat-exchange equipment, which are not particularly suitable for use in offshore installations.

There are other adverse effects from the presence of nitrogen in the crude gas stream. For example, removing nitrogen after, rather than before, the liquefaction stage increases energy consumption for liquefying the gas. In this regard, nitrogen increases the amount of gas to be liquefied. In addition, the presence of nitrogen reduces the liquefaction temperature of the mixture, since nitrogen has a lower boiling point than methane.

Due to the strict technical conditions, LNG plants for the pre-treatment of raw materials are large, heavy and expensive. For example, according to an idea of a floating LNG plant at nominal levels of contaminants (e.g., water up to saturation 1% CO _2, 4% N ₂₎ gas in the source device for the separation of these contaminants account for approximately 20% of the total weight of the deck installation. For technologies involving the processing of feed gas with high levels of pollutants (e.g. water to saturation plus 50% to 70% CO ₂ and H ₂ S), devices for separating pollutants can comprise more than 50% of the weight of the deck installation. In addition, large vertical pressure vessels or columns, which are typically used to separate contaminants, can have an undesirable effect on the stability of a floating structure.

Thus, there is a need for an improved plant that processes natural gas for liquefaction, which is less sensitive to the movement of waves and has little effect on the stability of the floating structure. In addition, there is a need for a more compact, lightweight and energy efficient LNG system that can be used for an offshore platform. In addition, there is a need for a method for efficiently processing natural gas for liquefaction, which is compatible with a refrigeration system with a high pressure expander cycle.

SUMMARY OF THE INVENTION

Firstly, a gas processing plant for liquefying a stream of a source of natural gas has been proposed. This unit has a more compact design and is more efficient than a traditional LNG plant. Thus, the installation proposed in this document is ideally suited as an LNG installation located at sea or in a remote location. For example, this gas processing facility may be located on a floating platform or gravity platform at sea.

First of all, the installation includes a gas separation unit having at least one fractionation tank. The fractionation tank serves to separate contaminants from methane gas. For this purpose, each tank has a gas inlet for receiving a mixture of natural gas. In addition, according to one embodiment, each reservoir includes an adsorption material that has a kinetic selectivity in favor of pollutants with respect to methane of more than 5. Thus, the pollutants are kinetically adsorbed adsorption material. In addition, each tank includes a gas outlet. The gas outlet releases a stream of methane-enriched gas.

One or more adsorption layers are used in the reservoir for adsorption kinetic separation. The adsorption layers release a stream of methane-rich feed gas. According to one aspect, a single reservoir is used having multiple adsorption layers arranged in series. For example, at least one fractionation tank in the gas separation unit may be a tank containing a plurality of adsorption layers arranged in series, such that:

the first adsorption layer is mainly intended to separate water and other liquid components from the dehydrated natural gas feed stream;

the second adsorption layer is mainly intended for separating the desiccant from the dehydrated natural gas feed stream; and

the third reservoir includes an adsorption layer, mainly for separating the sulfur-containing gaseous component from the dehydrated natural gas feed stream.

Additional tanks can be installed to adsorb and separate nitrogen and various sulfur-containing gases.

According to another aspect, a plurality of tanks installed in series are used, each tank discharging a stream of methane gas, gradually purged of sulfur. For example,

in the first tank, an adsorption layer is used to separate the water remaining in the dehydrated natural gas feed stream;

in the second tank, an adsorption layer is used to separate the desiccant from the dehydrated stream of the source natural gas; and

in the third tank, an adsorption layer is used to separate the sulfur-containing gaseous component from the dehydrated natural gas feed stream.

The acidic gaseous component may be one or more sulfur compounds. Alternatively, the acidic gaseous component may be carbon dioxide.

At least one fractionation tank in the gas separation unit operates in the mode of adsorption at variable pressure (APD) or short-cycle adsorption at variable pressure (KCAPD). In addition, at least one fractionation tank can operate in a variable temperature adsorption (APT) or variable temperature short-cycle adsorption (CAPT). In any configuration, fractionation tanks are designed to adsorb CO ₂ , H ₂ S, H ₂ O, heavy hydrocarbons, volatile organic compounds (VOCs), mercaptans, or combinations thereof.

The installation also includes a refrigeration system with a high pressure expander cycle. The refrigeration system includes a first compressor unit. The first compressor unit is designed to receive a substantial portion of the methane-rich gas stream from the gas separation unit and to compress the methane-rich gas stream to an absolute pressure of more than about 1000 psi (6895 kPa). Thus, a stream of compressed feed gas is obtained.

The refrigeration system also cools the methane-rich feed gas stream in one or more refrigerators and then expands the chilled feed gas stream to form a liquefied product stream. For this purpose, the system includes a first cooler designed to cool the compressed feed gas stream and produce a compressed compressed chilled feed gas stream, and a first expander designed to expand the compressed chilled feed gas stream and produce a product stream.

The product stream contains a liquid fraction and a small residual vapor fraction. Preferably, the gas processing unit also includes a liquid separation tank. This separation tank is designed to separate the liquid fraction and the residual vapor fraction. The vapor fraction is still very cold, and it can be trapped as an instantaneous gas and circulated as part of the first cooling circuit. The first cooling circuit includes at least one heat exchanger that serves as a first refrigerator. The first refrigerator receives the vapor fraction from the first expander and releases (i) a stream of compressed cooled feed gas and (ii) a stream of partially heated steam after heat exchange with a stream of compressed feed gas.

A refrigeration system with a high pressure expander cycle may include a separate heat exchanger that is designed to further cool the compressed feed gas stream. This is done, at least in part, by indirect heat exchange between the refrigerant stream (together with part of the vapor stream) and the compressed methane-rich feed gas stream. A separate heat exchanger is a second refrigerator. In addition, the refrigeration system also includes a second refrigeration circuit having (i) a second compressor unit for re-compressing the refrigerant stream after the refrigerant stream has passed through the second refrigerator, and (ii) a second expander for receiving the compressed stream refrigerant from the second refrigerator and expanding the compressed refrigerant stream before returning to the second refrigerator.

The second refrigerator may subcool the chilled feed gas stream after the chilled feed gas stream exits the first cooler. As an alternative, which is more preferred, the second refrigerator pre-cools the compressed feed gas stream before the compressed feed gas stream enters the first refrigerator. For this purpose, the second refrigerator receives a partially heated steam stream from the first refrigerator for additional heat exchange with the compressed feed gas stream, and discharges the heated product steam stream into the third compressor unit to complete the first cooling circuit.

In any case, the first cooling circuit preferably returns the steam portion of the product back to the first compressor unit. For this purpose, the first cooling circuit may include a third compressor unit for compressing the partially heated steam stream after heat exchange with the compressed source gas stream and a line for combining the compressed partially heated steam stream and the compressed methane-rich source gas stream. This completes the first cooling circuit.

The gas processing unit preferably further includes a dewatering tank. The dewatering tank is designed to receive a stream of natural gas feed and to separate a substantial portion of the water from the natural gas feed stream. The dewatering unit then releases a dehydrated natural gas feed stream to the gas separation unit.

In addition, this document provides a method for liquefying a stream of feed natural gas. In this method, adsorption kinetic separation is used to produce a methane-rich gas stream. In addition, this method uses a refrigeration system with a high pressure expander cycle to cool methane and produce commercial LNG. Commercial LNG is preferably produced at sea on a floating platform or gravity platform.

Firstly, the method includes receiving a feed of natural gas in a gas separation unit. The gas separation unit includes at least one fractionation tank. The fractionation tanks are constructed in accordance with the fractionation tank described above in accordance with its various embodiments. The fractionation tanks preferably operate in a pressure swing adsorption (APD) or variable pressure short cycle adsorption (HACCP) mode to regenerate a sequence of adsorption layers. Adsorption layers are designed to adsorb CO ₂ , H ₂ S, H ₂ O, heavy hydrocarbons, volatile organic compounds (VOCs), mercaptans, nitrogen, or combinations thereof.

The method also includes substantial separation of methane from pollutants in the feed stream of natural gas. This is accomplished through the use of adsorption layers in one or more fractionation tanks. As a result, the method also includes discharging a stream of methane-rich gas from the gas separation unit. In one aspect, methane is separated from contaminants by a gas separation unit at an absolute pressure of at least about 500 psi (3447.5 kPa).

In addition, the method includes directing the flow of methane-enriched gas into a refrigeration system with a high pressure expander cycle. A refrigeration system is generally constructed in accordance with the refrigeration system described above in accordance with its various embodiments. Thus, the refrigeration system preferably includes a first cooling circuit for recirculating the steam portion of the product and its use as a refrigerant in the first refrigerator and a second cooling circuit for recycling nitrogen-containing gas as a refrigerant in the second refrigerator.

The method also includes compressing the methane-rich gas stream. The gas stream is compressed to an absolute pressure of more than about 1000 psi (6895 kPa) in order to obtain a compressed feed gas stream. In addition, the method includes cooling the compressed feed gas stream by means of the second and first refrigerators to produce a compressed cooled feed gas stream.

The method also includes expanding the compressed chilled feed gas stream. In this case, a LNG product stream is formed, which contains the liquid fraction and the residual vapor fraction.

The high pressure expansion cycle refrigeration system preferably includes a liquid separation tank. In addition, the method further comprises separating the liquid fraction and the residual vapor fraction.

In addition, this document provides a method for liquefying a stream of feed natural gas. As in the method described above, this method uses adsorption kinetic separation to produce a methane-rich gas stream. In addition, the method additionally uses a refrigeration system with a high pressure expander cycle to cool methane and produce commercial LNG. Commercial LNG is preferably produced at sea on a floating platform or gravity platform.

Firstly, the method includes receiving a stream of natural gas in a gas processing plant. The gas processing plant includes a dewatering tank. In addition, the method includes passing a stream of source natural gas through a dewatering tank. It serves to separate a substantial part of the water from the flow of the source natural gas. The dehydrated natural gas feed stream is then discharged into the gas separation unit as a dehydrated natural gas feed stream.

The gas separation unit includes at least one fractionation tank. The fractionation tanks are constructed in accordance with the fractionation tank described above in accordance with its various embodiments. The fractionation tanks preferably operate in a pressure swing adsorption (APD) or variable pressure short cycle adsorption (HACCP) mode to regenerate a sequence of adsorption beds.

In addition, the method includes passing a stream of dehydrated feed natural gas through a sequence of adsorption layers. They serve to separate methane gas from contaminants in a dehydrated natural gas feed stream. The layers use adsorption kinetic separation. Adsorption layers are designed to adsorb CO ₂ , H ₂ S, H ₂ O, heavy hydrocarbons, volatile organic compounds (VOCs), mercaptans, nitrogen, or combinations thereof.

According to one aspect, a single reservoir is used comprising a plurality of successive adsorption layers.

According to another aspect, a plurality of tanks are arranged in series, these tanks being installed in the direction of flow of the dehydrated natural gas feed stream. Each tank releases a stream of methane gas, sequentially purified from sulfur compounds.

As a result of passing a stream of dehydrated feed natural gas through the adsorption layers, a stream of methane-enriched gas is produced. The method includes discharging a stream of methane-enriched gas from a gas separation unit. The methane-rich gas stream is then sent to the refrigeration system with a high pressure expander cycle.

The refrigeration system is basically constructed in accordance with the refrigeration system described above in accordance with its various embodiments. Thus, the refrigeration system preferably includes a first refrigeration circuit for recycling the steam portion of the product for use as a refrigerant in the first refrigerator and a second refrigeration circuit for recycling the nitrogen-containing gas as a refrigerant in the second refrigerator.

The method also includes compressing the methane-rich gas stream. The gas stream is compressed to an absolute pressure of more than approximately 1000 psi (6895 kPa) in order to obtain a compressed feed gas stream. In addition, the method includes cooling a stream of compressed feed gas to produce a stream of compressed cooled feed gas.

The method further includes expanding the stream of compressed chilled feed gas. In this case, a LNG product stream is formed, which contains a liquid fraction and a small residual vapor fraction. In one aspect, expanding the compressed chilled feed gas stream includes reducing the pressure of the compressed chilled feed gas stream to an absolute pressure of 50 psi (345 kPa) to 450 psi (3103 kPa).

Brief Description of the Drawings

To make the present invention more clear, certain illustrations, drawings, and / or process flow diagrams are attached to this description. It should be noted, however, that these drawings illustrate only selected embodiments of the present invention, and therefore, should not be construed as limiting its scope, since other equally effective embodiments and applications may be valid for the present invention.

FIG. 1 is a flowchart of an LNG plant in accordance with one embodiment of the present invention. This installation includes a gas separation unit, which produces a stream of methane-enriched gas, and a refrigeration system with a high pressure expander cycle for the production of commercial LNG.

FIG. 2 is a perspective view of a variable pressure adsorption tank that can be used in the installation of FIG. 1, according to one embodiment. This reservoir is also a kinetic fractionator according to one embodiment of the present invention.

FIG. 3A is a perspective view of the adsorption layer and flow channels of the variable pressure adsorption tank shown in FIG. 2, according to one embodiment. The main flow channels are visible between the adsorption rods along the main axis of the adsorption layer.

FIG. 3B is an exploded view of the adsorption layer illustrated in FIG. 3A. FIG. 3B is an open view of an optional second gas outlet. A transverse flow channel is shown extending into the reservoir and serving as an auxiliary flow channel.

FIG. 3C is a longitudinal sectional view of the adsorption layer shown in FIG. 3A, according to an alternative embodiment. This section is taken through line C-C in FIG. 3A. Here you can see a series of stepped surfaces along the adsorption rods, which serve as auxiliary flow channels.

FIG. 4 is a perspective view of an adsorption layer and flow channels of a pressure swing adsorption tank illustrated in FIG. 2, according to a modified configuration. The main flow channels between the adsorption rods along the main axis of the adsorption layer are visible. The transverse flow channels, which are visible in the parts of the adsorption layer spaced apart in the image, serve as auxiliary flow channels.

FIG. 5 is a flow chart of a high pressure expansion cycle refrigeration system according to one embodiment. This refrigeration system receives a stream of methane-enriched gas and produces commercial LNG. The illustrated refrigeration system uses a secondary cooling circuit, which is a closed loop that uses gaseous nitrogen or a nitrogen-enriched gas or part of a methane-enriched gas stream from a gas separation unit.

FIG. 6 is a flowchart illustrating the steps of liquefying a crude natural gas stream.

FIG. 7 is a flowchart illustrating the steps of separating contaminants from a crude natural gas stream using adsorption kinetic separation.

Detailed Description of Certain Embodiments

Definitions

As used herein, the term “hydrocarbon” means an organic compound that includes, mainly, if not exclusively, elements such as hydrogen and carbon. Hydrocarbons, as a rule, are divided into two classes: aliphatic or straight-chain hydrocarbons and cyclic or ring containing hydrocarbons, including cyclic terpenes. Examples of hydrocarbon-containing materials include any form of natural gas, oil, coal, and bitumen that can be used as fuel or processed into fuel.

As used herein, the term “fluid” means gases, liquids and combinations of gases and liquids, as well as combinations of gases and solid materials and combinations of liquids and solid materials.

As used herein, the term “hydrocarbon fluids” means hydrocarbons or mixtures of hydrocarbons that are gases or liquids. For example, hydrocarbon fluids may include hydrocarbons or mixtures of hydrocarbons, which are gases or liquids under formation conditions, processing conditions, or environmental conditions, i.e. at 15 ° C and atmospheric pressure (0.1 MPa). Hydrocarbon fluids may include, for example, oil, natural gas, coalbed methane, shale oil, pyrolysis oil, pyrolysis gas, coal pyrolysis product, and other hydrocarbons that are in a gaseous or liquid state.

As used herein, the term “acid gas” means any gas that dissolves in water to form an acidic solution. Non-limiting examples of acid gases include hydrogen sulfide (H ₂ S), carbon dioxide (CO ₂ ), sulfur dioxide (SO ₂ ), carbon disulfide (CS ₂ ), carbon sulfide (COS), mercaptans, or mixtures thereof.

As used herein, the term "underground" means a geological formation below the earth's surface.

The term "seabed" means the bottom of the marine environment. The marine environment may be an ocean or sea or any other body of water in which waves, winds and / or currents arise.

The term "marine environment" means any marine object. A marine object may be in shallow waters or in deep waters. The marine environment may be an ocean, bay, large lake, estuary, sea or strait.

The term "approximately" is intended to resolve some deviation in mathematical accuracy due to tolerances that are acceptable in the art. Accordingly, any small deviations in the direction of increasing or decreasing from the value before which the term “approximately” is used should be considered as definitely corresponding to the specified value.

The term “variable adsorption process” includes processes such as variable pressure adsorption (APD), variable temperature adsorption (APT), and adsorption at variable partial pressure or pressure flushing (APPD), including combinations of these processes. These processes of variable adsorption can be carried out with short cycles, and in this case they are called the following terms: short-cycle adsorption at variable pressure (CACAP), short-cycle adsorption at variable temperature (CACAP) and short-cycle adsorption at variable partial pressure or pressure flushing (CACAP). The term “variable adsorption” also includes these short cycle processes.

When used in this document, the term "pressure swing adsorption" should be considered as combining all these processes, i.e. APD, APPD, KTSAPD and KTSAPD, including combinations of these processes in which pressure change is used for a purge cycle.

As used herein, the term “borehole” means a hole in an underground formation made by drilling or inserting a pipe into an underground formation. A borehole may have a substantially circular cross-section or other cross-sectional shapes. As used herein, the term “borehole” when used to denote a hole in a formation can be used interchangeably with the term “borehole”.

The term “platform” means any platform or surface whose dimensions and configuration are suitable for installing fluid processing equipment.

Description of specific embodiments

FIG. 1 is a schematic representation of a gas processing plant 100 for producing LNG in accordance with one embodiment of the present invention. The term “LNG” means natural gas that has been liquefied during cooling. Gas processing unit 100 receives crude natural gas by its action, separates certain undesirable components, producing a stream of gas purified from sulfur compounds that meets the established specifications, and then cools the stream of gas purified from sulfur compounds (enriched in methane), producing a practically liquid phase, ready for transportation.

In the configuration illustrated in FIG. 1, installation 100 receives fluids from a reservoir. The reservoir is shown in scheme number 110. The reservoir 110 is an underground reservoir that contains hydrocarbon fluids in quantities acceptable to the industry. Hydrocarbon fluids exist at the production site, mainly in the gas phase.

Produced fluids are obtained through a variety of boreholes. One illustrative borehole 112 is shown in FIG. 1. However, it should be understood that a plurality of boreholes 112 can be drilled through the earth's surface into an underground reservoir 110. The present invention is not limited to the number of boreholes or the manner in which boreholes are completed.

The borehole 112 carries hydrocarbon fluids from the reservoir 110 to the earth’s surface 115. The earth’s surface 115 may be on land. More preferred for the present invention, land surface 115 is the seabed. In this latter case, the wellhead (not shown in the drawing) is at the bottom of the marine environment. Underwater connecting lines and / or pipelines direct the produced fluids to a reservoir (not shown in the drawing), which then delivers the fluids to the ocean surface through one or more production risers.

In FIG. 1 shows a line 112 ′ for transporting hydrocarbon fluids. Line 112 ′ may be a land pipeline. A more preferred line 112 ′ is a production riser in the marine environment. In any case, the produced fluids enter the separator 120.

Upon entering the separator 120, the produced fluids are a mixture of crude natural gas. Produced fluids contain methane or natural gas. Produced fluids may also contain so-called “heavy hydrocarbons”, which are ethane and possibly propane. Most likely, the produced fluids also contain water (or saline), as well as nitrogen. In addition, produced fluids may contain hydrogen sulfide, carbon dioxide, and other so-called “sulfur-containing gaseous components”. Finally, produced fluids may contain benzene, toluene or other organic compounds.

The separator 120 provides a common separation of liquids and gases. As a rule, this is done at operating pressure. The separator 120 may be a gravity separator having thick steel walls. Separator 120 is used to filter impurities such as saline and drilling fluids. It can also separate at least a portion of any condensed hydrocarbons. Some particles may also be filtered.

A more preferred separator 120 serves as a dewatering tank. A dehumidifier uses a desiccant such as ethylene glycol to absorb water and release gas-phase fluids. Liquids are discharged from the lower part of the separator 120, while gases are discharged from the upper part.

In FIG. 1 line 121 is a liquid line. The fluids in line 121 are mainly water and possibly some heavy hydrocarbons. The heavy hydrocarbons in line 121 contain a small amount of ethane and possibly a small amount of propane and butane. Additional separation can be carried out by gravity separation, heat treatment or other methods known in the art for capturing valuable liquid hydrocarbons.

Line 122 is a gas line. The fluids in line 122 are mainly methane, and some ethane and other “heavy hydrocarbons” are also present. In addition, fluids in line 122 contain contaminants. These may include “acidic” components such as hydrogen sulfide and carbon dioxide. They may also include water in the form of steam. In addition, contaminants may include nitrogen. Certain metallic contaminants, such as arsenic, cobalt, molybdenum, mercury or nickel, may be suspended in the vapor. Finally, traces of organic compounds such as benzene, toluene or xylene may be present.

It turns out to be desirable to separate the various components in such a way that a fluid stream is obtained that is essentially methane. For international trade, LNG specifications may require that natural gas have the following impurity content:

To ensure the technical conditions of LNG, presented in table 1, it is necessary to carry out gas processing. In FIG. 1 is a schematic representation of a gas separation unit 130. The gas separation unit 130 may also be referred to as the term "selective component separation system" (CMSS). In the gas separation unit 130, a sequence of adsorption layers using adsorption kinetic separation (AKP) is used.

AKP is a method in which a relatively new class of solid adsorbents is used, and which is based on the rate at which certain substances are adsorbed on a structured material compared to other substances. The structured material is sometimes referred to as the “adsorption layer”. The principle of operation of the adsorption layers is that different molecules can have different affinity for adsorption. This provides a mechanism by which the adsorbent distinguishes between various gases and, thus, carries out their separation.

To carry out the separation, adsorption layers with a highly porous microstructure are used. The gas molecules selectively attach to the surface area that the pores possess. The gas adsorbed on the inner surfaces of the microporous material may be a layer whose thickness is only a few molecules. The microporous material may also have a specific surface area of several hundred square meters per gram. Such specifications provide gas adsorption a significant part of the mass of the adsorbent.

Various types of adsorption layers are known. Typical adsorbents include activated carbon, silica gel, alumina, and zeolites. In some cases, a polymeric material can be used as an adsorption material. In any case, the adsorption layer preferably adsorbs an easily adsorbed component (known as a "heavy" gas) compared to a hardly adsorbed component (known as a "light" gas) from a gas mixture.

In addition to their affinity for various gases, zeolites and certain types of activated carbon, the so-called “carbon molecular sieves,” can use their molecular sieve characteristics to exclude or slow the diffusion of certain gas molecules into their structure. This provides a selective adsorption mechanism based on the size of the molecules. In this case, the adsorption layer limits the adsorption capacity of larger molecules and, thus, allows the gas to selectively fill the microporous structure of the adsorption material with one or more substances from a multicomponent gas mixture.

Various adsorption techniques for gas separation are known. One adsorption technology is pressure swing adsorption (APD). APD processes are based on the fact that, under pressure, gaseous pollutants are prone to adsorption in the porous structure of the adsorption material or in the free volume of the polymer material to varying degrees. The higher the pressure in the adsorption tank, the more gas is adsorbed. In the case of natural gas, the natural gas mixture can be passed under pressure through an adsorption tank. The pores of the polymer or microporous adsorbent are filled with hydrogen sulfide and carbon dioxide to a higher degree than methane. Thus, the bulk or even the entire mass of H ₂ S and CO ₂ will remain in the adsorption layer, while the gas coming from the reservoir will be enriched in methane. Any residual water and possibly some heavy hydrocarbons will also be retained by adsorbents. In addition, any volatile organic compounds, such as benzene, toluene or others, will be delayed by adsorbents.

The pressure swing adsorption system may be a short cycle pressure swing adsorption system. In the so-called “short cycle” processes, the cycle time can be very short, amounting to only a few seconds. A short-cycle ADF (KCAPD) block may be especially advantageous, since such a block is compact compared to conventional ADF devices. In addition, KACAPD contactors can provide a significant increase in the intensity of the process (for example, an increase in the frequency of operation and gas flow rate) in comparison with traditional APD.

When the adsorption of contaminants in the adsorption layer ends, it can be regenerated by reducing the pressure. This causes the adsorbed components to exit from the reservoir. Thus, the concentrated pollutant stream is discharged separately from the methane gas stream. In this way, the adsorption layer can be regenerated for subsequent reuse.

In most cases, the pressure drop in the pressure chamber to the ambient pressure leads to the fact that the bulk of the hydrogen sulfide and other pollutants are discharged from the adsorption layer. In some cases, a variable pressure adsorption system may be facilitated by the use of a vacuum chamber to create pressure below ambient pressure in a stream of concentrated pollutants. Under reduced pressure, sulfur-containing components, carbon dioxide and heavy hydrocarbons will be more desorbed from the solid matrix constituting the adsorption layer.

Related technology for gas separation is adsorption at a variable temperature (APT). APT processes are also based on the fact that, under pressure, gases are prone to varying degrees to adsorption in the porous structure of microporous adsorption materials or in the free volume of a polymer material. When the temperature of the adsorption layer in the tank rises, the adsorbed gas molecules are released or desorbed. This is carried out in a regeneration heater in which heated dry gas is used. Dry gas mainly includes methane, but may also include nitrogen and helium. Due to the cyclical changes in the temperature of the adsorption layers in the tank, APT processes can be used to separate gases in a mixture.

When the APT process is used, a set of valves may be provided to create a pulsating flow of heating or cooling fluids that enter and exit the tank. You can also use an electric heating or cooling jacket to create temperature fluctuations. Optionally, for the adsorption unit under variable conditions, a partial pressure displacement blowing method is used. In this case, a valve or a set of valves is used to pulsate the purge displacement flow into the adsorption bed. The adsorption layer is located in the pressure vessel. Optionally, this reservoir and its associated valve system are located in a secondary high pressure reservoir. This secondary pressure vessel is designed to reduce the significance of leaks through seals in valves in the adsorption unit under variable conditions. This can be especially important when using rotary valves.

You can use a combination of regeneration at variable pressure and regeneration at variable temperature. In any case, the gas processing unit 130 uses a series of adsorption layers, each of which is designed to delay one or more components and simultaneously release the remaining components of the gas stream.

The adsorption material or layer is in a pressure vessel. FIG. 2 is a perspective view of an illustrative adsorption tank at a variable pressure of 200. The tank 200 operates to receive a mixture of natural gas and separate the mixture into at least two components.

The tank 200 is an elongated housing with high pressure. The reservoir 200 includes a shell 205. Preferably, the shell 205 is made of iron or steel. In the configuration of FIG. 2, the reservoir 200 is located on the surface 201 in an almost horizontal orientation. However, the reservoir 200 may alternatively operate in a vertical orientation. In any case, the reservoir 200 may include a variety of support legs or supports 215.

The tank 200 is capable of operating at high pressures in such a way as to withstand the inlet pressures arising during the processing of natural gas. For example, such inlet gauge pressures may exceed 200 psi (1379 kPa), and more often they are more than approximately 1000 psi (6895 kPa). This allows the reservoir 200 to be operated at a pressure equal to or close to reservoir pressure. To measure internal pressure, the reservoir 200 includes pressure gauges or other pressure measuring devices. An exemplary pressure gauge is indicated by 250 in FIG. 2. Of course, it should be understood that other modern devices for measuring pressure work mainly as digital systems that interact with valves, timers, and software that regulates operation.

The tank 200 has a first edge, indicated by the number 202, and a second edge, indicated by the number 204. The gas inlet 210 is located on the first edge 202, while the first gas outlet 230 is located on the second edge 204. An optional second gas outlet 220 is located between the first edge 202 and the second edge 204 or between the gas inlet 210 and the first gas outlet 230.

In operation, the reservoir 200 serves as a kinetic fractionator or adsorption contactor. The natural gas mixture or feed stream enters the reservoir 200 through the gas inlet 210. Arrow I indicates the movement of fluid into the reservoir 200. Natural gas comes into contact in the reservoir 200 with an adsorption layer (not shown in FIG. 2). Kinetic adsorption is used in the adsorption layer to capture contaminants. In this case, the adsorption layer releases a stream of methane-enriched gas through the first gas outlet 230. The movement of the stream of methane-enriched gas from the tank 200 is shown by arrow O ₁ .

It should be understood that the reservoir 200 is part of a larger gas separation unit 130. The gas separation unit 130 includes valves, reservoirs, and gauges that are necessary to regenerate the adsorption layer in the tank 200 and to trap the separated gaseous components. In addition, when using a short-cycle ADF, the reservoir includes a rotary valve with a rotating manifold for quick recirculation of the natural gas mixture. In this regard, tanks for short-cycle adsorption under variable pressure (KCAPD) can be designed with a rotary valve system, which simplifies the movement of gas through a rotary adsorption module, which contains a number of separate compartments or tubes of adsorption layers, each of which goes through a series of sorption stages and desorption, when the rotary module performs cyclic operation.

The rotary adsorption module typically includes a plurality of tubes located between two sealing plates at each edge of the rotary adsorption module, the sealing plates being in contact with a stator consisting of separate collectors. The inlet gas enters the KCAPD tubes and is processed into purified commercial gas, and the residual concentrated gas exiting the KCAPD tubes is discharged from the rotary adsorption module. Due to the suitable configuration of the sealing plates and manifolds, some individual compartments or tubes can pass through the characteristic stages of the complete cycle at any given time. On the other hand, in the case of traditional APD, when the flow and pressure changes are required for the SACAPD sorption / desorption cycle, the number of individual increments of the order of several seconds per cycle changes, which smoothes out the pressure pulsations and flow velocities caused by the compression and valve equipment. In this form, the KCAPD module includes valve elements distributed at angles along the circular path that the rotary adsorption module passes, so that each compartment sequentially passes the gas flow path with the corresponding direction and pressure to achieve one of the successive stages of pressure / flow direction in full KCAPD cycle.

In any configuration, an adsorption layer is used in the tank 200 to trap contaminants on the surface of the microporous adsorption material and in the pore spaces present therein. FIG. 3A is a perspective view of an adsorption layer 300 according to one embodiment. Here, the illustrative adsorption layer 300 has a hollow adsorption ring 305. The size of the adsorption ring 305 corresponds to the inner diameter of the shell 205 of the tank 200.

There are many adsorption rods 315 inside the adsorption ring 305. The adsorption rods 315 extend substantially along the entire length of the adsorption layer 300. This means that the rods 315 extend substantially from the first edge 302 to the second edge 304 of the reservoir 300. The adsorption ring 305 and the adsorption rods 315 are made of a material that preferably adsorbs unwanted gas. The unwanted gas may be water vapor, CO ₂ , H ₂ S, mercaptans, heavy hydrocarbons in the gas phase, or combinations thereof.

As the adsorption material, eight-membered zeolites are preferably selected in which the Si: Al ratio is from about 1: 1 to about 1000: 1, or preferably from about 10: 1 to about 500: 1, or more preferably from about 50: 1 to about 300 :one. The term “Si: Al ratio” as used herein means the molar ratio of silica to alumina in a zeolite structure. More preferred eight-membered zeolites for trapping sulfur-containing gas include DDR, Sigma-1 and ZSM-58. Zeolite materials having appropriate sized pores for separating heavy hydrocarbons include MF1, faujasite, MCM-41, and beta zeolite. The Si: Al ratio in the zeolites used to separate heavy hydrocarbons is preferably from about 20: 1 to about 1000: 1, and preferably from about 200: 1 to about 1000: 1, to prevent excessive adsorbent contamination.

Zeolite may be present in the adsorption ring 305 and adsorption rods 315 in any suitable form. For example, the zeolite material may be present in the form of granules that are packaged to form adsorption material. Granules or coarse grains of adsorbent are known in the art for variable adsorption processes, which may have any suitable shape, including spherical or irregular. Large grains of adsorbent can be formed by bonding microporous zeolite crystals using binders. Micropores exist due to the crystalline structure of the zeolite, in this case it is preferably eight-membered zeolites. The binder material, as a rule, is a dense material that does not have adsorption properties, but which is used to connect zeolite crystals. For effective functioning, the particle size of the binder material must be smaller than the size of individual zeolite crystals.

According to one embodiment of the adsorption layer 300, magnetic material can be embedded in the adsorption rods 315. For example, each rod 315 may have an internal drilled hole, and magnetic material may be placed in this internal drilled hole. The rods 315 can then be exposed to a magnetic or electromagnetic field during the packaging process. The magnetic field causes the rods 315 to push away from each other, and as a result, the same distance between the rods 315 is ensured. The uniform packing of the rods 315 is especially important for kinetic and short cycle adsorption processes and so that the gaseous components do not preferably pass through one flow channel 310 after another. The application of a magnetic field can additionally provide a uniform orientation of the zeolite material. Optionally, a magnetic field can be applied during the cycles themselves.

Again, consider FIG. 3, on which a plurality of flow channels are located within the hollow adsorption ring 305 and between the adsorption rods 315. The flow channels are indicated by the number 310. The flow channels 310 are the main flow channels that extend along the main axis of the adsorption layer 300.

Flow channels 310 form a structured adsorbent type contactor, which is called the term “parallel channel contactor”. Parallel channel contactors are a subset of adsorption contactors, including structured (modified) adsorbents, in which almost parallel flow channels are embedded in the adsorbent structure. Flow channels 310 can be manufactured in a variety of ways, some of which are described in US Patent Publication No. 2008/0282887, entitled "Separation of CO ₂ , N ₂ and H ₂ S from Gas Mixtures Containing Them", which is incorporated herein by reference.

The adsorption material constituting the hollow ring 305 and the rods 315 is distinguished by “kinetic selectivity” with respect to two or more gaseous components. As used herein, the term “kinetic selectivity” is defined as the ratio of the one-component diffusion coefficients D (m ² / s) of two different materials. One-component diffusion coefficients, also known as Stefan-Maxwell diffusion coefficients, which are measured for a given pure gaseous component. Thus, for example, the kinetic selectivity of a particular adsorbent for component A with respect to component B will be equal to D _A / D _B.

Coefficients of one-component diffusion of a material can be determined using studies known in the art of adsorption materials. A preferred method for measuring kinetic diffusion coefficients is a study of frequency characteristics as described by Reyes et al. In the article “Frequency Modulation Methods for Measuring Diffusion and Adsorption in Porous Solid Materials”, J. Phys. Chem. (Journal of Physical Chemistry), part B, 1997, v. 101, p. 614-622, which is incorporated herein by reference. For kinetically controlled separation in tank 200, it is preferable that the kinetic selectivity (i.e., D _A / D _B ratio) of the selected adsorbent in favor of the first component (e.g., CO ₂ ) with respect to the second component (e.g., methane) is greater than 5.

The term “selectivity” as used herein is based on a double comparison of the molar concentration of the components in the feed stream and the total number of moles of these components adsorbed by a particular adsorbent during the adsorption step of the process cycle under certain operating conditions of the system and composition of the feed stream. For the source gas stream, which contains component A, component B and optional additional components, an adsorbent that has a higher selectivity in favor of component A than in favor of component B will have at the end of the adsorption step of the process cycle a variable adsorption ratio:

U _A = (total number of moles A in the adsorbent) / (molar concentration A in the starting material)

which is greater than the ratio:

U _B = (total number of moles of B in the adsorbent) / (molar concentration of B in the starting material)

Where:

U _A is the adsorption absorption of component A, and

U _B is the adsorption absorption of component B.

Thus, for an adsorbent in which the selectivity in favor of component A with respect to component B is more than 1:

Selectivity = U _A / U _B (where U _A > U _B ).

When comparing various components in the feed of natural gas, the component with the minimum ratio of the total number of moles absorbed in the adsorbent and its molar concentration in the feed is the lightest component in the process of variable adsorption. The light component is a substance or molecular component, preferably not absorbed by the adsorbent during the adsorption process. This means that the molar concentration of the lightest component in the stream exiting during the adsorption step is more than the molar concentration of this lightest component in the feed stream. According to the present invention, the adsorption contactor 200 has a selectivity in favor of a first component (eg, CO ₂ ) with respect to a second component (eg, methane) of at least 5; preferred selectivity in favor of the first component with respect to the second component is at least 10; and the most preferred selectivity in favor of the first component with respect to the second component is at least 25.

It should be noted that the simultaneous separation of two or more pollutants; however, for convenience, the component or components that are to be separated by selective adsorption can be considered herein as the sole contaminant or heavy component.

The separation of the light component may also characterize the relative flow rate. Thus, methane separation can be defined as the time-averaged molar flow rate of methane in the product stream (denoted by O ₁ in the first issue 230) divided by the time-averaged molar flow rate of methane in the feed stream (designated as gas inlet 210). Similarly, the separation of carbon dioxide and other heavy components is defined as the time-averaged molar flow rate of heavy components in a pollutant stream (designated O ₂ in second gas outlet 220) divided by the time-averaged molar flow rate of a heavy component in the feed stream (indicated like gas inlet 210).

Further technical information regarding the diffusion coefficients of the components and kinetic selectivity is provided by the aforementioned US Patent Publication No. 2008/0282887 of the same applicant.

To increase the efficiency of the gas separation process, auxiliary flow channels in the layer 300 can also be provided. These auxiliary flow channels increase the active surface area of the adsorption material along the rods 315.

FIG. 3B is an exploded view of the adsorption layer 300 illustrated in FIG. 3A. The adsorption layer 300 is shown in section through an optional second gas outlet 220. Once again, the main flow channels 310 are visible passing through the adsorption layer 300. In addition, there is a transverse flow channel, designated 320. The transverse flow channel 320 serves as an auxiliary flow channel. A flow channel 320 is visible, partially extending into the adsorption layer 300. However, the transverse flow channel 320 may optionally extend the largest part of the path around the perimeter of the hollow adsorption ring 305.

In the configuration of FIG. 3B, only one auxiliary flow channel 320 is provided. However, the adsorption layer 300 may have a plurality of auxiliary flow channels 320. They may optionally be branched to combine flow at the second gas outlet 220.

FIG. 3C is a longitudinal sectional view of the adsorption layer 300 illustrated in FIG. 3A. This is a sectional view through line C-C in FIG. 3A. In FIG. 3C, longitudinal adsorption rods 315 are visible. In addition, main flow channels 310 are visible between the rods 315.

A sequence of stepped surfaces 325 is visible along the adsorption rods 315. Stepped surfaces 325 also serve as auxiliary flow channels. Instead of stepped surfaces 325, helical or spiral surfaces 325 may be present. In any configuration, stepped surfaces 325 can be used to complement or replace transverse channel 320 to increase surface area and increase kinetic selectivity without the need for large and expensive heat transfer units.

The main 310 and auxiliary flow channels 320, 325 create paths in the fractionator 300 through which gas can flow. Typically, flow channels 310, 320, 325 provide a relatively low resistance to the fluid in combination with a relatively high surface area. The length of the flow channels must be sufficient to provide the desired mass transfer zone, which is at least a function of the velocity of the fluid and the ratio of the surface area and volume of the channels.

The flow channels 310, 320, 325 are preferably designed to minimize the pressure drop in the reservoir 200. Thus, winding flow paths are minimized or eliminated. If an excessively large pressure drop occurs in the layer 300, it is difficult to achieve an increased cycle frequency, such as a frequency exceeding 100 cycles per minute. In addition, as noted above, it is preferable that the rods 315 were separated by equal intervals in such a way as to provide a given degree of uniformity of the channels.

In one aspect, the flow paths 310 are typically distributed such that the cross flow is small or absent. In this case, the fraction of the fluid stream that enters the channel 310 at the first edge 302 of the fractionator 200 does not have significant communication with any other fraction of the fluid that enters the other channel 310 at the first edge 302, as long as these fractions are not re-combined when exiting at the second edge 304. In this configuration, the volumes of the main flow channels 310 become almost equal, ensuring that all of the channels 310 are used in full and that there is a practically equal mass transfer zone the internal volume of the tank 200.

The dimensions of the flow channels 310 can be calculated taking into account the pressure drop along the contact tank 200. The flow channels 310 have a channel clearance of preferably from about 5 to about 1000 microns and more preferably from about 50 to about 250 microns. As used herein, the term “lumen” of the flow channel 310 is defined as the length of a line extending from the minimum dimension of the flow channel 310 when viewed perpendicular to the flow path. For example, if the flow channel 310 has a circular cross section, then the lumen of the channel is the inner diameter of this circle. However, if the channel has a rectangular cross section, then the lumen of the channel is the length of the diagonal line dividing the channel in half and passing through opposite corners of the section.

It should be noted that the main flow channels 310 can have a cross section of any configuration or geometric profile. In FIG. 3A and 3B, the main flow channels 310 are star-shaped. Regardless of the shape, the ratio of the volume of the adsorption material and the volume of the flow channel in the adsorption contactor 200 is preferably from about 0.5: 1 to about 100: 1, and more preferably from about 1: 1 to about 50: 1.

In some variable pressure adsorption applications, in particular in the case of CCAPD applications, flow channels are formed when the adsorbent sheets are laminated to each other. The flow channels in the sheets contain a gasket or mesh that acts as a gasket. However, gaskets take up so much space that laminated sheets are not preferred.

Instead of laminated sheets, it is possible to produce many small transverse auxiliary flow channels through the adsorption rods. FIG. 4 is a perspective view of the adsorption layer 400 of the variable pressure adsorption tank illustrated in FIG. 2, in a modified configuration. The adsorption layer 400 has an outer surface 405. The outer surface 405 is dimensioned to match the inner diameter of the shell 205 of the tank 200 in FIG. 2.

The main flow channels 410 are provided inside the monolithic adsorption material 415. The main flow channels 410 extend along the main axis of the adsorption layer 400. However, to further increase the surface area along the adsorption rods, small transverse channels 420 are provided through the monolithic material 415. These channels serve as auxiliary flow channels 420.

Auxiliary flow channels 420 can be very small tubular channels, in which the diameter is, for example, less than about 25 microns. The auxiliary flow channels 420 are not so large as to completely separate the adsorption rod 415. Thus, the need for support gaskets is eliminated.

The optional auxiliary flow channels 420 contribute to a pressure balance between the main flow channels 410. Both productivity and gas purity can be affected if there is excessive channel mismatch. In this regard, if one flow channel is larger than the adjacent flow channel, or receives a larger gas flow than the other channel, premature product breakthrough may occur. This, in turn, leads to a decrease in the purity of the commercial gas to unacceptable purity levels. In addition, devices operating at a cycle frequency of more than approximately 50 cycles per minute require higher uniformity of flow channels and lower pressure drop than devices operating at a lower number of cycles per minute.

Next, we again consider FIG. 2 and 3, where the reservoir 200 shown in FIG. 2 is in the form of a cylinder, and the adsorption rods 315 shown are tubular. However, other forms that are suitable for use in equipment for variable adsorption processes can be used. Non-limiting examples of reservoir configurations include monoliths of various shapes having many substantially parallel channels extending from one edge of the monolith to the other; many tubular parts; stacked layers of adsorbent sheets with gaskets between each pair of sheets; multilayer spiral rolls or bundles of hollow fibers, as well as bundles of substantially parallel solid fibers.

In addition, other embodiments for a parallel channel contactor may be used. Such embodiments include contactors provided and described in connection with FIG. 1-9 of US Patent Publication No. 2008/0282887. This publication in its entirety is hereby incorporated by reference again.

Again, consider FIG. 1, representing four illustrative stages of separation. This stage 132 ′ / 132 ", stage 134, stage 136 and stage 138. Each stage is an adsorption layer, and the stages 132 '/ 132", 134, 136, 138 are arranged in series. Each of the adsorption layers is preferably located in its own high pressure reservoir, such as reservoir 200 in FIG. 2. However, the scope of this application includes an option according to which at least some of the layers are in the same pressure vessel, while the remaining stages are arranged in series.

Firstly, step 132 ′ is the separation of water vapor from gas in line 122. Thus, a first adsorption layer is provided at step 132 ′ where the adsorption material is for adsorption of water vapor. When the adsorption material is saturated, desorption occurs in the layer at step 132 ′, and water vapor is discharged through line 131 ′. Optionally, water vapor combines with the liquid in line 121 from separator 120, as shown in line 125.

The fluids in line 125 are predominantly water. These fluids can be re-introduced into the reservoir as part of the water flooding operation. Alternatively, water can be processed and released into the marine environment. As another alternative, water can be treated and passed through a desalination process for use in irrigation or onshore industrial use. As another alternative, as noted above, the fluids in line 125 can be further separated to trap any hydrocarbons.

It turns out that the first stage 132 ′ is merely a final cleaning stage. This means that the bulk of the water has already been separated or removed by a previous dewatering tank (such as tank 120), and the adsorption layer at step 132 ′ simply separates the residual water vapor.

If a dewatering tank is used, the fluids in line 122 include a desiccant such as ethylene glycol. Thus, the auxiliary first stage 132 "is provided for separating the desiccant. In Fig. 1, the desiccant is removed from the gas separation unit 130 through a separate adsorption layer. When this layer becomes saturated, the desiccant is discharged through line 131". The desiccant can be regenerated for use in the dewatering tank 120.

FIG. 1 also represents a second pollutant separation stage 134. Illustrative second stage 134 is designed to separate heavy hydrocarbons. As noted above, heavy hydrocarbons mainly include any ethane from the feed gas stream. Some propane and butane may also be adsorbed. Heavy hydrocarbons are adsorbed in the adsorption layer, while sulfur-containing gas and light hydrocarbons are released.

It turns out that if the content of heavy hydrocarbons is very small, such components will be adsorbed on the first separation stage 132 ′ / 132 ″. This also depends on the composition of the adsorption layers on the first separation stage 132 ′ / 132 ″. However, if the content of heavy hydrocarbons is high and exceeds, for example, a level of 3 to 5 percent, then a separate special adsorption step 134 is desirable. After saturation, heavy hydrocarbons are released via line 133.

It turns out that the adsorption layer at step 134 is a zeolite material. Non-limiting examples of zeolites having appropriate sized pores for separating heavy hydrocarbons include MF1, faujasite, MCM-41, and beta zeolite. It is preferred that the Si / Al ratio of zeolites used to separate heavy hydrocarbons in the method according to an embodiment of the present invention is from about 20 to about 1000, preferably from about 200 to about 1000, in order to prevent excessive adsorbent contamination.

Layers of molecular sieves that are made of zeolite may be most effective for separating components containing from 2 to 4 carbon atoms, while silicon dioxide gel layers may be most effective for separating heavy hydrocarbons containing 5 or more carbon atoms. Additional technical information on the use of adsorption kinetic separation in the case of separation of gaseous hydrocarbon components is provided by US patent publication No. 2008/0282884, entitled "Separation of heavy hydrocarbons from gas mixtures containing heavy hydrocarbons and methane." This patent publication in its entirety is also incorporated herein by reference.

As noted above, the separated heavy hydrocarbons are discharged via line 133. Heavy hydrocarbons can be sold as a commercial fuel product. Alternatively, the heavy hydrocarbons may be subjected to some cooling to separate by condensation of the heavier components to produce methane vapor.

The gas stream then enters the third stage 136. The third stage 136 provides for the separation of sulfur-containing components. Sulfur-containing components may include hydrogen sulfide, sulfur dioxide and mercaptans. Sulfur-containing gaseous components are adsorbed in the adsorption layer, while methane passes to an optional fourth step 138. After saturation, sulfur-containing components are discharged through line 135.

If the dehydrated gas stream contains hydrogen sulfide, it may be advantageous to introduce tin silicates into the adsorbent. In particular, eight-membered zeolites can be prepared with tin silicates. The kinetic selectivity of eight-membered materials of this class ensures the rapid introduction of H ₂ S into zeolite crystals. After saturation, the layer is purged. It should be understood that sulfur-containing components are preferably separated by a subsequent sulfur recovery process.

An optional fourth stage 138 is also provided in the gas separation unit 130. The fourth stage 138 separates carbon dioxide and nitrogen from the gas stream. CO ₂ and N _{2 are} adsorbed in the adsorption layer of step 138, and at the same time a stream of gas purified from sulfur compounds is released. When purging, CO ₂ and N ₂ exit the gas separation unit 130 through an exhaust line 137. In this case, a stream of sulfur-free gas is discharged through line 140.

It should be understood that the gas separation unit 130 may comprise less or more than four stages. The number of stages of the ACP depends on the composition of the crude gas stream that exits through gas line 122. For example, if the crude gas stream in gas line 122 contains less than 0.5 ppm H ₂ S, then an adsorption step is likely to separate sulfur components are not required. On the other hand, if the raw gas stream in gas line 122 contains metallic contaminants, such as mercury, a special ACP stage will be added to separate them.

As noted above, an adsorption layer is used on each of the 132 ′ / 132 ″, 134, 136, 138 steps. Each adsorption layer may be a system of adsorption layers in which a plurality of parallel layers are installed. These layers may be filled, for example, with activated carbon or molecular sieves. The first layer in each system is used for adsorption. It is a working layer. The second layer is regenerated, for example, by reducing pressure, while the first layer is in the process of Ota. Next a third layer which has already passed the regeneration, is in reserve and is intended for use in the adsorption system when the first layer becomes saturated to a great extent. Thus, for more efficient operation can use at least three parallel layers.

At each stage 132 ′ / 132 ”, 134, 136, 138, the working layer may be located in its own separate tank, the tanks of each stage being installed in series. Alternatively, the working layers can be installed in series in one or more combined tanks. that the layers can be made from materials that simultaneously adsorb more than one component, for example, a single layer may be designed to simultaneously separate sulfur-containing components and carbon dioxide. Alternatively, two separate vessels may be arranged in series and designed for the separation of substantially the same component. For example, if the raw gas stream in gas line 122 has a high content of CO _2, it is possible to provide two layers in successive tanks for the preferred separation of CO ₂ .

You can use a combination of adsorption layers of various types in the transition from one stage to another. Using a combination of adsorption layers prevents heavy hydrocarbons from remaining in the gas phase and, ultimately, is connected to the stream of methane-rich gas 140. In any configuration, methane-rich gas 140 exits from the gas separation unit 130.

The gas processing unit 100 also provides liquefaction of natural gas. In the present context, this means that the sulfur-free stream of methane-enriched gas 140 is being cooled. FIG. 1 liquefaction plant is indicated by number 150.

Before entering the liquefaction plant 150, the stream of methane-enriched gas 140 can be moderately compressed. This is especially true where there is a distance between the gas separation unit 130 and the liquefaction plant 150. In the apparatus 100 in FIG. 1 there is an optional compressor, indicated by 145. Compressor 145 releases a stream of compressed methane-enriched gas 142, which enters liquefaction plant 150.

According to the present invention, the liquefaction apparatus 150 is an expander-based high-pressure apparatus. FIG. 5 is a flowchart of a refrigeration system with a high pressure expander cycle 150 according to one embodiment.

First, the refrigeration system 150 includes a first compressor unit 515. After entering the liquefaction plant 150, the stream of sulfur-free methane-enriched gas 140 (or 142) passes through the first compressor unit 515. The first compressor unit 515 may be, for example, a centrifugal high pressure compressor with dry seal. The first compressor unit 515 increases the flow pressure of the methane-enriched gas 140 to an absolute pressure of more than 1000 psi (6895 kPa). Thus, a compressed feed gas stream 517 is formed.

The fluidizing unit 150 also includes one or more compact heat exchangers for cooling the stream of sulfur-free compressed gas 517. In the configuration of FIG. 5 shows the first 525 and second 535 heat exchangers. The liquefaction plant 150 also utilizes one or more high pressure expanders for additional cooling. In FIG. 5 expander is indicated by the number 540.

Expander 540 may be of several types. For example, you can use the Joule-Thompson valve (Joule-Thompson). Alternatively, a turboexpander can be installed. A turboexpander is a centrifugal or axial turbine through which high-pressure gas expands. Turbo expanders are typically used to produce work that can be used, for example, to move a compressor. In this regard, turbo expanders are a source of mechanical work for processes such as compression or cooling. According to any embodiment, a liquefied natural gas (LNG) stream is produced. The LNG stream flows in the line indicated by number 542.

As noted above, the liquefaction plant 150 includes a first heat exchanger 525. The heat exchanger 525 is part of a first cooling circuit 520 and may be referred to as a “first cooler”. The first refrigerator 525 receives the compressed feed gas stream 517 from the first compressor unit 515. The first refrigerator 525 then cools the compressed feed gas stream 517 to a significantly reduced temperature. For example, temperatures can drop to -100 ° C (-148 ° F).

The first refrigerator 525 releases a stream of compressed cooled feed gas 522. A stream of compressed cooled feed gas 522 is directed to the first expander 540. It serves to further cool the compressed feed gas stream 517 to a temperature at which significant methane liquefaction occurs. Thus, a liquefied product stream 542 is released at a temperature of at least about -162 ° C (-260 ° F).

Product stream 542 contains a major liquid fraction and a residual minor vapor fraction. Thus, it is preferable that the fluidizing unit 150 also includes a liquid separation tank 550. A liquid separation tank 550 is designed to separate the liquid fraction and the residual vapor fraction. Thus, the liquid methane stream 152 is discharged in one line as a commercial product of LNG, and a separate cold vapor stream 552 is discharged as an overhead.

Cold steam stream 552 can be used as a refrigerant for the first refrigerator 525 in the first cooling circuit 520. As can be seen in FIG. 5, the cold steam stream 552 enters the first refrigerator 525, where heat is exchanged with the compressed feed gas stream 517. Then, a partially heated product stream 554 is discharged.

The partially heated product stream 554 is directed back to the beginning of the first cooling circuit 520. This means that the partially heated product stream 554 is again combined with the methane-rich gas stream 140 (or 142). To accomplish this, a third compressor block 555 is provided. A third compressor block 555 releases a stream of compressed partially heated product 557. A stream of compressed partially heated product 557 is preferably passed through the first compressor block 515 with a methane-rich gas stream 142.

It is preferred that the gas liquefaction apparatus 150 includes a second heat exchanger. The second heat exchanger, which is indicated by the number 535, is a second refrigerator. The second heat exchanger 535 can optionally be placed on the line in the first cooling circuit 520 after the first cooler 525. Thus, the second heat exchanger 535 provides subcooling in the feed stream of the compressed cooled gas 522. However, it is preferable that the second heat exchanger 535 is installed on the line in the first cooling circuit 520 before the first refrigerator 525. This configuration is shown in FIG. 5.

In FIG. 5, the second heat exchanger 535 or the second cooler receives the partially heated product stream 554 from the first refrigerator 525. Then, indirect heat exchange occurs between the partially heated product stream 554 and the compressed feed gas stream 517. The heat exchanger 535 pre-cools the compressed feed gas stream 517 before the compressed stream the source gas 517 enters the first refrigerator 525. The second heat exchanger 535 thus releases a stream of pre-cooled compressed source gas 532 into the first refrigerator 525.

The heat exchanger 535 also releases the heated product stream 556. In this configuration, the heated product stream 556 enters the third compressor unit 555, and is discharged as a compressed and partially heated product stream 557, which combines with the methane-rich gas stream 142.

In order to provide efficient pre-cooling in the second refrigerator 535, it is desirable to use a refrigerant in addition to the partially heated product stream 554. Thus, a second cooling circuit 530 is also provided. A second refrigerant circuit 530 uses a refrigerant in line 534. The refrigerant in line 534 is preferably nitrogen gas or nitrogen containing gas. The use of nitrogen as a refrigerant broadens the temperature range of pre-cooling.

Again, consider FIG. 1, where it can be seen that separates the contaminants from stage 138. They are N ₂ and possibly some amount of CO ₂ in line 137. Nitrogen is fed through line 147 in gazoszhizhayuschuyu unit 150. In addition, the operator can direct part of the stream methane enriched gas 140 for use as a refrigerant 534. This is done via line 141. As an alternative or addition, the operator may select a portion of the heavy hydrocarbons separated from step 136. Ethane (or other heavy hydrocarbons) is taken from SRI 133 via line 143. Lines 141, 143 and 147, which are represented as dashed lines indicate optional intersection fluid.

The gaseous components in lines 141, 143 and 147 are selectively and optionally taken from the gas separation unit 130 and combined in line 149. This is shown in FIG. 1. Components from lines 141, 143 and / or 147 are then routed through line 149 to a second cooling circuit 530. This is shown in FIG. 5. A valve 501 for controlling the flow of components from lines 141, 143 and / or 147 through line 149 to a second cooling circuit 530 is visible. Valve 501 can also be used to divert part of the components from lines 141, 143, 147 for combustion in a gas turbine for production electricity or for regeneration of the layer in connection with APT.

Of course, it should be understood that an additional valve system (not shown in the drawing) will regulate the relative volumes of the components in lines 141, 143, 147, which enter line 149. In addition, it is clear that the operator can remove nitrogen from a given tank (not shown in the drawing) as a refrigerant through line 534. In any configuration, the refrigerant exits through line 534 from the heat exchanger 535 in a heated state. The refrigerant passes through a second compressor unit 536 to increase the pressure and then is discharged through an expander 538 for re-cooling. The refrigerant in line 534 then goes back to the heat exchanger 535. You can optionally install a small refrigerator (not shown) in the second cooling circuit 530 after the expander 538 to further cool the refrigerant in line 534.

It should be noted that the heat exchanger 535 can only serve as a refrigerator for the gas liquefaction plant 150. In this configuration, the first refrigerator 525 is not used. In addition, part of the steam 552 is then preferably used as at least part of the refrigerant for line 534. However, the use of a heat exchanger 535 with expander 538 in the second cooling circuit 530 increases the overall cooling efficiency of the first circuit of the expander 520. In any case, the present invention is not limited to a specific the configuration of refrigerators or cooling circuits, unless other conditions are clearly defined in the claims.

FIG. 6 is a flowchart illustrating the steps of a process 600 for liquefying a crude natural gas stream. Process 600 uses adsorption kinetic separation to produce a stream of methane-rich gas. In addition, process 600 additionally uses a refrigeration system with a high pressure expander cycle to cool methane and produce commercial LNG. Commercial LNG is preferably produced on a floating platform or gravity platform at sea.

First, process 600 involves receiving a feed of natural gas in a gas separation unit. The gas separation unit includes one or more fractionation tanks. The fractionation tanks are constructed in accordance with the fractionation tanks described above in accordance with their various embodiments. The fractionation tanks preferably operate in a pressure swing adsorption (APD) or variable pressure short cycle adsorption (HACCP) mode to regenerate a sequence of adsorption beds. Adsorption layers are designed to adsorb CO ₂ , H ₂ S, H ₂ O, heavy hydrocarbons, volatile organic compounds (VOCs), mercaptans, nitrogen, or combinations thereof.

Process 600 also includes the substantial separation of methane from contaminants in the feed stream of natural gas. As a first separation step, the crude natural gas feed stream optionally passes through a dewatering tank. This serves to separate a substantial portion of the water and other liquid phase components from the natural gas stream. Block 620 represents the step of separating the liquid phase components (mainly water) from the gas phase components. The dehydrated natural gas feed stream is then discharged as a dehydrated natural gas feed stream.

After that, gas-phase contaminants are separated from the dehydrated crude gas stream. Block 630 represents the stage of separation of methane from gas-phase pollutants in the feed of natural gas. This stage is carried out by using adsorption layers in one or more fractionation tanks. In one aspect, methane is separated from contaminants by a gas separation unit at an absolute pressure of at least about 500 psi (3447.5 kPa).

FIG. 7 is a flowchart illustrating steps 700 for separating contaminants from a crude natural gas stream. At these stages, adsorption kinetic separation is used to create a flow of methane-rich gas.

First, water is adsorbed from the feed stream of natural gas. In this regard, an adsorption layer having water retention properties is used. Block 710 represents this step. As noted above, it is preferred that the separation step is merely a final purification step. This means that the bulk of the water has already been separated or removed by means of a previous dewatering tank in the stage that block 620 represents.

If a dewatering tank is used, the contaminants in the gas stream include a desiccant such as ethylene glycol. Accordingly, the next step in separating the components involves adsorption of a desiccant. This step is block 720.

As shown in FIG. 7, various additional adsorption steps can be carried out to separate contaminants. These steps may include separating sulfur-containing components (block 730), separating carbon dioxide and / or nitrogen (block 740), separating mercury or other metal elements (block 750), and separating heavy hydrocarbons (block 760). Depending on the design of the adsorption layers, some of these components can be separated in a single combined stage. In addition, it is possible to change the sequence of separation of pollutants, which is carried out at the stages indicated by blocks 710-760, although it turns out to be highly preferred to separate the water in the first stage, which is block 710. Thus, the process 600 is not a limited sequence, according to which contaminants are separated in steps 700, unless other conditions are specified in the claims.

According to one aspect, a single reservoir is used comprising a plurality of adsorption layers arranged in series. For example, at least one fractionation tank in the gas separation unit may include a tank containing a plurality of adsorption layers arranged in series, such that:

the first adsorption layer is mainly intended to separate water and other liquid components from the dehydrated natural gas feed stream;

the second adsorption layer is mainly intended for separating the desiccant from the dehydrated natural gas feed stream; and

the third reservoir includes an adsorption layer intended primarily to separate the sulfur-containing gaseous component from the dehydrated natural gas feed stream.

You can install additional tanks for adsorption and separation of various sulfur-containing gases.

According to another aspect, a plurality of tanks are used arranged in series, these tanks being located in the direction of flow of the dehydrated natural gas feed. Each tank releases a stream of methane gas that is gradually purified from sulfur compounds. For example,

in the first tank, an adsorption layer is used to separate the water remaining in the dehydrated natural gas feed stream;

in the second tank, an adsorption layer is used to separate the desiccant from the dehydrated stream of the source natural gas; and

in the third tank, an adsorption layer is used to separate the sulfur-containing gaseous component from the dehydrated natural gas feed stream.

The acidic gaseous component may be one or more sulfur containing components. Alternatively, the acidic gaseous component may be carbon dioxide.

As a result of the adsorption steps 700 shown in FIG. 7, a stream of methane-rich gas is formed. This stream is discharged from the gas separation unit as a dehydrated natural gas feed stream. Accordingly, process 600 further includes discharging a dehydrated methane-enriched gas stream from the gas separation unit. This represents block 640.

A stream of methane-enriched gas is sent to a refrigeration system with a high pressure expander cycle. This represents block 650. The refrigeration system is constructed in accordance with the refrigeration system 150 shown above in FIG. 5, as described in any of its various embodiments. Thus, the refrigeration system preferably includes a first refrigeration circuit for recirculating the steam portion of the product that is used as the refrigerant in the first refrigerator, and a second refrigeration circuit for recycling the nitrogen-containing gas as the refrigerant in the second refrigerator. In the second refrigerator, a nitrogen-based refrigerant and partially heated methane gas from the first refrigerator can be used as the working fluid.

Process 600 also includes compressing a methane-rich gas stream. This represents block 660. The gas stream is compressed to an absolute pressure of more than 1000 psi (6895 kPa), in order to obtain a stream of compressed source gas.

Process 600 further includes cooling the compressed feed gas stream to produce a compressed compressed feed gas stream. This is block 670. The cooling step represented by block 670 preferably includes taking a stream of compressed feed gas through at least one heat exchanger in a first cooling circuit 520. For example, a stream of compressed feed gas can be pre-cooled using a heat exchanger 535 (second cooler) in FIG. . 5, and then further cooled using the first refrigerator 525 in FIG. 5. Optionally, heat exchanger 535 (second cooler) can be installed in the first cooling circuit 520 after the first cooler 525. Thus, heat exchanger 535 cools the compressed feed gas stream 517 after the compressed feed gas stream 517 passes through the first cooler 525.

The first cooling circuit 520 recirculates the refrigerant through at least one heat exchanger (such as a refrigerator 525) and then directs the used (heated) refrigerant (554 and / or 556) to the compressor unit 555. In the compressor unit, the heated refrigerant is compressed to absolute pressure of approximately 1,500 to 3,500 psi (10,342 to 24,132 kPa). More preferably, the compressor unit compresses the heated product stream to an absolute pressure of about 2500 to 3000 psi (17237 to 20684 kPa).

The second refrigerator 535 is preferably part of a second cooling circuit 530. The second refrigerator 535 is designed to cool the compressed feed gas stream 517, at least in part, by indirect heat exchange between the refrigerant stream 534 and the compressed feed gas stream. The second cooling circuit 530 may also include a compressor unit 536. The compressor unit 536 is designed to re-compress the refrigerant stream after the refrigerant stream has passed through the second refrigerator 535. In addition, the second cooling circuit also includes an expander. The expander receives a stream of re-compressed refrigerated refrigerant and expands the flow of compressed refrigerated refrigerant before returning to the second refrigerator 535.

Process 600 also includes expanding the compressed chilled feed gas stream 522. This is block 680. In one aspect, expanding the compressed chilled feed gas stream 522 includes reducing the pressure of the compressed chilled feed gas stream to an absolute pressure of 50 psi (345 kPa) ) up to 450 psi (3103 kPa). As the cooled feed gas stream 522 expands, an LNG product stream 542 is formed. The product stream contains a liquid fraction and a residual vapor fraction.

The high pressure expansion cycle refrigeration system preferably includes a liquid separation tank. The process then further includes separating the liquid fraction and the residual vapor fraction. The liquid fraction can then be loaded into a transport tank. This represents block 690 in FIG. 6.

To demonstrate the use of process 600 and, in particular, the nitrogen separation step using the AKP system, certain data have been obtained. These data are presented in the tables in connection with the specific examples below.

Examples

The following tables represent comparisons made using the Aspen HYSYS® Process Simulator (2006 version), a computer program from Aspen Technology, Inc. (Cambridge, Massachusetts). In connection with these tables, the term "SSRK" is used. This term is an abbreviation of the term "selective component separation system" and in this context means an adsorption system AKP.

Table 2 first illustrates the effect of separating nitrogen from a natural gas stream before liquefying it. A comparison is made with the traditional approach, according to which nitrogen is separated off after liquefying a nitrogen-containing natural gas using a distillation column. The energy savings achieved (more than 7%) result in a reduction in energy-generating equipment. This, in turn, leads to a reduction in volume and mass, and as a result, offshore LNG production is ensured.

table 2
Effect of Nitrogen Separation by SCR on Liquefaction Power The molar composition of the source material Characteristics of LNG Produced without SSRK using SSRK Nitrogen 0,0431 0.0101 0.0053 Methane 0.9559 0.9888 0,9936 Ethane 0.0010 0.0011 0.0011 Liquefaction Power (%) one hundred 93.3

It should be noted that the required LNG characteristics are easily achieved.

The following table 3 illustrates the advantage of using a refrigeration system with a high pressure expander cycle in relation to process efficiency. The thermal energy required to produce LNG at an ambient temperature of 100 ° F (37.78 ° C) decreases with increasing source gas pressure up to 17% at an absolute pressure of 4000 psi (27580 kPa). Conventional gas preparation methods reduce the absolute pressure of the feed gas below 1000 psi (6895 kPa). Thus, compressive equipment and associated compressive power are required in order to increase the pressure of the feed gas and take advantage of thermal energy savings at elevated pressures. This extends the benefits of reduced capacity for liquefaction.

Table 3
The effect of increasing the pressure of the source gas on the required cooling load Absolute Source Gas Pressure (psi, 6895 Pa) Cooling load (normalized) Reduced cooling load (%) 4000 83.0 17.0 3000 86.4 13.6 2000 91.5 8.5 1000 98.4 1,6 800 100.0 0,0

It has been found that operating the AKP gas separation unit at elevated pressure retains and even increases these advantages.

Table 4 presents the increase in efficiency through the use of the separation method according to the present invention. In the traditional approach, the advantage of increased pressure of the source gas is achieved by additional compression of the source gas: the energy associated with the decrease in pressure from the wellhead, which is determined by the traditional method of gas treatment by solvent extraction, is usually lost. The SSRK block can be designed to maintain pressure at the wellhead, and as a result, the energy loss that occurs during the traditional approach is prevented.

It is believed that by using small lightweight ACP separators for the manufacture of a gas separation unit and by using a refrigeration system with a high pressure expander cycle, the environmental impact of equipment and the weight of gas treatment or treatment plants are reduced by 75%. This may correspond to a 21% reduction in the volume and weight of the floating LNG plant. Alternatively, the available volume and mass can be used to increase the capacity of the floating LNG plant. Thus, this decrease increases the economic viability of the industrial gas production project.

As can be seen, an improved gas processing plant for liquefying a natural gas stream is proposed. According to one aspect, the installation includes:

1. A gas separation unit, wherein the gas separation unit has at least one fractionation tank, including:

a gas inlet for receiving a natural gas mixture comprising methane,

an adsorption material that has kinetic selectivity in favor of pollutants with respect to methane of more than 5, so that the pollutants are kinetically adsorbed by the adsorption material, and

a gas outlet for exiting a stream of methane-enriched gas; and

refrigeration system with a high pressure expander cycle, including:

a first compressor unit for receiving a substantial portion of the methane-enriched gas stream and for compressing the methane-enriched gas stream to an absolute pressure of more than about 1000 psi (6895 kPa), resulting in a compressed feed gas stream;

a first refrigerator for cooling a stream of compressed feed gas and producing a stream of compressed chilled feed gas; and

the first expander designed to expand the flow of compressed chilled feed gas and obtain a product stream containing a liquid fraction and a residual vapor fraction.

2. Gas processing plant according to claim 1, in which:

the first refrigerator is designed to receive a portion of the product stream from the first expander, and use a portion of the product stream to cool the compressed feed gas stream through heat transfer.

3. The gas processing plant according to claim 1, in which:

the first refrigerator is designed to use an external refrigerant stream and to cool the compressed feed gas stream through heat exchange.

4. The gas processing plant according to claim 1, wherein the refrigeration system with a high pressure expander cycle further includes:

a liquid separation tank for separating the liquid fraction and the residual vapor fraction from the first expander.

5. Gas processing plant according to claim 4, in which:

the first refrigerator receives at least a portion of the vapor fraction, and uses the vapor fraction to cool the compressed feed gas stream through heat exchange as part of the first cooling circuit;

the first refrigerator discharges (i) a stream of chilled feed gas, and (ii) a stream of partially heated product after heat exchange with a stream of compressed feed gas; and

The refrigeration system with high pressure expander cycle further includes:

a second refrigerator designed to further cool the compressed feed gas stream, at least in part, by indirect heat exchange with the refrigerant stream and the vapor fraction; and

a second cooling circuit having (i) a second compressor unit for re-compressing the refrigerant stream after the refrigerant stream has passed through the second refrigerator, and (ii) a second expander for receiving the re-compressed refrigerant stream and expanding the stream again compressed refrigerant before returning to the second refrigerator.

6. The gas processing plant according to claim 5, in which the refrigeration system with a high pressure expander cycle further includes:

a third compressor unit in a first cooling circuit for compressing a partially heated product stream after heat exchange with a compressed source gas stream; and

a line for combining the compressed partially heated product stream with the feed gas stream and completing the first cooling circuit.

7. The gas processing plant of claim 5, wherein the second refrigerator subcooles the cooled feed gas stream after the cooled feed gas stream exits the first refrigerator.

8. The gas processing plant of claim 5, wherein the second refrigerator pre-cools the compressed feed gas stream before the compressed feed gas stream enters the first refrigerator.

9. The gas processing plant according to claim 8, in which:

the second refrigerator receives a partially heated product stream from the first refrigerator for additional heat exchange with the compressed feed gas stream; and

discharges the heated product stream into the third compressor unit to complete the first cooling circuit.

10. The gas processing facility according to claim 1, wherein the installation is located on (i) a floating platform, (ii) a gravity platform, or (iii) a ship-shaped tank in the sea.

11. The gas processing plant according to claim 1, in which at least one fractionation tank in the gas separation unit operates in the adsorption mode under variable pressure (APD) or short-cycle adsorption under variable pressure (KCAPD).

12. The gas processing plant of claim 11, wherein the at least one fractionation tank is designed to adsorb CO ₂ , H ₂ S, H ₂ O, heavy hydrocarbons, volatile organic compounds (VOCs), mercaptans, or combinations thereof.

13. The gas processing plant according to claim 12, further comprising:

a dewatering tank for receiving a natural gas feed stream, separating a substantial portion of the water from the natural gas feed stream, and discharging the dehydrated natural gas feed stream to at least one fractionation tank.

14. A method of liquefying a stream of source natural gas, including:

receiving a feed stream of natural gas in the gas separation unit, the gas separation unit having at least one fractionation tank, including:

a gas inlet for receiving a natural gas mixture comprising methane,

an adsorption material that has kinetic selectivity in favor of pollutants with respect to methane of more than 5, so that the pollutants are kinetically adsorbed by the adsorption material, and

a gas outlet for discharging a stream of methane-enriched gas;

significant separation of methane from pollutants in the stream of the source of natural gas;

the release of a stream of methane-enriched gas from the gas separation unit;

directing the flow of methane-enriched gas into the refrigeration system with a high pressure expander cycle;

compressing the methane-enriched gas stream to an absolute pressure of more than 1000 psi (6895 kPa) in order to obtain a compressed feed gas stream;

cooling the compressed feed gas stream to obtain a compressed compressed feed gas stream;

expanding the compressed chilled feed gas stream to obtain a product stream containing a liquid fraction and a residual vapor fraction; and

separation of the vapor fraction from the liquid fraction.

15. The method according to p. 14, in which the refrigeration system with an expander high pressure cycle includes:

a first compressor unit for receiving a substantial portion of the methane-enriched gas stream and producing a compressed feed gas stream;

a first refrigerator for cooling a stream of compressed feed gas and producing a stream of compressed chilled feed gas; and

the first expander designed to expand the flow of compressed chilled feed gas and obtain a product stream.

16. The method of claim 15, wherein cooling the compressed feed gas stream comprises:

introducing at least a portion of the vapor fraction from the product stream into the first refrigerator as part of the first cooling circuit; and

heat exchange of the vapor fraction of the product stream with the compressed feed gas stream to cool the compressed feed gas stream.

17. The method according to p. 16, in which:

a refrigeration system with a high pressure expander cycle further includes a liquid separation tank; and

the separation of the vapor fraction from the liquid fraction is carried out using a liquid separation tank.

18. The method according to p. 17, further comprising:

the release from the first refrigerator (i) a stream of chilled feed gas as a product stream and (ii) a stream of partially heated product as a working fluid;

the direction of flow of the partially heated product to the third compressor unit; and

combining the compressed partially heated product stream from the third compressor unit with the methane-rich gas stream to complete the first cooling circuit.

19. The method according to p. 18, in which the refrigeration system with an expander high pressure cycle further includes:

a second refrigerator designed to further cool the compressed feed gas stream, at least in part, by indirect heat exchange between the refrigerant stream and the vapor fraction; and

a second cooling circuit having (i) a second compressor unit for re-compressing the refrigerant stream after the refrigerant stream has passed through the second refrigerator, and (ii) a second expander for receiving the compressed refrigerant stream and expanding the compressed refrigerant stream agent before returning to the second refrigerator.

20. The method according to p. 19, in which the second refrigerator cools the stream of chilled feed gas after the stream of chilled feed gas leaves the first refrigerator.

21. The method of claim 19, wherein the second refrigerator pre-cools the compressed feed gas stream before the compressed feed gas stream enters the first refrigerator.

22. The method according to claim 1, in which the installation is located on (i) a floating platform, (ii) a gravity platform or (iii) a vessel-shaped vessel in the sea.

23. The method according to p. 22, in which at least one fractionation tank in the gas separation unit operates in the mode of adsorption at variable pressure (APD) or short-cycle adsorption at variable pressure (KCAPD).

24. The method according to claim 23, wherein the at least one fractionation tank is designed to adsorb CO ₂ , H ₂ S, H ₂ O, heavy hydrocarbons, volatile organic compounds (VOCs), mercaptans, or combinations thereof.

25. The method according to p. 22, further comprising:

passing a natural gas feed stream through a dewatering tank to separate a substantial portion of the water from the natural gas feed stream; and

discharging a dehydrated natural gas feed stream into at least one fractionation tank for separating contaminants.

26. A method of liquefying a stream of a source of natural gas, including:

receiving a stream of natural gas in a gas processing plant;

passing a natural gas feed stream through a dewatering tank to separate a substantial portion of the water from the natural gas feed stream;

discharging a dehydrated natural gas feed stream to a gas separation unit as a dehydrated natural gas feed stream;

passing the dehydrated feed natural gas stream in the gas separation unit through a series of adsorption layers to separate methane gas from contaminants in the dehydrated feed natural gas stream using adsorption kinetic separation;

the release of a stream of methane-enriched gas from the gas separation unit;

directing the flow of methane-enriched gas into the refrigeration system with a high pressure expander cycle;

compressing the methane-enriched gas stream to an absolute pressure of more than 1000 psi (6895 kPa) in order to obtain a compressed feed gas stream;

cooling the compressed feed gas stream to obtain a compressed compressed feed gas stream;

expanding the compressed chilled feed gas stream to obtain a product stream containing a liquid fraction and a residual vapor fraction.

27. The method according to p. 26, in which the sequence of adsorption layers includes:

a first adsorption layer for separating water remaining in the dehydrated natural gas feed stream;

a second adsorption layer, mainly intended to separate the desiccant from the dehydrated stream of the feed natural gas; and

a third adsorption layer, primarily intended to separate the sulfur-containing gaseous component from the dehydrated natural gas feed stream.

28. The method according to p. 27, in which each of the adsorption layers is connected to two additional adsorption layers, comprising three adsorption layers, wherein:

the first of the three adsorption layers is in operation and adsorbs the selected contaminant;

the second of the three adsorption layers is in the process of regeneration; and

the third of the three adsorption layers is in reserve to replace the first of the three adsorption layers; and

moreover, regeneration is part of the adsorption process at variable pressure.

As you can see, another advanced gas processing plant for liquefying a natural gas stream is proposed. According to one aspect, the installation includes:

1A. A gas processing plant for liquefying a stream of a source of natural gas, the installation including:

a gas separation unit, wherein the gas separation unit has at least one fractionation tank, including:

a gas inlet for receiving a natural gas mixture comprising methane,

an adsorption material that has kinetic selectivity in favor of pollutants with respect to methane of more than 5, so that the pollutants are kinetically adsorbed by the adsorption material, and

a gas outlet for exiting a stream of methane-enriched gas; and

refrigeration system with a high pressure expander cycle, including:

a first compressor unit for receiving a substantial portion of the methane-enriched gas stream and for compressing the methane-enriched gas stream to an absolute pressure of more than about 1000 psi (6895 kPa), resulting in a compressed feed gas stream;

a first refrigerator for cooling a stream of compressed feed gas and producing a stream of compressed chilled feed gas; and

the first expander designed to expand the flow of compressed chilled feed gas and obtain a product stream containing a liquid fraction and a residual vapor fraction.

2A. A gas processing plant according to claim 1A, wherein:

the first refrigerator is designed to receive part of the product stream from the first expander, and use part of the product stream to cool the compressed feed gas stream through heat transfer.

3A. A gas processing plant according to claim 1A, wherein:

the first refrigerator is designed to use an external refrigerant stream and to cool the compressed feed gas stream through heat exchange.

4A. The gas processing plant of claim 1A, wherein the refrigeration system with a high pressure expander cycle further includes:

a liquid separation tank for separating the liquid fraction and the residual vapor fraction from the first expander.

5A. A gas processing plant according to claim 4A, wherein:

the first refrigerator receives at least a portion of the vapor fraction, and uses the vapor fraction to cool the compressed feed gas stream through heat exchange as part of the first cooling circuit;

the first refrigerator discharges (i) a stream of chilled feed gas, and (ii) a stream of partially heated product after heat exchange with a stream of compressed feed gas; and

The refrigeration system with high pressure expander cycle further includes:

a second refrigerator designed to further cool the compressed feed gas stream, at least in part, by indirect heat exchange with the refrigerant stream and the vapor fraction; and

a second cooling circuit having (i) a second compressor unit for re-compressing the refrigerant stream after the refrigerant stream has passed through the second refrigerator, and (ii) a second expander for receiving the re-compressed refrigerant stream and expanding the stream again compressed refrigerant before returning to the second refrigerator.

6A. The gas processing plant of claim 5A, wherein the refrigeration system with a high pressure expander cycle further includes:

a third compressor unit in a first cooling circuit for compressing a partially heated product stream after heat exchange with a compressed source gas stream; and

a line for combining the compressed partially heated product stream with the feed gas stream and completing the first cooling circuit.

7A. The gas processing plant of claim 5A, wherein the second refrigerator subcooles the cooled feed gas stream after the cooled feed gas stream exits the first refrigerator.

8A. The gas processing plant of claim 5A, wherein the second refrigerator pre-cools the compressed feed gas stream before the compressed feed gas stream enters the first refrigerator.

9A. The gas processing plant of claim 8A, wherein:

the second refrigerator receives a partially heated product stream from the first refrigerator for additional heat exchange with the compressed feed gas stream; and

discharges the heated product stream into the third compressor unit to complete the first cooling circuit.

10A. The gas processing plant of claim 9A, wherein the third compressor unit compresses the heated product stream to an absolute pressure of about 1,500 to 3,500 psi (10342 to 24132 kPa).

11A. The gas processing facility of Claim 1A, wherein the installation is located on (i) a floating platform, (ii) a gravity platform, or (iii) a ship-shaped tank in the sea.

12A. The gas processing plant of claim 5A, wherein:

the refrigerant stream includes a gas selected from the group consisting of: gaseous nitrogen, a nitrogen-containing gas, a side stream from a methane-rich gas stream and a residual vapor fraction, as well as combinations thereof; and

the refrigerant stream in the second cooling circuit moves in a closed circuit.

13A. The gas processing plant according to claim 1A, wherein the at least one fractionation tank in the gas separation unit operates in a pressure swing adsorption (APD) or variable pressure short cycle adsorption (CCAPD).

14A. The gas processing plant of Claim 13A, wherein the at least one fractionation tank in the gas separation unit further operates in a variable temperature adsorption (APT) or a variable cycle short-range adsorption (CCCAT).

15A. The gas processing facility of Claim 13A, wherein the at least one fractionation tank is designed to adsorb CO ₂ , H ₂ S, H ₂ O, heavy hydrocarbons, volatile organic compounds (VOCs), mercaptans, or combinations thereof.

16A. The gas processing facility of Claim 13A, wherein each of the at least one fractionation tank operates in conjunction with other fractionation tanks to form a pressure swing adsorption system, including:

at least one working adsorption layer,

at least one layer during regeneration under reduced pressure, and

at least one regenerated layer in reserve and intended for use in an adsorption system when at least one working layer becomes substantially saturated.

17A. The gas processing plant of Claim 13A, further comprising:

a dewatering tank for receiving a natural gas feed stream, separating a substantial portion of the water from the natural gas feed stream, and discharging the dehydrated natural gas feed stream to at least one fractionation tank.

18A. The gas processing plant of claim 17A, wherein the at least one fractionation tank in the gas separation unit includes a plurality of tanks arranged in series, such that:

the first reservoir includes an adsorption layer designed to separate the water remaining in the dehydrated natural gas feed stream;

the second reservoir includes an adsorption layer intended primarily to separate the desiccant from the dehydrated stream of the feed natural gas; and

the third reservoir includes an adsorption layer intended primarily to separate the sulfur-containing gaseous component from the dehydrated natural gas feed stream.

19A. The gas processing plant of claim 17A, wherein the at least one fractionation tank in the gas separation unit includes a tank containing a plurality of adsorption layers arranged in series, such that:

the first adsorption layer is mainly intended to separate water and other liquid components from the dehydrated natural gas feed stream;

the second adsorption layer is mainly intended for separating the desiccant from the dehydrated natural gas feed stream; and

the third reservoir includes an adsorption layer, mainly for separating the sulfur-containing gaseous component from the dehydrated natural gas feed stream.

20A. A method of liquefying a stream of a source of natural gas, including:

receiving a feed stream of natural gas in the gas separation unit, the gas separation unit having at least one fractionation tank, including:

a gas inlet for receiving a natural gas mixture comprising methane,

an adsorption material that has kinetic selectivity in favor of pollutants with respect to methane of more than 5, so that the pollutants are kinetically adsorbed by the adsorption material, and

a gas outlet for discharging a stream of methane-enriched gas;

significant separation of methane from pollutants in the stream of the source of natural gas;

the release of a stream of methane-enriched gas from the gas separation unit;

directing the flow of methane-enriched gas into the refrigeration system with a high pressure expander cycle;

compressing the methane-enriched gas stream to an absolute pressure of more than 1000 psi (6895 kPa) in order to obtain a compressed feed gas stream;

cooling the compressed feed gas stream to obtain a compressed compressed feed gas stream;

expanding the compressed chilled feed gas stream to obtain a product stream containing a liquid fraction and a residual vapor fraction; and

separation of the vapor fraction from the liquid fraction.

21A. The method of claim 20A, wherein the high pressure expansion cycle refrigeration system includes:

a first compressor unit for receiving a substantial portion of the methane-enriched gas stream and producing a compressed feed gas stream;

a first refrigerator for cooling a stream of compressed feed gas and producing a stream of compressed chilled feed gas; and

the first expander designed to expand the flow of compressed chilled feed gas and obtain a product stream.

22A. The method of claim 21A, wherein cooling the compressed feed gas stream comprises:

introducing at least a portion of the vapor fraction from the product stream into the first refrigerator as part of the first cooling circuit; and

heat exchange of the vapor fraction of the product stream with the compressed feed gas stream to cool the compressed feed gas stream.

23A. The method of claim 22A, wherein:

a refrigeration system with a high pressure expander cycle further includes a liquid separation tank; and

the separation of the vapor fraction from the liquid fraction is carried out using a liquid separation tank.

24A. The method of claim 23A, further comprising:

the release from the first refrigerator (i) a stream of chilled feed gas as a product stream and (ii) a stream of partially heated product as a working fluid;

the direction of flow of the partially heated product to the third compressor unit; and

combining the compressed partially heated product stream from the third compressor unit with the methane-rich gas stream to complete the first cooling circuit.

25A. The method of claim 24A, wherein the refrigeration system with a high pressure expander cycle further comprises:

a second refrigerator designed to further cool the compressed feed gas stream, at least in part, by indirect heat exchange between the refrigerant stream and the vapor fraction; and

a second cooling circuit having (i) a second compressor unit for re-compressing the refrigerant stream after the refrigerant stream has passed through the second refrigerator, and (ii) a second expander for receiving the compressed refrigerant stream and expanding the compressed refrigerant stream agent before returning to the second refrigerator.

26A. The method of claim 25A, wherein the second refrigerator cools the cooled feed gas stream after the cooled feed gas stream exits the first refrigerator.

27A. The method of claim 25A, wherein the second refrigerator pre-cools the compressed feed gas stream before the compressed feed gas stream enters the first refrigerator.

28A. The method of claim 23A, wherein the installation is located on (i) a floating platform, (ii) a gravity platform, or (iii) a ship-shaped tank at sea.

29A. The method of claim 23A, wherein the at least one fractionation tank in the gas separation unit operates in a pressure swing adsorption (APD) or pressure swing short cycle adsorption (CCAPD).

30A. The method according to claim 23A, wherein the at least one fractionation tank in the gas separation unit further operates in a variable temperature adsorption (APT) or a variable temperature short cycle adsorption (CAPT).

31A. The method of claim 30A, wherein the at least one fractionation tank is designed to adsorb CO ₂ , H ₂ S, H ₂ O, heavy hydrocarbons, volatile organic compounds (VOCs), mercaptans, or combinations thereof.

32A. The method of claim 31A, further comprising:

passing a natural gas feed stream through a dewatering tank to separate a substantial portion of the water from the natural gas feed stream; and

discharging a dehydrated natural gas feed stream into at least one fractionation tank for separating contaminants.

33A. The method of claim 32A, wherein the at least one fractionating tank in the gas separation unit includes a plurality of tanks arranged in series, such that:

the first reservoir includes an adsorption layer designed to separate the water remaining in the dehydrated natural gas feed stream;

the second reservoir includes an adsorption layer intended primarily to separate the desiccant from the dehydrated stream of the feed natural gas; and

the third reservoir includes an adsorption layer intended primarily to separate the sulfur-containing gaseous component from the dehydrated natural gas feed stream.

34A. The method of claim 32A, wherein the at least one fractionation tank in the gas separation unit includes a tank containing a plurality of adsorption layers arranged in series, such that:

the first adsorption layer is mainly intended to separate water and other liquid components from the dehydrated natural gas feed stream;

the second adsorption layer is mainly intended for separating the desiccant from the dehydrated natural gas feed stream; and

the third reservoir includes an adsorption layer intended primarily to separate the sulfur-containing gaseous component from the dehydrated natural gas feed stream.

35A. A method of liquefying a stream of a source of natural gas, including:

receiving a stream of natural gas in a gas processing plant;

passing a natural gas feed stream through a dewatering tank to separate a substantial portion of the water from the natural gas feed stream;

discharging a dehydrated natural gas feed stream to a gas separation unit as a dehydrated natural gas feed stream;

passing the dehydrated feed natural gas stream in the gas separation unit through a series of adsorption layers to separate methane gas from contaminants in the dehydrated feed natural gas stream using adsorption kinetic separation;

the release of a stream of methane-enriched gas from the gas separation unit;

directing the flow of methane-enriched gas into the refrigeration system with a high pressure expander cycle;

compressing the methane-enriched gas stream to an absolute pressure of more than 1000 psi (6895 kPa) in order to obtain a compressed feed gas stream;

cooling the compressed feed gas stream to obtain a compressed compressed feed gas stream;

expanding the compressed chilled feed gas stream to obtain a product stream containing a liquid fraction and a residual vapor fraction.

36A. The method of claim 35A, wherein the sequence of adsorption layers comprises:

a first adsorption layer for separating water remaining in the dehydrated natural gas feed stream;

a second adsorption layer, mainly intended to separate the desiccant from the dehydrated stream of the feed natural gas; and

a third adsorption layer, primarily intended to separate the sulfur-containing gaseous component from the dehydrated natural gas feed stream.

37A. The method of claim 36A, wherein the first, second, and third adsorption layers are arranged sequentially in the direction of flow of the dehydrated feed natural gas in a single pressure vessel.

38A. The method of claim 36A, wherein the first, second, and third adsorption layers are in separate pressure vessels that are arranged in series in the direction of flow of the dehydrated feed natural gas.

39A. The method of claim 36A, wherein each of the adsorption layers comprises a solid adsorption layer made of zeolite material.

40A. The method of claim 37A, wherein each of the adsorption layers is connected to two additional adsorption layers, comprising three adsorption layers, wherein:

the first of the three adsorption layers is in operation and adsorbs the selected contaminant;

the second of the three adsorption layers is in the process of regeneration; and

the third of the three adsorption layers is in reserve to replace the first of the three adsorption layers; and in which

regeneration is part of the pressure swing adsorption process.

41A. The method of claim 36A, wherein cooling the compressed feed gas stream comprises:

passing a stream of compressed feed gas through the first heat exchanger to provide heat exchange with a cooled stream of refrigerant, resulting in a stream of supercooled feed gas; and

passing a stream of supercooled source gas through a second heat exchanger to provide heat exchange with a stream of cooling gas, resulting in a stream of compressed cooled source gas.

42A. The method of claim 41A, further comprising:

separating part of the residual vapor fraction from the product stream;

reducing the pressure of the separated portion of the residual vapor fraction to an absolute pressure of about 30 to 200 psi (207 to 1379 kPa) to produce a low pressure gas stream;

passing a low pressure gas stream through a second heat exchanger as a cooling gas stream; and

discharging a low pressure gas stream from a second heat exchanger as a partially heated gas stream.

43A. The method of claim 42A, further comprising:

passing a partially heated gas stream through the first heat exchanger as a cooling gas stream; and

returning the partially heated gas stream to the dehydrated natural gas feed stream for compression with the methane-rich gas stream.

44A. The method of claim 36A, wherein:

compressing a methane-enriched gas stream includes compressing a methane-enriched gas stream to an absolute pressure of about 1200 psi (8274 kPa) to 4500 psi (31026 kPa); and

expanding the compressed chilled feed gas stream includes reducing the pressure of the compressed chilled feed gas stream to an absolute pressure of 50 psi (345 kPa) to 450 psi (3103 kPa).

As you can see, the proposed processes, systems and methods for liquefying the flow of the source of natural gas using AKP and a refrigeration system with a high pressure expander cycle. Such processes, systems and methods make it possible to obtain LNG using a unit having a lower mass than conventional units. The above-mentioned processes, systems and methods also allow the rapid execution of production operations at sea. The inventions presented herein are not limited to the specific embodiment described herein, but are defined by the claims below. Although it is obvious that the inventions described herein are well adapted to achieve the above benefits and advantages, it should be noted that modifications, variations and changes can be made to these inventions without deviating from their idea.

Claims (26)

1. A gas processing unit for liquefying a stream of a source of natural gas, the installation including:
a gas separation unit, wherein at least one fractionation tank is included in the gas separation unit:
a gas inlet for receiving a natural gas mixture comprising methane,
an adsorption material that has kinetic selectivity in favor of pollutants with respect to methane of more than 5, so that the pollutants are kinetically adsorbed by the adsorption material, and
a gas outlet to exit a stream of methane-enriched gas; and
refrigeration system with a high pressure expander cycle, including:
a first compressor unit for receiving a substantial portion of the methane-enriched gas stream and for compressing the methane-enriched gas stream to an absolute pressure of more than about 1000 psi (6895 kPa), resulting in a compressed feed gas stream;
a first refrigerator for cooling a stream of compressed feed gas and producing a stream of compressed chilled feed gas; and
the first expander designed to expand the compressed chilled feed gas stream and to obtain a product stream containing a liquid fraction and a residual vapor fraction, where at least one fractionation tank in the gas separation unit operates in the mode of short-cycle adsorption under variable pressure (CCAPD). 2. Gas processing plant according to claim 1, in which:
the first refrigerator is designed to receive part of the product stream from the first expander and use part of the product stream to cool the compressed feed gas stream through heat transfer. 3. The gas processing plant according to claim 1, in which:
the first refrigerator is designed to use an external refrigerant stream to cool the compressed feed gas stream through heat transfer. 4. The gas processing plant according to claim 1, wherein the refrigeration system with a high pressure expander cycle further includes:
a liquid separation tank for separating the liquid fraction and the residual vapor fraction from the first expander. 5. Gas processing plant according to claim 4, in which:
the first refrigerator receives at least a portion of the vapor fraction and uses the vapor fraction to cool the compressed feed gas stream through heat exchange as part of the first cooling circuit;
the first refrigerator discharges (i) a stream of chilled feed gas and (ii) a stream of partially heated product after heat exchange with a stream of compressed feed gas; and
The refrigeration system with high pressure expander cycle further includes:
a second refrigerator designed to further cool the compressed feed gas stream, at least in part, by indirect heat exchange with the refrigerant stream and the vapor fraction; and
a second cooling circuit having (i) a second compressor unit for re-compressing the refrigerant stream after the refrigerant stream has passed through the second refrigerator, and (ii) a second expander for receiving the re-compressed refrigerant stream and expanding the stream again compressed refrigerant before returning to the second refrigerator. 6. The gas processing plant according to claim 5, in which the refrigeration system with a high pressure expander cycle further includes:
a third compressor unit in a first cooling circuit for compressing a partially heated product stream after heat exchange with a compressed source gas stream; and
a line for combining the compressed partially heated product stream with the feed gas stream and completing the first cooling circuit. 7. The gas processing plant of claim 5, wherein the second refrigerator subcooles the cooled feed gas stream after the cooled feed gas stream exits the first refrigerator. 8. The gas processing plant of claim 5, wherein the second refrigerator pre-cools the compressed feed gas stream before the compressed feed gas stream enters the first refrigerator. 9. The gas processing plant according to claim 8, in which:
the second refrigerator receives a stream of partially heated product from the first refrigerator for additional heat exchange with a stream of compressed source gas / and
discharges the heated product stream into the third compressor unit to complete the first cooling circuit. 10. The gas processing plant of claim 9, wherein the third compressor unit compresses the heated product stream to an absolute pressure of about 1500 to 3500 psi (10342 to 24132 kPa). 11. Gas processing plant according to claim 5, in which:
the refrigerant stream includes a gas selected from the group consisting of: gaseous nitrogen, a nitrogen-containing gas, a side stream from a methane-rich gas stream and a residual vapor fraction, as well as combinations thereof; and
the refrigerant stream in the second cooling circuit moves in a closed circuit. 12. The gas processing plant according to claim 1, in which at least one fractionation tank in the gas separation unit operates in the adsorption at variable pressure (APD) or short cycle adsorption at variable pressure (KCAPD) and in which each of at least one fractionating tank works together with other fractionation tanks, forming an adsorption system at variable pressure, including:
at least one working adsorption layer,
at least one layer during regeneration under reduced pressure, and
at least one regenerated layer in reserve and intended for use in an adsorption system when at least one working layer becomes substantially saturated. 13. The gas processing plant according to claim 1, in which at least one fractionation tank in the gas separation unit operates in the mode of adsorption at variable pressure (APD) or short-cycle adsorption at variable pressure (KCAPD) and further includes:
a dewatering tank for receiving a natural gas feed stream, separating a substantial portion of the water from the natural gas feed stream, and discharging the dehydrated natural gas feed stream to at least one fractionation tank. 14. The gas processing installation according to claim 13, in which at least one fractionation tank in the gas separation unit includes a plurality of tanks arranged in series, so that:
the first reservoir includes an adsorption layer designed to separate the water remaining in the dehydrated natural gas feed stream;
the second reservoir includes an adsorption layer intended primarily to separate the desiccant from the dehydrated stream of the feed natural gas; and
the third reservoir includes an adsorption layer intended primarily to separate the sulfur-containing gaseous component from the dehydrated natural gas feed stream. 15. The gas processing installation according to claim 13, in which at least one fractionation tank in the gas separation unit includes a tank containing a plurality of adsorption layers arranged in series, so that:
the first adsorption layer is mainly intended to separate water and other liquid components from the dehydrated natural gas feed stream;
the second adsorption layer is mainly intended for separating the desiccant from the dehydrated natural gas feed stream; and
the third reservoir includes an adsorption layer, mainly for separating the sulfur-containing gaseous component from the dehydrated natural gas feed stream. 16. A method of liquefying a stream of source natural gas, including:
receiving a feed stream of natural gas in the gas separation unit, the gas separation unit having at least one fractionation tank, including:
a gas inlet for receiving a natural gas mixture comprising methane, an adsorption material that has kinetic selectivity in favor of at least one of the pollutants with respect to methane of more than 5, so that the pollutants are kinetically adsorbed adsorption material, and
a gas outlet for discharging a stream of methane-rich gas;
substantial separation of methane from at least one of the pollutants in the feed stream of natural gas;
the release of a stream of methane-enriched gas from the gas separation unit;
directing the flow of methane-enriched gas into the refrigeration system with a high pressure expander cycle;
compressing the methane-enriched gas stream to an absolute pressure of more than 1000 psi (6895 kPa) in order to obtain a compressed feed gas stream;
cooling the compressed feed gas stream to obtain a compressed compressed feed gas stream;
expanding the compressed chilled feed gas stream to obtain a product stream containing a liquid fraction and a residual vapor fraction; and
separation of the vapor fraction from the liquid fraction, where at least one fractionation tank in the gas separation unit operates in the mode of short-cycle adsorption at variable pressure (KCAPD). 17. The method according to p. 16, in which the refrigeration system with an expander high pressure cycle includes:
a first compressor unit for receiving a substantial portion of the methane-enriched gas stream and producing a compressed feed gas stream;
a first refrigerator for cooling a stream of compressed feed gas and producing a stream of compressed chilled feed gas; and
the first expander designed to expand the flow of compressed chilled feed gas and obtain a product stream. 18. The method of claim 17, wherein cooling the compressed feed gas stream comprises:
introducing at least a portion of the vapor fraction from the product stream into the first refrigerator as part of the first cooling circuit; and
heat exchange of the vapor fraction of the product stream with the compressed feed gas stream to cool the compressed feed gas stream. 19. The method according to p. 18, in which:
a refrigeration system with a high pressure expander cycle further includes a liquid separation tank; and
the separation of the vapor fraction from the liquid fraction is carried out using a liquid separation tank. 20. The method according to p. 19, further comprising:
the release from the first refrigerator (i) a stream of chilled feed gas as a product stream and (ii) a stream of partially heated product as a working fluid;
the direction of flow of the partially heated product to the third compressor unit; and
combining the compressed partially heated product stream from the third compressor unit with the methane-rich gas stream to complete the first cooling circuit. 21. The method according to p. 20, in which the refrigeration system with an expander high pressure cycle further includes:
a second refrigerator designed to further cool the compressed feed gas stream, at least in part, by indirect heat exchange between the refrigerant stream and the vapor fraction; and
a second cooling circuit having (i) a second compressor unit for re-compressing the refrigerant stream after the refrigerant stream has passed through the second refrigerator, and (ii) a second expander for receiving the compressed refrigerant stream and expanding the compressed refrigerant stream agent before returning to the second refrigerator. 22. The method according to p. 21, in which the second refrigerator cools the stream of chilled source gas after the stream of chilled source gas leaves the first refrigerator. 23. The method of claim 21, wherein the second refrigerator pre-cools the compressed feed gas stream before the compressed feed gas stream enters the first refrigerator. 24. The method according to p. 19, in which at least one fractionation tank in the gas separation unit operates in the mode of adsorption at variable pressure (APD) or short-cycle adsorption at variable pressure (KCAPD);
in which at least one fractionation tank in the gas separation unit additionally operates in the mode of adsorption at a variable temperature (APT) or short-cycle adsorption at a variable temperature (CAPT);
in which at least one fractionation tank is designed to adsorb CO ₂ , H ₂ S, H ₂ O, heavy hydrocarbons, volatile organic compounds (VOCs), mercaptans, or combinations thereof; and
further comprising:
passing a natural gas feed stream through a dewatering tank to separate a substantial portion of the water from the natural gas feed stream; and
discharging a dehydrated natural gas feed stream into at least one fractionation tank for separating contaminants. 25. The method according to p. 24, in which at least one fractionation tank in the gas separation unit includes a plurality of tanks arranged in series, so that:
the first reservoir includes an adsorption layer designed to separate the water remaining in the dehydrated natural gas feed stream;
the second reservoir includes an adsorption layer intended primarily to separate the desiccant from the dehydrated stream of the feed natural gas; and
the third reservoir includes an adsorption layer intended primarily to separate the sulfur-containing gaseous component from the dehydrated natural gas feed stream. 26. The method according to p. 24, in which at least one fractionation tank in the gas separation unit includes a tank containing many adsorption layers arranged in series, so that:
the first adsorption layer is mainly intended to separate water and other liquid components from the dehydrated natural gas feed stream;
the second adsorption layer is mainly intended for separating the desiccant from the dehydrated natural gas feed stream; and
the third reservoir includes an adsorption layer intended primarily to separate the sulfur-containing gaseous component from the dehydrated natural gas feed stream.

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