TWI577954B - Gas processing facility and process for natural gas liquefaction - Google Patents

Description

Gas processing equipment and natural gas liquefaction method Cross-references to related applications

The present application claims the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the benefit of the disclosure.

Description of the invention

This section is intended to introduce a variety of different aspects of the prior art, which may be related to exemplary embodiments of the disclosure. This discussion helps to provide an architecture that promotes a better understanding of the particular form of the disclosure. Therefore, this section should be read from this point of view, but it does not have to be considered prior art.

The present invention relates to a method of treating a gaseous fluid. More specifically, the invention relates to the liquefaction of natural gas, particularly hydrocarbon gases produced at remote locations.

As the world's demand for fossil fuels increases, energy companies continue to look for hydrocarbon resources located in more distant and disadvantaged regions of the world, coastal and offshore. This includes the exploration of natural gas.

Due to its clean burning quality, natural gas has been widely used in recent years. However, many natural gas sources are located in geographical areas that are quite far from the commercial market. In some instances, a duct may be utilized or constructed for transport. Natural gas to the commercial market. However, when it is not possible to transport by means of a transport pipe, the natural gas produced by large sea-going transport is often used.

In order to maximize the volume of gas transported, this gas is often obtained by liquefaction. Liquefied natural gas ("LNG") is formed by cooling very light hydrocarbons, such as methane-containing gases, to about -160 °C. The liquefied gas can be stored under ambient pressure in a special low temperature tank installed on a large ship. Alternatively, the LNG can be liquefied at elevated pressures and at a warmer temperature (i.e., above -160 °C), which in this case is referred to as pressurized LNG ("PLNG"). For the purposes of this disclosure, PLNG and LNG may be collectively referred to as "LNG."

According to the current development, the gas permeation method is obtained at a position close to the manufacturing site. This means the construction of large collection and liquefaction centres in the producing countries. Alternatively, the liquefaction process can be carried out offshore on a platform or a large vessel, such as a floating production storage oil (FPSO) vessel. Currently, large liquefaction equipment exists in Qatar, Russia (Sakhalin), Indonesia and other countries. Australia is building or is currently planning several large LNG loading and unloading stations.

After the natural gas is cooled to a liquid state, the hydrocarbon product is placed on a marine vessel. Such a boat is called an LNG tanker. Cooling natural gas into a liquid state allows for the transport of much larger volumes of gas.

One of the most important concerns in the design of LNG equipment is the method of converting natural gas feed streams to LNG. Currently, the most common liquefaction method uses some form of refrigeration system. Although many refrigeration cycles have been used to liquefy natural gas, there are three types of refrigeration systems that are most commonly used for LNG equipment.

The first type of system is known as the "step cycle." Step Cycles A variety of one-component coolants are used in a progressively arranged heat exchanger to reduce the gas temperature to the liquefaction temperature. The second type of refrigeration system is a "multi-component refrigeration cycle." This system uses a multi-component coolant in a specially designed exchanger. The third type of system is the "expander cycle." The expander circulation system expands the gas from the feed gas pressure to a low pressure, which produces a corresponding decrease in temperature according to the wave's ear law. Common natural gas liquefaction cycles apply these three basic types of changes or combinations.

A recent variation of the expander cycle is the High Pressure Expander Cycle (High Pressure Expander Cylce). This system provides a more efficient and compact liquefaction process than the above cycle. As a result, it has become an attractive option for remote or offshore applications.

A limitation for the use of any liquefaction system is the presence of contaminants in the natural gas stream. The raw material natural gas produced by the underground storage layer often contains components which are not desired in the LNG process. These components include water, carbon dioxide and hydrogen sulfide. Water and CO ₂ should be removed as it will freeze at the liquefaction temperature and block the liquefaction equipment. H ₂ S should be removed as it may have an unfavorable safety shock or may adversely affect the LNG product specification. Therefore, natural gas manufacturing is often treated prior to liquefaction to remove unwanted components or contaminants.

When H ₂ S and CO ₂ are produced as part of a hydrocarbon gas stream such as methane or ethane, the feed gas stream is sometimes referred to as a "sour gas." The H ₂ S and CO ₂ are often referred to together as "acid gas." A method has been devised to remove acid gas from a raw natural gas stream. In some examples, cryogenic gas treatment is used. This involves cooling the gas stream in a large cryogenic vessel so that CO ₂ and H ₂ S into a solid component off. The hydrocarbon components are distilled from the vessel. This method often necessitates dehydration of the feed gas stream prior to cryogenic separation.

Alternatively, the hydrocarbon gas stream can be treated with a solvent. The solvent may include a chemical solvent such as an amine. Examples of the amine used in the acid gas treatment include monoethanolamine (MEA), diethanolamine (DEA), and methyldiethanolamine (MDEA). Physical solvents are sometimes used in place of amine solvents. Examples of physical solvents include Selexol ^® and Rectisol ^TM. Mixed solvents have been used in some instances, meaning mixtures of physical and chemical solvents. An example of this is Sulfinol®. However, the use of amine-based sour gas to remove solvents is most common. In all cases, solvent extraction is often accomplished using large thick-wall countercurrent contact towers.

This solvent extraction method uses a water-based solvent to absorb unwanted substances. As a result, the treated gas retains moisture which must be removed again to avoid subsequent freezing and block the liquefaction plant.

Whether the water is removed before or after the sour gas separation, the water removal process is often completed in fractional stages to meet the requirements for very low water content of the gas to be liquefied. The process in the development process is based on a diol dehydration system for removing large amounts of water, followed by several molecular sieve beds as a finishing stage. Therefore, for the solvent extraction step, several large heavy equipment sensitive to movement are required. This device is not attractive for offshore applications where space and weight are an additional cost and cannot avoid fluctuations.

In addition to water, nitrogen can also be removed from the gas stream. Nitrogen should be removed because it does not contain calorific value and, therefore, adversely affects fuel quality. Nitrogen is often removed after acid gas removal and liquefaction occurs. Use the so-called denitrification unit or The NRU distillation column removes nitrogen. This NRU is sensitive to fluctuations. In addition, NRUs often involve several large, heavy parts of heat exchange equipment, and these are particularly unsuitable for offshore applications.

Other adverse effects are the presence of nitrogen in the feed gas stream. For example, after the liquefaction step, rather than before, the removal of nitrogen increases the liquefaction energy requirement of the gas. In this case, nitrogen will increase the amount of gas that must be liquefied. In addition, the presence of nitrogen lowers the liquefaction temperature of the mixture because nitrogen has a lower boiling temperature than methane.

Due to the strict specifications for LNG, feed pretreatment equipment is large, heavy and expensive. For example, in a floating LNG concept with a nominal concentration of contaminants (eg, water saturation, 1% CO ₂ , 4% N ₂ ) in the inlet gas, the equipment that removes those contaminants represents the total weight of the upper side equipment. About 20%. When extended to the inlet gas having a high concentration of contaminants (e.g., water saturation of 50% to plus 70% CO ₂ and H ₂ S content), the contaminant removal device may represent more than 50% by weight on the topside of the device. Moreover, large vertical pressure vessels or towers commonly used for contaminant removal may have an undesirable effect on the stability of the floating construction.

Accordingly, there is a need for an improved apparatus for treating natural gas for liquefaction that is less sensitive to fluctuations and that has minimal impact on the stability of the floating construction. In addition, there is a need for a smaller, more economical, lightweight and lower horsepower LNG system that can be used on offshore platforms. Still further, there is a need for a method for more efficient treatment of natural gas for liquefaction, and which is compatible with high pressure expander recirculating refrigeration systems.

First, a gas processing apparatus for a liquefied natural gas feed stream is provided. The equipment is designed to be smaller, more economical and more efficient than conventional LNG equipment. Therefore, the equipment provided herein is ideally suited for offshore or remotely located LNG equipment. For example, the gas treatment device can be placed on an offshore floating platform or a gravity based platform.

The apparatus first comprises a gas separation unit having at least one fractionation vessel. The fractionation vessel is used to separate contaminants from methane gas. Finally, each vessel has a gas inlet for receiving a natural gas mixture. Additionally, in one embodiment, each container comprises a sorbent material having a kinetic selectivity of methane to methane greater than 5. In this manner, the contaminant becomes kinetically adsorbed within the adsorbent material. Additionally, each container includes a gas outlet. The gas outlet releases a methane-rich gas stream.

The vessel uses one or more adsorbent beds for adsorptive kinetic separation. The adsorbent beds release a methane-rich gas feed stream. In one aspect, a single vessel having a plurality of adsorbent beds in series is used. For example, at least one of the fractionation vessels in the gas separation unit can be a vessel containing a plurality of adsorbent beds in series such that the first adsorbent bed is designed to primarily remove water from the dehydrated natural gas feed stream. And other liquid components; the second adsorbent bed is designed to primarily remove the desiccant from the dewatered natural gas feed stream; and the third vessel comprises primarily for removing the dewatered natural gas feed stream An adsorption bed for acid gas components.

Other containers can be added to adsorb and separate nitrogen and different acid gases body.

In another aspect, a plurality of containers in series are used, and each container releases a progressively deodorized methane stream. For example, the first vessel uses an adsorbent bed designed to remove residual water from the dewatered natural gas feed stream; the second vessel uses a desiccant designed to remove the dewatered natural gas feed stream The adsorbent bed; and the third vessel uses an adsorbent bed designed to remove acid gas components from the dehydrated natural gas feed stream.

The acid gas component can be one or more sulfur-containing components. Alternatively, the acid gas component can be carbon dioxide.

At least one of the fractionation vessels of the gas separation unit operates in accordance with pressure swing adsorption (PSA) or rapid cycle pressure swing adsorption (RCPSA). The at least one fractionation vessel can additionally be operated in accordance with temperature swing adsorption (TSA) or rapid cycle temperature swing adsorption (RCTSA). In any embodiment, such vessel fractionation system constructed to adsorb _{CO 2, H 2 S, H} 2 O, heavy hydrocarbons, the VOC, thiols, or combination thereof.

The apparatus also includes a high pressure expander recirculating refrigeration system. The high pressure expander cycle refrigeration system includes a first compression unit. The first compression unit is configured to accept a substantial portion of the methane-rich gas stream from the gas separation unit and compress the methane-rich gas stream to a pressure above about 1,000 psia (6,895 kPa). In this manner, a compressed gas feed stream is provided.

The refrigeration system also cools the methane-rich in one or more coolers The gas feed stream is then expanded by the cooled gas feed stream to form a liquefied product stream. To this end, the system also includes a first cooler configured to cool the compressed gas feed stream to form a compressed cooled gas feed stream; and a first expander constructed to The cooled, compressed gas feed stream is expanded to form a product stream.

The product stream has a liquid portion and a small portion of residual vapor. Preferably, the gas treatment device also includes a liquid separation container. The separation vessel is constructed to separate the liquid portion and the remaining vapor portion. The vapor portion is still very cold and can be captured in the form of a flash gas and circulated as part of the first refrigeration loop. The first refrigeration loop has at least one heat exchanger as a first cooler. The first cooler receives a vapor portion from the first expander and releases (i) the compressed cooled gas feed stream and (ii) a portion after heat exchange with the compressed gas feed stream Warmed vapor stream.

The high pressure expander cycle refrigeration system can include individual heat exchangers configured to further cool the compressed gas feed stream. This is at least partially accomplished by indirect heat exchange between the coolant stream (along with a portion of the vapor stream) and the compressed methane-rich gas feed stream. The individual heat exchanger is a second cooler. The refrigeration system thus also includes a second refrigeration loop having (i) a second compression unit configured to compress the coolant stream after the coolant stream passes through the second cooler, and (ii) a second expander configured to accept a compressed coolant flow from the second cooler and to compress the compressed coolant stream prior to returning it to the second cooler Flow expansion.

The second cooler sub-cools the cooled gas feed stream after the cooled gas feed stream exits the first cooler. Alternatively and more preferably, the second cooler pre-cools the compressed gas feed stream before the compressed gas feed stream enters the first cooler. To this end, the second cooler receives a partially warmed vapor stream from the first cooler for further heat exchange with the compressed gas feed stream and releases the warmed vapor product stream to a third compression unit To complete the first refrigeration loop.

In any event, the first refrigeration loop preferably circulates the vapor portion of the product back to the first compression unit. To this end, the first refrigeration loop may include a third compression unit for compressing the partially warmed vapor stream after heat exchange with the compressed gas feed stream, and for combining the compressed portion of the warming unit A stream of vaporized stream and the compressed methane-rich gas feed stream. This completes the first refrigeration loop.

The gas treatment device additionally comprises a dewatering vessel. The dewatering vessel is constructed to accept the natural gas feed stream and remove a substantial portion of the water from the natural gas feed stream. The dewatering unit then releases the dehydrated natural gas feed stream to the gas separation unit.

A method for liquefying a natural gas feed stream is also provided herein. The process uses adsorptive kinetic separation to produce a methane-rich feed stream. The method then additionally circulates the refrigeration system with a high pressure expander to cool the methane and provide the LNG product. The LNG product is preferably produced on an offshore floating platform or a gravity based platform.

The method first includes accepting the natural gas feed stream at a gas separation unit. The gas separation unit has at least one fractionation vessel. The fractionation vessels are designed in accordance with the fractionation vessels described in the various embodiments above. The fractionation vessels are preferably operated in accordance with pressure swing adsorption (PSA) or rapid cycle pressure swing adsorption (RCPSA) to regenerate the adsorption beds in series. The adsorbent beds are designed to adsorb CO ₂ , H ₂ S, H ₂ O, heavy hydrocarbons, VOCs, mercaptans, nitrogen, or combinations thereof.

The method also includes substantially separating methane from contaminants within the natural gas feed stream. This is achieved by using an adsorbent bed in the one or more fractionation vessels. As a result, the method also includes releasing a methane-rich gas stream from the gas separation unit. In one aspect, separating methane from the contaminant is performed through the gas separation unit at an absolute pressure of at least about 500 pounds per square inch (psia).

The method next includes introducing the methane-rich gas stream into a high pressure expander cycle refrigeration system. The refrigeration system is generally designed in accordance with the refrigeration system described in various different embodiments above. Accordingly, the refrigeration system preferably includes a first refrigeration loop for circulating a vapor portion of the product as a coolant in the first cooler; and a second refrigeration loop for circulating a nitrogen-containing gas And as a coolant in the second cooler.

The method also includes compressing the methane-rich gas stream. The gas stream is compressed to a pressure above about 1,000 psia (6,895 kPa) to form a compressed gas feed stream. The method then includes cooling the compressed gas feed stream through the second and first coolers to form a compressed, cooled gas feed stream.

The method also includes expanding the cooled compressed gas feed stream. This will form a stream of LNG product having a liquid portion and a remaining vapor portion.

The high pressure expander recirculating refrigeration system preferably comprises a liquid separation vessel. The method thus additionally comprises separating the liquid portion from the vapor portion.

A method for liquefying a natural gas feed stream is also provided herein. As with the above process, the process uses adsorptive kinetic separation to produce a methane-rich gas stream. The method then additionally circulates the refrigeration system with a high pressure expander to cool the methane and provide the LNG product. The LNG product is preferably produced on an offshore floating platform or a gravity based platform.

The method first includes accepting the natural gas feed stream at a gas processing facility. The gas processing apparatus includes a dewatering vessel. The method then includes passing the natural gas feed stream through a dewatering vessel. This is used to remove a substantial portion of the water from the natural gas feed stream. The dehydrated natural gas feed stream is then released to the gas separation unit as a dehydrated natural gas feed stream.

The gas separation unit has at least one fractionation vessel. The fractionation vessels are designed in accordance with the fractionation vessels described in the various embodiments above. The fractionation vessels are preferably operated in accordance with pressure swing adsorption (PSA) or rapid cycle pressure swing adsorption (RCPSA) to regenerate the adsorption beds in series.

The method next includes passing the dewatered natural gas feed stream through a series of adsorbent beds. This is used to separate methane gas from contaminants in the dewatered natural gas feed stream. These beds are subjected to adsorptive kinetic separation. The adsorbent beds are designed to adsorb CO ₂ , H ₂ S, H ₂ O, heavy hydrocarbons, VOCs, mercaptans, nitrogen, or combinations thereof.

In one aspect, a single vessel having a plurality of adsorbent beds aligned in series is used.

In another aspect, a plurality of containers in series are used, and the containers are The flow of the dewatered natural gas feed stream is aligned in series. Each container releases a progressively deodorized methane stream.

A methane-rich gas stream is produced as a result of passing the dewatered natural gas feed stream through the adsorbent beds. The method includes releasing the methane-rich gas stream from the gas separation unit. The methane-rich gas stream is then directed to a high pressure expander recycle refrigeration system.

The refrigeration system is generally designed in accordance with the refrigeration system described in various different embodiments above. Accordingly, the refrigeration system preferably includes a first refrigeration loop for circulating a vapor portion of the product as a coolant in the first cooler; and a second refrigeration loop for circulating a nitrogen-containing gas And as a coolant in the second cooler.

The method also includes compressing the methane-rich gas stream. The gas stream is compressed to a pressure above about 1,000 psia (6,895 kPa) to form a compressed gas feed stream. The method then includes cooling the compressed gas feed stream to form a compressed, cooled gas feed stream.

The method additionally includes expanding the cooled compressed gas feed stream. This forms a stream of LNG product having a liquid portion and a small portion of the remaining vapor. In one aspect, the expansion of the cooled compressed gas feed stream comprises reducing the pressure of the cooled compressed gas feed stream to between about 50 psia (345 kPa) and 450 psia (3,103 kPa). pressure.

definition

As used herein, the phrase "hydrocarbon" means an organic compound, if not Exclusive, it mainly includes elemental hydrogen and carbon. Hydrocarbons generally fall into two categories: aliphatic or linear hydrocarbons, and cyclic or closed-loop hydrocarbons, including cyclic terpenes. Examples of hydrocarbon-containing materials include any form of natural gas, oil, coal, and bitumen that can be used as a fuel or upgraded to fuel.

As used herein, the phrase "fluid" means a gas, a liquid, a combination of a gas and a liquid, a combination of a gas and a solid, and a combination of a liquid and a solid.

As used herein, the phrase "hydrocarbon fluid" means a hydrocarbon or mixture of hydrocarbons that are gases or liquids. For example, the hydrocarbon fluid can be included as a gas or liquid mixture of hydrocarbons or hydrocarbons under conditions of formation, under processing conditions, or under ambient conditions (15 ° C and 1 atm pressure). Hydrocarbon fluids may include, for example, oils, natural gas, coal bed methane, shale oil, pyrolysis oil, pyrolysis gases, coal pyrolysis products, and other hydrocarbons that are gaseous or liquid.

As used herein, the phrase "acid gas" means any gas that is dissolved in water to make 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 ), sulfurized carbonyl (COS), mercaptans, or combinations thereof.

As used herein, the phrase "under the ground" indicates the presence of a geological formation below the surface.

The wording "seabed" means the bottom of the marine environment. The marine environment can be ocean or waterfront or any other body of water that experiences waves, winds and/or tides.

The phrase "marine environment" means any offshore location. The offshore location can be in shallow water or in deep water. The marine environment can be a marine body, a bay, a large lake, a estuary, a waterfront or a waterway.

The phrase "about" is intended to allow mathematical precision to a certain margin to account for acceptable tolerances in trade. Therefore, any small deviation from the value modified by the wording "about" should be considered to be within the scope of the specified value.

The phrase "variable adsorption method" includes, for example, the following methods: pressure swing adsorption (PSA), temperature swing adsorption (TSA), and partial pressure or displacement wash adsorption (PPSA), including combinations of these methods. These variable adsorption methods can be rapidly cycled, in this case they represent rapid cycle pressure swing adsorption (RCPSA), rapid cycle temperature swing adsorption (RCTSA), and rapid cycle partial pressure or displacement wash adsorption (RCPPSA). This wording change adsorption also includes these fast cycle methods.

As used herein, the phrase "pressure swing adsorption" is considered to include all of these methods, namely, PSA, PPSA, RCPSA, and RCPPSA, including combinations of these methods that apply pressure changes for the wash cycle.

As used herein, the phrase "wellbore" means a hole made under the ground that is inserted under the ground via a bore or conduit. The wellbore can have a substantially circular cross section or other cross sectional shape. As used herein, the phrase "well", when referring to the opening of the formation, may be used interchangeably with the word "well".

The phrase "platform" means any specification and platform or surface that is constructed to accept fluid processing equipment.

Description of a particular embodiment

1 is a schematic illustration of a gas processing apparatus 100 for fabricating LNG in accordance with one embodiment of the text. The "LNG" is already cold But the method of liquefying natural gas. The gas processing apparatus 100 operates to accept raw natural gas, remove specific undesirable components to produce a "sweetened" gas stream that meets established specifications, and then deodorize ("methane-rich" The gas stream is cooled to a substantial liquid phase for transport.

In the illustrative embodiment of Figure 1, the apparatus 100 accepts production fluid from a repository. A summary of the repository is shown at 110. The reservoir 110 represents a subterranean formation containing a commercially acceptable amount of hydrocarbon fluid. The hydrocarbon fluids are primarily present in situ in the gas phase.

These production stream systems are manufactured through multiple wellbores. A single exemplary wellbore 112 is indicated in FIG. However, it is understood that many wells 112 are drilled through the surface and into the underground storage 110. The invention is not limited by the number of wellbores or the way the wellbore is completed.

The wellbore 112 transports hydrocarbon fluid from the reservoir 110 and transports it to the surface 115. The surface 115 can be on land. More preferably, the surface 115 is a seabed. In the latter case, a wellhead (not shown) is installed along the bottom of the marine environment. The subsea jumper and/or the flow line directs the production fluid to a manifold (not shown) and then delivers the fluid to the surface of the ocean via one or more production risers.

In Figure 1, line 112' shows the transport of hydrocarbon fluid. Line 112' can be a fluid line on land. More preferably, line 112' represents a production riser within the marine environment. In either case, the production fluids are delivered to separator 120.

After reaching the separator 120, the production fluids represent the raw material natural gas mixture. These production fluids contain methane or natural gas. Such production streams The body may also contain so-called "heavy hydrocarbons", representing ethane and, if possible, propane. Most likely, these production fluids also contain water (or brine), along with nitrogen. Moreover, the production fluids may contain hydrogen sulfide, carbon dioxide, and other so-called "acid gases" components. Finally, the production fluids may contain benzene, toluene or other organic compounds.

The separator 120 provides a separate liquid from a gas. This is often done under production pressure. The separator 120 can be a gravity separator having a thick steel wall. The separator 120 is used to filter out impurities such as brine and drilling fluid. At least a portion of any coagulated hydrocarbons can also be removed. Some particle filtering can also occur.

More preferably, the separator 120 acts as a dewatering vessel. The dewatering vessel uses a desiccant such as ethylene glycol to absorb water and release the vapor phase fluid. The liquid is released from the bottom of the separator 120 and the gas is released at the top.

In Figure 1, line 121 represents a liquid line. The fluid in line 121 is primarily water and, if possible, some heavy hydrocarbons. The heavy hydrocarbons in line 121 are probably small amounts of ethane and perhaps a little propane and butane. Another separation can be performed by gravity separation, heat treatment, or other means known in the art to capture valuable liquid hydrocarbons.

Line 122 represents a gas line. The fluid in line 122 is primarily methane, as well as some ethane and other "heavy hydrocarbons". Additionally, the fluid in line 122 may have contaminants. These may include "acidic" components such as hydrogen sulfide and carbon dioxide. These may also include water in the form of a vapor. Additionally, the contaminants can include nitrogen. Some metal contaminants may be suspended in a vapor such as arsenic, cobalt, molybdenum, mercury or nickel. Finally, there may be trace organic compounds Such as benzene, toluene or xylene.

We want to separate a number of different components to create a fluid stream that substantially contains methane. Regarding international sales, the LNG specification may require natural gas to have the following contents:

In order to achieve the LNG specification of Table 1, gas treatment must be performed. In Fig. 1, the gas separation unit 130 is schematically shown. The gas separation unit 130 can also be referred to as a Selective Component Removal System or "SCRS." The gas separation unit 130 utilizes a series of adsorbent beds that employ Adsorptive Kinetic Separation or "AKS".

AKS is a method of using newer types of solid adsorbents that rely on the rate at which a particular substance is adsorbed onto the structured material relative to other materials. This structured material is sometimes referred to as an adsorbent bed. The sorbent bed operates on the principle that different molecules can have different affinities for adsorption. This provides that the adsorbent is treated differently for different gases and thus provides separation The mechanism used.

To achieve this separation, the adsorbent bed uses a very porous microstructure. The selected gas molecules become attached to the surface area provided along the pores. The gas adsorbed on the inner surface of the microporous material may be composed of a layer having a thickness of only a few molecules. The microporous material may also have a surface area of several hundred square meters per gram. Such a specification enables adsorption of a large portion of the gas that is the weight of the adsorbent.

Different types of adsorbent beds are known. Typical adsorbents include activated carbon, silicone, alumina, and zeolites. In some cases, polymeric materials can be used as adsorbent materials. In any of the examples, the adsorbent bed preferentially adsorbs components that are more readily adsorbed (known as "heavy" gases) relative to the less readily adsorbable components of the gas mixture (known as "light" gases).

In addition to its affinity for different gases, zeolites and some types of activated carbon (called carbon molecular sieves) can utilize their molecular sieve characteristics to eliminate or slow the diffusion of some gas molecules into their structures. This provides a mechanism for selective adsorption based on molecular size. In this example, the adsorbent bed limits the ability of larger molecules to be adsorbed, thus allowing one or more of the gas and multicomponent gas mixture to selectively fill the microporous structure of the adsorbent material.

Different adsorption techniques for gas separation are known. One adsorption technique is pressure swing adsorption, or "PSA". The PSA process is based on the tendency of gaseous contaminants to be adsorbed to the pore structure of the adsorbent material to varying degrees under pressure or within the free volume of the polymeric material. The higher the pressure in the adsorption vessel, the more gas is adsorbed. In the case of natural gas, the natural gas mixture can pass through the adsorption vessel under pressure. The pores of the polymer or microporous adsorbent become filled with hydrogen sulfide and carbon dioxide to a greater extent than filled with methane. Thus, most or even all of the H ₂ S and CO ₂ will remain in the adsorbent bed, while the gas leaving the methane-rich containers. Any remaining water and possibly some heavy hydrocarbons can also be retained as adsorbents. In addition, any benzene, toluene or other volatile organic compound can be retained as an adsorbent.

The pressure swing adsorption system can be a rapid cycle pressure swing adsorption system. In the so-called "fast cycle" method, the cycle time can be as small as a few seconds. A fast cycle PSA ("RCPSA") unit may be particularly beneficial because this unit is small and economical compared to a typical PSA device. In addition, RCPSA contactors significantly increase the degree of processing enhancement (ie, higher operating frequency and airflow speed) when compared to conventional PSAs.

When the adsorbent bed reaches the end of its capacity to adsorb contaminants, it can be regenerated by depressurization. This causes the container to release the adsorbed components. The concentrated contaminant stream is thus released separately from the methane stream. In this manner, the adsorbent bed can be regenerated for subsequent reuse.

In most PSA cases, the pressure in the pressurized chamber drops to ambient pressure and will cause most of the hydrogen sulphide and other contaminants to be released from the sorbent bed. In some cases, the pressure swing adsorption system can assist in applying a sub-ambient pressure to the concentrated contaminant stream by using a vacuum chamber. At lower pressures, the sulfur-containing components, carbon dioxide, and heavy hydrocarbons will more completely desorb from the solid matrix that makes up the adsorbent bed.

A related gas separation technique is a temperature swing adsorption process, or "TSA". The TSA method is also based on the fact that under pressure, the gas tends to be adsorbed to varying degrees. Within the pore structure of the microporous adsorbent material, or within the free volume of the polymeric material. When the temperature of the adsorbent bed in the vessel is increased, the adsorbed gas molecules will be released or desorbed. This is done in a regenerative heater using a heated drying gas. The dry gas mainly contains methane, but may also include nitrogen and helium. The TSA process can be used to separate the gases in the mixture by periodically varying the temperature of the adsorbent bed within the vessel.

When the TSA method is used, a set of valves can be provided to pulse the flow of heating or cooling fluid into and out of the vessel. Electrothermal or cooled jackets can also be used to create temperature variations. Optionally, the variable adsorption unit applies a partial pressure wash replacement method. In this case, a valve or set of valves is provided to cause a pulse of the flow of the purge displacement stream into the adsorbent bed. The adsorbent bed was placed in a pressure vessel. Optionally, the container and associated valve are mounted in a secondary pressure vessel. The secondary pressure vessel is designed to mitigate the severity of leakage through the seals in the valves within the variable adsorption unit. This can be especially important when using a rotary valve.

A combination of a pressure swing regeneration method and a temperature change regeneration method can be used. In either case, the gas processing apparatus 130 uses a series of adsorbent beds, each adsorbent bed being designed to retain one or more components while releasing the remainder of the gas stream.

The adsorbent material or "bed" is held in a pressure vessel. FIG. 2 provides a perspective view of an exemplary pressure swing adsorption vessel 200. The vessel 200 operates to achieve the purpose of accepting the natural gas mixture and dividing the mixture into at least two components.

The container 200 is shown as an elongated, pressure-containing body. The container 200 pack The housing 205 is included. Preferably, the outer casing 205 is made of iron or steel. In the apparatus of Figure 2, the container 200 is placed along the surface in a substantially horizontal orientation. However, the container 200 operates either in a vertical orientation. In either case, the container 200 can include a plurality of different support feet or pads 215.

The vessel 200 can be operated at high pressure to accommodate inlet pressures for natural gas processing. For example, such inlet pressures may exceed 200 psig, and more often greater than about 1,000 psig. This allows the container 200 to operate at or near reservoir pressure. To monitor internal pressure, the container 200 includes a meter or other pressure monitoring device. A representative gauge is shown at 250 in Figure 2. Of course, it is understood that modern pressure monitoring devices operate primarily in the form of digital systems that interact with valves, clocks, and operational control software.

The container 200 has a first end as shown at 202 and a second end as indicated at 204. A gas inlet 210 is disposed at the first end 202, and a first gas outlet 230 is disposed at the second end 204. Optionally, a second gas outlet 220 is disposed intermediate the first end 202 and the second end 204, or the gas inlet 210 is intermediate the first gas outlet 230.

In operation, the vessel 200 acts as a kinetic fractionator or adsorbent contactor. A natural gas mixture or feed stream is introduced into the vessel 200 through the gas inlet 210. The arrow " I " indicates that fluid has flowed into the container 200. The natural gas is contacted with the adsorbent bed within the vessel 200 (not shown in Figure 2). The adsorbent bed utilizes kinetic adsorption to capture contaminants. At the same time, the adsorbent bed releases a methane-rich gas stream through the first gas outlet 230. Arrow O ₁ represents the flow of the methane-rich gas stream of the vessel 200.

It is understood that the container 200 is part of the larger gas separation unit 130. Minute. The gas separation unit 130 includes valves, vessels, and meters as needed to perform regeneration of the adsorbent bed within the vessel 200 and capture of separated gas components. Additionally, where a fast cycle PSA is used, the vessel includes a rotary valve with a rotating manifold for rapid circulation of the natural gas mixture. In this regard, a rapid cycle pressure swing adsorption vessel (RCPSA) vessel can construct a rotary valve system to facilitate the flow of gas containing a plurality of individual adsorbent bed sections or "tubes" through the rotary adsorber module when the rotary module completes the cycle of operation Each of the intervals or tubes is continuously cycled through the adsorption and desorption steps.

The rotary adsorber module typically includes a plurality of tubes secured between two sealing plates on either end of the rotating adsorber module, wherein the sealing plates are in contact with a stator comprising individual manifolds. The inlet gas is directed to the RCPSA tube and the treated purified product gas and retained tail gas exiting the RCPSA tubes are removed from the rotary adsorber module. With the proper arrangement of the sealing plates and manifolds, a number of individual sections or tubes can pass through the characteristic steps of the entire cycle at any given time. Conversely, for conventional PSA, the flow and pressure changes required for the RCPSA adsorption/desorption cycle are varied in several increments at several cycles per cycle, which level the pressure and flow rate encountered by the compression and valve mechanism pulse. In this manner, the RCPSA module includes valve elements spaced apart in angular relationship around the circular path taken by the rotary adsorption module, so that each section is continuously connected to the airflow path in an appropriate direction and pressure to achieve the entire RCPSA cycle. One of the steps of increasing the pressure/flow direction.

In any aspect, the vessel 200 utilizes a bed of adsorbent to trap contaminants on the surface of the microporous adsorbent material and along the pore spaces therein. Figure 3A is a perspective view of a sorbent bed 300 in a particular embodiment. Here, the illustrative adsorbent bed 300 has an annular adsorbent ring 305. The annular adsorbent ring 305 is sized to fit the inner diameter of the outer casing 205 of the container 200.

Within the sorbent ring 305 are a plurality of sorbent rods 315. The sorbent rods 315 travel substantially along the length of the sorbent bed 300. This means that the rods 315 are substantially from the first end 302 to the second end 304 of the container 300. The adsorbent ring 305 and the adsorbent rod 315 are made of a material that preferentially adsorbs an undesired gas. The undesired gas may be water vapor, CO ₂ , H ₂ S, mercaptans, heavy hydrocarbons in the gas phase, or a combination thereof.

Preferably, the adsorbent material is selected from Si:Al ratios having 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 300:1. 8-ring zeolite. The phrase "Si:Al ratio" as used herein means the molar ratio of cerium oxide to alumina of the zeolite structure. Preferred 8-ring zeolites for trapping acid gases include DDR, σ-1 and ZSM-58. Zeolite materials having suitable pore sizes for the removal of heavy hydrocarbons include MFI, faujasite, MCM-41 and beta. Preferably, the Si:Al ratio of the zeolite for heavy hydrocarbon removal is from about 20:1 to about 1,000:1, and preferably from about 200:1 to about 1,000:1, to prevent excess product of the adsorbent. dirt.

The zeolite may be present in the adsorbent ring 305 and the adsorbent rods 315 in any suitable form. For example, the zeolitic material can be in the form of beads that are loaded to form the sorbent material. Adsorbent beads or agglomerates for use in variable adsorption processes are known in the prior art and can be of any suitable shape, including spherical or irregular. Adsorbent agglomerates by micropores The zeolite crystals are formed by sticking together with the binder material. In this case, the micropores are present due to the crystalline structure of the zeolite, preferably 8-ring zeolite. The adhesive material is often a dense material that is not adsorptive, but is used to bond the zeolite crystals. In order to function effectively, the size of the binder particles must be smaller than the size of the individual zeolite crystals.

In one embodiment of the sorbent bed 300, a magnetic material can be added to the sorbent rods 315. For example, each of the rods 315 can have an inner bore along which the magnetic material can be placed. The rods 315 can then be subjected to a magnetic or electromagnetic field at the time of loading. This magnetic field causes the rods 315 to repel each other, thereby ensuring a uniform spacing between the rods 315. The uniform loading of the rods 315 is particularly important for kinetics and rapid cycle adsorption processes, so that the gas components do not preferentially pass through one of the flow channels 310. The application of the magnetic field can additionally provide a uniform orientation of the zeolitic material. Optionally, the magnetic field can be applied during the cycle itself.

Referring again to Figure 3, within the annular adsorbent ring 305 and between the adsorbent rods 315 are a plurality of flow channels. These flow channels are found at 310. The flow channels 310 define a primary flow channel that flows along the major axis of the sorbent bed 300.

The flow channels 310 form a structured adsorbent contactor of the type known as a "parallel channel contactor." A parallel channel contactor is a subset of adsorbent contactors comprising a structured (special) adsorbent in which substantially parallel flow channels are added. The flow channels 310 can be formed by a variety of different means, some of which are described in the U.S. Patent Publication No. 2008/0282887, entitled "Removal of CO ₂ , N ₂ , and H ₂ S from Gas Mixtures Containing Same". This is incorporated herein by reference.

The sorbent material forming the annular ring 305 and the rods 315 has a "kinetic selectivity" for two or more gas components. As used herein, the term "kinetic selectivity" is defined as the ratio of the one-component diffusion coefficient (D (expressed in m ² /sec)) of two different materials. These one-component diffusion coefficients, also known as Stefan-Maxwell transport diffusion coefficients, are measured from the specific pure gas components of a particular adsorbent. Thus, for example, the kinetic selectivity of component A of a particular adsorbent relative to component B is equal to D _A /D _B .

The one-component diffusion coefficient of the material can be determined by tests known in the art of adsorbent materials. A preferred way of measuring the dynamic diffusion coefficient is by Reyes et al., "Frequency Modulation Methods for Diffusion and Adsorption Measurements in Porous Solids", J. Phys. Chem. B. 101, pp. 614-622 (1997). Frequency response techniques are incorporated herein by reference. The kinetic control of the separation container 200, the preferred is the first component of the selected adsorbents (e.g., CO ₂₎ with respect to a second component (e.g., methane) kinetic selectivity (i.e., D _A / D _B ) is greater than 5.

As used herein, the phrase "selectivity" is the molar concentration of the components in the feed stream and the adsorption by the particular adsorbent during the adsorption step of the treatment cycle under specified system operating conditions and feed stream composition. The comparison of the two components of the total moles of these components is based. With respect to the feed gas stream comprising component A, component B and any other components, the adsorbent having a "selectivity" greater than component B greater than component B has the following ratio at the end of the adsorption step of the variable adsorption treatment cycle: U _A = (the total number of moles of A in the adsorbent) / (the concentration of A mole in the feed), this ratio is higher than the ratio: U _B = (the total number of moles of B in the adsorbent) / / (B Mo concentration in the feed) wherein: U _A is "adsorption uptake rate of component A", and U _B is "adsorption uptake rate of component B".

Thus, for an adsorbent having a selectivity of component A to component B, the selectivity is greater than 1: selectivity = U _A / U _B (where U _A > U _B ).

In the comparison of the different components in the natural gas feed stream, for the ratio of the total number of moles charged in the adsorbent to the molar concentration in the feed stream, the fraction having the smallest proportion is The lightest component of the variable adsorption process. The light component is regarded as a substance or a molecular component which is not preferentially adsorbed by the adsorbent in the adsorption method. This means that the lightest component molar concentration in the stream exiting at the adsorption step is greater than the lightest component molar concentration in the feed stream. In the present disclosure, the first component (eg, CO ₂ ) of the adsorbent contactor 200 has a selectivity to the second component (eg, methane) of at least 5, and the first component to the second component The selectivity is preferably at least 10, and the selectivity of the first component to the second component is preferably at least 25.

Note that two or more contaminants can be removed simultaneously; however, components that can be removed by selective adsorption for convenience may be referred to herein as single contaminants or heavy components.

The recovery or relative flow rate of the light component is characteristic. Thus, methane recovery may be defined as a product stream (e.g., a first outlet O in _{FIG. 1} 230) of methane divided by the time-averaged molar flow rate of the feed stream time of methane (gas inlet 210 depicted) Average Mohr flow rate. Similarly, the recovery of carbon dioxide and other heavy components is defined as the time-averaged molar flow rate of the heavy components in the contaminant stream (as indicated by O ₂ in the second gas outlet 220) divided by the feed stream (eg, The time-averaged molar flow rate of the heavy components in the gas inlet 210 is depicted.

Other technical information regarding the component diffusion coefficient and the kinetic selectivity is provided in the commonly-owned U.S. Patent Publication No. 2008/0282887.

To enhance the efficiency of the gas separation process, the bed 300 can also provide a secondary flow path. The secondary flow channels increase the surface area exposure of the adsorbent material along the rods 315.

Figure 3B provides an exploded view of the adsorbent bed 300 of Figure 3A. The sorbent bed 300 crosses any second gas outlet 220. The main flow channel 310 passing through the adsorbent bed 300 is again seen. In addition, a lateral flow passage is seen at 320. The lateral flow channel 320 acts as a secondary flow channel. It can be seen that the flow passage 320 partially extends into the adsorbent bed 300. However, the lateral flow passages 320 can optionally extend in a manner that most surrounds the circumference of the annular adsorbent ring 305.

In the scheme of Figure 3B, only a single secondary flow channel 320 is shown. However, the sorbent bed 300 can have a plurality of secondary flow channels 320. These may be arbitrarily stacked with the streams collected in the second gas outlet 220 together.

Figure 3C is a longitudinal cross-sectional view of the adsorbent bed 300 of Figure 3A. This figure cuts through line C-C of Figure 3A. The longitudinal adsorbent rod 315 is seen in Figure 3C. Additionally, primary flow channel 310 can be seen between the bars 315.

A series of step surfaces 325 can be seen along the adsorbent rods 315. These step surfaces 325 also serve as secondary flow channels. Instead of the step surface 325, the surfaces 325 can be spiral surfaces. In any aspect, in addition to or in lieu of the lateral channel 320, the step surfaces 325 can be used to increase surface area and improve kinetic selectivity without the need for large and expensive heat transfer units.

The primary flow channel 310 and the secondary flow channels 320, 325 provide a path through which the gas can flow in the fractionator 300. Typically, the flow channels 310, 320, 325 provide lower fluid resistance and higher surface area. The length of the flow channel should be sufficient to provide the desired mass transfer path, which is at least a function of the ratio of fluid velocity to surface area to channel volume.

The flow channels 310, 320, 325 are preferably constructed to minimize pressure drop in the vessel 200. Therefore, the flow path of the tortuosity can be minimized or avoided. If too much pressure drop occurs across the bed 300, it is not easy to achieve a higher cycle frequency, such as a rating greater than 100 cpm. Moreover, and as specifically mentioned above, it is preferred that the rods 315 are equally spaced apart to create a certain degree of channel uniformity.

In one aspect, the flow channels 310 are generally separated so there is little or no cross flow. In this example, the first in the fractionator 200 The portion of fluid flow entering end 310 of passage 302 is not in significant communication with any other portion of the fluid from which first end 302 enters another passage 310 until the portions are combined after discharge at second end 304. In this arrangement, the volumes of the primary flow channels 310 are substantially equal to ensure that all of the channels 310 are fully utilized and substantially equally accommodating the mass transfer zone defined by the interior volume of the container 200.

The size of the flow channels 310 can be calculated by considering the pressure drop along the contactor vessel 200. Preferably, the flow channels 310 have a channel gap of from about 5 to about 1,000 microns, preferably from about 50 to about 250 microns. As used herein, the "channel gap" of the flow channel 310 is defined as the line length that traverses the smallest dimension of the flow channel 310 as viewed orthogonally to the flow path. For example, if the cross section of the flow channel 310 is circular, the channel gap is the inner diameter of the circle. However, if the cross section of the passage gap is a rectangle, the flow gap is a distance separating the flow gap from the corner to the corner.

It should be noted that the primary flow channels 310 can be structural or geometrical sections of any cross section. In Figures 3A and 3B, the primary flow channels 310 are star shaped. Regardless of the shape, it is preferred that the ratio of the volume of adsorbent material to the volume of the flow channel in the adsorbent contactor 200 is from about 0.5:1 to about 100:1, and more preferably from about 1:1 to about 50:1.

In some pressure swing applications, particularly RCPSA applications, these flow channels are formed when thin layers of adsorbent are laminated together. The flow channels in the layers contain spacers or screens as spacers. However, such spacers occupy a much larger space, so it is not preferable to use a laminated thin layer.

Instead of the laminated thin layers, a plurality of small transverse secondary flow channels can be machined through the adsorbent rods. In a refinement, Figure 4 provides a perspective view of a sorbent bed 400 for the pressure swing adsorption vessel of Figure 2. The sorbent bed 400 has an outer surface 405. The outer surface 405 is sized to fit the inner diameter of the outer casing 205 of the container 200 of Fig. 2.

The primary flow channel 410 is disposed within the monolith sorbent material 415. The primary flow channels 410 are formed along the major axis of the sorbent bed 400. However, to further increase the surface area along the adsorbent rods, a small transverse passage 420 is formed through the monolithic material 415. These channels act as secondary flow channels 420.

The secondary flow channel 420 can be a very small tubular channel, for example, having a diameter of less than about 25 microns. The secondary flow passage 420 is not large enough to completely separate the sorbent rods 415. In this way, the need to support spacers can be avoided.

The arbitrary secondary flow channels 420 promote pressure equalization between the primary flow channels 410. If there are too many channel inconsistencies, both productivity and gas purity may be compromised. To this end, if one flow channel is larger than the adjacent flow channel or accepts more airflow than the other flow channel, premature product penetration may occur. This can result in the purity of the product gas to an unacceptable purity. Furthermore, devices operating at a cycle frequency of more than about 50 cycles per minute (cmp) require a higher flow channel uniformity and lower pressure drop than devices with lower cycle operation per minute.

Referring now to Figures 2 and 3, the container 200 of Figure 2 is shown as a cylinder, and the sorbent rod 315 therein is shown as a tubular assembly. however, Other shapes suitable for variable adsorption processing equipment can be used. Non-limiting examples of container arrangements include a plurality of differently shaped monoliths having a plurality of substantially parallel channels extending from one end of the monolith to the other end; a plurality of tubular components; a stack of adsorbent layers and each There are spacers between the thin layers; a multi-layer spiral roll or bundle of hollow fibers, and a substantially parallel solid fiber bundle.

In addition, other specific embodiments for parallel channel contactors can be used. Such a specific embodiment includes the contactors shown and described in Figures 1 through 9 of U.S. Patent Publication No. 2008/0282887. This publication is hereby incorporated by reference in its entirety.

Returning to Figure 1, four exemplary separation stages are shown. These are stages 132'/132", stage 134, stage 136, and stage 138. Each stage represents a bed of adsorbent and the stages 132'/132", 134, 136, 138 are placed in series. Preferably, the adsorbent beds are each present in their unique pressure vessel, such as vessel 200 of Figure 2. However, it is within the scope of the present invention that at least some of the beds are present in the same pressure vessel while maintaining a series connection.

First, stage 132' represents the removal of water vapor from the gas in line 122. Accordingly, the first adsorbent bed is installed in stage 132' wherein the adsorbent material is designed to adsorb water vapor. Once the adsorbent material is saturated, the bed in stage 132' is desorbed and water vapor is released through line 131'. Optionally, the water vapor is combined with liquid line 121 from the separator 120, as indicated by line 125.

The liquid in line 125 is primarily water. These liquids can be reinjected into the reservoir as part of a water flooding operation. or Water can be disposed of and discarded in the surrounding marine environment. Alternatively, the water can be treated and obtained by desalting for irrigation or coastal industrial use. Additionally or alternatively, and as specifically mentioned above, the liquid in line 125 can be further separated to capture any hydrocarbons.

Preferably, the first stage 132' is only a "refining" stage. This means that most of the water has been removed or "shot" by a pre-dewatering vessel (e.g., vessel 120) and the adsorbent bed in stage 132' simply removes residual water vapor.

Where a dewatering vessel is used, the fluid in line 122 includes a desiccant such as ethylene glycol. Thus, the auxiliary first stage 132" is used for desiccant removal. In Figure 1, the desiccant is removed from the gas separation unit 130 through a separate adsorbent bed. Once the bed becomes saturated, the desiccant is passed through. Line 131" is released. The desiccant can be recycled for use in the dewatering vessel 120.

Figure 1 also shows the second stage of contaminant removal at 134. This exemplary second stage 134 is used to remove heavy hydrocarbons. As stated, heavy hydrocarbons primarily comprise any ethane from the original gas stream. It can also adsorb some propane and butane. The heavy hydrocarbons are adsorbed on the adsorbent bed while releasing acid gases and lighter hydrocarbons.

If the heavy hydrocarbon composition is very small, such components may be adsorbed during the first 132'/132" removal stage. This is also related to the adsorbent bed in the first 132'/132" removal stage. Component related. However, if the heavy hydrocarbon content is high, such as greater than 3 to 5 percent, then a separate dedicated adsorption stage 134 is desirable. After saturation, the heavy hydrocarbons are released through line 133.

Preferably, the adsorbent bed in stage 134 is a zeolitic material. Non-limiting examples of zeolites having pore size suitable for the removal of heavy hydrocarbons include MFI, faujasite, MCM-41 and beta. Preferably, the zeolite for heavy hydrocarbon removal in the process of the present invention has a Si/Al ratio of from about 20 to about 1,000, preferably from about 200 to about 1,000, to prevent excessive build-up of the adsorbent.

The molecular sieve bed made from zeolite effectively removes the C ₂ to C ₄ components while the silicone bed is most effective in removing C ₅ + heavy hydrocarbons. Further technical information on the separation of hydrocarbon gas components by the adsorptive kinetic separation process is provided in U.S. Patent Publication No. 2008/0282887, the entire disclosure of which is incorporated herein by reference. The entire disclosure of this patent application is hereby incorporated by reference herein.

The separated heavy hydrocarbons are released through line 133 as described above. The heavy hydrocarbons can be sold as industrial fuel products. Alternatively, the heavy hydrocarbons may be cooled to condense the heavier components and reuse any methane vapor.

This gas flow is then moved to a third stage 136. This third stage 136 is for the removal of sulfur containing components. The sulfur-containing component may include hydrogen sulfide, sulfur dioxide, and mercaptans. The acid gas component is adsorbed onto the adsorbent bed while methane is passed to any fourth stage 138. After saturation, the sulfur-containing components are released via line 135.

In the case where the dehydration gas stream contains hydrogen sulfide, it may be beneficial to formulate the adsorbent with a tin silicate. Specifically, the 8-ring zeolite can be produced from a tin silicate. The kinetic selectivity of such 8-ring materials allows H ₂ S to be quickly transferred into the zeolite crystals. After saturation, the bed is washed. It is understood that these sulfur-containing components are preferably obtained by subsequent sulfur recovery methods.

An optional fourth stage 138 is also installed in the gas separation unit 130. This fourth stage 138 is for removing carbon dioxide and nitrogen from the gas stream. CO ₂ and N _{2 are} adsorbed to the adsorbent bed of stage 138 while releasing the deodorized gas stream. After washing, CO ₂ and N _{2 are} discharged through the discharge line 137 to the gas separation unit 130. At the same time, the deodorizing gas stream is released through line 140.

It is understood that the gas separation unit 130 can have fewer or more than four stages. The number of AKS stages depends on the composition of the feed gas stream entering through gas line 122. For example, if the feed gas stream in line 122 having a volume of less than 0.5 ppm of H ₂ S, is likewise no need for a removal of the sulfur component adsorption stage. Conversely, if the feed gas stream in gas line 122 has a metal contaminant (such as mercury), this separation will add a separate AKS stage.

As described above, each stage 132'/132", 134, 136, 138 uses one adsorbent bed. Each adsorbent bed may represent an adsorbent bed system based on a plurality of parallel beds. These beds may be packed, for example, active Carbon or molecular sieve. The first bed of each system is used for adsorption. This is called a service bed. When the first bed is in use, the second bed is regenerated (eg, through pressure drop). The third bed has been regenerated and maintained for use as a working bed in the adsorption system when the first bed becomes substantially saturated. Therefore, a more efficient operation can use a minimum of 3 beds in parallel.

In each stage 132'/132", 134, 136, 138, the work bed can be in its own dedicated container, and the containers of the various stages are connected in series. Alternatively, the work beds can be combined in one or more The containers are aligned in series. It is also noted that the beds may be fabricated from materials that adsorb more than one component for a certain period of time. For example, a single bed may be designed to preferentially remove both sulfur-containing components and carbon dioxide. individual containers can be mounted in series, such containers are designed based components to substantially remove the same. For example, if the feed gas stream in line 122 having a high content of CO.'s _2, two beds may be mounted in the vessel consequential For priority removal of CO ₂ .

Combinations of different types of adsorbent beds can be applied between stages and stages. The use of a combination of adsorbent beds helps prevent heavy hydrocarbons from remaining in the gas phase and eventually ends with a methane-rich gas stream 140. In any aspect, the methane-rich gas stream 140 is released from the gas separation unit 130.

The gas treatment device 100 is also used for liquefaction of the natural gas. In this context, this means that the deodorized methane-rich gas stream 140 will be cooled. In Figure 1, the liquefaction device is shown at 150.

The methane-rich gas stream 140 can be moderately compressed prior to entering the liquefaction plant 150. This is particularly practical in the case where there is a distance between the gas separation unit 130 and the liquefaction device 150. In the apparatus 100 of Figure 1, any compressor is shown at 145. The compressor 145 releases the compressed methane-rich gas stream 142 that is fed to the liquefaction plant 150.

In the present invention, the liquefaction apparatus 150 is a high pressure expander based apparatus. In a specific embodiment, FIG. 5 shows a schematic flow diagram of the high pressure expander cycle refrigeration system 150.

The refrigeration system 150 initially includes a first compression unit 515. Enter this After the liquefaction apparatus 150, the deodorized methane-rich gas stream 140 (or 142) is passed through the first compression unit 515. The first compression unit 515 can be, for example, a high pressure centrifugal drying sealed compressor. The first compression unit 515 increases the pressure of the methane-rich gas stream 140 to a pressure above 1,000 psia (6,895 kPa). In this manner, a compressed gas feed stream 517 is formed.

The liquefaction plant 150 also includes one or more compression heat exchangers for cooling the deodorized and compressed gas stream 517. In the arrangement of Fig. 5, the first heat exchanger 525 and the second heat exchanger 535 are shown. The liquefaction plant 150 also uses one or more high pressure expanders for further cooling. In Figure 5, the expander is shown at 540.

The expander 540 can be of several types. For example, a Joule-Thompson valve can be used. Alternatively, a turbo expander can be installed. A turboexpander is a centrifugal or axial turbine through which high pressure gas expands. Turboexpanders are commonly used to generate work that can be used, for example, to drive a compressor. In this regard, the turboexpander produces a source of shaft work for a process such as compression or freezing. In any particular embodiment, a liquefied natural gas, or LNG stream, is produced. The LNG stream is shown in liquefied product stream 542.

As described above, the liquefaction apparatus 150 includes a first heat exchanger 525. The heat exchanger 525 is part of the first refrigeration loop 520 and may be referred to as a first cooler. The first cooler 525 receives the compressed gas feed stream 517 from the first compression unit 515. The first cooler 525 then cools the compressed gas feed stream 517 to a substantially cooled temperature. For example, the temperature can be as low as -100 ° C (-148 ° F).

The first cooler 525 releases the compressed cooled gas feed stream 522. The compressed, cooled gas feed stream 522 is introduced into the first expander 540. This serves to further cool the compressed gas feed stream 517 to a temperature at which substantial liquefaction of methane occurs. Thus, a liquefied product stream 542 of at least -162 ° C (-260 ° F) is released.

The product stream 542 has a large liquid portion and a residual small vapor portion. Therefore, it is preferred that the liquefaction apparatus 150 also includes a liquid separation container 550. The liquid separation vessel 550 is constructed to separate the liquid portion and the remaining vapor portion. Thus, a liquid methane stream 152 is released from one line to become an LNG industrial product, while a separate cold vapor stream 552 is released at the top.

The cold vapor stream 552 can be used as a coolant for the first cooler 525 in the first refrigeration loop 520. It can be seen in FIG. 5 that the cold vapor stream 552 enters the first cooler 525 where it undergoes heat exchange with the compressed gas feed stream 517. A partially warmed product stream 554 is then released.

The partially warmed product stream 554 is directed back to the beginning of the first refrigeration loop 520. This means that the partially warmed product stream 554 is combined back into the methane-rich gas stream 140 (or 142). In order to accomplish this, a third compression unit 555 is provided. The third compression unit 555 releases the product stream 557 that is warmed by the compression portion. The compressed partially warmed product stream 557 is preferably obtained by the first compression unit 515 together with the methane-rich gas stream 142.

Preferably, the gas liquefaction apparatus 150 includes a second heat exchanger. Will A second heat exchanger is shown at 535 and represents a second cooler. The second heat exchanger 535 can be arbitrarily disposed in the pipeline of the first refrigeration loop 520 after the first cooler 525. In this manner, the second heat exchanger 535 can be re-cooled into the compressed, cooled gas feed stream 522. However, it is preferred that the second heat exchanger 535 is disposed in the pipeline of the first refrigeration loop 520 before the first cooler 525. This configuration is shown in FIG.

In FIG. 5, the second heat exchanger 535 or the second cooler receives a partially warmed product stream 554 from the first cooler 525. The partially warmed product stream 554 is then indirectly heat exchanged with the compressed gas feed stream 517. The heat exchanger 535 pre-cools the compressed gas feed stream 517 before the compressed gas feed stream 517 enters the first cooler 525. The second heat exchanger 535 thus releases the pre-cooled compressed gas feed stream 532 into the first cooler 525.

The heat exchanger 535 also releases the warmed product stream 556. In this arrangement, the warmed product stream 556 enters the third compression unit 555 and is released into the compressed and partially warmed product stream 557, which is coupled to the methane-rich gas stream 142. merge.

In order to provide effective pre-cooling in the second cooler 535, a coolant is used in addition to the partially warmed product stream 554. Therefore, a second refrigeration loop 530 is also installed. The second refrigeration loop 530 uses coolant, shown in line 534. The coolant in line 534 is preferably nitrogen or a nitrogen containing gas. The application of nitrogen to the coolant will expand the pre-cooling temperature range.

Referring back to Figure 1, it can be seen that some of the contaminants from stage 138 were intercepted. This represents N ₂ and possibly some of the CO ₂ in line 137. This nitrogen is brought to the gas liquefaction plant 150 via line 147. Additionally, an operator may take a portion of the methane-rich gas stream 140 as the coolant 534. This is done via line 141. Alternatively or additionally, the operator may take a portion of the heavy hydrocarbons separated from stage 136. Ethane (or other heavy hydrocarbons) is taken from line 133 via line 143. Lines 141, 143, and 147 are shown as dashed lines indicating any fluid interception.

The gas components in lines 141, 143, and 147 are selectively and arbitrarily taken from the gas separation unit 130 and incorporated into line 149. This is shown in Figure 1. The components from lines 141, 143 and/or 147 are then directed through line 149 to the second refrigeration loop 530. This is shown in Figure 5. Valve 501 is shown to control the flow of components from lines 141, 143, and/or 147 through line 149 into the second refrigeration loop 530. Valve 501 can also be used to transfer a portion of the components from lines 141, 143, 147 for combustion in a gas turbine to generate electricity or to regenerate a bed associated with the TSA.

Of course, it is understood that other valves (not shown) can control the relative volumes of the components in the lines 141, 143, 147 that are introduced into line 149. It is also known that the operator can extract nitrogen from a dedicated tank (not shown) for use in the coolant in line 534. In any arrangement, the coolant from line 534 exits the heat exchanger 535 in a warmed state. The coolant moves through the second compression unit 536 for pressurization and is then passed through the expander 538 for re-cooling. The coolant in line 534 then re-enters the heat exchanger 535. A small cooler (not shown) may be added to the second after the expander 538 Freeze loop 530 to further cool the coolant in line 534.

Note that the heat exchanger 535 can serve as the sole cooler for the gas liquefaction plant 150. In this scenario, the first cooler 525 cannot be used. Additionally, the vapor portion 552 is preferably used subsequently as at least a portion of the coolant for line 534. However, the simultaneous use of the heat exchanger 535 and the expander 538 in the second refrigeration loop 530 will improve the overall cooling efficiency of the first refrigeration loop 520. In any instance, the invention is not limited to a particular arrangement of a chiller or a refrigerating loop unless explicitly stated in the scope of the patent application.

Figure 6 is a flow chart showing the steps of a method 600 for liquefying a feedstock natural gas stream. The method 600 utilizes an adsorptive kinetic separation process to produce a methane-rich gas stream. The method 600 then further recycles the refrigeration system with a high pressure expander to cool the methane and provide the LNG product. The LNG product is preferably produced on an offshore floating platform or a gravity based platform.

The method 600 first includes accepting the natural gas feed stream at a gas separation unit. The gas separation unit has one or more fractionation vessels. The fractionation vessels are designed in accordance with the fractionation vessel of a plurality of different embodiments above. The fractionation vessels are preferably operated in accordance with pressure swing adsorption (PSA) or rapid cycle pressure swing adsorption (RCPSA) to regenerate the adsorption beds in series. The adsorbent beds are designed to adsorb CO ₂ , H ₂ S, H ₂ O, heavy hydrocarbons, VOCs, mercaptans, nitrogen, or combinations thereof.

The method 600 also includes substantially separating methane from contaminants within the natural gas feed stream. As for the first separation step, the feed natural gas feed stream is arbitrarily taken through a dewatering vessel. This is used to remove considerable gas from the natural gas stream Part of the water and other liquid components. The step of separating the liquid phase component (primarily water) from the gas phase component is shown at block 620. The dehydrated natural gas feed stream is then released as a dehydrated natural gas feed stream.

Next, gas phase contaminants are removed from the dehydrated feed gas stream. The step of separating methane from the gaseous phase contaminants within the natural gas feed stream is shown at block 630. This step is accomplished by using an adsorption bed in one or more fractionation vessels. In one aspect, separating methane from the contaminant is performed through the gas separation unit at an absolute pressure of at least about 500 pounds per square inch (psia).

Figure 7 is a flow chart showing a step 700 for separating contaminants from the feed natural gas stream. These steps use an adsorptive kinetic separation to form the methane-rich gas stream.

First, water is adsorbed from the natural gas feed stream. In this case, an adsorbent bed having water retention property is used. This step is shown at block 710. As mentioned above, it is preferred that the water removal stage is only a "refining" stage. This means that most of the water has been removed or "shot" by the pre-dewatering vessel (according to the steps of block 620).

In the case of a dewatering vessel, the contaminants in the gas stream include a desiccant such as ethylene glycol. Therefore, the next stage of separation of the components involves adsorption of the desiccant. This is provided at block 720.

As shown in Figure 7, multiple additional adsorptive stages can be employed to remove contaminants. These may include removal of sulfur containing components (block 730), removal of carbon dioxide and/or nitrogen (block 740), removal of mercury or other metallic elements (block 750), and removal of heavy hydrocarbons (blocks) 760). according to Depending on the design of the adsorbent beds, some of these components can be removed in a single combined stage. Additionally, the order of contaminant removal provided by the steps of blocks 710 through 760 can be varied, but it is preferred to first remove water in the manner indicated by block 710. Thus, the method 600 is not limited to the order in which the contaminants are removed in step 700, unless otherwise indicated in the scope of the patent application herein.

In one aspect, a single vessel having a plurality of adsorbent beds aligned in series is used. For example, at least one of the gas separation units can comprise a vessel comprising a plurality of adsorbent beds in series such that the first adsorbent bed is designed to primarily remove water from the dewatered natural gas feed stream. And other liquid components; the second adsorbent bed is designed to primarily remove the desiccant from the dewatered natural gas feed stream; and the third vessel comprises a design primarily to remove the dehydrated natural gas feed stream The adsorbent bed of the acid gas component in the medium.

Other containers can be added to adsorb and separate the different acid gases.

In another aspect, a plurality of vessels in series are used, and the vessels are aligned using the flow of the dewatered natural gas feed stream. Each container releases a progressively deodorized methane stream. For example, the first vessel uses an adsorbent bed designed to remove residual water from the dewatered natural gas feed stream; the second vessel uses a desiccant designed to remove the dewatered natural gas feed stream The adsorbent bed; and the third container is designed to remove the dehydrated natural gas feed An adsorbent bed of acid gas components in the stream.

The acid gas component can be one or more sulfur-containing components. Alternatively, the acid gas component can be carbon dioxide.

As a result of the adsorption step 700 in Figure 7, a methane-rich gas stream is produced. This gas stream is released from the gas separation unit as a dehydrated natural gas feed stream. Thus, the method 600 next includes releasing a dehydrated methane-rich gas stream from the gas separation unit. This is indicated at block 640.

The methane-rich gas stream is directed to the high pressure expander cycle refrigeration system. This can be seen at block 650. The refrigeration system is in accordance with Figure 5, shown above, and the refrigeration system 150 as described in any of its various different embodiments. Accordingly, the refrigeration system preferably includes a first refrigeration circuit for circulating a vapor portion of the product as a coolant in the first cooler, and for circulating a nitrogen-containing gas as a coolant in the second cooler The second refrigeration loop. The second cooler can simultaneously utilize a nitrogen-based coolant and a partially warmed methane gas from the first cooler to become a working fluid.

The method 600 also includes compressing the methane-rich gas stream. This step is provided at block 660. The gas stream is compressed to a pressure above 1,000 psia (6,895 kPa) to form a compressed gas feed stream.

The method 600 then includes cooling the compressed gas feed stream to form a compressed, cooled gas feed stream. This can be seen at block 670. The cooling step of block 670 preferably involves taking the compressed gas feed stream through at least one heat exchanger within the first refrigeration loop 520. For example, the compressed gas feed stream can use heat exchanger 535 of Figure 5 (second The cooler) is pre-cooled and then further cooled using the first cooler 525 of FIG. Optionally, the heat exchanger 535 (second cooler) may be disposed after the first cooler 525 in the first refrigeration loop 520. In this manner, the heat exchanger 535 cools the compressed gas feed stream 517 after the compressed gas feed stream 517 has passed through the first cooler 525.

The first refrigeration loop 520 circulates coolant through at least one heat exchanger (e.g., cooler 525) and then directs the used (warm) coolant (554 and/or 556) to compression unit 555. The compression unit compresses the warmed coolant to between about 1,500 and 3,500 psia (10,342 to 24,132 kPa). More preferably, the compression unit compresses the warmed product stream to between about 2,500 and 3,000 psia (17,237 to 20,684 kPa).

The second cooler 535 is preferably part of the second refrigeration loop 530. The second cooler 535 is configured to cool the compressed gas feed stream 517 at least in part by indirect heat exchange between the coolant stream 534 and the compressed gas feed stream. The second refrigeration loop 530 can also include a compression unit 536. The compression unit 536 is configured to compress the coolant stream after the coolant stream passes through the second cooler 535. The second refrigeration loop also then includes an expander. The expander receives the recompressed cooled coolant stream and expands the compressed cooled coolant stream prior to returning the recompressed cooled coolant stream to the second cooler 535.

The method 600 also includes expanding the cooled compressed gas feed stream 522. This step is provided at block 680. In one aspect, the expansion of the cooled compressed gas feed stream 522 comprises cooling the compressed gas. The pressure of the bulk feed stream is reduced to a pressure between about 50 psia (345 kPa) and 450 psia (3,103 kPa). The expansion of the cooled gas feed stream 522 forms the LNG product stream 542. The product stream has a liquid portion and a residual vapor portion.

The high pressure expander circulation refrigeration system preferably includes a liquid separation vessel. The method then further includes separating the liquid portion and the residual vapor portion. The liquid portion can then be loaded into a delivery container. This step is shown in block 690 of Figure 6.

To confirm the efficacy of the method 600, and in particular to use the AKS system to remove nitrogen, some data is generated. This data is presented in the tables in the examples below.

Example

The results of the comparison are detailed in the table below using the Aspen HYSYS® (2006 version) process simulator (a computer-aided design program from Aspen Technology, Inc., of Cambridge, Massachusetts). The wording "SCRS" is used in the table. This wording is an abbreviation of "selective component removal system" and in this context denotes an AKS adsorptive system.

First, Table 2 illustrates the effect of removing nitrogen from the natural gas stream prior to liquefaction. A comparison is made with a conventional method of removing nitrogen using a distillation column after liquefaction of the nitrogen-containing natural gas. The energy savings achieved (above 7%) result in simplification of the power generation equipment. This can be interpreted as a reduction in space and weight, and the ability to manufacture LNG offshore.

Note that the specifications required for LNG can be easily achieved.

Next, Table 3 is provided to illustrate the benefits of processing performance using a high pressure expander recirculating refrigeration system. When the feed pressure is increased, the thermal energy required to produce the LNG from an ambient temperature of 100 °F will be reduced, and for a pressure of 4,000 psia, the thermal energy is reduced by up to 17%. Conventional gas treatments reduce the feed gas pressure to less than 1,000 psia. Therefore, in order to take advantage of the reduced heat energy benefits of compression, compression equipment and associated compression horsepower are required to increase the feed pressure. This offsets the benefit of this reduced liquefaction horsepower.

It has been found that operating AKS-based gas separation under elevated pressure Units can maintain and even enhance these benefits.

Table 4 emphasizes the performance improvement effect using the separation method of the present invention. In conventional methods, the benefit of increasing the feed gas pressure is achieved by increasing the compression of the feed gas: the energy associated with the pressure drop at the source of the conventional solvent extraction gas conditioning process is typically wasted. The SCRS unit can be constructed to maintain source pressure and to avoid wasted energy by conventional methods.

The gas separation unit was formed by using a small and lightweight AKS separator, and by using a high pressure expander to circulate the refrigeration system, the equipment and weight of the gas conditioning or processing equipment was reduced by 75%. This translates into a 21% reduction in space and weight for FLNG barges. Alternatively, the available space and weight can be used to increase the capacity of the FLNG barge. This reduction is therefore improved The economic implementation possibilities of the gas commercialization plan.

As can be seen, the present invention provides an improved gas processing apparatus for liquefying a natural gas stream. In one aspect, the device comprises:

A gas separation unit having at least one fractionation vessel, the at least one fractionation vessel comprising: a gas inlet for receiving a natural gas mixture comprising methane, a sorbent material, and a kinetic selection of the pollutant for methane The rate is greater than 5, such that the contaminant becomes kinetically adsorbed in the adsorbent material, and the gas outlet is used to release the methane-rich gas stream; and the high pressure expander recirculating refrigeration system includes: the first compression a unit configured to accept a substantial portion of the methane-rich gas stream and compress the methane-rich gas stream to a pressure greater than about 1,000 psia (6,895 kPa) to provide a compressed gas feed stream; a cooler configured to cool the compressed gas feed stream to form a compressed cooled gas feed stream; and a first expander configured to cause the cooled compressed gas feed stream Expanded to form a product stream having a liquid portion and a remaining vapor portion.

2. The gas processing apparatus of paragraph 1, wherein: the first cooler is configured to accept a portion of the product stream from the first expander and use the portion of the product stream to pass through heat exchange to cool the compressed Gas feed stream.

3. The gas processing apparatus of paragraph 1, wherein: the first cooler is constructed to pass an external coolant flow through the heat exchange The compressed gas feed stream is instead cooled.

4. The gas processing apparatus of paragraph 1, wherein the high pressure expander circulation refrigeration system further comprises: a liquid separation vessel configured to separate the liquid portion and the remaining vapor portion from the first expander.

5. The gas processing apparatus of paragraph 4, wherein: the first cooler receives at least a portion of the vapor portion and uses the vapor portion to cool the compressed gas feed stream by heat exchange to serve as a first refrigeration a portion of the loop; the first cooler releasing (i) the cooled gas feed stream, and (ii) a partially warmed product stream after heat exchange with the compressed gas feed stream; The high pressure expander recirculating refrigeration system additionally includes: a second cooler configured to further cool the compressed gas feed stream at least in part by heat exchange with the coolant stream and the vapor portion; and second a refrigeration loop having (i) a second compression unit configured to compress the coolant stream after the coolant stream passes through the second cooler, and (ii) a second expander The second expander is configured to accept the recompressed coolant stream and expand the recompressed coolant stream prior to returning the recompressed coolant stream to the second cooler.

6. The gas processing apparatus of paragraph 5, wherein the high pressure expander circulation refrigeration system additionally comprises: a third compression unit in the first refrigeration loop, the third compression unit for compressing the partially warmed product stream after heat exchange with the compressed gas feed stream; and for combining the The compressed partially warmed product stream and the gas feed stream complete the line of the first refrigeration loop.

7. The gas processing apparatus of paragraph 5, wherein the second cooler sub-cools the cooled gas feed stream after the cooled gas feed stream exits the first cooler.

8. The gas processing apparatus of paragraph 5, wherein the second cooler pre-cools the compressed gas feed stream prior to the compressed gas feed stream entering the first cooler.

9. The gas processing apparatus of paragraph 8, wherein: the second cooler receives a partially warmed product stream from the first cooler for further heat exchange with the compressed gas feed stream; and will be warm The stream of product is released to a third compression unit to complete the first refrigeration loop.

10. The gas treatment apparatus of paragraph 1, wherein the apparatus is located offshore (i) a floating platform, (ii) a gravity based platform, or (iii) a boat shaped container.

11. The gas processing apparatus of paragraph 1, wherein at least one of the gas separation units is operated according to a pressure swing adsorption (PSA) or rapid cycle pressure swing adsorption (RCPSA) process.

12. The gas processing device of paragraph 11, wherein the at least one container fractionation system constructed to adsorb _{CO 2, H 2 S, H} 2 O, heavy hydrocarbons, the VOC, thiols, or combination thereof.

13. The gas processing apparatus of paragraph 12, further comprising: a dewatering vessel configured to accept the natural gas feed stream and to remove substantial water from the natural gas feed stream and to dehydrate the natural gas The feed stream is released to the at least one fractionation vessel.

14. A method for liquefying a natural gas feed stream, comprising: receiving a natural gas feed stream at a gas separation unit, the gas separation unit having at least one fractionation vessel, the at least one fractionation vessel comprising: a gas inlet for Accepting a mixture of natural gas containing methane, the adsorbent material, the kinetic selectivity of the pollutant to methane is greater than 5, such that the contaminant becomes kinetically adsorbed in the adsorbent material, and the gas outlet is constructed to release a methane-rich gas stream; substantially separating methane from the contaminant in the natural gas feed stream; releasing a methane-rich gas stream from the gas separation unit; and introducing the methane-rich gas stream into the high pressure expander circulation refrigeration system; Compressing the methane-rich gas stream to a pressure above 1,000 psia (6,895 kPa) to form a compressed gas feed stream; cooling the compressed gas feed stream to form a compressed, cooled gas feed stream; The cooled compressed gas feed stream expands to form a product stream having a liquid portion and a remaining vapor portion; and the liquid portion and the vapor portion Separation.

15. The method of paragraph 14, wherein the high pressure expander circulation refrigeration system comprises: a first compression unit configured to accept a substantial portion of the methane-rich gas stream and to produce the compressed gas feed stream; a first cooler configured to cause the compressed gas feed stream Cooling to form the compressed, cooled gas feed stream; and a first expander constructed to expand the cooled, compressed gas feed stream to form the product stream.

16. The method of paragraph 15, wherein the cooling of the compressed gas feed stream comprises: transporting at least a portion of the vapor portion from the product stream to the first cooler as part of the first refrigeration loop; The vapor portion of the product stream is heat exchanged with the compressed gas feed stream to cool the compressed gas feed stream.

17. The method of paragraph 16, wherein: the high pressure expander circulation refrigeration system additionally comprises a liquid separation vessel; and the separation of the liquid portion from the vapor portion is accomplished using the liquid separation vessel.

18. The method of paragraph 17, further comprising: releasing (i) the cooled gas feed stream from the first cooler to form the product stream, and (ii) partially warming the product stream to become a work a fluid; directing the partially warmed product stream to a third compression unit; and combining the compressed partially warmed product stream from the third compression unit with the methane-rich gas stream to complete the first refrigeration loop .

19. The method of paragraph 18, wherein the high pressure expander recirculating refrigeration system further comprises: a second cooler configured to be further cooled, at least in part, by indirect heat exchange between the coolant stream and the vapor portion a compressed gas feed stream; and a second refrigeration loop having (i) a second compression unit configured to recompress the coolant stream after passing the second cooler a coolant flow, and (ii) a second expander configured to accept the compressed coolant stream and prior to returning the compressed coolant stream to the second cooler The compressed coolant stream expands.

20. The method of paragraph 19, wherein the second cooler cools the cooled gas feed stream after the cooled gas feed stream exits the first cooler.

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

22. The method of paragraph 1, wherein the apparatus is located offshore (i) a floating platform, (ii) a gravity based platform, or (iii) a boat shaped container.

23. The method of paragraph 22, wherein at least one of the fractionation vessels of the gas separation unit operates in accordance with a pressure swing adsorption (PSA) or rapid cycle pressure swing adsorption (RCPSA) process.

24. The method of paragraph 23, wherein the at least one container fractionation system constructed to adsorb _{CO 2, H 2 S, H} 2 O, heavy hydrocarbons, the VOC, thiols, or combination thereof.

25. The method of paragraph 22, further comprising: passing the natural gas feed stream through a dewatering vessel to remove substantial portions of water from the natural gas feed stream; and releasing the dehydrated natural gas feed stream to the at least one Fractionation vessel for removal of contaminants.

26. A method for liquefying a natural gas feed stream, comprising: receiving a natural gas feed stream at a gas processing plant; passing the natural gas feed stream through a dewatering vessel to remove substantial water from the natural gas feed stream Discharging the dehydrated natural gas feed stream to the gas separation unit in the form of a dehydrated natural gas feed stream; in the gas separation unit, passing the dehydrated natural gas feed stream through a series of adsorbent beds to utilize adsorption a kinetic separation process for separating methane gas from contaminants in the dehydrated natural gas feed stream; releasing a methane-rich gas stream from the gas separation unit; introducing the methane-rich gas stream into a high pressure expander circulation refrigeration system Compressing the methane-rich gas stream to a pressure above 1,000 psia (6,895 kPa) to form a compressed gas feed stream; cooling the compressed gas feed stream to form a compressed, cooled gas feed stream; The cooled, compressed gas feed stream is expanded to form a product stream having a liquid portion and a remaining vapor portion.

27. The method of paragraph 26, wherein the series of adsorbent beds comprises: a first adsorbent bed for removing residual water from the dehydrated natural gas feed stream; and a second adsorbent bed designed to be The desiccant is primarily used to remove the dewatered natural gas feed stream; and the third adsorbent bed is designed to be primarily used to remove acid gas components from the dehydrated natural gas feed stream.

28. The method of paragraph 27, wherein the adsorbent beds are each in communication with two additional adsorbent beds to form three adsorbent beds, wherein: the first adsorbent bed of the three adsorbent beds is used Adsorbing selected contaminants; regenerating a second adsorbent bed of the three adsorbent beds; and maintaining a third adsorbent bed of the three adsorbent beds to replace the first of the three adsorbent beds a sorbent bed; and wherein the regeneration system is part of a pressure swing adsorption process.

As can be seen, the present invention provides another enhanced gas treatment apparatus for liquefying a natural gas stream. In one aspect, the device comprises:

1A. A gas processing apparatus for liquefying a natural gas feed stream, the apparatus comprising: a gas separation unit having at least one fractionation vessel, the at least one fractionation vessel comprising: a gas inlet for accepting methane-containing Natural gas mixture, adsorbent material, its kinetic selectivity for methane is greater than 5 So that the contaminant becomes kinetically adsorbed in the adsorbent material, and the gas outlet is used to release the methane-rich gas stream; and the high pressure expander recirculating refrigeration system comprises: a first compression unit configured to accept a substantial portion of the methane-rich gas stream and compress the methane-rich gas stream to a pressure above about 1,000 psia (6,895 kPa) to provide a compressed gas feed stream a first cooler configured to cool the compressed gas feed stream to form a compressed, cooled gas feed stream; and a first expander constructed to cool the compressed gas The feed stream expands to form a product stream having a liquid portion and a remaining vapor portion.

2A. The gas processing apparatus of paragraph 1A, wherein: the first cooler is configured to accept a portion of the product stream from the first expander and use the portion of the product stream to pass through heat exchange to cool the compressed Gas feed stream.

3A. The gas processing apparatus of paragraph 1A, wherein: the first cooler is configured to cool the compressed gas feed stream by heat exchange using an external coolant stream.

4A. The gas processing apparatus of paragraph 1A, wherein the high pressure expander circulation refrigeration system further comprises: a liquid separation vessel configured to separate the liquid portion and the remaining vapor portion from the first expander.

5A. Gas treatment equipment as in paragraph 4A, wherein: The first cooler receives at least a portion of the vapor portion and uses the vapor portion to cool the compressed gas feed stream through heat exchange as part of a first refrigeration loop; the first cooler is released ( i) a cooled gas feed stream, and (ii) a partially warmed product stream after heat exchange with the compressed gas feed stream; and the high pressure expander recycle refrigeration system additionally comprises: a second cooler Constructed to further cool the compressed gas feed stream at least in part by heat exchange with a coolant stream and the vapor portion; and a second refrigeration loop having (i) a second compression unit The second compression unit is configured to compress the coolant stream after the coolant stream passes through the second cooler, and (ii) a second expander that is constructed to accept the The compressed coolant stream is expanded and the recompressed coolant stream is expanded prior to returning the recompressed coolant stream to the second cooler.

6A. The gas processing apparatus of paragraph 5A, wherein the high pressure expander circulation refrigeration system further comprises: a third compression unit in the first refrigeration loop, the third compression unit being used in the compressed The partially warmed product stream is compressed after the gas feed stream is heat exchanged; and a line for combining the compressed partially warmed product stream with the gas feed stream to complete the first refrigeration loop.

7A. The gas processing apparatus of paragraph 5A, wherein the second cooler The cooled gas feed stream is cooled after the cooled gas feed stream exits the first cooler.

8A. The gas processing apparatus of paragraph 5A, wherein the second cooler pre-cools the compressed gas feed stream prior to the compressed gas feed stream entering the first cooler.

9A. The gas processing apparatus of paragraph 8A, wherein: the second cooler receives a partially warmed product stream from the first cooler for further heat exchange with the compressed gas feed stream; The stream of product is released to a third compression unit to complete the first refrigeration loop.

10A. The gas processing apparatus of paragraph 9A, wherein the third compression unit compresses the warmed product stream to between about 1,500 and 3,500 psia (10,342 to 24,132 kPa).

11A. A gas processing apparatus according to paragraph 1A, wherein the apparatus is located offshore (i) a floating platform, (ii) a gravity based platform, or (iii) a boat shaped container.

12A. The gas processing apparatus of paragraph 5A, wherein: the coolant stream comprises a gas selected from the group consisting of nitrogen, a nitrogen-containing gas, a side stream from the methane-rich gas stream, and a remaining vapor a portion and a combination thereof; and causing a flow of coolant in the second refrigeration loop to flow in the closed loop.

13A. The gas processing apparatus of paragraph 1A, wherein at least one of the gas separation units is operated in accordance with a pressure swing adsorption (PSA) or rapid cycle pressure swing adsorption (RCPSA) process.

14A. The gas treatment apparatus of paragraph 13A, wherein at least one of the fractionation vessels of the gas separation unit is additionally operated according to a temperature swing adsorption (TSA) or rapid cycle temperature swing adsorption (RCTSA) process.

. 15A. The gas processing apparatus. 13A paragraph, wherein the at least one container fractionation system constructed to adsorb _{CO 2, H 2 S, H} 2 O, heavy hydrocarbons, the VOC, thiols, or combination thereof.

16A. The gas treatment apparatus of paragraph 13A, wherein each of the at least one fractionation vessel cooperates with another fractionation vessel to form a pressure swing adsorption system comprising: at least one working bed providing adsorption, at least one bed being regenerated, And it produces a pressure drop condition, and at least one regenerated bed that is maintained for use as a working bed in the adsorption system when the at least one working bed becomes substantially saturated.

17A. The gas treatment apparatus of paragraph 13A, further comprising: a dewatering vessel configured to accept the natural gas feed stream and to remove substantial water from the natural gas feed stream and to dehydrate the natural gas The feed stream is released to the at least one fractionation vessel.

The gas treatment apparatus of paragraph 17A, wherein the at least one fractionation vessel of the gas separation unit comprises a plurality of vessels connected in series such that: the first vessel comprises a residue for removing the dewatered natural gas feed stream a water adsorption bed; the second vessel comprises an adsorbent bed primarily designed to remove a desiccant from the dewatered natural gas feed stream; The third vessel contains an adsorbent bed that is primarily designed to remove acid gas components from the dewatered natural gas feed stream.

The gas processing apparatus of paragraph 17A, wherein at least one of the gas separation units comprises a vessel comprising a plurality of adsorbent beds in series such that the first adsorbent bed is designed to primarily remove the Water and other liquid components in the dewatered natural gas feed stream; the second adsorbent bed is designed to primarily remove the desiccant from the dewatered natural gas feed stream; and the third vessel contains primarily for removal of the An adsorbent bed of acid gas components in the dehydrated natural gas feed stream.

20A. A method for liquefying a natural gas feed stream, comprising: accepting the natural gas feed stream at a gas separation unit, the gas separation unit having at least one fractionation vessel, the at least one fractionation vessel comprising: a gas inlet for Accepting a mixture of natural gas containing methane, the adsorbent material, the kinetic selectivity of the pollutant to methane is greater than 5, such that the contaminant becomes kinetically adsorbed in the adsorbent material, and the gas outlet is constructed to release a methane-rich gas stream; substantially separating methane from the contaminant in the natural gas feed stream; releasing a methane-rich gas stream from the gas separation unit; and introducing the methane-rich gas stream into the high pressure expander circulation refrigeration system; Compressing the methane-rich gas stream to a pressure above 1,000 psia (6,895 kPa) to form a compressed gas feed stream; Cooling the compressed gas feed stream to form a compressed cooled gas feed stream; expanding the cooled compressed gas feed stream to form a product stream having a liquid portion and a remaining vapor portion; and causing the liquid portion Separated from the vapor portion.

The method of paragraph 20A, wherein the high pressure expander circulation refrigeration system comprises: a first compression unit configured to accept a substantial portion of the methane-rich gas stream and to produce the compressed gas feed stream; a first cooler configured to cool the compressed gas feed stream to form the compressed cooled gas feed stream; and a first expander constructed to cool the compressed gas The feed stream expands to form the product stream.

The method of paragraph 21A, wherein the cooling of the compressed gas feed stream comprises: transporting at least a portion of the vapor portion from the product stream to the first cooler as part of the first refrigeration loop; The vapor portion of the product stream is heat exchanged with the compressed gas feed stream to cool the compressed gas feed stream.

The method of paragraph 22A, wherein: the high pressure expander circulation refrigeration system additionally comprises a liquid separation vessel; and the separation of the liquid portion from the vapor portion is accomplished using the liquid separation vessel.

24A. The method of paragraph 23A, further comprising: releasing (i) the cooled gas feed stream from the first cooler to form the product stream, and (ii) partially warming the product stream to become a work a fluid; directing the partially warmed product stream to a third compression unit; and combining the compressed partially warmed product stream from the third compression unit with the methane-rich gas stream to complete the first refrigeration loop .

The method of paragraph 24A, wherein the high pressure expander circulation refrigeration system further comprises: a second cooler configured to be further cooled, at least in part, by indirect heat exchange between the coolant stream and the vapor portion a compressed gas feed stream; and a second refrigeration loop having (i) a second compression unit configured to recompress the coolant stream after passing the second cooler a coolant flow, and (ii) a second expander configured to accept the compressed coolant stream and prior to returning the compressed coolant stream to the second cooler The compressed coolant stream expands.

The method of paragraph 25A, wherein the second cooler cools the cooled gas feed stream after the cooled gas feed stream exits the first cooler.

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

28A. The method of paragraph 23A, wherein the apparatus is located offshore (i) a floating platform, (ii) a gravity based platform, or (iii) a boat shaped container.

29A. The method of paragraph 23, wherein at least one of the fractionation vessels of the gas separation unit operates according to a pressure swing adsorption (PSA) or rapid cycle pressure swing adsorption (RCPSA) process.

30A. The method of paragraph 23, wherein at least one of the fractionation vessels of the gas separation unit is additionally operated according to a temperature swing adsorption (TSA) or rapid cycle temperature swing adsorption (RCTSA) process.

31A. The method of paragraph 30, wherein the at least one fractionation vessel is constructed to adsorb CO ₂ , H ₂ S, H ₂ O, heavy hydrocarbons, VOCs, mercaptans, or a combination thereof.

32A. The method of paragraph 31A, further comprising: passing the natural gas feed stream through a dewatering vessel to remove substantial portions of water from the natural gas feed stream; and releasing the dehydrated natural gas feed stream to the at least one Fractionation vessel for removal of contaminants.

The method of paragraph 32A, wherein the at least one fractionation vessel of the gas separation unit comprises a plurality of vessels connected in series such that: the first vessel comprises water for removing residual water in the dewatered natural gas feed stream An adsorbent bed; the second vessel comprises an adsorbent bed primarily designed to remove a desiccant in the dewatered natural gas feed stream; and the third vessel comprises a primary vessel primarily designed to remove the dehydrated natural gas An adsorbent bed of acid gas components in the feed stream.

34A. The method of paragraph 32, wherein the at least one fractionation vessel of the gas separation unit comprises a vessel comprising a plurality of adsorbent beds in series such that the first adsorbent bed is designed to primarily remove the dewatered Water and other liquid components in the natural gas feed stream; the second adsorbent bed is designed to primarily remove the desiccant from the dewatered natural gas feed stream; and the third vessel comprises primarily for removal of the dewatered An adsorbent bed of acid gas components in the natural gas feed stream.

35A. A method for liquefying a natural gas feed stream, comprising: receiving, by a gas processing plant, the natural gas feed stream; passing the natural gas feed stream through a dewatering vessel to remove substantial portions of water from the natural gas feed stream; The dehydrated natural gas feed stream is released to the gas separation unit as a dehydrated natural gas feed stream; in the gas separation unit, the dehydrated natural gas feed stream is passed through a series of adsorbent beds to utilize adsorption The kinetic separation method separates methane gas from the contaminant in the dehydrated natural gas feed stream; releases a methane-rich gas stream from the gas separation unit; and introduces the methane-rich gas stream into the high pressure expander circulation refrigeration system; Compressing the methane-rich gas stream to a pressure above 1,000 psia (6,895 kPa) to form a compressed gas feed stream; The compressed gas feed stream is cooled to form a compressed, cooled gas feed stream; the cooled, compressed gas feed stream is expanded to form a product stream having a liquid portion and a remaining vapor portion.

36A. The method of paragraph 35A, wherein the series of adsorbent beds comprises: a first adsorbent bed for removing residual water from the dehydrated natural gas feed stream; and a second adsorbent bed designed to be The desiccant is primarily used to remove the dewatered natural gas feed stream; and the third adsorbent bed is designed to be primarily used to remove acid gas components from the dehydrated natural gas feed stream.

37A. The method of paragraph 36A, wherein the first, second, and third adsorbent beds are aligned in series with the flow of the dehydrated natural gas feed stream in a single pressure vessel.

38A. The method of paragraph 36A, wherein the first, second, and third adsorbent beds are present in separate pressure vessels, the individual pressure vessels being aligned in series with the flow of the dewatered natural gas feed stream.

39A. The method of paragraph 36, wherein the adsorbent beds each comprise a bed of solid adsorbent made from a zeolitic material.

40A. The method of paragraph 37A, wherein the adsorbent beds are each in communication with two additional adsorbent beds to form three adsorbent beds, wherein: the first adsorbent bed of the three adsorbent beds is for Adsorption of selected contaminants; Regenerating a second adsorbent bed of the three adsorbent beds; and maintaining a third adsorbent bed of the three adsorbent beds to replace the first adsorbent bed of the three adsorbent beds; This regeneration is part of the pressure swing adsorption process.

41A. The method of paragraph 36A, wherein the cooling of the compressed gas feed stream comprises passing the compressed gas feed stream through a first heat exchanger for heat exchange with the cooled coolant stream. Forming a re-cooled gas feed stream; and passing the re-cooled gas feed stream through a second heat exchanger for heat exchange with the cooling gas stream to form the compressed, cooled gas feed stream.

42A. The method of paragraph 41A, further comprising: withdrawing a portion of the remaining vapor portion from the product stream; reducing the pressure of the withdrawn portion of the residual vapor portion to a pressure of between about 30 and 200 psia (207 to 1,379 kPa) And generating a depressurized gas stream; passing the depressurized gas stream through the second heat exchanger as a cooling gas stream; and releasing the depressurized gas stream from the second heat exchanger to become a partially warmed gas stream .

43A. The method of paragraph 42A, further comprising: passing the partially warmed gas stream through the first heat exchanger to form a cooling gas stream; The partially warmed gas stream is returned to the dewatered natural gas feed stream for compression with the methane-rich gas stream.

44A. The method of paragraph 36A, wherein: compressing the methane-rich gas stream comprises compressing the methane-rich gas stream to a pressure of between about 1,200 psia (8,274 kPa) and 4,500 psia (31,026 kPa); And expanding the cooled compressed gas feed stream comprises reducing the pressure of the cooled compressed gas feed stream to a pressure between about 50 psia (345 kPa) and 450 psia (3,103 kPa).

As can be seen, the present invention provides a program system and method for liquefying a natural gas feed stream using an AKS and a high pressure expander recirculating refrigeration system. Such programs, systems, and methods can form LNG using devices that are lighter than conventional devices. These programs, systems, and methods can also quickly equip work machines for offshore production operations. The invention described herein is not limited to the specific embodiments disclosed herein, but is determined by the scope of the appended claims. Although it is apparent that the invention described herein has been explicitly inferred to achieve the above benefits and advantages, it is obvious that the inventions are susceptible to modifications, changes and changes without departing from the spirit thereof.

100‧‧‧ gas treatment equipment

110‧‧‧storage

112‧‧‧ Wellbore

112’‧‧‧ pipeline

115‧‧‧ surface

120‧‧‧Separator

121, 122‧‧‧ pipeline

125‧‧‧ pipeline

130‧‧‧Gas separation unit

131’‧‧‧ pipeline

131”‧‧‧ pipeline

132’‧‧‧ separation stage

132”‧‧‧Separation stage

133‧‧‧ pipeline

134‧‧‧separation phase

135‧‧‧ pipeline

136‧‧‧separation phase

137‧‧‧ pipeline

138‧‧‧separation phase

140‧‧‧ pipeline

141‧‧‧ pipeline

142‧‧‧Compressed methane-rich gas stream

143‧‧‧ pipeline

145‧‧‧Compressor

147‧‧‧ pipeline

149‧‧‧ pipeline

150‧‧‧Liquidization equipment

152‧‧‧Liquid methane flow

200‧‧‧Vapor Pressure Vessel Container

202‧‧‧ first end

204‧‧‧second end

205‧‧‧Shell

210‧‧‧ gas inlet

215‧‧‧ Support feet

220‧‧‧Second gas outlet

230‧‧‧First gas outlet

250‧‧‧meter

300‧‧‧ adsorbent bed

302‧‧‧ first end

304‧‧‧ second end

305‧‧‧Circular adsorbent ring

310‧‧‧Flow channel

315‧‧‧Adsorbent rod

320‧‧‧lateral flow channel

325‧‧‧ step surface

400‧‧‧ adsorbent bed

410‧‧‧main flow channel

415‧‧‧Single sorbent material

420‧‧‧ secondary flow channels

501‧‧‧ valve

515‧‧‧First compression unit

517‧‧‧Compressed gas feed stream

520‧‧‧First refrigeration loop

522‧‧‧Compressed and cooled gas feed stream

525‧‧‧First heat exchanger

530‧‧‧Second refrigeration loop

532‧‧‧Pre-cooled compressed gas feed stream

534‧‧‧ pipeline

535‧‧‧second heat exchanger

536‧‧‧Second compression unit

538‧‧‧Expander

540‧‧‧Expander

542‧‧‧Liquified product stream

550‧‧‧Liquid separation container

552‧‧‧ Cold steam flow

554‧‧‧ Partial warming product stream

555‧‧‧ Third compression unit

556‧‧‧Production of warming

557‧‧‧Production of compressed partial warming

Therefore, the present invention may be more readily understood, and specific illustrations, diagrams, and/or flowcharts are attached thereto. However, it is to be noted that the drawings are merely illustrative of the specific embodiments of the invention and are therefore not to be considered as limiting.

Figure 1 is a schematic illustration of an apparatus for making LNG in accordance with one embodiment of the text. The apparatus includes a gas separation unit that produces a methane-rich gas stream, and a high pressure expander cycle refrigeration system for producing LNG products.

Figure 2 is a perspective view of a pressure swing adsorption vessel that can be used in the apparatus of Figure 1 in a particular embodiment. The vessel also represents the kinetic fractionator of the present invention in a particular embodiment.

Figure 3A is a perspective view of the adsorbent bed and flow passage of the pressure swing adsorption vessel of Figure 2 in a particular embodiment. The main flow channel is seen between the adsorbent rods along the major axis of the adsorbent bed.

Figure 3B provides an exploded view of the adsorbent bed of Figure 3A. Figure 3B provides an exploded view of any second gas outlet. A cross-flow channel is shown extending into the container as a secondary flow channel.

Figure 3C is a longitudinal cross-sectional view of the adsorbent bed in place of Figure 3A of the specific embodiment. This figure is taken across line C-C of Figure 3A. Here, a series of stepped surfaces are seen along the adsorbent rod, which serves as a secondary flow path.

Figure 4 is a perspective view of the adsorbent bed and flow channel of the pressure swing adsorption vessel of Figure 2 in a modified version. The main flow channel is seen between the adsorbent rods along the major axis of the adsorbent bed. A cross flow passage is seen in the decomposition site of the adsorbent bed as a secondary flow passage.

Figure 5 is a schematic flow diagram of a high pressure expander recirculating refrigeration system in one embodiment. The refrigeration system accepts a methane-rich gas stream and produces an LNG product. This exemplary refrigeration system uses a secondary cooling loop, which The secondary cooling loop is a closed loop that uses nitrogen, a nitrogen-rich gas, or a portion of the methane-rich gas stream from the gas separation unit.

Figure 6 is a flow chart showing the steps used to liquefy the raw natural gas stream.

Figure 7 is a flow chart showing the steps used to separate contaminants from the feed natural gas stream using an adsorptive kinetic separation process.

100‧‧‧ gas treatment equipment

110‧‧‧storage

112‧‧‧ Wellbore

112’‧‧‧ pipeline

115‧‧‧ surface

120‧‧‧Separator

121, 122‧‧‧ pipeline

125‧‧‧ pipeline

130‧‧‧Gas separation unit

131’‧‧‧ pipeline

131”‧‧‧ pipeline

132’‧‧‧ separation stage

132”‧‧‧Separation stage

133‧‧‧ pipeline

134‧‧‧separation phase

135‧‧‧ pipeline

136‧‧‧separation phase

137‧‧‧ pipeline

138‧‧‧separation phase

140‧‧‧ pipeline

141‧‧‧ pipeline

142‧‧‧Compressed methane-rich gas stream

143‧‧‧ pipeline

145‧‧‧Compressor

147‧‧‧ pipeline

149‧‧‧ pipeline

150‧‧‧Liquidization equipment

152‧‧‧Liquid methane flow

Claims (42)

A gas processing apparatus for liquefying a natural gas feed stream, the apparatus comprising: a gas separation unit having at least one fractionation vessel, the at least one fractionation vessel comprising: a gas inlet for receiving a natural gas mixture comprising methane The adsorbent material has a kinetic selectivity of the pollutant to methane of more than 5, such that the contaminant becomes kinetically adsorbed in the adsorbent material, and the gas outlet is used to release the methane-rich gas stream; And a high pressure expander recirculating refrigeration system comprising: a first compression unit configured to accept a substantial portion of the methane-rich gas stream and compress the methane-rich gas stream to greater than about 1,000 a pressure of psia (6,895 kPa) to provide a compressed gas feed stream; a first cooler configured to cool the compressed gas feed stream to form a compressed, cooled gas feed stream; a first expander constructed to expand the cooled compressed gas feed stream to form a liquid portion and a remaining vapor portion Product stream, wherein the gas separation unit of the container system according to at least one fractionation rapid cycle pressure swing adsorption (RCPSA) operation. For example, the gas processing equipment of claim 1 of the patent scope, wherein: The first cooler is configured to accept a portion of the product stream from the first expander and use the portion of the product stream to pass through a heat exchange to cool the compressed gas feed stream. A gas processing apparatus according to claim 1 wherein: the first cooler is configured to cool the compressed gas feed stream by heat exchange using an external coolant stream. The gas processing apparatus of claim 1, wherein the high pressure expander circulation refrigeration system further comprises: a liquid separation vessel configured to separate the liquid portion and the remaining vapor portion from the first expander. The gas processing apparatus of claim 4, wherein: the first cooler receives at least a portion of the vapor portion, and uses the vapor portion to cool the compressed gas feed stream by heat exchange, as a first a portion of the refrigeration loop; the first cooler releasing (i) the cooled gas feed stream, and (ii) a partially warmed product stream after heat exchange with the compressed gas feed stream; The high pressure expander recirculating refrigeration system additionally includes a second cooler configured to further cool the compressed gas feed stream at least in part by heat exchange with a coolant stream and the vapor portion; a refrigeration circuit having (i) a second compression unit configured to compress the coolant stream after the coolant stream passes through the second cooler, and (ii) a second expansion Second expansion The expander is configured to accept the recompressed coolant stream and expand the recompressed coolant stream prior to returning the recompressed coolant stream to the second cooler. The gas processing apparatus of claim 5, wherein the high pressure expander circulation refrigeration system further comprises: a third compression unit in the first refrigeration loop, the third compression unit being used for compression The partially heated product stream is compressed after the gas feed stream is heat exchanged; and a line for combining the compressed partially warmed product stream with the gas feed stream to complete the first refrigeration loop. The gas processing apparatus of claim 5, wherein the second cooler sub-cools the cooled gas feed stream after the cooled gas feed stream exits the first cooler. A gas processing apparatus according to claim 5, wherein the second cooler pre-cools the compressed gas feed stream before the compressed gas feed stream enters the first cooler. The gas processing apparatus of claim 8 wherein: the second cooler receives a partially warmed product stream from the first cooler for further heat exchange with the compressed gas feed stream; The warmed product stream is released to a third compression unit to complete the first refrigeration loop. The gas processing apparatus of claim 9, wherein the third compression unit compresses the warmed product stream to between about 1,500 and 3,500 psia (10,342 to 24,132 kPa). A gas processing apparatus according to claim 1 wherein the apparatus is located offshore (i) a floating platform, (ii) a gravity based platform, or (iii) a boat shaped container. A gas processing apparatus according to claim 5, wherein: the coolant stream comprises a gas selected from the group consisting of nitrogen, a nitrogen-containing gas, a side stream from the methane-rich gas stream, and the remainder a vapor portion and a combination thereof; and flowing a coolant in the second refrigeration loop to flow in the closed loop. The gas processing apparatus of claim 1, wherein at least one of the gas separation units is additionally operated according to a temperature swing adsorption (TSA) method or a rapid cycle temperature swing adsorption method (RCTSA). The gas processing apparatus of claim 1, wherein the at least one fractionation vessel is constructed to adsorb CO ₂ , H ₂ S, H ₂ O, heavy hydrocarbons, VOCs, mercaptans, or a combination thereof. The gas processing apparatus of claim 1, wherein the at least one fractionation vessel cooperates with the other fractionation vessels to form a pressure swing adsorption system comprising: at least one working bed providing adsorption, at least one bed being regenerated, and It produces a pressure drop condition and at least one regenerated bed that is maintained for use as a working bed in the adsorption system when the at least one working bed becomes substantially saturated. The gas processing apparatus of claim 1, further comprising: a dewatering vessel configured to accept the natural gas feed stream and The natural gas feed stream removes a substantial portion of the water and releases the dehydrated natural gas feed stream to the at least one fractionation vessel. The gas processing apparatus of claim 16, wherein the at least one fractionation vessel of the gas separation unit comprises a plurality of vessels connected in series such that: the first vessel comprises for removing the dewatered natural gas feed stream a bed of residual water; a second vessel comprising an adsorbent bed designed primarily to remove a desiccant from the dewatered natural gas feed stream; and a third vessel comprising a primary vessel designed to remove the dewatered An adsorbent bed of sour gas components in the natural gas feed stream. The gas processing apparatus of claim 16, wherein the at least one fractionation vessel of the gas separation unit comprises a vessel comprising a plurality of adsorbent beds connected in series such that: the first adsorbent bed is designed to be primarily removed Water and other liquid components in the dewatered natural gas feed stream; the second adsorbent bed is designed to primarily remove the desiccant from the dewatered natural gas feed stream; and the third vessel contains primarily for removal An adsorbent bed of acid gas components in the dehydrated natural gas feed stream. A method for liquefying a natural gas feed stream, comprising: accepting the natural gas feed stream at a gas separation unit, the gas separation unit having at least one fractionation vessel, the at least one fractionation vessel comprising: a gas inlet for accepting inclusion a natural gas mixture of methane, The adsorbent material has a kinetic selectivity of the pollutant to methane of more than 5, such that the contaminant becomes kinetically adsorbed in the adsorbent material, and the gas outlet is constructed to release a methane-rich gas stream; Methane is substantially separated from the contaminants in the natural gas feed stream; a methane-rich gas stream is withdrawn from the gas separation unit; the methane-rich gas stream is introduced into a high pressure expander recycle refrigeration system; the methane-rich gas stream is Compressed to a pressure above 1,000 psia (6,895 kPa) to form a compressed gas feed stream; the compressed gas feed stream is cooled to form a compressed cooled gas feed stream; the cooled, compressed gas is passed The stream expands to form a product stream having a liquid portion and a remaining vapor portion; and separating the liquid portion from the vapor portion, wherein the at least one fractionation vessel in the gas separation unit is based on a rapid cycle pressure swing adsorption (RCPSA) Running. The method of claim 19, wherein the high pressure expander recirculating refrigeration system comprises: a first compression unit configured to accept a substantial portion of the methane-rich gas stream and to produce the compressed gas feed stream a first cooler configured to cool the compressed gas feed stream to form the compressed cooled gas feed stream; and a first expander constructed to cool the compressed The gas feed stream expands to form the product stream. The method of claim 20, wherein the cooling of the compressed gas feed stream comprises: transporting at least a portion of the vapor portion from the product stream to the first cooler as part of the first refrigeration loop; And heat-exchange the vapor portion of the product stream with the compressed gas feed stream to cool the compressed gas feed stream. The method of claim 21, wherein the high pressure expander circulation refrigeration system additionally comprises a liquid separation vessel; and the separation of the liquid portion from the vapor portion is performed using the liquid separation vessel. The method of claim 22, further comprising: releasing (i) the cooled gaseous feed stream from the first cooler to form the product stream, and (ii) partially warming the product stream to become Working fluid; directing the partially warmed product stream to a third compression unit; and combining the compressed partially warmed product stream from the third compression unit with the methane-rich gas stream to complete the first refrigeration loop road. The method of claim 23, wherein the high pressure expander circulation refrigeration system further comprises: a second cooler configured to further at least partially indirectly exchange heat between the coolant stream and the vapor portion Cooling the compressed gas feed stream; and a second refrigeration loop having (i) a second compression unit, the second The compression unit is configured to compress the coolant stream after the coolant stream passes through the second cooler, and (ii) a second expander configured to accept the compressed coolant Flowing and expanding the compressed coolant stream prior to returning the compressed coolant stream to the second cooler. The method of claim 24, wherein the second cooler cools the cooled gas feed stream after the cooled gas feed stream exits the first cooler. The method of claim 24, wherein the second cooler pre-cools the compressed gas feed stream before the compressed gas feed stream enters the first cooler. The method of claim 22, wherein the apparatus is located offshore (i) a floating platform, (ii) a gravity-based platform, or (iii) a boat-shaped container. The method of claim 22, wherein the at least one fractionation vessel of the gas separation unit is additionally operated according to a temperature swing adsorption (TSA) method or a rapid cycle temperature swing adsorption method (RCTSA). The method of claim 28, wherein the at least one fractionation vessel is constructed to adsorb CO ₂ , H ₂ S, H ₂ O, heavy hydrocarbons, VOCs, mercaptans, or a combination thereof. The method of claim 29, further comprising: passing the natural gas feed stream through a dewatering vessel to remove a substantial portion of the water from the natural gas feed stream; and releasing the dehydrated natural gas feed stream to the at least a fractionation container For the removal of contaminants. The method of claim 30, wherein the at least one fractionation vessel of the gas separation unit comprises a plurality of vessels connected in series such that: the first vessel comprises a residue for removing the dewatered natural gas feed stream a water adsorption bed; the second vessel comprises an adsorbent bed designed primarily to remove a desiccant from the dewatered natural gas feed stream; and the third vessel comprises a primary vessel designed to remove the dehydrated natural gas An adsorbent bed of acid gas components in the stream. The method of claim 30, wherein the at least one fractionation vessel of the gas separation unit comprises a vessel comprising a plurality of adsorbent beds in series such that the first adsorbent bed is designed to primarily remove the dewatering Water and other liquid components in the natural gas feed stream; the second adsorbent bed is designed to primarily remove the desiccant from the dewatered natural gas feed stream; and the third vessel comprises primarily for removing the An adsorbent bed of acid gas components in the dehydrated natural gas feed stream. A method for liquefying a natural gas feed stream, comprising: receiving a natural gas feed stream at a gas processing plant; passing the natural gas feed stream through a dewatering vessel to remove substantial water from the natural gas feed stream; Dehydrated natural gas feed stream with dehydrated natural gas feed stream Form is released to the gas separation unit; in the gas separation unit, the dehydrated natural gas feed stream is passed through a series of adsorbent beds to utilize the adsorptive kinetic separation process from the dehydrated natural gas feed stream Separating methane gas; releasing a methane-rich gas stream from the gas separation unit; introducing the methane-rich gas stream into a high pressure expander circulation refrigeration system; compressing the methane-rich gas stream to above 1,000 psia (6,895 kPa) Pressure to form a compressed gas feed stream; cooling the compressed gas feed stream to form a compressed cooled gas feed stream; expanding the cooled compressed gas feed stream to form a liquid portion and remaining A product stream of a vapor portion, wherein the gas separation unit operates in accordance with a rapid cycle pressure swing adsorption (RCPSA) process. The method of claim 33, wherein the series of adsorbent beds comprises: a first adsorbent bed for removing residual water in the dehydrated natural gas feed stream; and a second adsorbent bed Designed to primarily remove the desiccant from the dewatered natural gas feed stream; and a third adsorbent bed designed to primarily remove acid gas components from the dehydrated natural gas feed stream . The method of claim 34, wherein the first, second, and third adsorbent beds are dehydrated natural in a single pressure vessel. The flow of the gas feed stream is aligned in series. The method of claim 34, wherein the first, second and third adsorbent beds are present in separate pressure vessels, the individual pressure vessels being aligned in series with the flow of the dehydrated natural gas feed stream . The method of claim 34, wherein the adsorbent beds each comprise a bed of solid adsorbent made from a zeolitic material. The method of claim 35, wherein the adsorbent beds are each in communication with two other adsorbent beds to form three adsorbent beds, wherein: the first adsorbent bed of the three adsorbent beds is used Adsorbing the selected contaminants; regenerating the second adsorbent bed of the three adsorbent beds; and maintaining a third adsorbent bed of the three adsorbent beds to replace the three adsorbent beds An adsorbent bed; and wherein the regeneration system is part of a pressure swing adsorption process. The method of claim 34, wherein the cooling of the compressed gas feed stream comprises passing the compressed gas feed stream through a first heat exchanger for heat exchange with the cooled coolant stream, The re-cooled gas feed stream is formed; and the re-cooled gas feed stream is passed through a second heat exchanger for heat exchange with the cooling gas stream to form the compressed, cooled gas feed stream. For example, the method of claim 39, which additionally includes: Extracting a portion of the remaining vapor portion from the product stream; reducing the pressure of the withdrawn portion of the residual vapor portion to a pressure of between about 30 and 200 psia (207 to 1,379 kPa) to produce a reduced pressure gas stream; The gas stream passes through the second heat exchanger as a cooling gas stream; and the depressurized gas stream is released from the second heat exchanger to become a partially warmed gas stream. The method of claim 40, further comprising: passing the partially warmed gas stream through the first heat exchanger to form a cooling gas stream; and returning the partially warmed gas stream to the dehydrated natural gas feed The stream is compressed with the methane-rich gas stream. The method of claim 34, wherein the compressing the methane-rich gas stream comprises compressing the methane-rich gas stream to a pressure of between about 1,200 psia (8,274 kPa) and 4,500 psia (31,026 kPa). And expansion of the cooled, compressed gas feed stream comprises reducing the pressure of the cooled, compressed gas feed stream to a pressure between about 50 psia (345 kPa) and 450 psia (3,103 kPa).