Natural Gas Liquefaction Process

Abstract

A gas processing facility for the liquefaction of a natural gas feed stream is provided. The facility comprises a gas separation unit having at least one fractionation vessel. The gas separation unit employs adsorbent beds for adsorptive kinetic separation. The adsorbent beds release a methane-rich gas feed stream. The facility also includes a high-pressure expander cycle refrigeration system. The refrigeration system compresses the methane-rich gas feed stream to a pressure greater than about 1,000 psia. The refrigeration system also chills the methane-rich gas feed stream in one or more coolers, and then expands the chilled gas feed stream to form a liquefied product stream. Processes for liquefying a natural gas feed stream using AKS and a high-pressure expander cycle refrigeration system are also provided herein. Such processes allow for the formation of LNG using a facility having less weight than conventional facilities.

Description

CROSS REFERENCE TO RELATED APPLICATION

This application claims the benefit of U.S. Provisional Patent Application 61/521,657, filed Aug. 9, 2011 entitled NATURAL GAS LIQUEFACTION PROCESS, the entirety of which is incorporated by reference herein.

BACKGROUND OF THE INVENTION

This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.

FIELD OF THE INVENTION

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

DISCUSSION OF TECHNOLOGY

As the world's demand for fossil fuels increases, energy companies find themselves pursuing hydrocarbon resources located in more remote and hostile areas of the world, both onshore and offshore. This includes the pursuit of natural gas.

Because of its clean burning qualities, natural gas has become widely used in recent years. However, many sources of natural gas are located in geographical areas that are great distances from commercial markets. In some instances, a pipeline is available or may be constructed for transporting produced natural gas to a commercial market. However, when a pipeline is not available for transportation, produced natural gas is often transported via large ocean-going vessels.

To maximize gas volumes for transportation, the gas is frequently taken through a liquefaction process. The liquefied natural gas (“LNG”) is formed by chilling very light hydrocarbons, e.g., gases containing methane, to approximately −160° C. The liquefied gas may be stored at ambient pressure in special, cryogenic tanks disposed on large ships. Alternatively, LNG may be liquefied at an increased pressure and at a warmer temperature, i.e., above −160° C., in which case it is known as Pressurized LNG (“PLNG”). For purposes of the present disclosure, PLNG and LNG may be referred to collectively as “LNG.”

As currently developed, gas is taken through a liquefaction process at a location proximate the point of production. This means that a large gathering and liquefaction center is erected in the producing country. Alternatively, the liquefaction process may take place offshore on a platform or vessel, such as a floating production, storage and offloading (FPSO) vessel. Currently, large liquefaction facilities exist in Qatar, Russia (Sakhalin Island), Indonesia, and other countries. Several significant LNG terminals are either under construction in or are presently planned for Australia.

After natural gas is chilled to a liquid state, the hydrocarbon product is loaded onto marine transport vessels. Such vessels are known as LNG tankers. The chilling of natural gas into a liquefied state enables the transport of much larger volumes of gas.

In the design of an LNG plant, one of the most important considerations is the process for converting the natural gas feed stream into LNG. Currently, the most common liquefaction processes use some form of refrigeration system. Although many refrigeration cycles have been used to liquefy natural gas, there are three types of refrigeration systems most commonly used in LNG plants.

The first type of system is known as a “cascade cycle.” A cascade cycle uses multiple, single-component refrigerants in heat exchangers arranged progressively to reduce the temperature of the gas to a liquefaction temperature. The second type of refrigeration system is the “multi-component refrigeration cycle.” This system uses a multi-component refrigerant in specially designed exchangers. The third type of system is the “expander cycle.” The expander cycle system expands gas from feed gas pressure to a low pressure, producing a corresponding reduction in temperature under Boyle's Law. Most natural gas liquefaction cycles use variations or combinations of these three basic types.

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

A limitation to the use of any liquefaction system is the presence of contaminants in the natural gas stream. Raw natural gas produced from subsurface reservoirs typically contains components that are undesirable in the LNG process. Such components include water, carbon dioxide and hydrogen sulfide. Water and CO₂ should be removed because they will freeze at liquefaction temperatures and plug the liquefaction equipment. H₂S should be removed as it may have adverse safety impacts or may adversely affect the LNG product specifications. Therefore, natural gas production is typically treated before liquefaction to remove the undesirable components or contaminants.

When H₂S and CO₂ are produced as part of a hydrocarbon gas stream (such as methane or ethane), the raw gas stream is sometimes referred to as “sour gas.” The H₂S and CO₂ are often referred to together as “acid gases.” Processes have been devised to remove acid gases from a raw natural gas stream. In some instances, cryogenic gas processing is used. This involves chilling the gas stream in a large cryogenic vessel so that CO₂ and H₂S components drop out as solids. The hydrocarbon components are distilled out of the vessel. This process typically requires that the raw gas stream undergo dehydration before cryogenic separation.

As an alternative, the hydrocarbon gas stream may be treated with a solvent. Solvents may include chemical solvents such as amines. Examples of amines used in sour gas treatment include monoethanol amine (MEA), diethanol amine (DEA), and methyl diethanol amine (MDEA). Physical solvents are sometimes used in lieu of amine solvents. Examples of physical solvents include Selexol® and Rectisol™. In some instances hybrid solvents, meaning mixtures of physical and chemical solvents, have been used. An example is Sulfinol®. However, the use of amine-based acid gas removal solvents is most common. In any instance, solvent extraction is typically accomplished using a large, thick-walled counter-current contacting tower.

The solvent extraction method uses a water-based solvent to absorb the undesirable species. As a consequence, the treated gas retains water that again must be removed to avoid subsequent freezing and plugging of the liquefaction equipment.

Whether water is removed before or after acid gas separation, the water removal process is typically done in several stages to meet the extremely low water content requirement on the gas to be liquefied. A process under development is based on a glycol dehydration system for bulk water removal, followed by several molecular-sieve beds as polishing stages. Thus, several pieces of large and heavy equipment which are sensitive to motion are required for the solvent extraction step. Such equipment is unattractive for offshore applications where space and weight are a premium and wave motions are unavoidable.

In addition to water, nitrogen may also be removed from the gas stream. Nitrogen should be removed as it contains no heating value and, accordingly, adversely affects the fuel quality. Nitrogen is typically removed after both acid gas removal and liquefaction have occurred. Nitrogen is removed using a distillation column known as a nitrogen rejection unit, or NRU. The NRU is sensitive to wave motions. Further, a NRU typically involves several large and heavy items of heat exchange equipment which are not particularly suitable for offshore applications.

Other adverse impacts exist from the presence of nitrogen in a raw gas stream. For example, removing the nitrogen after, rather than before, the liquefaction step increases the liquefaction power requirement for the gas. In this respect, nitrogen increases the amount of gas that must be liquefied. Further, the presence of nitrogen lowers the liquefaction temperature of the mixture since nitrogen has a lower boiling temperature than methane.

Because of the stringent specifications for the LNG, feed pretreatment facilities are large, heavy, and costly. For example, in one floating LNG concept with nominal levels of contaminants (e.g., water saturation, 1% CO₂, 4% N₂) in the inlet gas, facilities to remove those contaminants represent approximately 20% of the total topside facilities weight. For developments with high levels of inlet gas contaminants (e.g., water saturation plus 50% to 70% CO₂ and H₂S content), the contaminant removal facilities can represent greater than 50% of topside facilities weight. Furthermore, the large vertical pressure vessels or towers that are typically used for contaminant removal may have an undesirable affect on the stability of a floating structure.

Therefore, a need exists for an improved facility for processing natural gas for liquefaction that is less sensitive to wave motions and that has little affect on the stability of a floating structure. Further, a need exists for a more compact, lightweight, and lower-horsepower LNG system that may be employed on an offshore platform. Still further, a need exists for a method of efficiently processing natural gas for liquefaction that is compatible with a high pressure expander cycle refrigeration system.

BRIEF SUMMARY OF THE INVENTION

A gas processing facility for the liquefaction of a natural gas feed stream is first provided. The facility is designed to be more compact and more efficient than conventional LNG facilities. Therefore, the facility offered herein is ideally suited for LNG facilities that are offshore or are located in remote locations. For example, the gas processing facility may be located on a floating platform or a gravity-based platform offshore.

The facility first comprises a gas separation unit having has at least one fractionation vessel. The fractionation vessel serves to separate contaminants from methane gas. To this end, each vessel has a gas inlet for receiving a natural gas mixture. Further, in one embodiment each vessel includes an adsorbent material that has a kinetic selectivity for contaminants over methane greater than 5. In this way, the contaminants become kinetically adsorbed within the adsorbent material. Further, each vessel includes a gas outlet. The gas outlet releases a methane-rich gas stream.

The vessel employs one or more adsorbent beds for adsorptive kinetic separation. The adsorbent beds release the methane-rich gas feed stream. In one aspect, a single vessel having a plurality of adsorbent beds in series is used. For example, the at least one fractionation vessel in the gas separation unit may be a vessel containing a plurality of adsorbent beds in series, such that:

a first adsorption bed is designed to primarily remove water and other liquid components from the dehydrated natural gas feed stream;

a second adsorption bed is designed to primarily remove a desiccant from the dehydrated natural gas feed stream; and

a third vessel comprises an adsorption bed primarily for the removal of a sour gas component from the dehydrated natural gas feed stream.

Additional vessels may be added to adsorb and separate nitrogen and different sour gases.

In another aspect, multiple vessels in series are employed, with each vessel releasing a progressively sweeter methane gas stream. For example,

a first vessel uses an adsorption bed designed for the removal of water remaining in a dehydrated natural gas feed stream;

a second vessel uses an adsorption bed designed for the removal of a desiccant from the dehydrated natural gas feed stream; and

a third vessel use an adsorption bed designed for the removal of a sour gas component from the dehydrated natural gas feed stream.

The sour gas component may be one or more sulfurous components. Alternatively, the sour gas component may be carbon dioxide.

The at least one fractionation vessel in the gas separation unit operates on pressure swing adsorption (PSA) or on rapid cycle pressure swing adsorption (RCPSA). The at least one fractionation vessel may further operate on temperature swing adsorption (TSA) or rapid cycle temperature swing adsorption (RCTSA). In any arrangement, the fractionation vessels are configured to adsorb CO₂, H₂S, H₂O, heavy hydrocarbons, VOC's, mercaptans, or combinations thereof.

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

The refrigeration system also chills the methane-rich gas feed stream in one or more coolers, and then expands the chilled gas feed stream to form a liquefied product stream. To this end, the system includes a first cooler configured to cool the compressed gas feed stream to form a compressed, cooled gaseous feed stream, and a first expander configured to expand the cooled, compressed, gaseous feed stream to form a product stream.

The product stream has a liquid fraction and a small remaining vapor fraction. Preferably, the gas processing facility also includes a liquid separation vessel. The separation vessel is configured to separate the liquid fraction and the remaining vapor fraction. The vapor fraction is still very cold and may be captured as a flash gas and circulated as part of a first refrigeration loop. The first refrigeration loop will have at least one heat exchanger that serves as the first cooler. The first cooler will receive the vapor fraction from the first expander, and release (i) the compressed, cooled gaseous feed stream and (ii) a partially-warmed vapor stream after heat-exchanging with the compressed gas feed stream.

The high-pressure expander cycle refrigeration system may include a separate heat exchanger that is configured to further cool the compressed gas feed stream. This is done at least partially by indirect heat exchange between a refrigerant stream (along with a portion of the vapor stream) and the compressed, methane-rich gas feed stream. The separate heat exchanger is a second cooler. The refrigeration system will then also include a second refrigeration loop having (i) a second compression unit configured to re-compress the refrigerant stream after the refrigerant stream passes through the second cooler, and (ii) a second expander configured to receive the compressed refrigerant stream from the second cooler, and expand the compressed refrigerant stream prior to returning it to the second cooler.

The second cooler may sub-cool the chilled gas feed stream after the chilled gas feed stream leaves 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 do this, the second cooler receives the partially-warmed vapor stream from the first cooler for further heat-exchanging with the compressed gas feed stream, and releases a warmed vapor product stream to a third compression unit to complete the first refrigeration loop.

In any event, the first refrigeration loop preferably cycles the vapor portion of the product back to the first compression unit. To do this, the first refrigeration loop may include a third compression unit for compressing the partially-warmed vapor stream after heat-exchanging with the compressed gas feed stream, and a line for merging the compressed, partially-warmed vapor stream with the compressed methane-rich gas feed stream. This completes the first refrigeration loop.

The gas processing facility preferably further comprises a dehydration vessel. The dehydration vessel is configured to receive the natural gas feed stream and remove a substantial portion of water from the natural gas feed stream. The dehydration unit then releases a dehydrated natural gas feed stream to the gas separation unit.

A process for liquefying a natural gas feed stream is also provided herein. The process employs adsorptive kinetic separation to produce a methane-rich gas stream. The process then further utilizes a high-pressure expander cycle refrigeration system to chill the methane and to provide an LNG product. The LNG product is preferably generated on a floating platform or a gravity-based platform offshore.

The process first includes receiving 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 fraction vessel described above in its various embodiments. The fractionation vessels preferably operate on pressure swing adsorption (PSA) or rapid cycle pressure swing adsorption (RCPSA) to regenerate a series of adsorption beds. The adsorption beds are designed to adsorb CO₂, H₂S, H₂O, heavy hydrocarbons, VOC's, mercaptans, nitrogen, or combinations thereof.

The process also includes substantially separating methane from contaminants within the natural gas feed stream. This is done through the use of adsorption beds in the one or more fractionation vessels. As a result, the process also includes releasing a methane-rich gas stream from the gas separation unit. In one aspect, separating methane from contaminants is conducted through the gas separation unit at a pressure of at least about 500 pounds per square inch absolute (psia).

The process next comprises directing 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 above in its various embodiments. Thus, the refrigeration system preferably includes a first refrigeration loop for cycling the vapor portion of the product for use as a coolant in a first cooler, and a second refrigeration loop for cycling a nitrogen-containing gas as a refrigerant in a second cooler.

The process also includes compressing the methane-rich gas stream. The gas stream is compressed to a pressure that is greater than about 1,000 psia (6,895 kPa) in order to form a compressed gas feed stream. The process then comprises cooling the compressed gas feed stream through the second and first coolers to form a compressed, cooled gaseous feed stream.

The process also includes expanding the cooled, compressed, gaseous feed stream. This forms the LNG product stream having a liquid fraction and a remaining vapor fraction.

The high-pressure expander cycle refrigeration system preferably includes a liquid separation vessel. The process then further comprises separating the liquid fraction and the remaining vapor fraction.

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

The method first includes receiving the natural gas feed stream at a gas processing facility. The gas processing facility will include a dehydration vessel. The method then includes passing the natural gas feed stream through a dehydration vessel. This serves to remove a substantial portion of water from the natural gas feed stream. A dehydrated natural gas feed stream is then released to a 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 fraction vessel described above in its various embodiments. The fractionation vessels preferably operate on pressure swing adsorption (PSA) or rapid cycle pressure swing adsorption (RCPSA) to regenerate a series of adsorption beds.

The method next comprises passing the dehydrated natural gas feed stream through the series of adsorbent beds. This serves to separate methane gas from contaminants in the dehydrated natural gas feed stream. The beds use adsorptive kinetic separation. The adsorption beds are designed to adsorb CO₂, H₂S, H₂O, heavy hydrocarbons, VOC's, 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, multiple vessels in series are employed, with the vessels being aligned in series with the flow of the dehydrated natural gas feed stream. Each vessel releases a progressively sweeter methane gas stream.

As a result of passing the dehydrated natural gas feed stream through the adsorbent beds, a methane-rich gas stream is produced. The method comprises releasing the methane-rich gas stream from the gas separation unit. The methane-rich gas stream is then directed into a high-pressure expander cycle refrigeration system.

The refrigeration system is generally designed in accordance with the refrigeration system described above in its various embodiments. Thus, the refrigeration system preferably includes a first refrigeration loop for cycling the vapor portion of the product for use as a coolant in a first cooler, and a second refrigeration loop for cycling a nitrogen-containing gas as a refrigerant in a second cooler.

The method also includes compressing the methane-rich gas stream. The gas stream is compressed to a pressure that is greater than about 1,000 psia (6,895 kPa) in order to form a compressed gas feed stream. The process then comprises cooling the compressed gas feed stream to form a compressed, cooled gaseous feed stream.

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

BRIEF DESCRIPTION OF THE DRAWINGS

So that the present inventions can be better understood, certain illustrations, charts and/or flow charts are appended hereto. It is to be noted, however, that the drawings illustrate only selected embodiments of the inventions and are therefore not to be considered limiting of scope, for the inventions may admit to other equally effective embodiments and applications.

FIG. 1 is a schematic flow diagram of a facility for producing LNG, in accordance with one embodiment herein. The facility includes a gas separation unit that produces a methane-rich gas stream, and a high-pressure expander cycle refrigeration system for generating an LNG product.

FIG. 2 is a perspective view of a pressure swing adsorption vessel as may be used in the facility of FIG. 1, in one embodiment. The vessel also represents a kinetic fractionator of the present inventions, in one embodiment.

FIG. 3A is a perspective view of the adsorbent bed and flow channels for the pressure swing adsorption vessel of FIG. 2, in one embodiment. Major flow channels are seen between adsorbent rods along a major axis of the adsorbent bed.

FIG. 3B provides an exploded view of the adsorbent bed of FIG. 3A. FIG. 3B provides an exposed view of the optional second gas outlet. A transverse flow channel is shown extending into the vessel, serving as a minor flow channel.

FIG. 3C is a longitudinal, cross-sectional view of the adsorbent bed of FIG. 3A, in an alternate embodiment. The view is taken across line C-C of FIG. 3A. Here, a series of stepped surfaces are seen along the adsorbent rods, which serve as minor flow channels.

FIG. 4 is a perspective view of the adsorbent bed and flow channels for the pressure swing adsorption vessel of FIG. 2, in a modified arrangement. Major flow channels are seen between adsorbent rods along a major axis of the adsorbent bed. Transverse flow channels are seen in exploded-away portions of the adsorbent bed, which serve as minor flow channels.

FIG. 5 is a schematic flow diagram of a high-pressure expander cycle refrigeration system, in one embodiment. The refrigeration system receives a methane-rich gas stream, and generates an LNG product. The illustrative refrigeration system employs a secondary cooling loop that is a closed loop using nitrogen gas, or a nitrogen-rich gas, or a portion of the methane-rich gas stream from the gas separation unit.

FIG. 6 is a flow chart showing steps for liquefying a raw natural gas stream.

FIG. 7 is a flowchart showing steps for separating contaminants from the raw natural gas stream using adsorptive kinetic separation.

DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS

Definitions

As used herein, the term “hydrocarbon” refers to an organic compound that includes primarily, if not exclusively, the elements hydrogen and carbon. Hydrocarbons generally fall into two classes: aliphatic, or straight chain hydrocarbons, and cyclic, or closed ring 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 into a fuel.

As used herein, the term “fluid” refers to gases, liquids, and combinations of gases and liquids, as well as to combinations of gases and solids, and combinations of liquids and solids.

As used herein, the term “hydrocarbon fluids” refers to a hydrocarbon or mixtures of hydrocarbons that are gases or liquids. For example, hydrocarbon fluids may include a hydrocarbon or mixtures of hydrocarbons that are gases or liquids at formation conditions, at processing conditions, or at ambient conditions (15° C. and 1 atm pressure). Hydrocarbon fluids may include, for example, oil, natural gas, coal bed methane, shale oil, pyrolysis oil, pyrolysis gas, a pyrolysis product of coal, and other hydrocarbons that are in a gaseous or liquid state.

As used herein, an “acid gas” means any gas that dissolves in water producing an acidic solution. Non-limiting examples of acid gases include hydrogen sulfide (H₂S), carbon dioxide (CO₂), sulfur dioxide (SO₂), carbon disulfide (CS₂), carbonyl sulfide (COS), mercaptans, or mixtures thereof.

As used herein, the term “subsurface” refers to geologic strata occurring below the earth's surface.

The term “seabed” refers to the floor of a marine environment. The marine environment may be an ocean or sea or any other body of water that experiences waves, winds, and/or currents.

The term “marine environment” refers to any offshore location. The offshore location may be in shallow waters or in deep waters. The marine environment may be an ocean body, a bay, a large lake, an estuary, a sea, or a channel.

The term “about” is intended to allow some leeway in mathematical exactness to account for tolerances that are acceptable in the trade. Accordingly, any small deviations upward or downward from the value modified by the term “about” should be considered to be explicitly within the scope of the stated value.

The term “swing adsorption process” includes processes such as pressure swing adsorption (PSA), thermal swing adsorption (TSA), and partial pressure swing or displacement purge adsorption (PPSA), including combinations of these processes. These swing adsorption processes can be conducted with rapid cycles, in which case they are referred to as rapid cycle pressure swing adsorption (RCPSA), rapid cycle thermal swing adsorption (RCTSA), and rapid cycle partial pressure swing or displacement purge adsorption (RCPPSA). The term swing adsorption also includes these rapid cycle processes.

As used herein, the term “pressure swing adsorption” shall be taken to include all of the processes, i.e., PSA, PPSA, RCPSA, and RCPPSA, including combinations of these processes, that employ a change in pressure for a purge cycle.

As used herein, the term “wellbore” refers to a hole in the subsurface made by drilling or insertion of a conduit into the subsurface. A wellbore may have a substantially circular cross section, or other cross-sectional shapes. As used herein, the term “well,” when referring to an opening in the formation, may be used interchangeably with the term “wellbore.”

The term “platform” means any platform or surface dimensioned and configured to receive fluid processing equipment.

DESCRIPTION OF SPECIFIC EMBODIMENTS

FIG. 1 is a schematic diagram of a gas processing facility 100 for producing LNG in accordance with one embodiment herein. The “LNG” is natural gas that has been liquefied through a cooling process. The gas processing facility 100 operates to receive raw natural gas, remove certain undesirable components in order to produce a “sweetened” gas stream that meets established specifications, and then chill the sweetened (“methane-rich”) gas stream into a substantially liquid phase for ready transport.

In the illustrative arrangement of FIG. 1, the facility 100 receives production fluids from a reservoir. A reservoir is shown schematically at 110. The reservoir 110 represents a subsurface formation that contains hydrocarbon fluids in commercially acceptable quantities. The hydrocarbon fluids exist in situ in primarily a gaseous phase.

The production fluids are produced through a plurality of wellbores. A single illustrative wellbore 112 is indicated in FIG. 1. However, it is understood that numerous wellbores 112 will be drilled through the earth surface and into the subsurface reservoir 110. The present inventions are not limited by the number of wellbores or the manner in which wellbore completions are made.

The wellbore 112 transports hydrocarbon fluids from the reservoir 110 and to an earth surface 115. The earth surface 115 may be on land. More preferably for the present inventions, the earth surface 115 is a seabed. In this latter instance, wellheads (not shown) are placed along the bottom of a marine environment. Subsea jumpers and/or flowlines will direct production fluids to a manifold (not shown), which then delivers fluids to an ocean surface via one or more production risers.

In FIG. 1, line 112′ is shown transporting hydrocarbon fluids. Line 112′ may be a flow line on land. More preferably, line 112′ is representative of a production riser within a marine environment. In either instance, the production fluids are delivered to a separator 120.

Upon arrival at the separator 120, the production fluids represent a raw natural gas mixture. The production fluids contain methane, or natural gas. The production fluids may also contain so-called “heavy hydrocarbons,” representing ethane and, possibly, propane. Most likely, the production fluids will also contain water (or brine), along with nitrogen. Also, the production fluids may contain hydrogen sulfide, carbon dioxide, and other so-called “sour gas” components. Finally, the production fluids may contain benzene, toluene, or other organic compounds.

The separator 120 provides a general separation of liquids from gases. This is typically done at production pressure. The separator 120 may be a gravity separator having thick steel walls. The separator 120 serves to filter out impurities such as brine and drilling fluids. It may also remove at least a portion of any condensed hydrocarbons. Some particle filtration may also take place.

More preferably, the separator 120 serves as a dehydration vessel. The dehydration vessel uses a desiccant such as ethylene glycol in order to absorb water and release gas-phase fluids. Liquids are released from the bottom of the separator 120, while gases are released at the top.

In FIG. 1, line 121 represents a liquid line. The fluids in line 121 are primarily water, with possibly some heavy hydrocarbons. The heavy hydrocarbons in line 121 will be a small amount of ethane and, perhaps, a bit of propane and butane. Additional separation may take place through gravity separation, heat treatment, or other means known in the art to capture the valuable liquid hydrocarbons.

Line 122 represents a gas line. The fluids in line 122 are primarily methane, with some ethane and other “heavy hydrocarbons” as well. In addition, the fluids in line 122 will have contaminants. These may include “sour” components such as hydrogen sulfide and carbon dioxide. These may also include water in vapor form. Further, the contaminants may include nitrogen. Certain metal contaminants may be suspended in the vapor, such as arsenic, cobalt, molybdenum, mercury, or nickel. Finally, trace organic compounds such as benzene, toluene, or xylene, may be present.

It is desirable to separate the various components so that a fluid stream comprising substantially methane is produced. For international sales, LNG specifications may require that natural gas have the following content:

TABLE 1
Pretreatment LNG Specifications
Component Feed Specification
CO2       <50 ppmv
H2O       <0.5 ppmv
H2S       <3.5 ppm
Total S   <20 mg/Nm3
Hg        <μg/Nm3
C5+       <0.1 mol. %
C6H6      <1 ppmv

In order to achieve the LNG specifications of Table 1, gas treatment must take place. In FIG. 1, a gas separation unit 130 is schematically shown. The gas separation unit 130 may also be referred to as a Selective Component Removal System, or “SCRS.” The gas separation unit 130 utilizes a series of adsorbent beds using Adsorptive Kinetic Separation, or “AKS.”

AKS is a process that employs a relatively new class of solid adsorbents that rely upon the rate at which certain species are adsorbed onto a structured material relative to other species. The structured material is sometimes referred to as an absorbent bed. Adsorbent beds operate on the principle that different molecules can have different affinities for adsorption. This provides a mechanism for the adsorbent to discriminate between different gasses and, therefore, to provide separation.

In order to effectuate the separation, adsorbent beds employ a highly porous microstructure. Selected gas molecules become attached to the surface area provided along the pores. The gas adsorbed onto the interior surfaces of the micro-porous material may consist of a layer only a few molecules in thickness. The micro-porous material may have also surface areas of several hundred square meters per gram. Such specifications enable the adsorption of a significant portion of the adsorbent's weight in gas.

Different types of adsorbent beds are known. Typical adsorbents include activated carbons, silica gels, aluminas, and zeolites. In some cases, a polymeric material can be used as the adsorbent material. In any instance, the adsorbent bed preferentially adsorbs a more readily adsorbed component (known as the “heavy” gas) relative to a less readily adsorbed component (known as the “light” gas) of the gas mixture.

In addition to their affinity for different gases, zeolites and some types of activated carbons, called carbon molecular sieves, may utilize their molecular sieve characteristics to exclude or slow the diffusion of some gas molecules into their structure. This provides a mechanism for selective adsorption based on the size of the molecules. In this instance, the adsorbent bed restricts the ability of larger molecules to be adsorbed, thus allowing the gas to selectively fill the micro-porous structure of an adsorbent material with one or more species from a multi-component gas mixture.

Different adsorption techniques for gas separation are known. One adsorption technique is pressure swing adsorption, or “PSA.” PSA processes rely on the fact that, under pressure, gaseous contaminants tend to be adsorbed within the pore structure of an adsorbent material, or within the free volume of a polymeric material, to different extents. The higher the pressure in the adsorption vessel, the more gas is adsorbed. In the case of natural gas, the natural gas mixture may be passed under pressure through an adsorption vessel. The pores of the polymeric or micro-porous adsorbent become filled with hydrogen sulfide and carbon dioxide to a greater extent than with methane. Thus, most or even all of the H₂S and CO₂ will stay in the sorbent bed, while the gas coming out of the vessel will be enriched in methane. Any remaining water and possibly some heavy hydrocarbons will also be retained as adsorbents. In addition, any benzene, toluene, or other volatile organic compounds will be retained as adsorbents.

The pressure swing adsorption system may be a rapid cycle pressure swing adsorption system. In the so-called “rapid cycle” processes, cycle times can be as small as a few seconds. A rapid cycle PSA (“RCPSA”) unit can be particularly advantageous, as such a unit is compact relative to normal PSA devices. Further, RCPSA contactors can enable a significant increase in process intensification (e.g., higher operating frequencies and gas flow velocities) when compared to conventional PSA.

When the adsorbent bed reaches the end of its capacity to adsorb contaminants, it can be regenerated by reducing the pressure. This causes the vessel to release the adsorbed components. A concentrated contaminant stream is thus released separate from the methane gas stream. In this way, the adsorption bed may be regenerated for subsequent re-use.

In most PSA cases, reducing the pressure in the pressurized chamber down to ambient pressure will cause a majority of the hydrogen sulfide and other contaminants to be released from the adsorbent bed. In some cases, the pressure swing adsorption system may be aided by the use of a vacuum chamber to apply sub-ambient pressure to the concentrated contaminant stream. In the presence of lower pressure, sulfurous components, carbon dioxide, and heavy hydrocarbons will more completely desorb from the solid matrix making up the adsorbent bed.

A related gas separation technique is temperature swing adsorption, or “TSA.” TSA processes also rely on the fact that, under pressure, gases tend to be adsorbed within the pore structure of micro-porous adsorbent materials or within the free volume of a polymeric material, to different extents. When the temperature of the adsorbent bed in the vessel is increased, the adsorbed gas molecules are released, or de-sorbed. This is done in a regeneration heater that employs a heated dry gas. The dry gas comprises primarily methane, but may also include nitrogen and helium. By cyclically swinging the temperature of adsorbent beds within a vessel, TSA processes can be used to separate gases in a mixture.

When a TSA process is used, a set of valves may be provided to pulse the flow of heating or cooling fluids that enter and leave the vessel. An electric heating or cooling jacket may also be used to produce temperature swings. Optionally, the swing adsorption unit uses a partial pressure purge displacement process. In this case, a valve or set of valves is provided to pulse the flow of the purge displacement stream into the adsorption bed. The adsorption bed is contained within a pressure vessel. Optionally, this vessel and the associated valving is contained within a secondary pressure vessel. This secondary pressure vessel is designed to mitigate the significance of leaks through seals in the valves inside the swing adsorption unit. This can be especially important when rotary valves are used.

A combination of pressure swing regeneration and thermal swing regeneration may be employed. In either instance, the gas treating facility 130 employs a series of absorbent beds, each designed to retain one or more components while releasing the remainder of the gas stream.

The adsorptive material or “bed” is maintained in a pressure vessel. FIG. 2 provides a perspective view of an illustrative pressure swing adsorption vessel 200. The vessel 200 operates for the purpose of receiving a natural gas mixture, and separating the mixture into at least two components.

The vessel 200 defines an elongated, pressure-containing body. The vessel 200 includes a housing 205. Preferably, the housing 205 is fabricated from iron or steel. In the arrangement of FIG. 2, the vessel 200 rests along a surface 201 in a substantially horizontal orientation. However, the vessel 200 may alternatively be operated in a vertical orientation. In either instance, the vessel 200 may include various supporting legs or pads 215.

The vessel 200 is able to operate at high pressures so as to accommodate the inlet pressures experienced with the processing of natural gas. For example, such inlet pressures may exceed 200 psig, and more frequently may be greater than about 1,000 psig. This allows the vessel 200 to operate at or close to reservoir pressure. To monitor internal pressure, the vessel 200 includes gauges or other pressure-monitoring devices. A representative gauge is shown at 250 in FIG. 2. Of course, it is understood that modern pressure-monitoring devices operate primarily as digital systems that interact with valves, clocks, and operational control software.

The vessel 200 has a first end shown at 202, and a second end shown at 204. A gas inlet 210 is provided at the first end 202, while a first gas outlet 230 is provided at the second end 204. Optionally, a second gas outlet 220 is provided intermediate the first end 202 and the second end 204, or intermediate the gas inlet 210 and the first gas outlet 230.

In operation, the vessel 200 serves 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. Arrow “I” indicates the flow of fluid into the vessel 200. The natural gas is contacted within the vessel 200 by an adsorbent bed (not shown in FIG. 2). The adsorbent bed uses kinetic adsorption to capture contaminants. At the same time, the adsorbent bed releases a methane-rich gas stream through the first gas outlet 230. Flow of the methane-rich gas stream from the vessel 200 is indicated at arrow O₁.

It is understood that the vessel 200 is part of the larger gas separation unit 130. The gas separation unit 130 includes valving, vessels, and gauges as needed to carry out regeneration of the adsorbent bed within the vessel 200 and the capture of the separated gas components. Further, where rapid cycle PSA is employed, the vessel will include rotary valving with a rotating manifold for rapidly cycling a natural gas mixture. In this respect, rapid cycle pressure swing adsorption (RCPSA) vessels can be constructed with a rotary valving system to facilitate the flow of gas through a rotary adsorber module that contains a number of separate adsorbent bed compartments or “tubes,” each of which is successively cycled through the sorption and desorption steps as the rotary module completes the cycles of operation.

A rotary adsorber module is normally comprised of multiple tubes held between two seal plates on either end of the rotary adsorber module wherein the seal plates are in contact with a stator comprised of separate manifolds. The inlet gas is conducted to the RCPSA tubes and the processed purified product gas and the tail retentate gas exiting the RCPSA tubes are conducted away from the rotary adsorber module. By suitable arrangement of the seal plates and manifolds, a number of individual compartments or tubes may pass through the characteristic steps of the complete cycle at any given time. In contrast, with conventional PSA, the flow and pressure variations, required for the RCPSA sorption/desorption cycle, changes in a number of separate increments on the order of seconds per cycle, which smoothes out the pressure and flow rate pulsations encountered by the compression and valving machinery. In this form, the RCPSA module includes valving elements angularly spaced around the circular path taken by the rotating sorption module so that each compartment is successively passed to a gas flow path in the appropriate direction and pressure to achieve one of the incremental pressure/flow direction steps in the complete RCPSA cycle.

In any arrangement, the vessel 200 utilizes an adsorbent bed to capture contaminants on the surface of a micro-porous adsorbent material and along the pore spaces therein. FIG. 3A is a perspective view of an adsorbent bed 300, in one embodiment. Here, the illustrative adsorbent bed 300 has an annular adsorbent ring 305. The adsorbent ring 305 is dimensioned to fit along an inner diameter of the housing 205 of the vessel 200.

Within the adsorbent ring 305 is a plurality of adsorbent rods 315. The adsorbent rods 315 run substantially along the length of the adsorbent bed 300. This means that the rods 315 run essentially from the first end 302 to the second end 304 of the vessel 300. The adsorbent ring 305 and the adsorbent rods 315 are fabricated from a material that preferentially adsorbs an undesirable gas. The undesirable gas may be water vapor, CO₂, H₂S, mercaptans, heavy hydrocarbons in gaseous phase, or combinations thereof.

The adsorbent material is preferably selected from the 8-ring zeolites having a Si:Al ratio 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. The term “Si:Al ratio” as used herein means the molar ratio of silica to alumina of the zeolite structure. The more preferred 8-ring zeolites for the capture of sour gas include DDR, Sigma-1 and ZSM-58. Zeolite materials having appropriate pore sizes for the removal of heavy hydrocarbons include MFI, faujasite, MCM-41, and Beta. It is preferred that the Si:Al ratio of zeolites utilized for heavy hydrocarbon removal be from about 20:1 to about 1,000:1, and preferably from about 200:1 to about 1,000:1 in order to prevent excessive fouling of the adsorbent.

The zeolite may be present in the adsorbent ring 305 and the adsorbent rods 315 in any suitable form. For example, zeolite material may be in the form of beads that are packed to form the adsorbent material. Adsorbent beads, or aggregates, for swing adsorption processes are known in the art and can be of any suitable shape, including spherical or irregular. Adsorbent aggregates may be formed by adhering micro-porous zeolite crystals together with binder materials. The micro-pores exist due to the crystalline structure of the zeolite, in this case, preferably 8-ring zeolites. The binder material is typically a dense material that does not have adsorptive properties, but which is used to bind the zeolite crystals. In order to function effectively, the size of binder particles must be smaller than the size of the individual zeolite crystals.

In one embodiment of the adsorbent bed 300, a magnetic material may be incorporated into the adsorbent rods 315. For example, each rod 315 may have an inner bore, and a magnetic material may be placed along the inner bore. The rods 315 may then be subjected to a magnetic or an electromagnetic field during packing. The magnetic field causes the rods 315 to repel one another, thereby assuring uniform spacing between the rods 315. Uniform packing of rods 315 is particularly important for kinetic and fast cycled adsorption processes so that gas components are not preferentially driven through one flow channel 310 over another. Application of the magnetic field may further provide for a homogeneous orientation of the zeolite material. Optionally, the magnetic field may be applied during the cycles themselves.

Referring again to FIG. 3, within the annular adsorbent ring 305 and between the adsorbent rods 315 is a plurality of flow channels. The flow channels are seen at 310. The flow channels 310 define major flow channels that flow along a major axis of the adsorbent bed 300.

The flow channels 310 create a type of structured adsorbent contactor referred to as a “parallel channel contactor.” Parallel channel contactors are a subset of adsorbent contactors comprising structured (engineered) adsorbents in which substantially parallel flow channels are incorporated into the adsorbent structure. The flow channels 310 may be formed by a variety of means, some of which are described in U.S. Pat. Publ. No. 2008/0282887 titled “Removal of CO₂, N₂, and H₂S from Gas Mixtures Containing Same,” incorporated herein by reference.

The adsorbent 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 single component diffusion coefficients, D (in m²/sec), for two different species. The single component diffusion coefficients are also known as the Stefan-Maxwell transport diffusion coefficients that are measured for a given adsorbent for a given pure gas component. Therefore, for example, the kinetic selectivity for a particular adsorbent for a component A with respect to a component B would be equal to D_A/D_B.

The single component diffusion coefficients for a material can be determined by tests known in the adsorptive materials art. The preferred way to measure the kinetic diffusion coefficient is with a frequency response technique described by Reyes, et al. in “Frequency Modulation Methods for Diffusion and Adsorption Measurements in Porous Solids,” J. Phys. Chem. B. 101, pages 614-622 (1997), which is incorporated herein by reference. In the kinetically controlled separation for the vessel 200, it is preferred that kinetic selectivity (i.e., D_A/D_B) of the selected adsorbent for the first component (e.g., CO₂) with respect to the second component (e.g., methane) be greater than 5.

The term “selectivity” as used herein is based on a binary comparison of the molar concentration of components in the feed stream and the total number of moles of these components adsorbed by the particular adsorbent during the adsorption step of the process cycle under the specific system operating conditions and feed stream composition. For a feed gas stream containing a component A, a component B, and optionally additional components, an adsorbent that has a greater “selectivity” for component A than component B will have at the end of the adsorption step of the swing adsorption process cycle a ratio:

U_A=(total moles of A in the adsorbent)/(molar concentration of A in the feed)

that is greater than the ratio:

U_B=(total moles of B in the adsorbent)/(molar concentration of B in the feed)

where: U_A is the “Adsorption Uptake of component A,” and

U_B is the “Adsorption Uptake of component B.”

Therefore, for an adsorbent having a selectivity for component A over component B that is greater than one:

Selectivity=U_A/U_B (where U_A>U_B).

Amongst a comparison of different components in a natural gas feed stream, the component with the smallest ratio of the total moles picked up in the adsorbent to its molar concentration in the feed stream is the lightest component in the swing adsorption process. The light component is taken to be the species, or molecular component, that is not preferentially taken up by the adsorbent in the adsorption process. This means that the molar concentration of the lightest component in the stream coming out during the adsorption step is greater than the molar concentration of that lightest component in the feed stream. In the present disclosure, the adsorbent contactor 200 has a selectivity for a first component (e.g., CO₂) over a second component (e.g., methane) of at least 5, more preferably a selectivity for a first component over a second component of at least 10, and most preferably a selectivity for a first component over a second component of at least 25.

Note that it is possible to remove two or more contaminants simultaneously; however, for convenience the component or components that are to be removed by selective adsorption may be referred to herein as a single contaminant or a heavy component.

Recovery of the light component may also be characterized by relative flow rate. Thus, recovery of methane may be defined as the time averaged molar flow rate of the methane in the product stream (shown at O₁ in the first outlet 230) divided by the time averaged molar flow rate of the methane in the feed stream (depicted as gas inlet 210). Similarly, recovery of the carbon dioxide and other heavy components is defined as the time averaged molar flow rate of the heavy components in the contaminant stream (shown at O₂ in the second gas outlet 220) divided by the time averaged molar flow rate of the heavy component in the feed stream (depicted as gas inlet 210).

Additional technical information concerning component diffusion coefficients and kinetic selectivity is provided in co-owned U.S. Pat. Publ. No. 2008/0282887, referenced above.

In order to enhance the efficiency of the gas separation process, minor flow channels may also be provided in the bed 300. The minor flow channels increase the surface area exposure of the adsorbent material along the rods 315.

FIG. 3B provides an exploded view of the adsorbent bed 300 of FIG. 3A. The adsorbent bed 300 is cut across the optional second gas outlet 220. The major flow channels 310 running through the adsorbent bed 300 are again seen. In addition, a transverse flow channel is seen at 320. The transverse flow channel 320 serves as a minor flow channel. The flow channel 320 is seen partially extending into the adsorbent bed 300. However, the transverse flow channel 320 may optionally extend most of the way around the circumference of the annular adsorbent ring 305.

In the arrangement of FIG. 3B, only a single minor flow channel 320 is shown. However, the adsorbent bed 300 may have a plurality of minor flow channels 320. These may optionally be manifolded together with flow converging on the second gas outlet 220.

FIG. 3C is a longitudinal, cross-sectional view of the adsorbent bed 300 of FIG. 3A. The view is cut through line C-C of FIG. 3A. Longitudinal adsorbent rods 315 are seen in FIG. 3C. In addition, major flow channels 310 are visible between the rods 315.

A series of stepped surfaces 325 are seen along the adsorbent rods 315. The stepped surfaces 325 also serve as minor flow channels. In lieu of stepped surfaces 325, the surfaces 325 may be helical or spiraled surfaces. In any arrangement, the stepped surfaces 325 may be used in addition to or in lieu of the transverse channel 320 to increase surface area and improve kinetic selectivity without need of large and expensive heat transfer units.

The major 310 and minor 320, 325 flow channels provide paths in the fractionator 300 through which gas may flow. Generally, the flow channels 310, 320, 325 provide for relatively low fluid resistance coupled with relatively high surface area. Flow channel length should be sufficient to provide the desired mass transfer zone, which is, at least, a function of the fluid velocity and the ratio of surface area to channel volume.

The flow channels 310, 320, 325 are preferably configured to minimize pressure drop in the vessel 200. Thus, tortuous flow paths are minimized or avoided. If too much pressure drop occurs across the bed 300, then higher cycle frequencies, such as on the order of greater than 100 cpm, are not readily achieved. In addition, and as noted above, it is preferred that the rods 315 be equidistantly spaced so as to create a degree of channel uniformity.

In one aspect, the flow channels 310 are generally divided so that there is little or no cross-flow. In this instance, a fluid flow fraction entering a channel 310 at the first end 302 of the fractionator 200 does not significantly communicate with any other fluid fraction entering another channel 310 at the first end 302 until the fractions recombine upon exiting at the second end 304. In this arrangement, the volumes of the major flow channels 310 will be substantially equal to ensure that all of the channels 310 are being fully utilized, and that the mass transfer zone defined by the interior volume of the vessel 200 is substantially equally contained.

The dimensions of the flow channels 310 can be computed from considerations of pressure drop along the contactor vessel 200. It is preferred that the flow channels 310 have a channel gap from about 5 to about 1,000 microns, preferably from about 50 to about 250 microns. As utilized herein, the “channel gap” of a flow channel 310 is defined as the length of a line across the minimum dimension of the flow channel 310 as viewed orthogonal to the flow path. For instance, if the flow channel 310 is circular in cross-section, then the channel gap is the internal diameter of the circle. However, if the channel gap is rectangular in cross-section, the flow gap is the distance of a line bisecting the flow gap from corner to corner.

It should be noted that the major flow channels 310 can be of any cross-sectional configuration or geometric profile. In FIGS. 3A and 3B, the major flow channels 310 are star-shaped. Regardless of the shape, it is preferred that the ratio of the volume of adsorbent material to the flow channel volume in the adsorbent contactor 200 be 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 with RCPSA applications, the flow channels are formed when adsorbent sheets are laminated together. The flow channels within the sheets will contain a spacer or mesh that acts as a spacer. However, the spacers take up much-needed space so the use of laminated sheets is not preferred.

In lieu of laminated sheets, a plurality of small, transverse minor flow channels may be machined through the adsorbent rods. FIG. 4 provides a perspective view of an adsorbent bed 400 for the pressure swing adsorption vessel of FIG. 2, in a modified arrangement. The adsorbent bed 400 has an outer surface 405. The outer surface 405 is dimensioned to fit along an inner diameter of the housing 205 of the vessel 200 of FIG. 2.

Major flow channels 410 are provided within a monolithic adsorbent material 415. The major flow channels 410 are formed along a major axis of the adsorbent bed 400. However, to further increase surface area along the adsorbent rods, small transverse channels 420 are formed through the monolithic material 415. These channels serve as minor flow channels 420.

The minor flow channels 420 may be very small tubular channels, having a diameter of less than about 25 microns, for example. The minor flow channels 420 are not so large as to completely sever an adsorbent rod 415. In this way, the need for supporting spacers is avoided.

The optional minor flow channels 420 facilitate pressure balancing between the major flow channels 410. Both productivity and gas purity may suffer if there is excessive channel inconsistency. In this respect, if one flow channel is larger than an adjacent flow channel or receives more gas stream than another, premature product break-through may occur. This, in turn, leads to a reduction in the purity of the product gas to unacceptable purity levels. Moreover, devices operating at cycle frequencies greater than about 50 cycles per minute (cpm) require greater flow channel uniformity and less pressure drop than those operating at lower cycles per minute.

Returning now to FIGS. 2 and 3, the vessel 200 in FIG. 2 is shown as a cylinder, and the adsorbent rods 315 therein are shown as tubular members. However, other shapes may be employed that are suitable for use in swing adsorption process equipment. Non-limiting examples of vessel arrangements include various shaped monoliths having a plurality of substantially parallel channels extending from one end of the monolith to the other; a plurality of tubular members; stacked layers of adsorbent sheets with spacers between each sheet; multi-layered spiral rolls or bundles of hollow fibers, as well as bundles of substantially parallel solid fibers.

In addition, other embodiments for a parallel channel contactor may be employed. Such embodiments include the contactors shown in and described in connection with FIGS. 1 through 9 of U.S. Pat. Publ. No. 2008/0282887. This publication is again incorporated herein in its entirety by reference.

Returning to FIG. 1, four illustrative separation stages are shown. These are stage 132′/132″, stage 134, stage 136, and stage 138. Each stage represents an adsorbent bed, with the stages 132/132″, 134, 136, 138 being placed in series. The adsorbent beds preferably each reside within their own pressure vessel, such as vessel 200 of FIG. 2. However, it is within the scope of the present application for at least some of the beds to reside within the same pressure vessel while remaining in series.

First, stage 132′ represents the removal of water vapor from the gas in line 122. Thus, a first adsorbent bed is provided at stage 132′ wherein the adsorbent material is designed to adsorb water vapor. Once the adsorbent material is saturated, the bed in stage 132′ is de-sorbed and water vapor is released through line 131′. Optionally, the water vapor is merged with the liquids line 121 from the separator 120, as indicated at line 125.

The liquids in line 125 will be predominantly water. These liquids may be reinjected into the reservoir as part of a water flooding operation. Alternatively, the water may be treated and disposed of in a surrounding marine environment. Alternatively still, the water may be treated and taken through a desalinization process for use in irrigation or industrial use on-shore. Alternatively still, and as noted above, the liquids in line 125 may undergo further separation to capture any hydrocarbons.

It is preferred that the first stage 132′ simply be a “polishing” stage. This means that most water has already been removed or “knocked out” by a previous dehydration vessel (such as vessel 120, and the adsorbent bed in stage 132′ is simply removing remaining water vapor.

Where a dehydration vessel is used, the fluids in line 122 will include a desiccant such as ethylene glycol. Therefore, an ancillary first stage 132″ is provided for desiccant removal. In FIG. 1, desiccant is removed from the gas separation unit 130 through a separate adsorption bed. Once the bed has become saturated, the desiccant is released through line 131″. The desiccant may be recycled for use in the dehydration vessel 120.

FIG. 1 also shows a second stage of contaminant removal at 134. The illustrative second stage 134 is for the removal of heavy hydrocarbons. As noted, heavy hydrocarbons will primarily include any ethane from the original gas stream. Some propane and butane may also be adsorbed. The heavy hydrocarbons are adsorbed onto the adsorbent bed, while sour gas and lighter hydrocarbons are released.

It is possible that if the heavy hydrocarbon composition is very small, such components will be adsorbed in the first 132′/132″ removal stage. This is also dependent on the composition of the adsorbent beds in the first 132′/132″ removal stage. However, if the heavy hydrocarbon content is large, such as greater than 3 to 5 percent, then a separate, dedicated adsorption stage 134 is desirable. Upon saturation, heavy hydrocarbons are released through line 133.

It is preferred that the adsorbent bed in stage 134 be a zeolite material. Non-limiting examples of zeolites having appropriate pore sizes for the removal of heavy hydrocarbons include MFI, faujasite, MCM-41 and Beta. It is preferred that the Si/Al ratio of zeolites utilized in an embodiment of a process of the present invention for heavy hydrocarbon removal be from about 20 to about 1,000, preferably from about 200 to about 1,000 in order to prevent excessive fouling of the adsorbent.

Molecular sieve beds fabricated from zeolite may be most effective at removing C₂ to C₄ components, while silica gel beds may be most effective at removing C₅+ heavy hydrocarbons. Additional technical information about the use of adsorptive kinetic separation for the separation of hydrocarbon gas components is provided in U.S. Pat. Publ. No. 2008/0282884 entitled “Removal of Heavy Hydrocarbons From Gas Mixtures Containing Heavy Hydrocarbons and Methane.” This patent publication is also incorporated herein by reference in its entirety.

As noted, the separated heavy hydrocarbons will be released through line 133. The heavy hydrocarbons can be sold as a commercial fuel product. Alternatively, the heavy hydrocarbons may undergo some cooling to condense out the heavier components and to reclaim any methane vapor.

The gas stream next moves to the third stage 136. The third stage 136 provides for the removal of sulfurous components. Sulfurous components may include hydrogen sulfide, sulfur dioxide, and mercaptans. The sour gas components are adsorbed onto the adsorbent bed, while methane is passed on to an optional fourth stage 138. Upon saturation, the sulfurous components are released through line 135.

Where a dehydrated gas stream contains hydrogen sulfide, it may be advantageous to formulate the adsorbent with stannosilicates. Specifically, 8-ring zeolites may be fabricated with stannosilicates. The kinetic selectivity of this class of 8-ring materials allows H₂S to be rapidly transmitted into zeolite crystals. Upon saturation, the bed is purged. It is understood that the sulfurous components will preferably be taken through a subsequent sulfur recovery process.

An optional fourth stage 138 is also provided in the gas separation unit 130. The fourth stage 138 provides for the removal of carbon dioxide and nitrogen from the gas stream. CO₂ and N₂ are adsorbed onto the adsorbent bed of stage 138, while a sweetened gas stream is released. Upon purging, CO₂ and N₂ exit the gas separation unit 130 through exit line 137. At the same time, the sweetened gas stream is released through line 140.

It is understood that the gas separation unit 130 may have fewer or more than four stages. The number of AKS stages is dependent on the composition of the raw gas stream entering through gas line 122. For example, if the raw gas stream in gas line 122 has less than 0.5 ppm by volume H₂S, then an adsorption stage for sulfurous components removal likely will not be required. Reciprocally, if the raw gas stream in gas line 122 has metal contaminants such as mercury, then a separate AKS stage will be added for such separation.

As noted, each stage 132′/132″, 134, 136, 138 will employ an adsorbent bed. Each adsorbent bed may represent an adsorbent bed system that relies on a plurality of beds in parallel. These beds may be packed, for example, with activated carbons or molecular sieves. A first bed in each system is used for adsorption. This is known as a service bed. A second bed undergoes regeneration, such as through pressure reduction while the first bed is in service. Yet a third bed has already been regenerated and is held in reserve for use in the adsorption system when the first bed becomes substantially saturated. Thus, a minimum of three beds may be used in parallel for a more efficient operation.

In each stage 132′/132″, 134, 136, 138, the service bed may be in its own dedicated vessel, with the vessels of each stage being in series. Alternatively, the service beds may by aligned in series within one or more combined vessels. It is also noted that the beds may be fabricated from materials that will adsorb more than one component at a time. For example, a single bed may be designed to preferentially remove both sulfurous components and carbon dioxide. Alternatively, two separate vessels may be provided in series that are designed to remove substantially the same component. For example, if the raw gas stream in gas line 122 has a high CO₂ content, then two beds may be provided in sequential vessels for preferential removal of the CO₂.

A combination of different types of adsorbent beds may be used from stage to stage. Using a combination of adsorbent beds helps to prevent heavy hydrocarbons from remaining in the gas phase and ultimately ending up with the methane-rich gas stream 140. In any arrangement, a methane-rich gas 140 is released from the gas separation unit 130.

The gas processing facility 100 also provides for the liquefaction of the natural gas. In the present context, this means that the sweetened, methane-rich gas stream 140 will be chilled. In FIG. 1, a liquefaction facility is shown at 150.

Before entering the liquefaction facility 150, the methane-rich gas stream 140 may undergo modest compression. This is particularly true where there is a distance between the gas separation unit 130 and the liquefaction facility 150. In the facility 100 of FIG. 1, an optional compressor is shown at 145. The compressor 145 releases a compressed methane-rich gas stream 142 that feeds into the liquefaction facility 150.

In the present inventions, the liquefaction facility 150 is a high-pressure, expander-based facility. FIG. 5 presents a schematic flow diagram of the high-pressure expander cycle refrigeration system 150, in one embodiment.

The refrigeration system 150 first includes a first compression unit 515. Upon entering the liquefaction facility 150, the sweetened methane-rich gas stream 140 (or 142) is passed through the first compression unit 515. The first compression unit 515 may be, for example, a high pressure centrifugal dry seal compressor. The first compression unit 515 will increase the pressure of the methane-rich gas stream 140 to a pressure greater than 1,000 psia (6,895 kPa). In this way, a compressed gas feed stream 517 is created.

The liquefaction facility 150 also includes one or more compact heat exchangers for cooling the sweetened and compressed gas stream 517. In the arrangement of FIG. 5, first 525 and second 535 heat exchangers are shown. The liquefaction facility 150 also employs one or more high pressure expanders for further cooling. In FIG. 5, an expander is shown at 540.

The expander 540 may be of several types. For example, a Joule-Thompson valve may be used. Alternatively, a turbo-expander may be provided. A turbo-expander is a centrifugal or axial flow turbine through which a high pressure gas is expanded. Turbo-expanders are typically used to produce work that may be used, for example, to drive a compressor. In this respect, turbo-expanders create a source of shaft work for processes like compression or refrigeration. In any embodiment, a liquefied natural gas, or LNG stream, is produced. An LNG stream is shown at line 542.

As noted, the liquefaction facility 150 includes a first heat exchanger 525. The heat exchanger 525 is part of a 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 chills the compressed gas feed stream 517 down to a substantially chilled temperature. For example, the temperature may be as low as −100° C. (−148° F.).

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

The product stream 542 will have a large liquid fraction and a remaining small vapor fraction. Therefore, it is preferred that the liquefaction facility 150 also include a liquid separation vessel 550. The liquid separation vessel 550 is configured to separate the liquid fraction and the remaining vapor fraction. Thus, a liquid methane stream 152 is released in one line as the LNG commercial product, and a separate cold vapor stream 552 is released overhead.

The cold vapor stream 552 may 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 heat exchange takes place 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 merged back with the methane-rich gas stream 140 (or 142). To accomplish this, a third compression unit 555 is provided. The third compression unit 555 releases a compressed, partially-warmed product stream 557. The compressed, partially-warmed product stream 557 is preferably taken through the first compression unit 515 with the methane-rich gas stream 142.

It is preferred that the gas liquefaction facility 150 include a second heat exchanger. The second heat exchanger is shown at 535, and represents a second cooler. The second heat exchanger 535 may optionally be placed in line in the first refrigeration loop 520 after the first cooler 525. In this way, the second heat exchanger 535 would provide sub-cooling to the compressed, cooled gaseous feed stream 522. However, it is preferred that the second heat exchanger 535 be placed in line in the first refrigeration loop 520 before the first cooler 525. This is the arrangement shown in FIG. 5.

In FIG. 5, the second heat exchanger 535, or second cooler, receives the partially-warmed product stream 554 from the first cooler 525. Indirect heat exchange then takes place between the partially-warmed product stream 554 and the compressed gas feed stream 517. The heat exchanger 535 pre-cools the compressed gas feed 517 stream before the compressed gas feed stream 517 enters the first cooler 525. The second heat exchanger 535 thus releases a pre-cooled compressed gas feed stream 532 into the first cooler 525.

The heat exchanger 535 also releases a warmed product stream 556. In this arrangement, the warmed product stream 556 enters the third compression unit 555, and is released as the compressed and partially-warmed product stream 557 that is merged with the methane-rich gas stream 142.

In order to provide effective pre-cooling in the second cooler 535, it is desirable to employ a coolant in addition to the partially-warmed product stream 554. Therefore, a second refrigeration loop 530 is also provided. The second refrigeration loop 530 employs a refrigerant, indicated at line 534. The refrigerant in line 534 is preferably a nitrogen gas, or a nitrogen-containing gas. The use of nitrogen in the refrigerant expands the pre-cooling temperature regime.

Referring back to FIG. 1, it can be seen that a portion of the contaminant from stage 138 is intercepted. This represents N₂ and, perhaps, some CO₂ in line 137. The nitrogen is taken via line 147 to the gas liquefaction facility 150. In addition, the operator may take a portion of the methane-rich gas stream 140 to use as the refrigerant 534. This is done via line 141. Alternatively or in addition, the operator may take a portion of the heavy hydrocarbons separated from stage 136. The ethane (or other heavy hydrocarbons) is taken from line 133 via line 143. Lines 141, 143, and 147 are shown as dashed lines, indicating optional fluid interceptions.

The gas components in lines 141, 143, and 147 are selectively and optionally taken from the gas separation unit 130 and merged into line 149. This is shown in FIG. 1. The components from lines 141, 143, and/or 147 are then directed through line 149 into the second refrigeration loop 530. This is shown in FIG. 5. Valve 501 is seen for controlling the flow of components from lines 141, 143, and/or 147 through line 149 into the second refrigeration loop 530. Valve 501 may also be used to divert a portion of the components from lines 141, 143, 147 for burning in a gas turbine to generate electricity or for regenerating a bed in connection with TSA.

It is, of course, understood that additional valving (not shown) will control the relative volumes of the components in lines 141, 143, 147 taken into line 149. It is further understood that the operator may draw from a dedicated tank of nitrogen (not shown) for the refrigerant in line 534. In any arrangement, the refrigerant from line 534 leaves the heat exchanger 535 in a warmed state. The refrigerant moves through a second compression unit 536 for pressure boosting, and is then taken through an expander 538 for re-cooling. The refrigerant in line 534 then re-enters the heat exchanger 535. A small chiller (not shown) may be added to the second refrigeration loop 530 after the expander 538 to further cool the refrigerant in line 534.

It is noted that the heat exchanger 535 may serve as the only cooler for the gas liquefaction facility 150. In this arrangement, the first cooler 525 would not be used. Further, the vapor portion 552 would preferably then be used as at least a portion of the refrigerant for line 534. However, the use of the heat exchanger 535 with the expander 538 in the second refrigeration loop 530 improves the overall cooling efficiency of the first expander loop 520. In any instance, the present invention is not limited by the specific arrangement of coolers or refrigeration loops unless so expressly stated in the claims.

FIG. 6 is a flow chart showing steps for a process 600 for liquefying a raw natural gas stream. The process 600 employs adsorptive kinetic separation to produce a methane-rich gas stream. The process 600 then further utilizes a high-pressure expander cycle refrigeration system to chill the methane and to provide an LNG product. The LNG product is preferably generated on a floating platform or a gravity-based platform offshore.

The process 600 first includes receiving 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 fraction vessels described above in their various embodiments. The fractionation vessels preferably operate on pressure swing adsorption (PSA) or rapid cycle pressure swing adsorption (RCPSA) to regenerate a series of adsorption beds. The adsorption beds are designed to adsorb CO₂, H₂S, H₂O, heavy hydrocarbons, VOC's, mercaptans, nitrogen, or combinations thereof.

The process 600 also includes substantially separating methane from contaminants within the natural gas feed stream. As a first separation step, the raw natural gas feed stream is optionally taken through a dehydration vessel. This serves to remove a substantial portion of water and other liquid phase components from the natural gas stream. The step of separating liquid-phase components (primarily water) from gas phase components is shown in Box 620. A dehydrated natural gas feed stream is then released as a dehydrated natural gas feed stream.

Next, gas-phase contaminants are removed from the dehydrated raw gas stream. The step of separating methane from gas-phase contaminants within the natural gas feed stream is shown at Box 630. This step is done through the use of adsorption beds in the one or more fractionation vessels. In one aspect, separating methane from contaminants is conducted through the gas separation unit at a pressure of at least about 500 pounds per square inch absolute (psia).

FIG. 7 is a flow chart showing steps 700 for separating contaminants from the raw natural gas stream. The steps use adsorptive kinetic separation to create the methane-rich gas stream.

First, water is adsorbed from the natural gas feed stream. In this respect, an adsorptive bed having water-retentive properties is employed. This step is shown in Box 710. As noted above, it is preferred that the water removal stage simply be a “polishing” stage. This means that most water has already been removed or “knocked out” by a previous dehydration vessel (per the step of Box 620).

Where a dehydration vessel is used, the contaminants in the gas stream will include a desiccant such as ethylene glycol. Accordingly, a next stage in separating components involves the adsorption of the desiccant. This is provided in Box 720.

As shown in FIG. 7, various additional adsorptive stages may be undertaken for the removal of contaminants. These may include the removal of sulfurous components (Box 730), the removal of carbon dioxide and/or nitrogen (Box 740), the removal of mercury or other metallic elements (Box 750), and the removal of heavy hydrocarbons (Box 760). Depending on how the adsorbent beds are designed, some of these components may be removed in a single combined stage. Further, the order of contaminant removal as provided in the steps of Boxes 710 through 760 may be changed, although it is highly preferred that water be removed first as shown in Box 710. Thus, the process 600 is not limited by the order in which contaminants are removed in the steps 700 unless so stated in the claims herein.

In one aspect, a single vessel having a plurality of adsorbent beds aligned in series is used. For example, the at least one fractionation vessel in the gas separation unit may comprise a vessel containing a plurality of adsorbent beds in series, such that:

a first adsorption bed is designed to primarily remove water and other liquid components from the dehydrated natural gas feed stream;

a second adsorption bed is designed to primarily remove a desiccant from the dehydrated natural gas feed stream; and

a third vessel comprises an adsorption bed designed primarily for the removal of a sour gas component from the dehydrated natural gas feed stream.

Additional vessels may be added to adsorb and separate different sour gases.

In another aspect, multiple vessels in series are employed, with the vessels being aligned with the flow of the dehydrated natural gas feed stream. Each vessel releases a progressively sweeter methane gas stream. For example,

a first vessel uses an adsorption bed designed for the removal of water remaining in the dehydrated natural gas feed stream;

a second vessel uses an adsorption bed designed for the removal of a desiccant from the dehydrated natural gas feed stream; and

a third vessel uses an adsorption bed designed for the removal of a sour gas component from the dehydrated natural gas feed stream.

The sour gas component may be one or more sulfurous components. Alternatively, the sour gas component may be carbon dioxide.

As a result of the adsorption steps 700 in FIG. 7, a methane-rich gas stream is generated. This stream is released from the gas separation unit as a dehydrated natural gas feed stream. Accordingly, the process 600 next includes releasing a dehydrated, methane-rich gas stream from the gas separation unit. This is indicated at Box 640.

The methane-rich gas stream is directed to the high-pressure expander cycle refrigeration system. This is seen at Box 650. The refrigeration system is in accordance with the refrigeration system 150 shown above in FIG. 5, and as described in any of its various embodiments. Thus, the refrigeration system preferably includes a first refrigeration loop for cycling the vapor portion of the product for use as a coolant in a first cooler, and a second refrigeration loop for cycling a nitrogen-containing gas as a refrigerant in a second cooler. The second cooler may utilize both the nitrogen-based refrigerant and a partially-warmed methane gas from the first cooler as working fluids.

The process 600 also includes compressing the methane-rich gas stream. This is provided at Box 660. The gas stream is compressed to a pressure that is greater than 1,000 psia (6,895 kPa) in order to form a compressed gas feed stream.

The process 600 next comprises cooling the compressed gas feed stream to form a compressed, cooled gaseous feed stream. This is seen at Box 670. The cooling step of Box 670 preferably involves taking the compressed gas feed stream through at least one heat exchanger within a first refrigeration loop 520. For example, the compressed gas feed stream may be pre-chilled using the heat exchanger 535 (second cooler) of FIG. 5, and then further cooled using the first cooler 525 of FIG. 5. Optionally, the heat exchanger 535 (second cooler) may be placed in the first refrigeration loop 520 after the first cooler 525. In this way, the heat exchanger 535 sub-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 cycles coolant through at least one heat exchanger (such as cooler 525), and then directs the used (warmed) coolant (554 and/or 556) to a compression unit 555. The compression unit compresses the warmed coolant to about 1,500 to 3,500 psia (10,342 to 24,132 kPa). More preferably, the compression unit compresses the warmed product stream to about 2,500 to 3,000 psia (17,237 to 20,684 kPa).

The second cooler 535 is preferably part of a second refrigeration loop 530. The second cooler 535 is configured to cool the compressed gas feed stream 517 at least partially by indirect heat exchange between a refrigerant stream 534 and the compressed, gas feed stream. The second refrigeration loop 530 may also include a compression unit 536. The compression unit 536 is configured to re-compress the refrigerant stream after the refrigerant stream passes through the second cooler 535. The second refrigeration loop will also then include an expander. The expander receives the re-compressed, cooled refrigerant stream, and expands the compressed, cooled refrigerant stream prior to returning it to the second cooler 535.

The process 600 also includes expanding the cooled, compressed, gaseous feed stream 522. This is provided at Box 680. In one aspect, expanding the cooled, compressed, gaseous feed stream 522 comprises reducing the pressure of the cooled, compressed, gaseous feed stream to a pressure between about 50 psia (345 kPa) and 450 psia (3103 kPa). Expansion of the cooled gaseous feed stream 522 forms the LNG product stream 542. The product stream has a liquid fraction and a remaining vapor fraction.

The high-pressure expander cycle refrigeration system preferably includes a liquid separation vessel. The process then further comprises separating the liquid fraction and the remaining vapor fraction. The liquid portion may then be loaded into a transport vessel. This is indicated at Box 690 of FIG. 6.

In order to demonstrate the utility of the process 600, and particularly the step of removing nitrogen using an AKS system, certain data has been generated. This date is presented in Tables in connection with certain examples, below.

EXAMPLES

The Tables below depict comparisons developed using an Aspen HYSYS® (version 2006) process simulator, a computer-aided design program from Aspen Technology, Inc., of Cambridge, Mass. In connection with the Tables, the term “SCRS” is used. This term is an acronym for “Selective Component Removal System,” and in this context refers to an AKS adsorptive system.

First, Table 2 illustrates the effect of removing nitrogen from the natural gas stream prior to liquefaction. The comparison is with the conventional approach where the nitrogen is removed after the nitrogen-containing natural gas is liquefied using a distillation column. The power saving (greater than 7%) achieved results in a reduction of power generation equipment. This, in turn, translates into space and weight reductions, thereby enabling offshore LNG production.

TABLE 2
Effect of N2 Removal with SCRS on Liquefaction Horsepower
	Feed Molar	LNG Product Specification
	Composition	w/o SCRS	w/ SCRS
Nitrogen	0.0431	0.0101	0.0053
Methane	0.9559	0.9888	0.9936
Ethane	0.0010	0.0011	0.0011
Liquefaction Power (%)		100	93.3
Note that the required specifications on the LNG are handily achieved

Next, Table 3 is provided to illustrate the benefit of using a high-pressure expander cycle refrigeration system on process performance. The thermal energy required to produce the LNG from an ambient temperature of 100° F. is reduced as the feed pressure is increased, up to 17% for a pressure of 4,000 psia. Conventional gas conditioning methods reduce the feed gas pressure below 1,000 psia. Therefore compression equipment and the associated compression horsepower are required to boost the feed pressure in order to capitalize on the benefit of the reduced thermal energy at elevated pressures. This offsets the liquefaction horsepower reduction benefits.

TABLE 3
Effect of Elevated Feed Gas Pressure on Refrigeration Duty Requirement
	Refrigeration
Feed Gas	Duty	Refrigeration Duty
Pressure (psia)	(normalized)	% Reduction
4,000	83.0	17.0
3,000	86.4	13.6
2,000	91.5	8.5
1,000	98.4	1.6
800	100.0	0.0

It has been discovered that operating the AKS-based gas separation unit at an elevated pressure preserves and even enhances these benefits.

Table 4 highlights the performance improvement using the inventive separation process. In the conventional approach, the benefit of the elevated feed gas pressure is achieved by adding feed gas compression: the energy associated with the pressure reduction from the wellhead dictated by the conventional solvent extraction gas treating method is typically wasted. The SCRS unit may be configured to preserve the wellhead pressure and thereby avoid the wasted energy resulting from the conventional approach.

TABLE 4
Effect of Elevated Feed Gas Pressure on Liquefaction Power
		Liquefaction Power %
	Feed Gas	Reduction	Incremental %
	Pressure	w/ Feed Gas		Improvement
	(psia)	Compression	w/o SCRS	w/ SCRS
	5,000	10.9	38.7	27.9
	4,500	12.0	37.4	25.3
	4,000	13.1	35.9	22.8
	3,500	14.1	33.9	19.8
	3,000	15.0	32.0	17.0
	2,500	15.0	28.8	13.8
	2,000	14.3	24.3	10.0
	1,500	10.5	16.0	5.5
	1,250	7.6	10.5	2.9
	1,000	0.0	0.0	0.0

It is believed that by using small, light-weight AKS separators to form the gas separation unit, and by using a high-pressure expander cycle refrigeration system, the equipment footprint and weight of the gas conditioning or treating facilities are reduced by 75%. This may translate into a 21% reduction in space and weight on a FLNG barge. Alternatively, the available space and weight may be used to increase the capacity of the FLNG barge. The reduction therefore improves the economic viability of the gas commercialization project.

As can be seen, an improved gas processing facility for the liquefaction of a natural gas stream is provided. In one aspect, the facility comprises:

1. a gas separation unit, the gas separation unit having at least one fractionation vessel comprised of:

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

an adsorbent material that has a kinetic selectivity for contaminants over methane greater than 5, such that the contaminants become kinetically adsorbed within the adsorbent material, and

a gas outlet for releasing a methane-rich gas stream; and

a high-pressure expander cycle refrigeration system comprised of:

• • a first compression unit configured to receive a substantial portion of the methane-rich gas stream and to compress the methane-rich gas stream to greater than about 1,000 psia (6,895 kPa), thereby providing a compressed gas feed stream;
  • a first cooler configured to cool the compressed gas feed stream to form a compressed, cooled gaseous feed stream; and
  • a first expander configured to expand the cooled, compressed, gaseous feed stream to form a product stream having a liquid fraction and a remaining vapor fraction.
    2. The gas processing facility of paragraph 1, wherein:

the first cooler is configured to receive a portion of the product stream from the first expander, and use the portion of the product stream to cool the compressed gas feed stream through heat exchange.

3. The gas processing facility of paragraph 1, wherein:

the first cooler is configured to use an external refrigerant stream to cool the compressed gas feed stream through heat exchange.

4. The gas processing facility of paragraph 1, wherein the high-pressure expander cycle refrigeration system further comprises:

a liquid separation vessel configured to separate the liquid fraction and the remaining vapor fraction from the first expander.

5. The gas processing facility of paragraph 4, wherein:

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

the first cooler releases (i) a chilled gas feed stream, and (ii) a partially-warmed product stream after heat-exchanging with the compressed gas feed stream; and

the high-pressure expander cycle refrigeration system further comprises:

• • a second cooler configured to further cool the compressed gas feed stream at least partially by indirect heat exchange with a refrigerant stream and the vapor fraction; and
  • a second refrigeration loop having (i) a second compression unit configured to re-compress the refrigerant stream after the refrigerant stream passes through the second cooler, and (ii) a second expander configured to receive the re-compressed refrigerant stream, and expand the re-compressed refrigerant stream prior to returning it to the second cooler.
    6. The gas processing facility of paragraph 5, wherein the high-pressure expander cycle refrigeration system further comprises:

a third compression unit in the first refrigeration loop for compressing the partially-warmed product stream after heat-exchanging with the compressed gas feed stream; and

a line for merging the compressed, partially-warmed product stream with the gas feed stream to complete the first refrigeration loop.

7. The gas processing facility of paragraph 5, wherein the second cooler sub-cools the chilled gas feed stream after the chilled gas feed stream leaves the first cooler.
8. The gas processing facility of paragraph 5, wherein the second cooler pre-cools the compressed gas feed stream before the compressed gas feed stream enters the first cooler.
9. The gas processing facility of paragraph 8, wherein:

the second cooler receives the partially-warmed product stream from the first cooler for further heat-exchanging with the compressed gas feed stream; and

releases a warmed product stream to a third compression unit to complete the first refrigeration loop.

10. The gas processing facility of paragraph 1, wherein the facility is located on (i) a floating platform, (ii) a gravity-based platform, or (iii) a ship-shaped vessel offshore.
11. The gas processing facility of paragraph 1, wherein the at least one fractionation vessel in the gas separation unit operates on pressure swing adsorption (PSA) or rapid cycle pressure swing adsorption (RCPSA).
12. The gas processing facility of paragraph 11, wherein the at least one fractionation vessel is configured to adsorb CO₂, H₂S, H₂O, heavy hydrocarbons, VOC's, mercaptans, or combinations thereof.
13. The gas processing facility of paragraph 12, further comprising:

a dehydration vessel configured to receive the natural gas feed stream and remove a substantial portion of water from the natural gas feed stream, and release a dehydrated natural gas feed stream to the at least one fractionation vessel.

14. A process for liquefying a natural gas feed stream, comprising:

receiving the natural gas feed stream at a gas separation unit, the gas separation unit having at least one fractionation vessel comprised of:

• • a gas inlet for receiving a natural gas mixture comprising methane,
  • an adsorbent material that has a kinetic selectivity for contaminants over methane greater than 5, such that the contaminants become kinetically adsorbed within the adsorbent material, and
  • a gas outlet configured to release a methane-rich gas stream;
  • substantially separating methane from contaminants within the natural gas feed stream;
  • releasing a methane-rich gas stream from the gas separation unit;
  • directing the methane-rich gas stream into a high-pressure expander cycle refrigeration system;
  • compressing the methane-rich gas stream to a pressure that is greater than 1,000 psia (6,895 kPa) in order to form a compressed gas feed stream;
  • cooling the compressed gas feed stream to form a compressed, cooled gaseous feed stream;
  • expanding the cooled, compressed, gaseous feed stream to form a product stream having a liquid fraction and a remaining vapor fraction; and
  • separating the vapor fraction from the liquid fraction.
    15. The process of paragraph 14, wherein the high-pressure expander cycle refrigeration system comprises:

a first compression unit configured to receive a substantial portion of the methane-rich gas stream and to generate the compressed gas feed stream;

a first cooler configured to cool the compressed gas feed stream to form the compressed, cooled gaseous feed stream; and

a first expander configured to expand the cooled, compressed, gaseous feed stream to form the product stream.

16. The process of paragraph 15, wherein cooling the compressed gas feed stream comprises:

delivering at least a portion of the vapor fraction from the product stream to the first cooler as part of a first refrigeration loop; and

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

17. The process of paragraph 16, wherein:

the high-pressure expander cycle refrigeration system further comprises a liquid separation vessel; and

separating the vapor fraction from the liquid fraction is done using the liquid separation vessel.

18. The process of paragraph 17, further comprising:

releasing from the first cooler (i) a chilled gas feed stream as the product stream, and (ii) a partially-warmed product stream as a working fluid;

directing the partially-warmed product stream to a third compression unit; and

merging 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 process of paragraph 18, wherein the high-pressure expander cycle refrigeration system further comprises:

a second cooler configured to further cool the compressed gas feed stream at least partially by indirect heat exchange between a refrigerant stream and the vapor fraction; and

a second refrigeration loop having (i) a second compression unit configured to re-compress the refrigerant stream after the refrigerant stream passes through the second cooler, and (ii) a second expander configured to receive the compressed refrigerant stream, and expand the compressed refrigerant stream prior to returning it to the second cooler.

20. The process of paragraph 19, wherein the second cooler sub-cools the chilled gas feed stream after the chilled gas feed stream leaves the first cooler.
21. The process 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 process of paragraph 1, wherein the facility is located on (i) a floating platform, (ii) a gravity-based platform, or (iii) a ship-shaped vessel offshore.
23. The process of paragraph 22, wherein the at least one fractionation vessel in the gas separation unit operates on pressure swing adsorption (PSA) or rapid cycle pressure swing adsorption (RCPSA).
24. The process of paragraph 23, wherein the at least one fractionation vessel is configured to adsorb CO₂, H₂S, H₂O, heavy hydrocarbons, VOC's, mercaptans, or combinations thereof
25. The process of paragraph 22, further comprising:

passing the natural gas feed stream through a dehydration vessel in order to remove a substantial portion of water from the natural gas feed stream; and

release a dehydrated natural gas feed stream to the at least one fractionation vessel for contaminant removal.

26. A method for liquefying a natural gas feed stream, comprising:

receiving the natural gas feed stream at a gas processing facility;

passing the natural gas feed stream through a dehydration vessel in order to remove a substantial portion of water from the natural gas feed stream;

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

in the gas separation unit, passing the dehydrated natural gas feed stream through a series of adsorbent beds in order to separate methane gas from contaminants in the dehydrated natural gas feed stream using adsorptive kinetic separation;

releasing a methane-rich gas stream from the gas separation unit;

directing the methane-rich gas stream into a high-pressure expander cycle refrigeration system;

compressing the methane-rich gas stream to a pressure that is greater than 1,000 psia (6,895 kPa) in order to form a compressed gas feed stream;

cooling the compressed gas feed stream to form a compressed, cooled gaseous feed stream;

expanding the cooled, compressed, gaseous feed stream to form a product stream having a liquid fraction and a remaining vapor fraction.

27. The method of paragraph 26, wherein the series of adsorbent beds comprises:

a first adsorption bed for the removal of water remaining in the dehydrated natural gas feed stream;

a second adsorption bed designed primarily for the removal of a desiccant from the dehydrated natural gas feed stream; and

a third adsorption bed designed primarily for the removal of a sour gas component from the dehydrated natural gas feed stream.

28. The method of paragraph 27, wherein each of the adsorbent beds has associated with it two additional adsorbent beds to form three adsorbent beds, with:

a first of the three adsorbent beds being in service for adsorbing a selected contaminant;

a second of the three adsorbent beds undergoing regeneration; and

a third of the adsorbent beds being held in reserve to replace the first of the three adsorbent beds; and

wherein the regeneration is part of a pressure-swing adsorption process.

As can be seen, another enhanced gas processing facility for the liquefaction of a natural gas stream is provided. In one aspect, the facility comprises:

1A. A gas processing facility for the liquefaction of a natural gas feed stream, the facility comprising:

a gas separation unit, the gas separation unit having at least one fractionation vessel comprised of:

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

an adsorbent material that has a kinetic selectivity for contaminants over methane greater than 5, such that the contaminants become kinetically adsorbed within the adsorbent material, and

a gas outlet for releasing a methane-rich gas stream; and

a high-pressure expander cycle refrigeration system comprised of:

a first compression unit configured to receive a substantial portion of the methane-rich gas stream and to compress the methane-rich gas stream to greater than about 1,000 psia (6,895 kPa), thereby providing a compressed gas feed stream;

a first cooler configured to cool the compressed gas feed stream to form a compressed, cooled gaseous feed stream; and

a first expander configured to expand the cooled, compressed, gaseous feed stream to form a product stream having a liquid fraction and a remaining vapor fraction.

2A. The gas processing facility of paragraph 1A, wherein:

the first cooler is configured to receive a portion of the product stream from the first expander, and use the portion of the product stream to cool the compressed gas feed stream through heat exchange.

3A. The gas processing facility of paragraph 1A, wherein:
the first cooler is configured to use an external refrigerant stream to cool the compressed gas feed stream through heat exchange.
4A. The gas processing facility of paragraph 1A, wherein the high-pressure expander cycle refrigeration system further comprises:

a liquid separation vessel configured to separate the liquid fraction and the remaining vapor fraction from the first expander.

5A. The gas processing facility of paragraph 4A, wherein:

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

the first cooler releases (i) a chilled gas feed stream, and (ii) a partially-warmed product stream after heat-exchanging with the compressed gas feed stream; and

the high-pressure expander cycle refrigeration system further comprises:

a second cooler configured to further cool the compressed gas feed stream at least partially by indirect heat exchange with a refrigerant stream and the vapor fraction; and

a second refrigeration loop having (i) a second compression unit configured to re-compress the refrigerant stream after the refrigerant stream passes through the second cooler, and (ii) a second expander configured to receive the re-compressed refrigerant stream, and expand the re-compressed refrigerant stream prior to returning it to the second cooler.

6A. The gas processing facility of paragraph 5A, wherein the high-pressure expander cycle refrigeration system further comprises:

a third compression unit in the first refrigeration loop for compressing the partially-warmed product stream after heat-exchanging with the compressed gas feed stream; and

a line for merging the compressed, partially-warmed product stream with the gas feed stream to complete the first refrigeration loop.

7A. The gas processing facility of paragraph 5A, wherein the second cooler sub-cools the chilled gas feed stream after the chilled gas feed stream leaves the first cooler.
8A. The gas processing facility of paragraph 5A, wherein the second cooler pre-cools the compressed gas feed stream before the compressed gas feed stream enters the first cooler.
9A. The gas processing facility of paragraph 8A, wherein:

the second cooler receives the partially-warmed product stream from the first cooler for further heat-exchanging with the compressed gas feed stream; and

releases a warmed product stream to a third compression unit to complete the first refrigeration loop.

10A. The gas processing facility of paragraph 9A, wherein the third compression unit compresses the warmed product stream to about 1,500 to 3,500 psia (10,342 to 24,132 kPa).
11A. The gas processing facility of paragraph 1A, wherein the facility is located on (i) a floating platform, (ii) a gravity-based platform, or (iii) a ship-shaped vessel offshore.
12A. The gas processing facility of paragraph 5A, wherein:

the refrigerant stream comprises a gas selected from the group consisting of: nitrogen gas, nitrogen-containing gas, a side stream from the methane-rich gas stream, and the remaining vapor fraction, and combinations thereof; and

the refrigerant stream in the second refrigeration loop flows in a closed loop.

13A. The gas processing facility of paragraph 1A, wherein the at least one fractionation vessel in the gas separation unit operates on pressure swing adsorption (PSA) or rapid cycle pressure swing adsorption (RCPSA).
14A. The gas processing facility of paragraph 13A, wherein the at least one fractionation vessel in the gas separation unit further operates on temperature swing adsorption (TSA) or rapid cycle temperature swing adsorption (RCTSA).
15A. The gas processing facility of paragraph 13A, wherein the at least one fractionation vessel is configured to adsorb CO₂, H₂S, H₂O, heavy hydrocarbons, VOC's, mercaptans, or combinations thereof.
16A. The gas processing facility of paragraph 13A, wherein each of the at least one fractionation vessel cooperates with other fractionation vessels to form a pressure swing adsorption system comprising:

at least one service bed providing adsorption,

at least one bed in regeneration undergoing pressure reduction, and

at least one regenerated bed held in reserve for use in the adsorption system when the at least one service bed becomes substantially saturated.

17A. The gas processing facility of paragraph 13A, further comprising:

a dehydration vessel configured to receive the natural gas feed stream and remove a substantial portion of water from the natural gas feed stream, and release a dehydrated natural gas feed stream to the at least one fractionation vessel.

18A. The gas processing facility of paragraph 17A, wherein the at least one fractionation vessel in the gas separation unit comprises a plurality of vessels in series, such that:

a first vessel comprises an adsorption bed for the removal of water remaining in the dehydrated natural gas feed stream;

a second vessel comprises an adsorption bed designed primarily for the removal of a desiccant from the dehydrated natural gas feed stream; and

a third vessel comprises an adsorption bed designed primarily for the removal of a sour gas component from the dehydrated natural gas feed stream.

19A. The gas processing facility of paragraph 17A, wherein the at least one fractionation vessel in the gas separation unit comprises a vessel containing a plurality of adsorbent beds in series, such that:

a first adsorption bed is designed to primarily remove water and other liquid components from the dehydrated natural gas feed stream;

a second adsorption bed is designed to primarily remove a desiccant from the dehydrated natural gas feed stream; and

a third vessel comprises an adsorption bed primarily for the removal of a sour gas component from the dehydrated natural gas feed stream.

20A. A process for liquefying a natural gas feed stream, comprising:

receiving the natural gas feed stream at a gas separation unit, the gas separation unit having at least one fractionation vessel comprised of:

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

an adsorbent material that has a kinetic selectivity for contaminants over methane greater than 5, such that the contaminants become kinetically adsorbed within the adsorbent material, and

a gas outlet configured to release a methane-rich gas stream;

substantially separating methane from contaminants within the natural gas feed stream;

releasing a methane-rich gas stream from the gas separation unit;

directing the methane-rich gas stream into a high-pressure expander cycle refrigeration system;

compressing the methane-rich gas stream to a pressure that is greater than 1,000 psia (6,895 kPa) in order to form a compressed gas feed stream;

cooling the compressed gas feed stream to form a compressed, cooled gaseous feed stream;

expanding the cooled, compressed, gaseous feed stream to form a product stream having a liquid fraction and a remaining vapor fraction; and

separating the vapor fraction from the liquid fraction.

21A. The process of paragraph 20A, wherein the high-pressure expander cycle refrigeration system comprises:

a first compression unit configured to receive a substantial portion of the methane-rich gas stream and to generate the compressed gas feed stream;

a first cooler configured to cool the compressed gas feed stream to form the compressed, cooled gaseous feed stream; and

a first expander configured to expand the cooled, compressed, gaseous feed stream to form the product stream.

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

delivering at least a portion of the vapor fraction from the product stream to the first cooler as part of a first refrigeration loop; and

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

23A. The process of paragraph 22A, wherein:

the high-pressure expander cycle refrigeration system further comprises a liquid separation vessel; and

separating the vapor fraction from the liquid fraction is done using the liquid separation vessel.

24A. The process of paragraph 23A, further comprising:

releasing from the first cooler (i) a chilled gas feed stream as the product stream, and (ii) a partially-warmed product stream as a working fluid;

directing the partially-warmed product stream to a third compression unit; and

merging the compressed, partially-warmed product stream from the third compression unit with the methane-rich gas stream to complete the first refrigeration loop.

25A. The process of paragraph 24A, wherein the high-pressure expander cycle refrigeration system further comprises:

a second cooler configured to further cool the compressed gas feed stream at least partially by indirect heat exchange between a refrigerant stream and the vapor fraction; and

a second refrigeration loop having (i) a second compression unit configured to re-compress the refrigerant stream after the refrigerant stream passes through the second cooler, and (ii) a second expander configured to receive the compressed refrigerant stream, and expand the compressed refrigerant stream prior to returning it to the second cooler.

26A. The process of paragraph 25A, wherein the second cooler sub-cools the chilled gas feed stream after the chilled gas feed stream leaves the first cooler.
27A. The process 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 process of paragraph 23A, wherein the facility is located on (i) a floating platform, (ii) a gravity-based platform, or (iii) a ship-shaped vessel offshore.
29A. The process of paragraph 23A, wherein the at least one fractionation vessel in the gas separation unit operates on pressure swing adsorption (PSA) or rapid cycle pressure swing adsorption (RCPSA).
30A. The process of paragraph 23A, wherein the at least one fractionation vessel in the gas separation unit further operates on temperature swing adsorption (TSA) or rapid cycle temperature swing adsorption (RCTSA).
31A. The process of paragraph 30A, wherein the at least one fractionation vessel is configured to adsorb CO₂, H₂S, H₂O, heavy hydrocarbons, VOC's, mercaptans, or combinations thereof
32A. The process of paragraph 31A, further comprising:

passing the natural gas feed stream through a dehydration vessel in order to remove a substantial portion of water from the natural gas feed stream; and

release a dehydrated natural gas feed stream to the at least one fractionation vessel for contaminant removal.

33A. The process of paragraph 32A, wherein the at least one fractionation vessel in the gas separation unit comprises a plurality of vessels in series, such that:

a first vessel comprises an adsorption bed for the removal of water remaining in the dehydrated natural gas feed stream;

a second vessel comprises an adsorption bed designed primarily for the removal of a desiccant from the dehydrated natural gas feed stream; and

a third vessel comprises an adsorption bed designed primarily for the removal of a sour gas component from the dehydrated natural gas feed stream.

34A. The process of paragraph 32A, wherein the at least one fractionation vessel in the gas separation unit comprises a vessel containing a plurality of adsorbent beds in series, such that:

a first adsorption bed is designed to primarily remove water and other liquid components from the dehydrated natural gas feed stream;

a second adsorption bed is designed to primarily remove a desiccant from the dehydrated natural gas feed stream; and

a third vessel comprises an adsorption bed designed primarily for the removal of a sour gas component from the dehydrated natural gas feed stream.

35A. A method for liquefying a natural gas feed stream, comprising:

receiving the natural gas feed stream at a gas processing facility;

passing the natural gas feed stream through a dehydration vessel in order to remove a substantial portion of water from the natural gas feed stream;

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

in the gas separation unit, passing the dehydrated natural gas feed stream through a series of adsorbent beds in order to separate methane gas from contaminants in the dehydrated natural gas feed stream using adsorptive kinetic separation;

releasing a methane-rich gas stream from the gas separation unit;

directing the methane-rich gas stream into a high-pressure expander cycle refrigeration system;

compressing the methane-rich gas stream to a pressure that is greater than 1,000 psia (6,895 kPa) in order to form a compressed gas feed stream;

cooling the compressed gas feed stream to form a compressed, cooled gaseous feed stream;

expanding the cooled, compressed, gaseous feed stream to form a product stream having a liquid fraction and a remaining vapor fraction.

36A. The method of paragraph 35A, wherein the series of adsorbent beds comprises:

a first adsorption bed for the removal of water remaining in the dehydrated natural gas feed stream;

a second adsorption bed designed primarily for the removal of a desiccant from the dehydrated natural gas feed stream; and

a third adsorption bed designed primarily for the removal of a sour gas component from the dehydrated natural gas feed stream.

37A. The method of paragraph 36A, wherein the first, second, and third adsorption beds are aligned in series with 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 adsorption beds reside in separate pressure vessels that are aligned in series with the flow of the dehydrated natural gas feed stream.
39A. The method of paragraph 36A, wherein each of the adsorbent beds comprises a solid adsorbent bed fabricated from a zeolite material.
40A. The method of paragraph 37A, wherein each of the adsorbent beds has associated with it two additional adsorbent beds to form three adsorbent beds, with:

a first of the three adsorbent beds being in service for adsorbing a selected contaminant;

a second of the three adsorbent beds undergoing regeneration; and

a third of the adsorbent beds being held in reserve to replace the first of the three adsorbent beds; and wherein

the regeneration is part of a pressure-swing adsorption process.

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

passing the compressed gas feed stream through a first heat exchanger in order to provide heat exchange with a cooled refrigerant stream, thereby forming a sub-cooled gas feed stream; and

passing the sub-cooled gas feed stream through a second heat exchanger in order to provide heat exchange with a cooling gas stream, thereby forming the compressed, cooled gaseous feed stream.

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

withdrawing a portion of the remaining vapor fraction from the product stream;

reducing the pressure of the withdrawn portion of the remaining vapor fraction down to a pressure of about 30 to 200 psia (207 to 1,379 kPa) to produce a reduced pressure gas stream;

passing the reduced pressure gas stream through the second heat exchanger as the cooling gas stream; and

releasing the reduced pressure gas stream from the second heat exchanger as a partially-warmed gas stream.

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

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

returning the partially-warmed gas stream to the dehydrated natural gas feed stream for compressing 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 that is between about 1,200 psia (8,274 kPa) to 4,500 psia (31,026 kPa); and

expanding the cooled, compressed, gaseous feed stream comprises reducing the pressure of the cooled, compressed, gaseous feed stream to a pressure between about 50 psia (345 kPa) and 450 psia (3,103 kPa).

As can be seen, processes, systems and methods for liquefying a natural gas feed stream using AKS and a high-pressure expander cycle refrigeration system are provided. Such processes, systems and methods allow for the formation of LNG using a facility having less weight than conventional facilities. The processes, systems and methods also permit rapid tool-up for offshore production operations. The inventions described herein are not restricted to the specific embodiment disclosed herein, but are governed by the claims, which follow. While it will be apparent that the inventions herein described are well calculated to achieve the benefits and advantages set forth above, it will be appreciated that the inventions are susceptible to modification, variation and change without departing from the spirit thereof.

Claims

1. A gas processing facility for the liquefaction of a natural gas feed stream, the facility comprising:

a gas separation unit, the gas separation unit having at least one fractionation vessel comprised of: a gas inlet for receiving a natural gas mixture comprising methane, an adsorbent material that has a kinetic selectivity for contaminants over methane greater than 5, such that the contaminants become kinetically adsorbed within the adsorbent material, and a gas outlet for releasing a methane-rich gas stream; and a high-pressure expander cycle refrigeration system comprised of: a first compression unit configured to receive a substantial portion of the methane-rich gas stream and to compress the methane-rich gas stream to greater than about 1,000 psia (6,895 kPa), thereby providing a compressed gas feed stream; a first cooler configured to cool the compressed gas feed stream to form a compressed, cooled gaseous feed stream; and a first expander configured to expand the cooled, compressed, gaseous feed stream to form a product stream having a liquid fraction and a remaining vapor fraction.

2. The gas processing facility of claim 1, wherein:

the first cooler is configured to receive a portion of the product stream from the first expander, and use the portion of the product stream to cool the compressed gas feed stream through heat exchange.

3. The gas processing facility of claim 1, wherein:

the first cooler is configured to use an external refrigerant stream to cool the compressed gas feed stream through heat exchange.

4. The gas processing facility of claim 1, wherein the high-pressure expander cycle refrigeration system further comprises:

a liquid separation vessel configured to separate the liquid fraction and the remaining vapor fraction from the first expander.

5. The gas processing facility of claim 4, wherein:

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

the first cooler releases (i) a chilled gas feed stream, and (ii) a partially-warmed product stream after heat-exchanging with the compressed gas feed stream; and

the high-pressure expander cycle refrigeration system further comprises: a second cooler configured to further cool the compressed gas feed stream at least partially by indirect heat exchange with a refrigerant stream and the vapor fraction; and a second refrigeration loop having (i) a second compression unit configured to re-compress the refrigerant stream after the refrigerant stream passes through the second cooler, and (ii) a second expander configured to receive the re-compressed refrigerant stream, and expand the re-compressed refrigerant stream prior to returning it to the second cooler.

6. The gas processing facility of claim 5, wherein the high-pressure expander cycle refrigeration system further comprises:

a third compression unit in the first refrigeration loop for compressing the partially-warmed product stream after heat-exchanging with the compressed gas feed stream; and

a line for merging the compressed, partially-warmed product stream with the gas feed stream to complete the first refrigeration loop.

7. The gas processing facility of claim 5, wherein the second cooler sub-cools the chilled gas feed stream after the chilled gas feed stream leaves the first cooler.

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

9. The gas processing facility of claim 8, wherein:

the second cooler receives the partially-warmed product stream from the first cooler for further heat-exchanging with the compressed gas feed stream; and

releases a warmed product stream to a third compression unit to complete the first refrigeration loop.

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

11. The gas processing facility of claim 1, wherein the facility is located on (i) a floating platform, (ii) a gravity-based platform, or (iii) a ship-shaped vessel offshore.

12. The gas processing facility of claim 5, wherein:

the refrigerant stream comprises a gas selected from the group consisting of: nitrogen gas, nitrogen-containing gas, a side stream from the methane-rich gas stream, and the remaining vapor fraction, and combinations thereof; and

the refrigerant stream in the second refrigeration loop flows in a closed loop.

13. The gas processing facility of claim 1, wherein the at least one fractionation vessel in the gas separation unit operates on pressure swing adsorption (PSA) or rapid cycle pressure swing adsorption (RCPSA).

14. The gas processing facility of claim 13, wherein the at least one fractionation vessel in the gas separation unit further operates on temperature swing adsorption (TSA) or rapid cycle temperature swing adsorption (RCTSA).

15. The gas processing facility of claim 13, wherein the at least one fractionation vessel is configured to adsorb CO2, H2S, H2O, heavy hydrocarbons, VOC's, mercaptans, or combinations thereof.

16. The gas processing facility of claim 13, wherein each of the at least one fractionation vessel cooperates with other fractionation vessels to form a pressure swing adsorption system comprising:

at least one service bed providing adsorption,

at least one bed in regeneration undergoing pressure reduction, and

at least one regenerated bed held in reserve for use in the adsorption system when the at least one service bed becomes substantially saturated.

17. The gas processing facility of claim 13, further comprising:

a dehydration vessel configured to receive the natural gas feed stream and remove a substantial portion of water from the natural gas feed stream, and release a dehydrated natural gas feed stream to the at least one fractionation vessel.

18. The gas processing facility of claim 17, wherein the at least one fractionation vessel in the gas separation unit comprises a plurality of vessels in series, such that:

a first vessel comprises an adsorption bed for the removal of water remaining in the dehydrated natural gas feed stream;

a second vessel comprises an adsorption bed designed primarily for the removal of a desiccant from the dehydrated natural gas feed stream; and

a third vessel comprises an adsorption bed designed primarily for the removal of a sour gas component from the dehydrated natural gas feed stream.

19. The gas processing facility of claim 17, wherein the at least one fractionation vessel in the gas separation unit comprises a vessel containing a plurality of adsorbent beds in series, such that:

a first adsorption bed is designed to primarily remove water and other liquid components from the dehydrated natural gas feed stream;

a second adsorption bed is designed to primarily remove a desiccant from the dehydrated natural gas feed stream; and

a third vessel comprises an adsorption bed primarily for the removal of a sour gas component from the dehydrated natural gas feed stream.

20. A process for liquefying a natural gas feed stream, comprising:

receiving the natural gas feed stream at a gas separation unit, the gas separation unit having at least one fractionation vessel comprised of: a gas inlet for receiving a natural gas mixture comprising methane, an adsorbent material that has a kinetic selectivity for contaminants over methane greater than 5, such that the contaminants become kinetically adsorbed within the adsorbent material, and a gas outlet configured to release a methane-rich gas stream;

substantially separating methane from contaminants within the natural gas feed stream;

releasing a methane-rich gas stream from the gas separation unit;

directing the methane-rich gas stream into a high-pressure expander cycle refrigeration system;

compressing the methane-rich gas stream to a pressure that is greater than 1,000 psia (6,895 kPa) in order to form a compressed gas feed stream;

cooling the compressed gas feed stream to form a compressed, cooled gaseous feed stream;

expanding the cooled, compressed, gaseous feed stream to form a product stream having a liquid fraction and a remaining vapor fraction; and

separating the vapor fraction from the liquid fraction.

21. The process of claim 20, wherein the high-pressure expander cycle refrigeration system comprises:

a first compression unit configured to receive a substantial portion of the methane-rich gas stream and to generate the compressed gas feed stream;

a first cooler configured to cool the compressed gas feed stream to form the compressed, cooled gaseous feed stream; and

a first expander configured to expand the cooled, compressed, gaseous feed stream to form the product stream.

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

delivering at least a portion of the vapor fraction from the product stream to the first cooler as part of a first refrigeration loop; and

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

23. The process of claim 22, wherein:

the high-pressure expander cycle refrigeration system further comprises a liquid separation vessel; and

separating the vapor fraction from the liquid fraction is done using the liquid separation vessel.

24. The process of claim 23, further comprising:

releasing from the first cooler (i) a chilled gas feed stream as the product stream, and (ii) a partially-warmed product stream as a working fluid;

directing the partially-warmed product stream to a third compression unit; and

merging the compressed, partially-warmed product stream from the third compression unit with the methane-rich gas stream to complete the first refrigeration loop.

25. The process of claim 24, wherein the high-pressure expander cycle refrigeration system further comprises:

a second cooler configured to further cool the compressed gas feed stream at least partially by indirect heat exchange between a refrigerant stream and the vapor fraction; and

a second refrigeration loop having (i) a second compression unit configured to re-compress the refrigerant stream after the refrigerant stream passes through the second cooler, and (ii) a second expander configured to receive the compressed refrigerant stream, and expand the compressed refrigerant stream prior to returning it to the second cooler.

26. The process of claim 25, wherein the second cooler sub-cools the chilled gas feed stream after the chilled gas feed stream leaves the first cooler.

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

28. The process of claim 23, wherein the facility is located on (i) a floating platform, (ii) a gravity-based platform, or (iii) a ship-shaped vessel offshore.

29. The process of claim 23, wherein the at least one fractionation vessel in the gas separation unit operates on pressure swing adsorption (PSA) or rapid cycle pressure swing adsorption (RCPSA).

30. The process of claim 23, wherein the at least one fractionation vessel in the gas separation unit further operates on temperature swing adsorption (TSA) or rapid cycle temperature swing adsorption (RCTSA).

31. The process of claim 30, wherein the at least one fractionation vessel is configured to adsorb CO2, H2S, H2O, heavy hydrocarbons, VOC's, mercaptans, or combinations thereof.

32. The process of claim 31, further comprising:

passing the natural gas feed stream through a dehydration vessel in order to remove a substantial portion of water from the natural gas feed stream; and

release a dehydrated natural gas feed stream to the at least one fractionation vessel for contaminant removal.

33. The process of claim 32, wherein the at least one fractionation vessel in the gas separation unit comprises a plurality of vessels in series, such that:

a first vessel comprises an adsorption bed for the removal of water remaining in the dehydrated natural gas feed stream;

a second vessel comprises an adsorption bed designed primarily for the removal of a desiccant from the dehydrated natural gas feed stream; and

a third vessel comprises an adsorption bed designed primarily for the removal of a sour gas component from the dehydrated natural gas feed stream.

34. The process of claim 32, wherein the at least one fractionation vessel in the gas separation unit comprises a vessel containing a plurality of adsorbent beds in series, such that:

a first adsorption bed is designed to primarily remove water and other liquid components from the dehydrated natural gas feed stream;

a second adsorption bed is designed to primarily remove a desiccant from the dehydrated natural gas feed stream; and

a third vessel comprises an adsorption bed designed primarily for the removal of a sour gas component from the dehydrated natural gas feed stream.

35. A method for liquefying a natural gas feed stream, comprising:

receiving the natural gas feed stream at a gas processing facility;

passing the natural gas feed stream through a dehydration vessel in order to remove a substantial portion of water from the natural gas feed stream;

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

in the gas separation unit, passing the dehydrated natural gas feed stream through a series of adsorbent beds in order to separate methane gas from contaminants in the dehydrated natural gas feed stream using adsorptive kinetic separation;

releasing a methane-rich gas stream from the gas separation unit;

directing the methane-rich gas stream into a high-pressure expander cycle refrigeration system;

compressing the methane-rich gas stream to a pressure that is greater than 1,000 psia (6,895 kPa) in order to form a compressed gas feed stream;

cooling the compressed gas feed stream to form a compressed, cooled gaseous feed stream;

expanding the cooled, compressed, gaseous feed stream to form a product stream having a liquid fraction and a remaining vapor fraction.

36. The method of claim 35, wherein the series of adsorbent beds comprises:

a first adsorption bed for the removal of water remaining in the dehydrated natural gas feed stream;

a second adsorption bed designed primarily for the removal of a desiccant from the dehydrated natural gas feed stream; and

a third adsorption bed designed primarily for the removal of a sour gas component from the dehydrated natural gas feed stream.

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

38. The method of claim 36, wherein the first, second, and third adsorption beds reside in separate pressure vessels that are aligned in series with the flow of the dehydrated natural gas feed stream.

39. The method of claim 36, wherein each of the adsorbent beds comprises a solid adsorbent bed fabricated from a zeolite material.

40. The method of claim 37, wherein each of the adsorbent beds has associated with it two additional adsorbent beds to form three adsorbent beds, with:

a first of the three adsorbent beds being in service for adsorbing a selected contaminant;

a second of the three adsorbent beds undergoing regeneration; and

a third of the adsorbent beds being held in reserve to replace the first of the three adsorbent beds; and wherein

the regeneration is part of a pressure-swing adsorption process.

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

passing the compressed gas feed stream through a first heat exchanger in order to provide heat exchange with a cooled refrigerant stream, thereby forming a sub-cooled gas feed stream; and

passing the sub-cooled gas feed stream through a second heat exchanger in order to provide heat exchange with a cooling gas stream, thereby forming the compressed, cooled gaseous feed stream.

42. The method of claim 41, further comprising:

withdrawing a portion of the remaining vapor fraction from the product stream;

reducing the pressure of the withdrawn portion of the remaining vapor fraction down to a pressure of about 30 to 200 psia (207 to 1,379 kPa) to produce a reduced pressure gas stream;

passing the reduced pressure gas stream through the second heat exchanger as the cooling gas stream; and

releasing the reduced pressure gas stream from the second heat exchanger as a partially-warmed gas stream.

43. The method of claim 42, further comprising:

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

returning the partially-warmed gas stream to the dehydrated natural gas feed stream for compressing with the methane-rich gas stream.

44. The method of claim 36, wherein: expanding the cooled, compressed, gaseous feed stream comprises reducing the pressure of the cooled, compressed, gaseous feed stream to a pressure between about 50 psia (345 kPa) and 450 psia (3,103 kPa).

compressing the methane-rich gas stream comprises compressing the methane-rich gas stream to a pressure that is between about 1,200 psia (8,274 kPa) to 4,500 psia (31,026 kPa); and