Natural Gas Liquefaction System for Producing LNG and Merchant Gas Products

FIELD OF INVENTION

The present invention relates to the manufacture of liquid natural gas (LNG), liquid propane, butane and heavier hydrocarbon gases commonly referred to as natural gas liquids (NGL) and merchant liquid gases such as liquid nitrogen (LN), gaseous nitrogen (GAN), liquid oxygen (LOX), gaseous oxygen (GOX), and liquid argon (LAR) utilizing an air separation unit (ASU) and a combination of liquefaction units that liquefy both natural gas and nitrogen, the LNG, NGL and LN gases being derived from a conventional natural gas (NG) pipeline.

CROSS REFERENCE TO RELATED PATENTS

Of interest is commonly owned U.S. Pat. No. 6,131,407 entitled Natural Gas Letdown Liquefaction System filed Mar. 4, 1999 in the name of Robert Wissolik and U.S. Pat. No. 6,669,774 entitled Gas Liquefaction Method Using Natural Gas and Mixed Gas Refrigeration in the name of Rashad et al. assigned to Praxair Technology, Inc., both of which patents are incorporated by reference herein in their entirety.

BACKGROUND OF INVENTION

U.S. Pat. No. 6,131,407 discloses a natural gas letdown liquefaction system. A let down station employs a control valve or the like to reduce relatively high pipeline gas pressures, e.g., 715 psia, to lower user pressure levels, e.g., 200 psia or lower. This system uses the high gas pressure of the pipeline to assist in the generation of refrigeration. In this system, a liquid natural gas (LNG) generator generates LNG which is supplied to a nitrogen liquefaction section as an internal process intermediate gas to generate industrial merchant gas final output products such as liquid argon, liquid or gaseous oxygen or gaseous nitrogen using an air separation unit (ASU). The ASU may be a conventional nitrogen or oxygen plant.

In one embodiment, the liquid nitrogen (LN) is also stored as a product. However, the nitrogen is refrigerated by the LNG, each gas being processed in a closed cycle independent of each other. That is, the natural gas (NG) is recycled in a closed loop through a LNG generator comprising a cascaded bank of first heat exchangers using only NG. The N₂is recycled in a closed loop in a separate independent nitrogen liquefaction section using a cascaded bank of second heat exchangers, which feed liquid N₂to the ASU. The LNG is fed to and processed in the N₂liquefaction section heat exchangers to liquefy the N₂as an intermediate gas.

In another embodiment, one bank of cascaded heat exchangers are employed to generate both liquid natural gas and liquid nitrogen. This cycle, however, is only used when less natural gas is available to make the desired amounts of merchant gas products. In this embodiment, and the in other disclosed embodiments, no liquid LNG or N₂products are provided outside that generated by the ASU outputting the desired non-LNG industrial merchant gas products.

U.S. Pat. No. 6,694,774 to Rashad discloses a gas liquefaction method also using a natural gas letdown system with natural gas and mixed gas refrigeration to generate LNG product. This reference discloses an output at line 36, FIGS. 1 and 2 and at line 79, FIG. 3. Line 36 comprises LNG product, and line 79 comprises industrial gas as liquefied nitrogen. The liquid nitrogen and the LNG are produced in different processes employing separate and independent systems in separate different corresponding manufacturing plants which is costly. Such different plants are not recognized by the prior art as being capable of being combined into a single manufacturing plant as recognized by the present inventor with the resulting considerable cost savings in the construction of such plants.

Air and oxygen are not liquefied directly with natural gas due to safety concerns. Traditionally, liquid natural gas (LNG) plants are constructed using a variety of refrigeration methods. Some use a nitrogen gas expansion cycle to create the refrigeration required to liquefy the natural gas. High pressure nitrogen gas is expanded, which results in relatively low temperatures that can then be used as refrigeration to liquefy the natural gas.

Airco Industrial Gases designed and installed a number of such plants in the early 1970s. One such plant was constructed for the Southern Connecticut Gas Company. Other companies use a mixed refrigerant cycle as done by British Oxygen Company in Avonmouth, England. A mixture of carefully chosen hydrocarbons is liquefied selectively, and the liquid is throttled to lower pressure providing the refrigeration necessary to liquefy both the mixed refrigerant and the natural gas feed stream. Air Products has built many plants using what they call the propane precooled multicomponent (mixed refrigerant) refrigeration cycle, or some variation of this process cycle. Air Products has published articles about their cycles as has Linde, a major corporate player in the LNG plant building business.

Linde also uses a mixed refrigeration cycle. Another method for generating refrigeration uses expanded natural gas available from natural gas pipeline letdown stations as done by Airco for the UIG Corporation in Reading, Pa. U.S. Pat. No. 6,694,774 to Rashad teaches this method of producing LNG using letdown stations in combination with a number of mixed refrigerant cycles.

The refrigeration cycle of choice for the industrial gas business is the nitrogen gas expansion cycle. It is the dominate cycle used in the United States and in most other parts of the world. The only exceptions may be found on newer merchant gas manufacturing plants. These plants take advantage of LNG to reduce the power consumption in manufacturing merchant gas liquid products. British Oxygen Company built one such plant in Dandenong, Australia. LNG at low pressure is vaporized and warmed by heat transfer using higher pressure nitrogen, and the nitrogen gas is liquefied by the warming natural gas. The refrigeration inherent in the LNG is saved, resulting in reduced power consumption for manufacturing industrial gas liquids. U.S. Pat. No. 6,130,407, discloses using a letdown station to produce LNG, which in turn is used in an internal process as an intermediate gas to liquefy the nitrogen, which in turn is used for the production of industrial merchant liquid and gaseous gas products as well as the LNG intermediate gas.

U.S. Pat. No. 6,449,984 to Paradowski discloses the liquefaction of natural gas and extraction of nitrogen from the natural gas under pressure to obtain liquid natural gas (LNG) 24 free of nitrogen product and waste gaseous nitrogen 29 essentially free of hydrocarbons that is vented to the atmosphere. There is no disclosure or suggestion of producing liquid nitrogen as a product nor the production of merchant gas products such as liquid oxygen, gaseous oxygen or gaseous argon. While the disclosed products produced in this reference include liquid natural gas and gaseous waste nitrogen, industrial merchant gas products such as liquid oxygen, gaseous oxygen or gaseous argon are not manufactured.

Qualls US Patent Application Nos. 2007/0012072 and Qualls et al. Patent Application No. 2012/0042690 disclose an LNG facility with integrated natural gas liquids (NGL). These applications are silent as to the generation of nitrogen and merchant liquid and gaseous gases.

US Patent Application No. 2008/0264099 to Mock et al. discloses LNG product and domestic natural gas product. The LNG process uses a mixed refrigerant process. The domestic gas product is defined as any gaseous predominantly methane stream originating within an LNG facility and routed to an external location prior to sale or use. Nitrogen or merchant gas, liquid or gaseous, product is not disclosed.

US Patent Application No. 2008/0271480 to Mak and US Patent Application No. 2013/0061633 to Mak et al. disclose integrated natural gas liquids (NGL) recovery and LNG liquefaction. The production of nitrogen or other industrial merchant gases, liquid or gaseous, is not disclosed.

US Patent Application No. 2010/0126186 to Marriott et al. discloses a method and apparatus for generating a gaseous hydrocarbon stream from a liquefied hydrocarbon stream useful for the starting up of a liquefaction plant. Nitrogen generation or other industrial merchant gases, liquid or gaseous, production is not disclosed.

PCT International Patent Application No. WO2013/052325 to Sethna et al. discloses a system for integration of a liquefied natural gas liquefier with the production of liquefied natural gas from a methane containing gas stream. The methane gas stream is fed through a heat exchanger to liquefy the natural gas while capturing gaseous nitrogen. The liquefied natural gas is captured and the Nitrogen gas recovered, fed through the heat exchanger to recover cold and purified. Only LNG is stored as product. Neither nitrogen nor other industrial merchant gases are produced as a product.

The present inventor recognizes that none of the aforementioned patents and applications disclose or suggest individually, or in combination, the production of LNG product, LN product, NGL product and industrial merchant liquid and gaseous product in the same plant. Typically, present manufacturers in this field either produce LNG product or merchant gas products in separate plants as represented by the aforementioned patents. The aforementioned U.S. Pat. No. 6,131,407 avoids this problem by using LNG to make the merchant gas products in an internal process and thus is less costly than the prior art plants. However, a separate plant is suggested as being needed to manufacture LNG as a product such as illustrated by the Rashad patent among others. Several of such plants may need external supplies of liquid nitrogen (LN) to make the desired merchant gas end products. The aforementioned Rashad patent discloses that separate and independent plants are needed to produce either LNG product, or the nitrogen merchant liquid product.

The present inventor recognizes that using separate plants to manufacture LNG and merchant gases such as O, N₂, and Ar is costly duplication of facilities. There are no plants presently in existence that produce both LNG product and industrial gas merchant liquid or gaseous O, Ar, and liquid and gaseous N₂product together. This is true even though a number of companies build both LNG plants and industrial gas merchant plants as independent separate gas manufacturing plants. Air Products, Airco, Air Liquide, and Linde are examples of companies that have built both types of gas manufacturing plants as separate facilities over the past forty years. The number of plants built by just these four companies is in the hundreds.

The development of vast new quantities of natural gas made available using advanced technologies has created a large economic incentive to replace diesel fuel with compressed natural gas and LNG. The LNG industry has many facets of the business that are common to the industrial merchant gas business even though these industries have developed along separate paths. An example is the economic distances of product distribution. The economics tend to dictate that product can only be distributed in most cases for a distance of two hundred to three hundred miles before distribution costs become prohibitive. Distribution costs dictate that numerous smaller plants are required to satisfy demand in their local area. This situation is exactly the same for the industrial gas merchant liquid gases nitrogen and oxygen.

As recognized by the present inventor, in contrast to present commercial gas production plants, according to an embodiment of the present invention, is the advantage of combining the product production in one plant, such as LNG and merchant gases O₂, N₂, and Ar.

Such an advantage is most easily seen by the implementation of the nitrogen gas expansion cycle shown in FIG. 1 of U.S. Pat. No. 6,131,407. The two nitrogen gas expanders required in the LNG plant and the two nitrogen gas expanders required in a merchant gas manufacturing plant can be combined into two larger nitrogen gas expanders according to an embodiment of the present invention. Sharing this process service is recognized by the present inventor as improving the overall economics of the combined plant.

A further economic enhancement that is recognized by the present inventor is realized due to economies of scale for the larger expansion equipment. The same is especially true of a nitrogen recycle compressor, and is also true for many other pieces of process equipment.

Among the objects and advantages according to an embodiment of the present invention as recognized by the present inventor is to produce LNG and liquid nitrogen, and merchant gaseous nitrogen, liquid and gaseous oxygen, and liquid argon together in the same plant rather than in separate plants as presently done. The economic benefit of producing both products together is realized when almost all of the compression equipment, expansion equipment, cold boxes, heat exchangers, process piping systems, instrumentation, controls, electrical equipment, buildings, computers, cooling water system, utility systems, loading facilities, and like systems can be shared according to an embodiment of the present invention.

The benefit is readily apparent as recognized by the present inventor when cost estimates for the capital of the combined plant are generated. The combined plant is estimated to save from 20% to 30% or more of the capital that would be required to build a separate LNG plant and a separate merchant liquid plant as presently done in the prior art.

The savings can be realized using a number of refrigeration cycles or by using other less conventional natural gas feed sources as recognized by the present inventor. The savings also can be realized with or without the use of natural gas pipeline letdown stations. The use of letdown stations is believed to improve the power consumption of a combined plant, but the combined plant without a letdown station does not share any power advantage over two separate plants. The amount of savings will depend on the situation encountered at a particular site.

Another object and advantage of the inventive system as recognized by the present inventor is when merchant liquid tanker trucks can use LNG fuel at spigot (rack) pricing without distribution costs, and possibly also without taxes, since LNG would be produced by the same plant as a product for such use. That is, as LNG is gradually coming into use as a fuel for vehicles, the trucks that are used to transport the LNG can also be fueled by the same facility supplying the LNG at considerable cost savings. Furthermore, most of the distribution for both industries is accomplished using tanker trucks that haul product from the plant to the customer and then return to the plant for refill. Long haul trucks returning to the same location are ideally suited for using LNG fuel at the present time. This extends the range of economically viable product sales.

Another object and advantage of the inventive system as further recognized by the present inventor is realized when the LNG portion of the plant utilizes utility nitrogen liquid at spigot pricing without distribution costs, and can use common liquid nitrogen storage.

Another object and advantage of the present invention is the use of NG flash gas as a fuel gas for gas engine drivers on selected compressors and electrical generator sets. This is especially valuable if the pipeline company will not take back the NT regenerated gas. It is also valuable when using non-conventional natural gas feed sources such as purified landfill gas.

A further object and advantage realized by the present invention is product diversity. This diversity is similar to the practice of stock diversification recommended by financial advisers. LNG product is currently the more profitable product in a newer market. But this could change as more LNG becomes available in the market resulting in stiffer competition. The industrial gases, however, are in a mature market with relatively lower pricing due to stiff competition. The pricing with these products is expected to rise slowly, but will rise.

A further object is the fact that according to an embodiment of the present invention wherein both LNG and LN products can be made in a common plant facility results in both products are less costly to make and therefore are more competitive.

In another embodiment, the present inventor also recognizes that the same plant can be used to manufacture propane and butane as an additional product, referred to as natural gas liquids or NGL, as distinguished from LNG (liquid natural gas comprising substantially methane and ethane) in addition to LN (liquid nitrogen) and LNG. This results in a further saving of capital costs in building separate plants using present technology in liquefied gas plant constructions.

SUMMARY OF THE INVENTION

A system for producing liquid natural gas (LNG), and liquid nitrogen utilizing a methane rich natural gas source and an air separation unit (ASU) to produce merchant gases according to an embodiment of the present invention comprise an LNG generator including at least one heat exchanger responsive to applied processed pipeline natural gas for producing liquid natural gas; a nitrogen liquefaction section for liquefying nitrogen received from the ASU; a liquid nitrogen storage unit and an LNG storage unit;

a first control valve for applying a predetermined amount of LNG in a selected first portion of the produced LNG to the LNG storage unit as product; and a second control valve for applying a second portion of the produced LNG by the LNG liquefaction generator to the nitrogen liquefaction section for assisting in the liquefaction of nitrogen as determined by the selected first portion amount; the liquefaction section for assisting in the production of the merchant gases as products by the ASU; and

a third control valve for applying liquid nitrogen from the liquefaction section to the liquid nitrogen storage unit for storing the liquefied nitrogen as product.

the LNG generator is arranged to be responsive to applied pressurized nitrogen and includes a nitrogen gas expansion arrangement for causing the pressurized nitrogen to produce refrigeration to assist in liquefying the natural gas into LNG in the LNG generator.

In a further embodiment, a nitrogen feed compressor is responsive to nitrogen gas fed from the ASU to provide compressed nitrogen to the LNG generator.

In a further embodiment, a compander is provided for supplying compressed and then expanded natural gas (NG) to the LNG generator.

In a further embodiment, the LNG generator includes a control valve and separator for producing vaporized low pressure and flashed natural gas and including a bank of heat exchangers for heating to ambient temperature the flashed natural gas passed through the heat exchangers and at least one compressor for compressing the passed natural gas to pipeline pressure.

In a further embodiment, an arrangement is included for recovering medium and low pressure nitrogen from the liquefaction section and recycling the recovered nitrogen through compression into the LNG generator.

In a further embodiment, the LNG generator includes a bank of heat exchangers, the arrangement for recovering nitrogen includes a series of compressors for sequentially compressing the nitrogen and for then selectively applying the compressed nitrogen to the LNG generator to selected ones of the heat exchangers.

In a further embodiment, a series of expanders are included each for expanding the compressed nitrogen applied to a different one of the selected ones of the heat exchangers.

In a further embodiment, the LNG generator produces liquid natural gas LNG wherein the liquid is produced by a series of nitrogen expanders and a series of nitrogen compressors for generating nitrogen refrigeration to assist in the production of the LNG.

In a further embodiment, the nitrogen liquefaction section comprises a bank of heat exchangers, a compressor arrangement and a gas flash arrangement for recycling nitrogen gas supplied by the ASU through the heat exchangers for the liquefying of the nitrogen in cooperation with the liquefied natural gas and for selectively feeding the liquefied nitrogen to a selected one or both of the ASU and nitrogen storage unit.

In a further embodiment, the nitrogen liquefaction section cooperates with the ASU for generating liquid nitrogen.

In a further embodiment, the nitrogen liquefaction section comprises a series of heat exchanger, a separator, and at least one nitrogen gas flash valve which cooperates with the ASU to produce liquid nitrogen.

In a further embodiment, a letdown station is in the pipeline to assist in reducing power required and for providing refrigeration to the LNG liquefaction generator.

In a further embodiment, a cooling heat exchanger is included comprising an ammonia refrigerant and an expander for expanding and cooling the natural gas output of the cooling heat exchanger coupled to the LNG generator.

In a further embodiment, the LNG generator comprises a series of nitrogen expanders for cooling nitrogen gas applied to a cascaded series of heat exchangers in the LNG generator.

In a further embodiment, the ASU supplies nitrogen to a series bank of compressors whose output of compressed nitrogen is applied to a series bank of heat exchangers in the LNG generator.

In a further embodiment, the LNG generator comprises a series of nitrogen expanders for cooling nitrogen gas applied to a cascaded series of heat exchangers in the LNG generator, the expanders comprising corresponding companders forming the compressors.

In a further embodiment, the LNG generator includes at least one expander and at least one cooling heat exchanger comprising an ammonia refrigerant for cooling at least one of nitrogen and natural gas.

In a further embodiment, the LNG generator includes at least one expander for expanding natural gas for cooling natural gas in the generator and at least one cooling heat exchanger comprising an ammonia refrigerant for cooling nitrogen gas used to cool the natural gas in the generator.

In a further embodiment, the LNG generator includes at least one expander for expanding and cooling natural gas applied thereto.

In a further embodiment, the system includes at least one nitrogen expander for expanding nitrogen gas applied thereto.

In a further embodiment, the system includes at least one natural gas expander for expanding recycled natural gas applied thereto.

In a further embodiment, the LNG generator further includes at least one natural gas expander and at least one nitrogen gas expander.

In a further embodiment, the LNG generator utilizes at least one ammonia gas refrigeration cooler, a nitrogen gas refrigeration cooling system and a mixed gas cooling refrigeration system.

In a further embodiment, a system is provided utilizing a source of a methane rich natural gas for producing 1) liquid natural gas (LNG), 2) natural gas liquids (NGL) predominately comprising propane and butane and heavier hydrocarbons, 3) liquid nitrogen and 4) an air separation unit (ASU) to produce merchant gases. The system including an arrangement for producing NGL product from the applied processed source of natural gas and for storing the NGL in a NGL storage unit.

In a further embodiment, the LNG generator includes a control valve and separator for producing vaporized low pressure and flashed natural gas and including a bank of heat exchangers for heating to ambient temperature the flashed natural gas passed through the heat exchangers whereby the passed natural gas can be partially or completely fed to an electrical generator set to generate electricity.

BRIEF DESCRIPTION OF THE DRAWING

FIGS. 1
a and 1b illustrate a first embodiment comprising a process flow diagram of a liquefaction refrigeration system to liquefy natural gas, nitrogen and selected merchant gases without a letdown station and includes a generator for generating liquid natural gas LNG, a liquefaction section for generating liquid nitrogen (LN) and an air separation unit (ASU) for generating merchant gases such as liquid argon LAR, gaseous and liquid oxygen GOX, LOX and gaseous nitrogen GAN products.

FIGS. 2
a and 2b illustrate a second embodiment of the present invention comprising a process flow diagram similar to that of FIGS. 1a and 1b with a letdown station illustrating an LNG generator, a liquid nitrogen (LN) liquefaction section for generating LN and an air separation unit (ASU) for generating merchant gas products LAR, GOX, LOX, and GAN products, utilizing two after cooling units and an expander in a LNG heat exchanger bank and one high pressure compressor and one low pressure compressor with associated cooling units using ammonia refrigerants;

FIGS. 3
a and 3b illustrate a third embodiment of the present invention comprising a process flow diagram similar to that of FIGS. 1a and 1b illustrating a LNG generator, an LN liquefaction section and an ASU for generating liquid and gaseous industrial merchant gas products LAR, LAX, LOX and GAN utilizing four N₂compressors in a N₂feedback cycle and three expanders for the LNG generator;

FIGS. 4
a and 4b illustrate a fourth embodiment of the present invention comprising a process flow diagram similar to that of FIGS. 1a and 1b illustrating a LNG generator, an LN liquefaction section and an ASU for generating liquid and gaseous industrial merchant gas products utilizing a similar feedback cycle as in FIGS. 3a, 3b and three expanders and two compressors for the LNG recycling for use with the LNG generator, all of the aforementioned embodiments using a similar nitrogen liquefaction section for generating LN;

FIGS. 5
a, 5b and 5c illustrate a fifth embodiment of the present invention comprising a process flow diagram illustrating the LNG generator of FIGS. 4a and 4b, including an ASU for generating LN and liquid and gaseous industrial merchant gas products, using a nitrogen liquefaction section having a different feedback cycle using the ASU for nitrogen refrigeration;

FIGS. 6
a and 6b illustrate a sixth embodiment, comprising an LNG generator having a cascaded set of five heat exchangers, three separator units, six ammonia refrigerant after coolers and an expander for generating LNG, a nitrogen liquefaction section for generating LN, and an ASU for generating liquid nitrogen LN and for generating liquid and gaseous industrial merchant gas products, using three refrigerants, ammonia, nitrogen and a mixed refrigerant in respective three closed refrigeration systems; and

FIGS. 7
a and 7b illustrate a seventh embodiment, including an LNG generator comprising a cascaded set of five heat exchangers, six ammonia refrigerant after coolers, two separator units, a distillation unit, a pump and two expanders, a separate nitrogen liquefaction section for generating LN, an arrangement for generating natural gas liquid (NGL) products, and an ASU for generating liquid nitrogen LN and liquid and gaseous industrial merchant gas products.

DETAILED DESCRIPTION

In the various figures, the source of natural gas is shown as a pipeline. However, this is by way of illustration and not limitation. It should be understood that natural gas source may be in any form such as a landfill or any other source of non-pipeline source of methane rich natural gas. In FIGS. 1a and 1b, system 15 is of relatively lower cost than the other embodiments disclosed herein. There are no natural gas NG expanders and no ammonia refrigeration units to provide added cooling as in these other embodiments. System 15 provides only nitrogen refrigeration. A letdown station could optionally be used in this embodiment. If a letdown station is used, it reduces the output pipeline pressure. Thus, there may be no need to compress the gas being returned to the relatively high pipeline pressure as without a letdown station. This saves power.

System 15 utilizes two nitrogen (N₂) expanders in the LNG generator and three N₂feed compressors according to an embodiment of the present invention. FIGS. 1a and 1b are related and illustrate a single system wherein the same Roman numerals of the two figures identify common interconnected gas transmission lines. A similar notation of common lines in a single system depicted by multiple figures is used in the remaining figures. Parts in the different figures with the same reference numerals comprise identical components. However, it should be understood that while the components may be identical in structure, the refrigerants and gases being processed by such components may differ.

In FIGS. 1a and 1b, an incoming stream 12 of natural gas (NG) is diverted from pipeline 11 to pipeline 10. This stream is conventional and may comprise any combination of gases including methane, butane, propane, CO₂and heavier hydrocarbons as known in this art. The pipeline NG stream may typically comprise 80% to 95% methane, and lesser, but different amounts of the other gaseous products. The stream 12 is under high pressure, typically 350 to 1000 psia, but in this case by way of example, may be at a pressure of about 715 psia and at ambient temperature, assumed to be generally at about 70° F. All temperatures given hereinafter will be in ° F. All temperatures and pressures given herein are approximate and could vary as would be understood by one of ordinary skill. The input pressure could be lower, especially if the natural gas is being fed from a sub-main, but is assumed to be 715 psia for illustrative purposes only. An optional letdown station 13, shown in phantom, is not present in this embodiment. However, a letdown station could be used in this embodiment if available. If the pipeline pressure is 100 psia, for example, then a feed compressor will be needed to raise the pressure. The pipe 10 downstream from the stream in pipeline 11 may have a slightly reduced pressure stream 14 of about 714 psia or lower. With respect to the various heat exchangers in the different figures, some are shown with a different number of flow channels. However, the exchangers with the same reference numerals are the same in construction with the different channels shown representing only the flow channels in use in that particular embodiment. This is only a matter of simplicity of illustration. If a different smaller heat exchanger is desired needing fewer gas flow channels, then one of ordinary skill could provide the same in the interest of cost savings.

Natural gas NG, which may comprise methane and other gases and/or fluids of different components as discussed above, for a specific customer or group of customers is withdrawn from the pipeline 11 at stream 12. The gas continues along the pipe 10 to outlet 90. The natural gas flows from stream 12 into NG liquefaction system 15 via stream 16. The natural gas diversion starts with stream 12. Stream 16 feeds into a first conventional process separator 17 which removes any undesirable liquids in the natural gas stream 16. Vapor from the first process separator 17 passes to a conventional moisture adsorption system comprising dryers 18. The dryers 18 remove moisture and CO₂from the incoming natural gas stream 16′. The two dryers 18 represent one dryer with two drying beds, which beds can be switched so that the stream from separator 17 can be applied to either dryer bed depending upon which of the dryers 18 is regenerated and which dryer has its bed being loaded with moisture and CO₂from the incoming stream 16′. This switching action is represented by the dashed lines showing that either of dryers 18 may be used in the incoming stream and the other in the return regeneration NG stream 74′ in the regeneration mode.

Stream 74 at the output of compressor 73 and its associated after cooler 73′ (all such after coolers may use cooling water as a refrigerant as known in this art) is returned to the selected dryer 18 from the NG refrigeration system generator 91 (FIG. 1b) and, therefore, is dry natural gas free of CO₂. The dryer 18 having output stream 74′ is being regenerated, while the other dryer 18 having output stream 19, is drying the incoming gas stream 16′ from separator 17. One of the dryers 18 is regenerated at a time by the gas, stream 74, returning from compressor 73 and its associated cooler 73′. Stream 71 from the liquefaction section 55 and stream 72 from the generator 91 are combined and inputted into compressor 73. If stream 74 has insufficient flow to properly regenerate dryer 18, then a small natural gas slip stream (not shown) is taken from dryer 18 discharge, flashed, and combined with stream 74 to make sufficient flow for proper dryer regeneration.

While removing the C0₂at ambient temperature by dryers 18 requires relatively large adsorbers and more energy, it does not waste refrigeration, which tends to be in short supply in most applications of this technology.

The dryers 18 selectively remove moisture and CO₂from the natural gas depending upon which one is in the incoming stream 16′ to prevent hydrate formation and frozen CO₂when the natural gas is cooled later in the cycle. Mercaptans used to impart an odor to the natural gas are also selectively removed in the incoming stream 16′ and corresponding dryer 18 as are aromatic hydrocarbons.

After drying by the selected dryer 18, the natural gas stream 19 is fed directly into a first heat exchanger 20 in liquid natural gas (LNG) generator 91, FIG. 1b. Generator 91 comprises a series bank of heat exchangers 20, 21 and 22, expanders 23 and 24 having respective corresponding compressors 23′ and 24′ (FIG. 1a), control valve 25 and separator 26. The heat exchanger 20, as are all of the heat exchangers disclosed herein, are compartmentalized with isolated fluid channels represented by the udulating lines depicted in each heat exchanger block. These lines represent separate gas flow channels for fluid isolating the different gases flowing through the heat exchangers from each other so that the only coupling of the gases in a heat exchanger is by thermal heat transfer from gas to gas.

Natural gas stream 19, FIG. 1b, at about 700 psia and ambient temperature, is fed into the respective bank of heat exchangers 20, 21 and 22 for liquefaction to about −205° F., stream 19′ The substantially liquefied gas is fed to separator 26 through control valve 25 where the gas is flashed to about 20 psia. The liquefied NG stream 28 at about −251° F. is outputted from the separator 26 and fed through control valves 27 and 29. A predetermined calculated portion of the LNG is passed through the valve 27 to storage tank 92.

After stream 19 is chilled in the first heat exchanger 20 and further chilled in the second and third heat exchangers 21 and 22, the temperature of the resulting stream 19′ is approximately minus 205° F. and, when throttled by control valve 25 results in a stream 19″ having about 80% liquefied natural gas (LNG) which could differ according to a given implementation. This mixed phase stream 19″ is inputted to the separator 26. The cold gas and liquid (LNG) are separated by separator 26. Pressure level of the stream 19″ may be varied, but in this example the pressure is kept at about 20 psia, and at a temperature of approximately minus 251° F. The LNG from the separator 26, stream 28, is fed into the heat exchanger 30 in nitrogen liquefaction section 55 through control valve 29 as stream 71′. Stream 71′ is at about −254° F. and about 18 psia.

The calculated portion of the LNG gas, stream 28, fed to valve 29 is determined by the setting of control valve 27. Separator 26 may be elevated to provide a gravity induced pressure head forcing the LNG product into tank 92 via valve 27, or the LNG may be pumped by a pump (not shown) into tank 92 via valve 27. This amount is important as it is set to pass a predetermined amount of LNG through the valve 29 to the liquefaction section 55. The amount of LNG fed to the liquefaction section 55 is that value that will result in the production of the predetermined desired amount of liquid nitrogen to be produced by the liquefaction section 55, the amount of nitrogen produced depending upon the amount of refrigeration available from the supplied LNG. The LNG is used as a major assist in the generation of liquid nitrogen LN by section 55. The amount of LNG fed to the section 55 is calculated to produce a given amount of LN by section 55 in combination with the other aspects of the section 55 refrigeration elements used together with the LNG to generate the LN.

The remaining portion of the LNG not passed to section 55 is fed to the tank 92 for storage via valve 27. The LNG in tank 92 is then removed as product at output 93 for transportation, typically by tanker trucks (not shown). Such trucks if fueled by LNG could also be fueled at output 93 also for efficient use of the LNG available. Stream 72′ is outputted by separator 26 in the generator 91 as flash natural gas from the valve 25, which is then fed through the bank of respective heat exchangers 22, 21 and 20 for cooling of incoming NG stream 19 forming warm output stream 72 at about 70° F. and at about 15 psia. Thus stream 72′ from the separatort 26 assists in the cooling of stream 19 in combination with other streams applied to the heat exchangers of generator 91 as discussed below.

In FIG. 1a, NG stream 72 is combined with NG stream 71, also at 70° F. and 15 psia, from heat exchanger 30, FIG. 1b, in the liquefaction section 55, whose input is LNG stream 71′. The stream 72 outputted by heat exchanger 20 of LNG generator 91, FIG. 1b, is combined with warm NG stream 71, FIG. 1a, and applied to compressor 73 and its associated cooler 73′ forming stream 74. Stream 74 is applied to a selected dryer 18 for regeneration of that dryer forming stream 74′, which is returned to the input stream 14 through booster compressor 75 and its associated cooler 75′ as output stream 76. Compressor 75 matches the pressure of the output stream 74′ of the selected dryer 18 to that of pipeline stream 14 and may or may not be necessary depending upon whether a letdown station 13 is employed. The natural gas stream exiting compressor 75 (if required) can be partially or completely diverted to an electrical generator 755 through line 754.

In FIG. 1b, the liquefaction section 55 is substantially the same in FIGS. 2b, 3b and 4b and thus the description of section 55 in FIG. 1b is representative. The liquefaction section 55 comprises a series coupled bank of heat exchangers 30, 31 and 32, separator 34, a throttling control valve 35 between LN stream 45′″, at about 84 psia and about −287° F., outputted from separator 34 and stream 45₃′″, at about 19 psia and about −316° F., applied as an input to heat exchanger 32 and a second control valve 36 having an input stream 45₄′″ at about −314° F. that outputs liquid nitrogen LN at stream 37 at about −318° F. The separator 34 separates the vapor-liquid stream, forming nitrogen stream 45″ and vapor stream 39′.

In FIG. 1a, stream 45, the stream formed from compressed stream 43 merged with stream 45′, is applied to heat exchanger 30 of the liquefaction section 55, FIG. 1b, at about 410 psia. In FIG. 1b, Nitrogen stream 45, to be cooled from about 85° F., is applied as an input to the cascaded series of respective heat exchangers 30 and 31 and outputted from exchanger 31 as stream 45″. Stream 45″ is applied to separator 34 via flash control valve 33. Separator 34 outputs the cooled nitrogen stream 45′″, which is divided into streams 45₁′″ and 45₂′″. These streams are applied respectively to heat exchanger 32 and flash control valve 35. The valve 35 output stream 45₃′″ and is inputted to heat exchanger 32 for further cooling of stream 45₁′″. The heat exchanger 32 output stream 45₄′″, which comprises the cooled input stream 45₁, is passed through flash control valve 36 and applied to storage tank 50 as liquid nitrogen LN product, stream 37. The LN product is withdrawn from the tank 50 via outlet 51.

The separator 34 of liquefaction section 55, FIG. 1b, receives the flash vapor from valve 33 outputting it as stream 39′ applied to the respective series cascaded respective heat exchangers 31 and 30. whose output is warmed nitrogen gas stream 39 merged with stream 41, FIG. 1a.

In FIG. 1b, the heat exchanger 31 nitrogen input stream 38″, i.e., the output of exchanger 32, is applied as an input stream to heat exchanger 31. Stream 38″ applied to the respective series of exchangers 31 and 30 is outputted from heat exchanger 30 as warmed nitrogen stream 38. The stream 38″ output of exchanger 32 is inputted to exchanger 32 as nitrogen stream 45₃′″ via valve 35 as cold flash gas at about −316° F. with some liquid and vapor at about 19 psia.

Air separation unit 65, FIG. 1a, outputs nitrogen stream 46 (from a nitrogen plant or oxygen plant) which combines with nitrogen stream 41 as a nitrogen input to feed compressor 42, at 70° F. 79 psia, forming stream 41′. Stream 41′ applied to serial bank of respective compressors 42, 23′, 24′ and corresponding coolers 42′, 23″ and 24″, which output high pressure warm nitrogen stream 43 at 410 psia and 85° F. The compressors 23′ and 24′ are associated with expanders 23, 24 and may be companders (compressor/expanders, typically one unit). Stream 43 is divided into two nitrogen streams 45′ and 45.

Stream 45′, FIG. 1b, is inputted into heat exchanger 20 of the LNG generator 91. The heat exchanger 20 output stream is split into two streams 45₁and 45₂each at about 396 psia and about −50° F. Stream 45₁is applied to expander 23 and stream 45₂is applied to heat exchanger 21 for further cooling. The output nitrogen stream of expander 23 is at about 83 psia and about −182° F. The nitrogen stream 45₃output of heat exchanger 21 at about 395 psia and about −120° F. is applied to expander 24 whose output is stream 45₄is about 84 psia and about −230° F. Stream 45₄is inputted into the series bank of respective heat exchangers 22, 21 and 20 for cooling the NG input stream 19, and outputted as warm nitrogen at about 70° F., stream 44. In FIG. 1a, stream 44 is combined with nitrogen streams 39 and 40 to form stream 41, which is at about 70° F. and at about 79 psia.

In the liquefaction section 55, FIG. 1b, high pressure warm nitrogen stream 45, at about 85° F. and about 410 psia, is applied to the series of cascaded respective bank of heat exchangers 30, 31 for cooling. The cooled stream 45 exits exchanger 31 as output stream 45″ at about −255° F. Stream 45″ is applied to separator 34 through control valve 33 as flash gas at about 84 psia and further cooled by valve 33 to about −287° F. The output stream 45′″ of separator 34 is split into two streams 45₁′″ and 45₂′″. Stream 45₁′″ is applied as an input to heat exchanger 32 which is further cooled by stream 45₂′″ applied to heat exchanger 32 in a reverse direction as stream 45₁′″ through flash control valve 35 and at about 19 psia and about −316° F.

The cold output vapor stream 39′ of separator 34 is applied as an input to the respective cascaded heat exchangers 31, 30 to provide cooling to the inputted nitrogen stream 45 applied to the heat exchangers in the reverse direction as stream 45, producing stream 45″. The stream 39′ exits these heat exchangers as stream 39, which is combined with stream 44 as discussed above to form stream 41 applied to compressor 42, FIG. 1a.

Nitrogen stream 45₂′″ derived from separator 34 output stream 45′″ is applied as an input to heat exchanger 32 through valve 35 forming stream 45₃′″ applied to the bank of heat exchangers 32, 31 and 30 in a direction opposite to the fed direction of stream 45. The output of exchanger 30 is stream 38. In FIG. 1a, stream 38 is compressed by compressor 54 and cooled by its associated cooler forming stream 40 which is merged with streams 39 and 44 forming stream 41.

In FIGS. 1a and 1b, nitrogen, N₂, from compressor 24′, stream 45′, at about 85° F. and 410 psia, is inputted to heat exchanger 20 of LNG generator 91 for cooling to about −50° F. 396 psia. The nitrogen output stream from exchanger 20 is split into two streams 45₁and 45₂. Stream 45₁is applied to expander 23, which cools the gas to about −182° and at about 83 psia, stream 44′. The stream 44′ is fed to the cascaded bank of respective heat exchangers 21 and 20 in a direction opposite to stream 45 to be cooled’. Stream 44′ is outputted from exchanger 20 as stream 44 and is combined with stream 39, forming stream 41 applied to compressor 42 of the bank of series compressors, FIG. 1a.

The output stream 45₃from exchanger 21, formed from exchanger 21 input stream 45₂, is applied to expander 24. Expander 24 output stream 45₄is cooled by the expander 24 to about 84 psia and −230° F. This stream is then applied to the respective bank of heat exchangers 22, 21 and 20 for cooling the NG input stream 19 applied to the heat exchangers in the opposite feed direction. The degree of cooling of streams 45₁and 45₃is a function of the pressure ratio and flow through expanders 23 and 24.

Freezing of the stream 45₄should not interfere with throughput through the plant, since the CO₂which might freeze and thus cause such interference has been removed by dryer 18.

In FIG. 1b, the output stream 45₄of the expander 24 is inputted into heat exchanger 22 for cooling stream 19. Exchanger 22 output stream 45₅is combined with expander 23 output stream 44′ and applied as an input into respective heat exchangers 21 and 20 for cooling respective streams 19, 45′ and 45₂.

The energy recovered from expanding the nitrogen gas in expanders 23 and 24 can be used to drive an electric generator brake (not shown). As shown, use of this energy drives a compression brake, compressors 23′ and 24′ on the expanders 23 and 24, rather than an electric generator brake. A compression or generator brake could be substituted with a compander such as expander 24 and compressor 24′. The compander as nitrogen compressors 23′ and 24′, saves nitrogen compression energy. Placement of such a compander could be at stream 43′, or stream 45 applied to nitrogen liquefaction section 55.

In FIG. 1a, in this example, the pressure levels only require compression of stream 38 by compressor 54 and forming stream 40 applied to stream 44 forming stream 41. However, with other systems, compression of both streams 38 and 39 may be required.

The air separation unit (ASU) 65, FIG. 1a, can either be a conventional nitrogen plant, common in the industrial gas industry; or it can be a common known oxygen plant that produces merchant gases such as gaseous oxygen (GOX) and gaseous nitrogen (GAN), respective streams 63 and 61, or liquid oxygen (LOX), stream 62, or liquid argon (LAR), stream 64. The air separation unit (ASU) 65 can be a self-supported plant from a refrigeration standpoint with one or more expanders providing the refrigeration. It could also be optionally liquid assisted from the liquefaction section 55 with liquid nitrogen as represented by the dashed lines 52 (input stream 45₄′″). Stream 53 (dashed line) is merged in this case with stream 38 to provide the nitrogen to the LNG generator for assisting in the generation of the LNG.

For all embodiments, if the ASU 65 is a nitrogen plant, i.e., medium pressure nitrogen, stream 46 is employed to feed the nitrogen liquefaction section 55. Gaseous nitrogen product stream 61 is also possible from a nitrogen ASU 65. Streams 62 (liquid oxygen), 63 (gaseous oxygen) and 64 (liquid argon) would not be employed then. If the ASU is an oxygen plant, streams 61 (gaseous nitrogen), 62, 63 and 64 are all possibly employed. The nitrogen liquefaction section 55 will be fed from low pressure nitrogen stream 53, and may or may not also be fed from the nitrogen stream 46.

If the air separation unit 65 is a nitrogen plant, the pressure of nitrogen stream 46 will vary between approximately 25 psia to 130 psia. If the air separation unit 65 is an oxygen plant producing nitrogen and argon as well as oxygen, the nitrogen of stream 46 will be close to 84 psia. In either case, the nitrogen stream 46 exiting the air separation unit 65 is compressed by compressors 42, 23′ and 24′ and thereafter cooled and liquefied by the LNG generator 91 and by the nitrogen liquefaction section 55. It should be understood that various valves in the fluid system for directing or closing off fluid streams are not shown for clarity of illustration.

Streams 62 and 64 preferably respectively represent liquid oxygen and argon exiting the air separation unit 65 after they have been optionally cooled by the nitrogen liquefaction system 55. In the alternative, such streams may be created by internal ASU refrigeration. Any combination of streams 61, 62, 63 and 64 may be withdrawn from the separation unit 65. In the example shown, an 80 ton per day air separation unit 65 is designed to produce 80 tons per day of liquid oxygen, 200 tons per day of liquid nitrogen and approximately 4 tons per day of liquid argon. All the refrigeration in this example is generated by the nitrogen liquefaction system 55 when optional stream 52 is employed.

It should be understood, that in the various figures herein, the number and positions of separators is given by way of example. There may be more or fewer such separators. Further, the particular number, configuration and position of heat exchangers is also by way of illustration. As shown in others of the figures below, a heat exchanger may be arranged to process a number of separate gases in different channels thereof. There may be more or fewer heat exchangers in the embodiment of FIGS. 1a and 1b for a given set of functions. A single heat exchanger performing multiple stages of heat exchange is contemplated, the multiple separate heat exchangers in FIGS. 1a and 1b being given by way of example. The above possible variations in the number and position and configuration of the heat exchangers is intended to be applicable both for natural gas liquefaction as well as the liquefaction processing of the merchant gas such as nitrogen and so on.

In the above process, it is important that the CO₂be removed from the stream of natural gas. Keeping the CO₂in the entire natural gas stream during liquefaction of the natural gas results in the freezing up of the CO₂and clogging of separators and so on resulting in a non-workable system. The dryers 18 remove 1 to 1.5% CO₂. If the CO₂content for the natural gas feed goes above 1 to 1.5% CO₂, then an additional CO₂removal system would be employed (not shown).

FIGS. 2
a and 2b, illustrate a letdown liquefaction system 15′ utilizing air separation unit (ASU) 65 and nitrogen liquefaction section 55, which as noted above, is identical to section 55, FIG. 1b. In this embodiment, letdown station 13 is utilized. This station reduces the pressure on line 12 to a substantial degree of more or less 200 psia by way of example. This assists in providing supplemental refrigeration over the FIG. 1a, 1b embodiments with no letdown station. As a result, more product can be produced due to the added refrigeration ability assuming a constant power utilization.

In FIG. 2a, stream 74 at the output of compressor 73 and its associated cooler 73′ (a heat exchanger) as shown in FIG. 1a is combined with stream 19a₃, the output stream of compressor 223′ and its associated cooler 223″, to form stream 74₁. This stream is returned to the selected dryer 18 from the NG refrigeration system generator 91′ (FIG. 2b) and, therefore, is dry natural gas free of CO₂. As shown, one dryer 18 is being regenerated, while the other dryer 18 is drying the incoming gas from separator 17 via stream 16′.

Oxygen gas from an oxygen plant could be substituted for nitrogen gas in these examples. While use of this gas is possible and falls within the scope of the claims appended hereto, it has not been illustrated because of its limited use due to safety concerns with processing natural gas and oxygen together in the liquefaction system 15′. The liquefaction of air is also possible within the scope of the claims appended hereto with liquid air assist to the air separation unit, but it also has not been shown for the same reasons as oxygen.

In FIGS. 2a and 2b, the nitrogen liquefaction section 55 is identical to section 55 of FIG. 1b. In FIG. 2a, letdown station 13 reduces the pipeline pressure to about 200 psia. Dryers 18 are selectively regenerated by the gas, stream 74₁, returning from compressors 23′ and 73 and their associated coolers. Stream 71 from the liquefaction section 55 and stream 72₁from the LNG generator 91′ are combined and inputted into compressor 73.

After drying by the selected dryer 18, the natural gas stream 19 is fed directly into a first heat exchanger 20 in liquid natural gas (LNG) generator 91′, FIG. 2b Generator 91′ comprises the series bank of heat exchangers 20, 21 and 22, expander 223 having the above noted respective corresponding compressor 223′ (FIG. 1a), control valve 25, separator 26 and coolers 230 and 231.

Natural gas stream 19, FIG. 2b, at about 700 psia and ambient temperature of about 75° F., is divided into two stream portions 19a and 19b, with both stream portions being fed into heat exchanger 20 for cooling. Stream portion 19a is fed through ammonia refrigeration cooler 230 for providing additional cooling to about −20° F. and about 695 psia and then expanded at expander 223 forming stream 19a₁. Both the cooler 230 and expander 223, FIG. 2b, are not utilized in the prior embodiment, but the cooler 230 could be utilized if desired. Ammonia refrigerant gas for this cooler and cooler 231 is used in this embodiment, but other refrigerants such as R-134a could be substituted for the ammonia. This stream 19a₁is further cooled to about 60 psia and about −185° F. and fed to heat exchangers 21 and 20 in the opposite direction of stream 19a. This stream exits heat exchanger 20 as stream 19a₂, which in turn is fed to compressor 223′, FIG. 2a. The output stream 19a₃of compressor 223′ and its associated cooler 223″ is at about 115 psia and ambient temperature.

Portion 19b of stream 19 is fed to heat exchanger 20 and, upon exiting this exchanger, is applied to exchanger 21 through cooler 231 as stream 19b₁, exiting cooler 231 at about −20° F. Upon exiting heat exchanger 21, stream 19b1 is fed to exchanger 22 whose output stream 19b₂is inputted into separator 26 through control valve 25, where the gas is flashed. The separator 26 outputs a liquefied NG stream 19b₃at 20 psia, and −251° F. The liquefied NG stream 19b₃is fed to control valve 27 and fed as stream 28 through control valve 29 as discussed above in connection with FIGS. 1a and 1b.

In FIG. 2a, NG stream 71, from heat exchanger 30 from the liquefaction section 55, FIG. 2b, is processed similarly as stream 71, FIG. 1a. The stream 72₁outputted by heat exchanger 20 of LNG generator 91, FIG. 1b, is combined with warm NG stream 71 forming stream 74 at the output of compressor 73 and its associated cooler 73′. Compressor 75, which may be optional, matches the pressure of the output stream 74₂of the selected dryer 18 to the lower pressure of pipeline stream 14′, if necessary.

The ASU 65 outputs nitrogen N₂stream 46. However, liquid nitrogen N₂stream 52 at about 82 psia and −314° F. is applied to the ASU from the liquefaction section 55, shown only as optional in the embodiment of FIGS. 1b and 1a via the phantom line in these figures. The ASU 65 also outputs nitrogen stream 53 at about 15 psia also optional in the FIG. 1a embodiment. The liquefaction section 55 outputs N₂streams 38 and 39 (FIG. 2a) from similar structures as in FIG. 1b as discussed previously. Stream 45, FIG. 1a, which is outputted from the LNG generator 91 is changed to stream 45a1, FIG. 2a. This stream is applied to section 55 heat exchanger 30 similarly as stream 45, FIG. 1b. Stream 38, FIG. 2a, is fed to compressor 54 and its associated cooler 54′ forming stream 40 as in FIG. 1a. The compressor 54 output stream is at about 200-280° F. whereas the output stream of its cooler 54′ is at about 85° F. Stream 40, the output of compressor 54 and its associated cooler 54′, is combined with stream 46 to form stream 41′, which is fed to compressor 42 and its associated cooler 42′ forming stream 45a1. The output stream 45a1 is at about 410 psia. The valve 29, FIG. 2b, and the surface area of heat exchanger 30 determines the amount of nitrogen that can be liquefied. The liquefied nitrogen LN is stored in tank 50.

FIGS. 3
a and 3b are a further embodiment, which is a variation of the embodiment of FIGS. 1a, 1b and 2a, 2b, in that both nitrogen and natural gas are utilized for cooling the NG in LNG generator 91″. No letdown station is used. (Letdown station 13 is shown with dashed lines as optional) In this embodiment more refrigeration is needed to increase the output volume of product as compared to the FIGS. 1a and 1b embodiment. The output can be several hundred tons per day of LNG and LN. The letdown station, if present, helps with reducing the power needed. Ammonia cooler 230, FIG. 3b, provides the additional refrigeration desired.

Liquefaction section 55′ is substantially similar to section 55 of FIGS. 1b and 2b, wherein heat exchanger 30 receives the LNG stream 71′ for cooling, which is at −254° F. and about 18 psia as in the FIG. 1b embodiment. The output streams 71, 38 and 39, FIG. 3b, are substantially as described with the prior embodiments. Nitrogen input stream 145′ fed into section 55 heat exchanger 30 from the LNG generator 91″ (FIG. 3b) corresponds generally to nitrogen stream 45 of the prior embodiments, but is processed differently.

Stream 46 (N₂) from ASU 65 is applied to the series bank of three compressors 42, 23′ and 24′, FIG. 3a, as in FIG. 1a. The output stream 145 of the compressor 24′ associated cooler 24″ is split into two streams 145′ and 145″. Stream 145″, FIG. 3a, is applied to the generator 91″ heat exchanger 20 similarly as stream 45′, FIG. 1a, and split also into stream 145′ applied to heat exchanger 30 of nitrogen liquefaction section 55. Stream 145″ is processed through the series of cascaded respective heat exchangers 20 and 21 and expanders 23 and 24, similarly as stream 45′, of the embodiment of FIG. 1b. Stream 145″ exits expanders 23 and 24 and returned as inputs in the opposing direction into respective heat exchangers 22 and 21 for providing cooling. The stream from expander 24 subsequently outputted by exchanger 22 is combined with the output stream of expander 23 applied to heat exchanger 21 and then fed into exchanger 20 in a direction to provide cooling to the exchangers. This arrangement is similar to that of FIG. 1b with respect to corresponding streams of these expanders.

Also, as in the embodiment of FIGS. 2a and 2b, the ASU 65 receives LN stream 52 and outputs stream 53 applied with stream 38 as a combined input to compressor 54. N₂stream 46 is generated from the ASU 65, which is required in FIG. 1a and optional in FIGS. 2a and 2b.

The natural gas input stream 19, FIG. 3a, is divided into two streams 19a and 19b. Stream 19a is processed by generator 91″ similarly as stream 19, FIG. 1b. Stream 19b is inputted into cooler 230 comprising an ammonia refrigerant and then into expander 233. The expander 233 output stream 234 is at about 120 psia and −157° F. The cooler 230 output is at about −20° F. Stream 234 is applied to series cascaded respective heat exchangers 21 and 20 in the opposing cooling direction as stream 19a in generator 91″ to be cooled thereby and outputted by exchanger 20 as stream 234′, FIG. 3a, applied to compressor 233′. The outputs from the associated coolers of compressors 73 and 233′ are combined to form stream 74a applied to dryer 18 for regeneration. Streams 72 and 71 are compressed by compressor 73 as in FIG. 1a. The letdown station 13 (shown in phantom) is not employed in this embodiment. The line pressure of stream 14 is high at about 714 psia. However, a letdown station could be employed in this embodiment, which results in power and cost savings. By increasing the output with added components, economy of the increased capacity makes up the difference in the increased system cost. Nitrogen is more efficient for refrigeration when used at the colder temperatures, e.g., −230° F.-−270° F. Ammonia is more efficient as a refrigerant at warmer temperatures, e.g., −20° F. Natural gas is most efficient as a refrigerant when processed at intermediate temperatures, e.g., −100° F.

FIGS. 4
a and 4b are a variation of the FIGS. 3a, 3b embodiment using an additional heat exchanger 222 in the LNG generator 91′″, FIG. 4a. Here, NG liquefaction system 15′″ comprises generator 91′″ and nitrogen liquefaction section 55. Stream 19 is applied to the respective cascaded series of heat exchangers 222 (FIG. 4a), 20, 21, and 22 through flash valve 25 (FIG. 4b) into separator 26 as partial LNG and vapors, stream 19a. The vapor output stream 19b of separator 26 is applied to the respective heat exchangers 22, 21, 20 and 222 in the reverse direction as the warm gas stream 19b applied thereto. This stream is outputted from heat exchanger 222 as stream 19c which is compressed by compressor 73 and applied in a return stream for regeneration of dryer 18. This stream is then returned to stream 14 through booster compressor 75 (optional and used if needed) for transmission to users.

In FIG. 4a, stream 19 of natural gas is divided into two streams 19a and 19b. Stream 19a is fed to heat exchanger 222. Stream 19b is combined with stream 234a outputted by heat exchanger 222 to form stream 234a′. Stream 234a′ is inputted into the respective series of two compressors 140 and 233′ (part of the compander having expander 233, FIG. 4b) each having an associated cooler at its output. The output stream 234b of compressor 233′ is at about 500 psia. The output stream 234b′ of the compressor 233′ associated cooler is inputted into heat exchanger 222 for cooling the inputted gas streams. This produces output stream 234b″ from heat exchanger 222 (FIGS. 4a and 4b). This output stream is applied as an input to the cooler 230, FIG. 4b. The output stream of cooler 230 is at −20° F. and 496 psia. The output stream 234 of expander 233, FIG. 4b, at −152° F. and at 85 psia, is applied as an input to the series of respective heat exchangers 21, 20 and 222 whose output is stream 234a. This stream is combined with stream 19b forming stream 234a′ applied to compressor 140, FIG. 4a. Stream 19_ais applied to control valve 25 through respective heat exchangers 222, 20, 21 and 22 and thence through control valve 25 as valve output stream 19_a1′ to separator 26. The output vapor stream 19b of separator 26 is then applied to the heat respective heat exchangers 22, 21, 20 and 222 for cooling the input gases. Stream 19b is outputted from heat exchanger 222 as stream 19c applied to compressor 73 for regenerating dryer 18 and fed back to stream 14 through optional compressor 75. Heat exchanger 222 is not used in the prior embodiments as discussed.

Nitrogen stream portion 43, FIG. 4a, output of compressor 24′ and its associate cooler is applied to heat exchanger 222 and outputted as stream 43a. In FIG. 4b, cooler 231 refrigerated with ammonia receives the cooled nitrogen stream 43a. The cooler 231 output at −20° F. is applied to heat exchangers 20 and 21 and expanders 23, 24 in a manner similar to that described above for stream 45′, FIG. 1b. Except for added heat exchanger 222, the series arrangement of compressors 140 and 233′ and added cooler 231, the remaining structures are the same as in the prior embodiment of FIGS. 3a, 3b. In FIG. 4a, the ASU 65 outputs one or more selected merchant gases as in the prior embodiments. A selected amount of LNG is stored in tank 92, FIG. 4b, as before and this amount is set to allow a predetermined amount of LNG flow to the nitrogen liquefaction section 55 through control valve 29 as stream 71″ for liquefaction of the nitrogen and stored as previously described. Stream 52 of LN is also applied to the ASU 65 as in certain of the prior embodiments. Temperatures and pressures correspond generally to that described in the prior embodiments with respect to similarly processed streams of the gases.

The ASU 65 in the various embodiments may provide it's own refrigeration including the production of liquid product. Both nitrogen and oxygen air separation units 65 are capable of this. A letdown liquefaction system can be integrated with the air separation units 65 to take advantage of a smaller compressor 75 as in the other embodiments. Nitrogen gas under the intermediate pressure (approximately 80 psia) is withdrawn from the air separator units 65. The nitrogen gas may come off the air separator unit 65 at sufficient pressure or some or all of it may need to be compressed by a nitrogen compressor (not shown) to obtain the proper pressure for streams 46.

In FIGS. 5a, 5b and 5c, a further embodiment of the present invention, a liquefaction system 15a is shown. In FIGS. 5a and 5b, the components of the system shown comprises the same corresponding components of FIGS. 4a and 4b. However, the nitrogen liquefaction section 55′ is different. The heat exchanger 32 and control valve 35 of FIG. 4b are not used. Instead, the ASU 65′ has heat exchangers that are used to supply additional nitrogen refrigeration previously supplied by the heat exchanger of the prior embodiments of the liquefaction sections 55. This is an alternate embodiment that is equivalent to the embodiment of FIGS. 4a and 4b with respect to the generation of LNG in LNG generator 91′″ and LN in exchanger 30.

FIGS. 6
a and 6b illustrate a further embodiment of the present invention. Refrigeration to cool and liquefy the natural gas can also be provided by a number of mixed refrigerant process cycles. One such cycle is illustrated in FIGS. 6a and 6b. A mixed refrigerant stream 850, FIG. 6a, is utilized in this process not used in the prior disclosed embodiments hereinabove. Stream 850, for example, in this embodiment, is composed of approximately 50 mole percent methane, 30 mole percent ethylene, 15 mole percent propane, and 5 mole percent nitrogen. The mixed refrigerant stream 850 is compressed from around 120 PSIA to over 500 PSIA in compressor 140. It is then cooled in the after cooler 140′ and fed into heat exchanger 224 as a mixed gas stream 852. Cooling of the mixed refrigerant stream 852 to 40° F. is provided by heat exchanger 224 and ammonia cooler 242. The cooled stream 852′ is further cooled by heat exchanger 223, and then cooled to −20 degrees F. via ammonia cooler 232. The mixed refrigerant stream is now partially liquefied and the liquid separated in separator 245.

Both gas 854 and liquid 856 streams from separator 245 are cooled in exchanger 20 to −90 degrees F. The liquid stream 856 is sub cooled as stream 856′ which is flashed through valve 246 where it flashes to around −109° F. providing refrigeration as it is sent back up through the respective bank of heat exchangers 20. 223 and 224 as stream 850. The other mixed refrigerant stream 854 cooled in exchanger 20 turns into a mixed phase stream 854′ that has its phases separated in separator 247, FIG. 6b. The gas stream 854₁from separator 247 is flashed via valve 249 forming stream 854₁′ The liquid stream 854″ from separator 247 is sub cooled in exchanger 21 to −145° F., flashed through valve 248 to −166° F., as stream 854′″, and combined with stream 854₁′ forming steam 858. This stream is applied in the reverse direction up through the heat exchanger bank of respective exchangers 21, 20, 223 and 224 forming stream 858′ out of exchanger 21. Stream 858′ combines with the output stream from valve 246, FIG. 6a, forming stream 860. Stream 860 applied to respective exchangers 223 and 224 is outputted at exchanger 224 as stream 850.

These latter streams provide refrigeration for cooling the natural gas feed stream 19 applied to the bank of heat exchangers starting with exchange 224, the nitrogen recycle stream 870 applied to the bank of exchangers starting with exchanger 224, the mixed refrigerant gas stream 858, FIG. 6b, from separator 247, and themselves. The gas stream 854₁from separator 247 is flashed through valve 249 to around 130 PSIA pressure at −166° F. and combined with the mixed refrigerant stream 854′″ that was flashed through valve 248.

The natural gas feed stream 19, FIG. 6a, at approximately 90° F. and 860 PSIA is fed into heat exchanger 224 to be cooled, then enters ammonia chiller 240 at 55° F. to be cooled to 40° F., further cooled in exchanger 223 to 14° F., chilled in ammonia chiller exchanger 230 to −20° F., cooled to −90° F. in exchanger 20, and “liquefied” in exchanger 21, FIG. 6b, exiting at −145° F. This stream 19a is then sub cooled in exchanger 22 to −190° F. before flashing through valve 25 to 20 PSIA at −251° F. before entering separator 26. As in previous embodiments (not shown), separator 26 may be elevated to provide a gravity induced pressure head forcing the LNG product into the tank 92 via valve 27 or the LNG is pumped by a pump (not shown) into tank 92 via the valve 27. Some of the LNG is diverted to the nitrogen liquefaction section 55 via valve 29 as in previous embodiments.

The nitrogen recycle stream is handled as described above in previous embodiments. The high pressure nitrogen N₂stream 870, FIG. 6a, at 90° F. and approximately 400 PSIA is cooled through the heat exchanger bank of exchangers 224, 223, 20 and 21 and the ammonia coolers, as shown, before entering the suction of expander 24, FIG. 6b, at −145° F. The nitrogen recycle stream 870′ exits the expander 24 at approximately −250° F. and 86 PSIA to provide refrigeration for all of the heat exchangers in LNG generator 98.

FIGS. 6
a and 6b show one possible mixed refrigerant process cycle. Many other mixed refrigerant process cycles are possible. One example would be to add butane to the mixed refrigerant stream which eliminates the need for the ammonia coolers. In another example, propane chillers can be substituted for the ammonia coolers. A cascade refrigerant cycle using propane or ammonia along with separate hydrocarbon compression cycles would also be possible.

In FIGS. 7a and 7b, some natural gas feeds at pipeline 12 to the LNG plant will be richer in ethane, propane, butane and heavier hydrocarbons. These heavier hydrocarbons are more economically valuable than the methane in the natural gas. Furthermore, the engine manufacturers who produce engines that will burn the LNG as fuel want the ethane content in the LNG product below 4 mole percent. This dictates that some natural gas liquids (NGL) (e.g., butane and propane) must be extracted from the natural gas feed stream in the LNG manufacturing process. Therefore, a natural gas liquids (NGL) product needs to be produced. This product needs to be added to the production of the LNG, LN and industrial merchant gas liquid products described in the above embodiments for the appropriate natural gas feeds. An example of such a process is presented in the embodiment of FIGS. 7a and 7b. This further process produces LNG, liquid nitrogen LN, liquid oxygen LOX, gaseous oxygen GOX, liquid argon LAR, GAN and natural gas liquids. The natural gas feed source at pipeline 12 is richer in the heavier hydrocarbons. The composition of this feed after drying is approximately 93.5 mole percent methane, 4.5 mole percent ethane, 1 mole percent propane, 0.7 mole percent nitrogen with the remaining heavier hydrocarbons at 0.3 mole percent combined.

The natural gas feed temperature is 90° F. and the feed pressure is 905 PSIA after drying.

The refrigeration scheme utilized is similar to the process cycle presented in FIGS. 1a and 1b. This scheme uses two nitrogen expander/companders 23, 24. Ammonia coolers 230, 231, 805, and 806 are added. However, equipment is also added for the NGL natural gas liquids extraction. The natural gas feed stream 19, FIG. 7a, is cooled in heat exchanger 800, chilled in ammonia cooler 230 to −20° F., and further cooled in heat exchanger 801 to about −70° F., forming stream 814. Valve 807, FIG. 7b, is added to flash the feed stream 814 down to 550 PSIA forming stream 815 in which a small amount of hydrocarbon liquid is present. The gas and liquid phases of the feed stream 815 output of the valve 807, are separated in separator 808. The gas stream 816 exiting separator 808 is low enough in ethane concentration to make the LNG product well under 4 mole percent ethane.

The liquid stream 817 from separator 808 is flashed through valve 809 to approximately 25 PSIA as stream 818 before entering distillation column 810 where the methane in the natural gas liquids is separated out to make acceptable NGL, natural gas liquids product. The natural gas liquid product stream from the bottom of distillation column 810 passing through reboiler 805 and pumped up in pressure by pump 811 forming stream 820. Stream 820 then is applied to respective heat exchangers 801 and 800, FIG. 7a, where its refrigeration is recovered. The NGL natural gas liquid product pressure is about 500 PSIA in this example. Reboiler 805 is heated by cooling the nitrogen stream at the suction of nitrogen expander 23, and condenser 806 is integrated by heating nitrogen exiting nitrogen expander 24. Methane rich gas from the top of distillation column 810 stream 821 is combined with flashed gas from separator 26 forming stream 822 to help refrigerate the natural gas feed stream 814′ cascading down through heat exchangers 802, 803 and 804. The natural gas feed stream exiting exchanger 804 at about −230° F. is flashed through valve 25 before entering separator 26. Separator 26 produces LNG, stream 823. The disposition of the LNG is the same as presented in FIGS. 1a and 1b enabling the LNG and industrial gas merchant liquid products to be generated. The NGL product stream 820′ exiting the successive chain of heat exchangers 804, 803, 802, 801 and 800, respectively, is stored in storage tank 826.

Thus, in one plant, the incoming stream of natural gas feed is formed into LNG, LN, merchant gases and NGL. Such products previously needed to be produced in separate plants, therefore reducing capital costs for the production of such gases.

It will occur to one of ordinary skill that various modifications may be made to the disclosed embodiments which are given by way of illustration and not limitation. For example, the merchant liquefied gases need not be returned to or supplied from an air separation unit. The merchant gas may be supplied from a separate gas source for liquefaction by the disclosed systems. Also, the gas returned to the air separation unit need not be liquid, but may be cold vapor. Drivers for expanders and compressors are not shown. The source of natural gas may be any methane rich natural gas feed whether from a pipeline, landfill, or biogas digester, for example. The number, configuration and location of the various elements such as heat exchangers, separators, compressors, control valves and so on may differ from the embodiments disclosed as discussed herein. It is intended that the scope of the invention is as defined in the appended claims.

Natural Gas Liquefaction System for Producing LNG and Merchant Gas Products

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