EP3390939B1

EP3390939B1 - Expander-based lng production processes enhanced with liquid nitrogen

Info

Publication number: EP3390939B1
Application number: EP16798358.4A
Authority: EP
Inventors: Fritz PIERRE Jr.; Michael W. Miles
Original assignee: ExxonMobil Upstream Research Co
Current assignee: ExxonMobil Upstream Research Co
Priority date: 2015-12-14
Filing date: 2016-11-10
Publication date: 2020-12-30
Anticipated expiration: 2036-11-10
Also published as: AU2016372710B2; WO2017105680A1; KR20180095870A; JP2019505755A; JP6772268B2; CA3006956A1; CN108369060B; AU2016372710A1; CA3006956C; CN108369060A; SG11201803523WA; EP3390939A1; KR102137939B1; US20170167785A1

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Patent Application 62/266,979, filed December 14, 2015 entitled EXPANDER-BASED LNG PRODUCTION PROCESSES ENHANCED WITH LIQUID Nitrogen.
This application is related to U.S. Provisional Patent Application number 62/266,976 titled "Method and System for Separating Nitrogen from Liquefied Natural Gas Using Liquefied Nitrogen;" U.S. Provisional Patent Application No. 62/266,983 titled "Method of Natural Gas Liquefaction on LNG Carriers Storing Liquid Nitrogen;" and U.S. Provisional Patent Application No. 62/622,985 titled "Pre-Cooling of Natural Gas by High Pressure Compression and Expansion," all having common inventors and assignee and filed on an even date herewith.

BACKGROUND

Field of Disclosure

The disclosure relates generally to the field of natural gas liquefaction to form liquefied natural gas (LNG). More specifically, the disclosure relates to the production and transfer of LNG from offshore and/or remote sources of natural gas.

Description of Related Art

This section is intended to introduce various aspects of the art, which may be associated with the present disclosure. This discussion is intended to provide 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 an admission of prior art.
LNG is a rapidly growing means to supply natural gas from locations with an abundant supply of natural gas to distant locations with a strong demand for natural gas. The conventional LNG cycle includes: a) initial treatments of the natural gas resource to remove contaminants such as water, sulfur compounds and carbon dioxide; b) the separation of some heavier hydrocarbon gases, such as propane, butane, pentane, etc. by a variety of possible methods including self-refrigeration, external refrigeration, lean oil, etc.; c) refrigeration of the natural gas substantially by external refrigeration to form liquefied natural gas at or near atmospheric pressure and about -160 °C; d) transport of the LNG product in ships or tankers designed for this purpose to a market location; and e) re-pressurization and regasification of the LNG at a regasification plant to form a pressurized natural gas stream that may distributed to natural gas consumers. Step (c) of the conventional LNG cycle usually requires the use of large refrigeration compressors often powered by large gas turbine drivers that emit substantial carbon and other emissions. Large capital investments in the billions of US dollars and extensive infrastructure are required as part of the liquefaction plant. Step (e) of the conventional LNG cycle generally includes re-pressurizing the LNG to the required pressure using cryogenic pumps and then re-gasifying the LNG to form pressurized natural gas by exchanging heat through an intermediate fluid but ultimately with seawater or by combusting a portion of the natural gas to heat and vaporize the LNG. Generally, the available exergy of the cryogenic LNG is not utilized.
A relatively new technology for producing LNG is known as floating LNG (FLNG). FLNG technology involves the construction of the gas treating and liquefaction facility on a floating structure such as barge or a ship. FLNG is a technology solution for monetizing offshore stranded gas where it is not economically viable to construct a gas pipeline to shore. FLNG is also increasingly being considered for onshore and near-shore gas fields located in remote, environmentally sensitive and/or politically challenging regions. The technology has certain advantages over conventional onshore LNG in that it has a lower environmental footprint at the production site. The technology may also deliver projects faster and at a lower cost since the bulk of the LNG facility is constructed in shipyards with lower labor rates and reduced execution risk.
Although FLNG has several advantages over conventional onshore LNG, significant technical challenges remain in the application of the technology. For example, the FLNG structure must provide the same level of gas treating and liquefaction in an area that is often less than a quarter of what would be available for an onshore LNG plant. For this reason, there is a need to develop technology that reduces the footprint of the FLNG plant while maintaining the capacity of the liquefaction facility to reduce overall project cost. One promising means of reducing the footprint is to modify the liquefaction technology used in the FLNG plant. Known liquefaction technologies include a single mixed refrigerant (SMR) process, a dual mixed refrigerant (DMR) process, and expander-based (or expansion) process. The expander-based process has several advantages that make it well suited for FLNG projects. The most significant advantage is that the technology offers liquefaction without the need for external hydrocarbon refrigerants. Removing liquid hydrocarbon refrigerant inventory, such as propane storage, significantly reduces safety concerns that are particularly acute on FLNG projects. An additional advantage of the expander-based process compared to a mixed refrigerant process is that the expander-based process is less sensitive to offshore motions since the main refrigerant mostly remains in the gas phase.
Although expander-based process has its advantages, the application of this technology to an FLNG project with LNG production of greater than 2 million tons per year (MTA) has proven to be less appealing than the use of the mixed refrigerant process. The capacity of known expander-based process trains is typically less than 1.5 MTA. In contrast, a mixed refrigerant process train, such as that of the propane-precooled process or the dual mixed refrigerant process, can have a train capacity of greater than 5 MTA. The size of the expander-based process train is limited since its refrigerant mostly remains in the vapor state throughout the entire process and the refrigerant absorbs energy through its sensible heat. For these reasons, the refrigerant volumetric flow rate is large throughout the process, and the size of the heat exchangers and piping are proportionately greater than those used in a mixed refrigerant process. Furthermore, the limitations in compander horsepower size results in parallel rotating machinery as the capacity of the expander-based process train increases. The production rate of an FLNG project using an expander-based process can be made to be greater than 2 MTA if multiple expander-based trains are allowed. For example, for a 6 MTA FLNG project, six or more parallel expander-based process trains may be sufficient to achieve the required production. However, the equipment count, complexity and cost all increase with multiple expander trains. Additionally, the assumed process simplicity of the expander-based process compared to a mixed refrigerant process begins to be questioned if multiple trains are required for the expander-based process while the mixed refrigerant process can obtain the required production rate with one or two trains. For these reasons, there is a need to develop an FLNG liquefaction process with the advantages of an expander-based process while achieving a high LNG production capacity. There is a further need to develop an FLNG technology solution that is better able to handle the challenges that vessel motion has on gas processing.
United States Patent No. 3,400,547 to Williams et al. discloses a process within an LNG production facility where liquid nitrogen (LIN) produced at a different location is used as a refrigerant to liquefy natural gas. The process uses propane chillers to cool the natural gas prior to condensing the natural gas by indirect heat exchange with the vaporizing LIN. GB Patent No. 1,596,330 to Thompson discloses a process within an LNG production facility where LIN produced at a different location is used as the refrigerant to liquefy natural gas. The process uses propane and ethylene chillers in combination with the LIN to liquefy the natural gas into LNG. The processes disclosed by these two patents have the disadvantage of using a mechanical refrigeration system while still requiring a significant of amount of LIN to produce the LNG. Both processes estimate that for every ton of LNG produced, approximately one or more tons of LIN is required. In FLNG applications, space for storage of LIN either topside or in the hull of the floating structure may be limited. It would be advantageous to have an LNG production technology on an FLNG that uses LIN since it would significantly reduce the required topside space for the liquefaction process. Additionally, it would be advantageous to have an LNG production technology that uses less than 1 ton of LIN, or more preferably less than 0.75 ton of LIN, or more preferably less than 0.5 ton of LIN, for every ton of LNG produced.
United States Patent No. 6,412,302 to Foglietta describes a feed gas expander-based process where two independent closed refrigeration loops are used to cool the feed gas to form LNG. The first closed refrigeration loop uses the feed gas or components of the feed gas as the refrigerant. Nitrogen gas is used as the refrigerant for the second closed refrigeration loop. This technology has an advantage of requiring smaller equipment and topside space than a dual loop nitrogen expander-based process. For example, the volumetric flow rate of the refrigerant into the low pressure compressor can be 20 to 50% smaller for this technology compared to a dual loop nitrogen expander-based process. The technology, however, is still limited to a capacity of less than 1.5 MTA.
United States Patent No. 8,616,012 to Minta describes a feed gas expander-based process where feed gas is used as the refrigerant in a closed refrigeration loop. Within this closed refrigeration loop, the refrigerant is compressed to a pressure greater than or equal to 1500 psia, or more preferably greater than 2500 psia. The refrigerant is then cooled and expanded to achieve cryogenic temperatures. This cooled refrigerant is then used in a heat exchanger to cool the feed gas from warm temperatures to cryogenic temperatures. A subcooling refrigeration loop is then employed to further cool the feed gas to form LNG. In one embodiment, the subcooling refrigeration loop is a closed loop with flash gas used as the refrigerant. This feed gas expander-based process has the advantage of not being limited to a train capacity range of less than 1 MTA. A train size of approximately 6 MTA has been considered. However, the technology has the disadvantage of a high equipment count and increased complexity due to its requirement for two independent refrigeration loops and the compression of the feed gas. Furthermore, the high pressure operation also means that the equipment and piping will be much heavier than that of other expander-based processes.
GB Patent No. 2,486,036 to Maunder et al. describes a feed gas expander-based process that is an open loop refrigeration cycle including a precooling expander loop and a liquefying expander loop, where the gas phase after expansion is used to liquefy the natural gas. According to Maunder, including a liquefying expander in the process significantly reduces the recycle gas rate and the overall required refrigeration power. This technology is simpler than the technologies described by Foglietta and Minta since only one type of refrigerant is used with a single compression string. However, the technology is still limited to capacity of less than 1.5 MTA and it requires the use of a liquefying expander, which is not standard equipment for LNG production. The technology has also been shown to be less efficient than the technologies described by Foglietta and Minta for the liquefaction of lean natural gas. GB Patent No. 2470062 describes a method for producing liquefied natural gas according to the preamble of claim 1.
There remains a need to develop an LNG production process with the advantages of an expander-based process while having a high LNG production capacity with a reduced facility footprint. There is a further need to develop an LNG technology solution that is better able to handle the challenges that vessel motion has on gas processing. Such a high capacity expander-based liquefaction process would be particularly suitable for FLNG applications where the inherent safety and simplicity of expander-based liquefaction processes are greatly valued.

SUMMARY

The present invention provides a method for producing liquefied natural gas (LNG) according to claim 1. A natural gas stream is directed to a mechanical refrigeration unit to liquefy the natural gas stream and form a pressurized liquefied natural gas (LNG) stream with a pressure greater than 50 psia (345 kPa) and less than 500 psia (3445 kPa). A liquid refrigerant subcooling unit is provided at a first location. Liquid refrigerant is produced at a second location that is geographically separate from the first location. The produced liquid refrigerant is transported to the first location. The pressurized LNG stream is subcooled in the liquid refrigerant subcooling unit by exchanging heat between the pressurized LNG stream and at least one stream of the liquid refrigerant to thereby produce an LNG stream.
The foregoing has broadly outlined the features of the present disclosure so that the detailed description that follows may be better understood. Additional features will also be described herein.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other features, aspects and advantages of the disclosure will become apparent from the following description, appending claims and the accompanying drawings, which are briefly described below.

Figure 1 is a graph showing a temperature cooling curve for an expander-based heat exchanger process.
Figure 2A is a simplified diagram of the value chain of known FLNG technology.
Figure 2B is a simplified diagram of the value chain of the disclosed aspects.
Figure 3 is a schematic diagram of a method according to the current invention.
Figure 4 is a schematic diagram of a mechanical refrigeration unit according to disclosed aspects.
Figure 5 is a schematic diagram of a liquid nitrogen (LIN) subcooling unit according to disclosed aspects.
Figure 6 is a schematic diagram of a LIN subcooling unit according to disclosed aspects.
Figure 7 is a flowchart showing a method according to disclosed aspects.

It should be noted that the figures are merely examples and no limitations on the scope of the present disclosure are intended thereby. Further, the figures are generally not drawn to scale, but are drafted for purposes of convenience and clarity in illustrating various aspects of the disclosure.

DETAILED DESCRIPTION

To promote an understanding of the principles of the disclosure, reference will now be made to the features illustrated in the drawings and specific language will be used to describe the same. It will nevertheless be understood that no limitation of the scope of the disclosure is thereby intended. Any alterations and further modifications, and any further applications of the principles of the disclosure as described herein are contemplated as would normally occur to one skilled in the art to which the disclosure relates. For the sake clarity, some features not relevant to the present disclosure may not be shown in the drawings.
At the outset, for ease of reference, certain terms used in this application and their meanings as used in this context are set forth. To the extent a term used herein is not defined below, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent.
As one of ordinary skill would appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name only. The figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in schematic form and some details of conventional elements may not be shown in the interest of clarity and conciseness. When referring to the figures described herein, the same reference numerals may be referenced in multiple figures for the sake of simplicity. In the following description and in the claims, the terms "including" and "comprising" are used in an openended fashion, and thus, should be interpreted to mean "including, but not limited to."
The articles "the," "a" and "an" are not necessarily limited to mean only one, but rather are inclusive and open ended so as to include, optionally, multiple such elements.
As used herein, the terms "approximately," "about," "substantially," and similar terms are intended to have a broad meaning in harmony with the common and accepted usage by those of ordinary skill in the art to which the subject matter of this disclosure pertains. It should be understood by those of skill in the art who review this disclosure that these terms are intended to allow a description of certain features described and claimed without restricting the scope of these features to the precise numeral ranges provided. Accordingly, these terms should be interpreted as indicating that insubstantial or inconsequential modifications or alterations of the subject matter described and are considered to be within the scope of the disclosure.
The term "heat exchanger" refers to a device designed to efficiently transfer or "exchange" heat from one matter to another. Exemplary heat exchanger types include a cocurrent or counter-current heat exchanger, an indirect heat exchanger (e.g. spiral wound heat exchanger, plate-fin heat exchanger such as a brazed aluminum plate fin type, shell-and-tube heat exchanger, etc.), direct contact heat exchanger, or some combination of these, and so on.
The term "dual purpose carrier" refers to a ship capable of (a) transporting LIN to an export terminal for natural gas and/or LNG and (b) transporting LNG to an LNG import terminal.
As previously described, the conventional LNG cycle includes: (a) initial treatments of the natural gas resource to remove contaminants such as water, sulfur compounds and carbon dioxide; (b) the separation of some heavier hydrocarbon gases, such as propane, butane, pentane, etc. by a variety of possible methods including self-refrigeration, external refrigeration, lean oil, etc.; (c) refrigeration of the natural gas substantially by external refrigeration to form LNG at or near atmospheric pressure and about -160 °C; (d) transport of the LNG product in ships or tankers designed for this purpose to a market location; and (e) re-pressurization and regasification of the LNG at a regasification plant to form a pressurized natural gas stream that may distributed to natural gas consumers. The present disclosure generally involves liquefying natural gas using liquid nitrogen (LIN). In general, using LIN to produce LNG is a non-conventional LNG cycle in which step (c) above is replaced by a natural gas liquefaction process that uses a significant amount of LIN as an open loop source of refrigeration, and in which step (e) above may be modified to use the exergy of the cryogenic LNG to facilitate the liquefaction of nitrogen gas to form LIN that may then be transported to the resource location and used as a source of refrigeration for the production of LNG. The disclosed LIN-to-LNG concept may further include the transport of LNG in a ship or tanker from the resource location (export terminal) to the market location (import terminal) and the reverse transport of LIN from the market location to the resource location.
Aspects disclosed herein provide a method for enhancing a mechanical refrigeration process for the production of LNG using liquid refrigerant produced at a different location to subcool the liquefied natural gas coming from the mechanical refrigeration process. More specifically, a process is described in which treated natural gas may be directed to a mechanical refrigeration process. The natural gas may be completely liquefied within the mechanical refrigeration process to produce a pressurized LNG stream where the pressure of the pressurized LNG stream is greater than 50 psia (or 345 kPa) and less than 500 psia (or 3445 kPa), or more specifically greater than 100 psia (or 690 kPa) and less than 400 psia (or 2758 kPa), or more specifically greater than 200 psia (or 1379 kPa) and less than 300 psia (or 2068 kPa). The pressurized LNG stream may then be subcooled by exchanging heat with at least one liquid refrigerant stream to form an LNG stream. The liquid refrigerant stream is produced at a different geographic location than the location where the natural gas is liquefied, and may be 50 miles, or 100 miles, or 200 miles, or 500 miles, or 1,000 miles, or more than 1,000 miles from such location. The mechanical refrigeration process may be a single-mixed refrigerant process, a pure component cascade refrigerant process, a dual-mixed refrigerant process, an expander-based refrigeration process, or any other commonly known refrigeration process that can liquefy a natural gas stream to produce a pressurized LNG stream.
In an aspect, an expander-based process for the production of LNG may be enhanced by using LIN produced at a different location to subcool the pressurized LNG coming from the expander-based process. Natural gas may be treated to remove impurities, if present, such as water, heavy hydrocarbons, and sour gases, to make the natural gas suitable for liquefaction. The treated natural gas may be completely liquefied within the expander-based process to produce a pressurized LNG stream where the pressure of the pressurized LNG stream is greater than 50 psia (or 345 kPa) and less than 500 psia (or 3445 kPa), or more specifically greater than 100 psia (or 690 kPa) and less than 400 psia (or 2758 kPa), or more specifically greater than 200 psia (or 1379 kPa) and less than 300 psia (or 2068 kPa). The pressurized LNG stream may then be subcooled by exchanging heat with at least one LIN stream to form an LNG stream. The expander-based process may be a nitrogen gas expander-based process or may be a feed gas expander-based process.
Figure 1 shows a typical temperature cooling curve 100 for an expander-based liquefaction process. The higher temperature curve 104 is the temperature curve for the natural gas stream. The lower temperature curve 102 is the composite temperature curve of a cold cooling stream and a warm cooling stream. As illustrated, the cooling curve is marked by three temperature pinch-points. The lowest temperature pinch-point 106 occurs where the colder of the two cooling streams, typically the cold cooling stream, enters the heat exchanger. The intermediate temperature pinch-point 108 occurs where the second cooling stream, typically the warm cooling stream, enters the heat exchanger. The warm temperature pinch-point 110 occurs where the cold and warm cooling streams exit the heat exchanger. The lowest temperature pinch-point 106 sets the required flow rate of the cold cooling stream. Since the cold cooling stream is first cooled by the warm cooling stream prior to being expanded to the low temperature, the flow rate of the cold cooling stream also impacts the required flow rate of the warm cooling stream. One way to increase the capacity of the expander-based process without significantly increasing equipment size and required power is to increase the temperature of lowest temperature pinch point. In such a case, to produce LNG additional refrigeration is needed to subcool the pressurized LNG coming from the expander-based process. It would not be advantageous nor efficient to subcool the pressurized LNG with another mechanical refrigeration cycle. For this reason, aspects described herein propose the use of a liquid refrigerant produced at a different location to subcool the pressurized LNG. The liquid refrigerant may be LIN.
Under certain circumstances, the liquid refrigerant can be produced with an amount of energy that makes the overall process of producing the pressurized LNG and liquefied refrigerant more thermodynamically efficient than a conventional LNG production process. For example, the refrigerant may be nitrogen produced from an air separation plant, where the nitrogen is liquefied using the cold available from the gasification of LNG. Typically during the gasification of LNG all the available exergy from gasifying the LNG is lost to the environment. Using this exergy can result in the production of LIN at a sufficiently low energy cost to make the overall energy requirement of the disclosed aspects comparable to or even less than the energy costs of a conventional LNG production process.
According to the disclosed aspects, the expander-based process may be a feed-gas expander-based process. The feed-gas expander-based process may be an open loop feed gas process where the recycling loop comprises a warm-end expander loop and a cold-end expander loop. The warm-end expander may discharge a first cooling stream and the cold-end expander may discharge the second cooling stream. The temperature of the first cooling stream may be higher than the temperature of the second cooling stream. The pressure of the first cooling stream may be the same or similar to the pressure of the second cooling stream. The cold-end expander may discharge a two-phase stream that is separated into a second cooling stream and a second pressurized LNG stream. Natural gas may be treated to remove impurities, if present, such as water, heavy hydrocarbons, and sour gases, to make the natural gas suitable for liquefaction. The treated natural gas may be completely liquefied by indirect exchange of heat with the first cooling stream and the second cooling stream to produce a first pressurized LNG stream. The first pressurized LNG stream may be mixed with the second pressurized LNG stream to form a pressurized LNG stream. The pressure of the pressurized LNG stream is greater than 50 psia (or 345 kPa) and less than 500 psia (or 3445 kPa), or more specifically greater than 100 psia (or 690 kPa) and less than 400 psia (or 2758 kPa), or more specifically greater than 200 psia (or 1379 kPa) and less than 300 psia (or 2068 kPa). The pressurized LNG stream may be subcooled by exchanging heat with at least one LIN stream to form an LNG stream. The subcooling process may include the use of at least one heat exchanger to allow for indirect heat exchange between the vaporizing LIN stream and the pressurized LNG stream. The subcooling process may additionally comprise other equipment such as compressors, expanders, separators and/or other commonly known equipment, to facilitate the cooling of the pressurized LNG stream. The vaporized LIN stream, after heat exchange with the pressurized LNG stream, may be used to liquefy a second stream of treated natural gas to produce an additional pressurized LNG stream. The additional pressurized LNG stream may be mixed with the pressurized LNG stream prior to the subcooling of the pressurized LNG stream with LIN.
In one disclosed aspect, the produced LNG may be loaded onto an LNG carrier and/or a dual-purpose carrier at the LNG production location and is transported to an import terminal at a different location where LNG is offloaded and regasified. The cold energy from the gasification of the LNG may be used to liquefy nitrogen that is then loaded onto a LIN carrier and/or a dual-purpose carrier and transported back to the LNG production location, where the LIN is used to liquefy the treated natural gas.
Figures 2A and 2B are simplified diagrams highlighting a difference between the value chain of the aspects disclosed herein and the value chain of conventional FLNG technology, where an FLNG facility contains all or virtually all equipment necessary to process and liquefy natural gas. As shown in Figure 2A, an LNG cargo ship 200a transports LNG from an FLNG facility 202 to a land-based import terminal 204 where the LNG is offloaded and regasified. The LNG cargo ship 200b, now empty of cargo and ballast, returns to the FLNG facility 202 to be re-loaded with LNG. In contrast, the aspects disclosed herein and shown in Figure 2B provide a floating processing unit (FPU) 206 having a much smaller footprint than the FLNG facility 202 (Figure 2A). Referring to Figure 2B, a LIN cargo ship or a dual purpose ship 208a, loaded with LIN at the import terminal 204, arrives at the FPU 206 and offloads its LIN cargo to storage tanks on and/or within the FPU 206. On the FPU 206 a mechanical refrigeration unit cools the natural gas into a pressurized LNG stream. The pressurized LNG stream is then subcooled within an LIN subcooling unit on the FPU 206 to produce LNG. The produced LNG is transported to the LNG cargo ship or the dual purpose ship 208b. The LNG cargo ship or dual purpose ship 208b, now loaded with LNG, sails to the import terminal 204, where the LNG may be offloaded and regasified. The cold energy from the regasification of the LNG is used to liquefy nitrogen at the import terminal 204. Nitrogen that is liquefied at the import terminal 204 may be produced at an air separation unit 210. The air separation unit 210 may be part of or within the import terminal 204, or a separate facility from the import terminal 204. The LIN may then be loaded into the LIN cargo ship or dual purpose ship, which returns to the FPU 206 to repeat the liquefaction process.
In another aspect, LIN may be used to liquefy LNG boil-off gas from the tanks during LNG production, transport and/or offloading. In another aspect, LIN and/or vaporized LIN from the subcooling process may be used to cool inlet air going into the gas turbines of the mechanical refrigeration process. In another aspect, LIN and/or LIN boil-off gas may be used to keep the liquefaction equipment cold during turndown or shutdown of the liquefaction process. In another aspect, nitrogen vapor may be used to derime the cryogenic heat exchangers during the periods between LNG production. The nitrogen vapor with contaminants may be vented to the atmosphere.
Figure 3 is a schematic diagram of a system 300 according to a disclosed aspect. Natural gas may be treated to remove impurities, if present, such as water, heavy hydrocarbons, and sour gases, to produce a treated natural gas stream 302 that is suitable for liquefaction. The treated natural gas stream 302 may be directed to a mechanical refrigeration unit 304 where the treated natural gas 302 is completely liquefied to produce a pressurized LNG stream 306. The pressure of the pressurized LNG stream 306 may be greater than 50 psia (or 345 kPa) and less than 500 psia (or 3445 kPa), or more specifically greater than 100 psia (or 690 kPa) and less than 400 psia (or 2758 kPa), or more specifically greater than 200 psia (or 1379 kPa) and less than 300 psia (or 2068 kPa). The mechanical refrigeration unit 304 may comprise a single-mixed refrigeration process, a pure component cascade refrigeration process, a dual-mixed refrigeration process, an expander-based refrigeration process, or any other commonly known refrigeration process that can liquefy the treated natural gas stream 302 to a pressurized LNG stream 306. The mechanical refrigeration unit 304 may comprise gas turbines that are used to provide the mechanical power to drive the compressors within the mechanical refrigeration unit 304. The pressurized LNG stream 306 may be directed to a liquid refrigerant subcooling unit 308 where the pressurized LNG stream 306 is subcooled by exchanging heat with a liquid refrigerant stream 310 to form an LNG stream 312. The liquid refrigerant stream 310 is produced at a different location than the location of the mechanical refrigeration unit 304 and the liquid refrigerant subcooling unit 308. The liquid refrigerant stream 310, after being vaporized and warmed within the liquid refrigerant subcooling unit 308 exits the liquid refrigerant subcooling unit 308 as a refrigerant gas vent 314. The liquid refrigerant subcooling unit 308 comprises at least one heat exchanger to allow for indirect heat exchange between the liquid refrigerant stream 310 and the pressurized LNG stream 306. The liquid refrigerant subcooling unit 308 may additionally comprise other equipment such as compressors, expanders, separators and/or other commonly known equipment, to facilitate the cooling of the pressurized LNG stream 306. The vaporized liquid refrigerant stream 310, after heat exchange with the pressurized LNG stream 306, may be used to liquefy a second stream of treated natural gas 316 to form an additional pressurized LNG stream. The additional pressurized LNG stream may be mixed with the pressurized LNG stream 306 prior to the subcooling of the pressurized LNG stream 306 with the liquid refrigerant stream 310 to form the LNG stream 312.
Figure 4 is an illustration of a mechanical refrigeration unit 400 according to disclosed aspects. The mechanical refrigeration unit 400 includes a feed gas expander-based process. Natural gas to be liquefied by the mechanical refrigeration unit 400 may be treated to remove impurities, if present, such as water, heavy hydrocarbons, and sour gases, to produce a treated natural gas stream 402 that is suitable for liquefaction. The treated natural gas stream 402 is mixed with a recycled refrigerant stream 404 using a combining device 403. The combined natural gas stream 405 may then be separated by one or more manifolds, splitters, or other types of separators 406, 408, 409 to produce a second treated natural gas stream 410, a first refrigerant stream 412, a second refrigerant stream 414, and a small treated natural gas stream 415 to be liquefied using a liquid refrigerant, as will be explained herein. The first refrigerant stream 412 is expanded in a first expander 417 to produce a first cooling stream 416. The first cooling stream 416 enters at least one heat exchanger 418 where it exchanges heat with the second treated natural gas stream 410 and the second refrigerant stream 414 to cool these two streams. The first cooling stream 416, now heated, exits the at least one heat exchanger 418 as a first warm stream 420. The second refrigerant stream 414, after being cooled in the at least one heat exchanger 418, is expanded in a second expander 422 to produce a two-phase stream 424. The pressure of the two-phase stream 424 may be the same or near the same to the pressure of the first cooling stream 416. The two-phase stream 424 may be separated into its vapor component and its liquid component in a two-phase separator 426 to form a second cooling stream 428 and a second pressurized LNG stream 430. The temperature of the first cooling stream 416 may be higher than the temperature of the second cooling stream 428. The second pressurized LNG stream 430 may be pumped, using a pump 432, to a higher pressure after it has exited the two-phase separator 426. The second cooling stream 428 may enter the at least one heat exchanger 418 where it exchanges heat with the second treated natural gas stream 410 and the second refrigerant stream 414 to cool said streams. The heated second cooling stream exits the at least one heat exchanger 418 as a second warm stream 434. The second treated natural gas stream 410 may exchange heat with the first cooling stream 416 and the second cooling stream 428 to produce a first pressurized LNG stream 436. The first pressurized LNG stream 436 may be reduced in pressure in a hydraulic turbine 437 or other pressure-reducing device after the first pressurized LNG stream 436 has exited the at least one heat exchanger 418. The first pressurized LNG stream 436 may be mixed with the second pressurized LNG stream 430 to form a combined pressurized LNG stream 438. The pressure of the combined pressurized LNG stream 438 may be greater than 50 psia (or 345 kPa) and less than 500 psia (or 3445 kPa), or more specifically greater than 100 psia (or 690 kPa) and less than 400 psia (or 2758 kPa), or more specifically greater than 200 psia (or 1379 kPa) and less than 300 psia (or 2068 kPa). The pressurized LNG stream 438 may be directed to a LIN subcooling unit, as will be further described herein.
The first warm stream 420 may be combined with the second warm stream 434 in a combining apparatus 440 to form a combined warm refrigerant stream 442. The combined warm refrigerant stream 442 may be compressed in multiple compressor stages to form the recycled refrigerant stream 404. The compressor stages may include a first compressor stage 444, a second compressor stage 446, and a third compressor stage 448. The first compressor stage 444 may be driven by a gas turbine (not shown). The second compressor stage 446 may be driven solely by the shaft power produced by the first expander 417. The third compressor stage 448 may be driven solely by the shaft power produced by the second expander 422. Coolers 450, 452, and 454 may cool the combined warm refrigerant stream 442 after the first, second, and third compressor stages 444, 446, 448, respectively.
Figure 5 is a schematic diagram of a LIN subcooling unit 500 according to disclosed aspects. The LIN subcooling unit 500 may be used with the mechanical refrigeration unit 400 depicted in Figure 4. LIN produced at a different location than the location of the LIN subcooling unit 500 is transported to the location of the LIN subcooling unit 500 and directed to at least one heat exchanger 502 as a LIN stream 504. The LIN stream 504 is vaporized in the at least one heat exchanger 502 by subcooling a pressurized LNG stream 506 (which may be the same as the combined pressurized LNG stream 438 of Figure 4) to produce a vaporized nitrogen stream 508 and an LNG stream 510. The vaporized nitrogen stream 508 may be directed to a secondary heat exchanger 512 to liquefy a treated natural gas stream 514, which may be the same as the small treated natural gas stream 415, to form an additional pressurized LNG stream 516. The additional pressurized LNG stream 516 may be combined with the pressurized LNG stream 506 in a combining apparatus 518 prior to entering the at least one heat exchanger 502. The additional pressurized LNG stream 516 may be reduced in pressure in a hydraulic turbine 520 or other pressure-reducing apparatus prior to being combined with the pressurized LNG stream 506. The vaporized nitrogen stream 508 is heated by the treated natural gas stream 514 in the secondary heat exchanger 512 to form a nitrogen vent gas 522 that may be vented to the atmosphere or used in other areas of the gas processing facility in which the LIN subcooling unit 500 is located.
Figure 6 is a schematic diagram of a LIN subcooling unit 600 according to disclosed aspects. The LIN subcooling unit 600 may be used with the mechanical refrigeration unit 400 depicted in Figure 4. LIN produced at a different location than the location of the LIN subcooling unit 600 is transported from the different location and directed to the LIN subcooling unit 600 as a LIN stream 602. A pump 604 may pump the LIN stream 602 to a pressure greater than 400 psi to form a high pressure LIN stream 606. The high pressure LIN stream 606 exchanges heat with a pressurized LNG stream 608 (which may be the same as the combined pressurized LNG stream 438 of Figure 4) in at least one heat exchanger 610 to form a first warmed nitrogen gas stream 612. The first warmed nitrogen gas stream 612 may be expanded in a first expander 614 to produce a first additionally cooled nitrogen gas stream 616. The first additionally cooled nitrogen gas stream 616 exchanges heat with the pressurized LNG stream 608 in the at least one heat exchanger 610 to form a second warmed nitrogen gas stream 618.
The second warmed nitrogen gas stream 618 may indirectly exchange heat with other process streams, for example in a secondary heat exchanger 619, prior to the second warmed nitrogen gas stream 618 being compressed in one or more compressor stages to form a compressed nitrogen gas stream 620. As shown in Figure 6, the one or more compressor stages may comprise two compressor stages, including a first compressor stage 622 and a second compressor stage 624. The second compressor stage 624 may be driven solely by the shaft power produced by the first expander 614. The first compressor stage 622 may be driven solely by the shaft power produced by a second expander 626. After each compression stage, the compressed nitrogen gas stream 620 may be cooled by indirect heat exchange with the environment in coolers 628, 630, respectively. The compressed nitrogen gas stream 620 may be expanded in the second expander 626 to produce a second additionally cooled nitrogen gas stream 632. The second additionally cooled nitrogen gas stream 632 exchanges heat with the pressurized LNG stream 608 in the at least one heat exchanger 610 to form a third warmed nitrogen gas stream 634. The pressurized LNG stream 608 is subcooled by exchanging heat with the high pressure LIN stream 606, the first additionally cooled nitrogen gas stream 616, and the second additionally cooled nitrogen gas stream 632 to form an LNG stream 636. The third warmed nitrogen gas stream 634 may be directed to a tertiary heat exchanger 638 to liquefy a treated natural gas stream 640, which may be the same as the small treated natural gas stream 415 in Figure 4, to form an additional pressurized LNG stream 642. The additional pressurized LNG stream 642 may be combined with the pressurized LNG stream 608 in a combining apparatus 644 prior to the subcooling of the pressurized LNG stream 608 in the at least one heat exchanger 610. The additional pressurized LNG stream 642 may be reduced in pressure in a hydraulic turbine 646 prior to being combined with the pressurized LNG stream 608. The third warmed nitrogen gas stream 634 may be heated by the treated natural gas stream 640 to form a nitrogen vent gas 648 that may be vented to the atmosphere or used in other areas of the gas processing facility in which the LIN subcooling unit 600 is located. The LIN subcooling unit 600 illustrated in Figure 6 reduces the LIN requirement for subcooling a pressurized LNG stream by approximately 20 to 25% compared to the LIN subcooling unit 500 illustrated in Figure 5. However, the choice of subcooling units may depend on criteria such as cost of LIN and available topside space for LIN storage and/or the LIN subcooling unit itself.
Figure 7 is a flowchart of a method 700 for producing liquefied natural gas (LNG). At block 702 a natural gas stream is directed to a mechanical refrigeration unit to liquefy the natural gas stream and form a pressurized liquefied natural gas (LNG) stream with a pressure greater than 50 psia (345 kPa) and less than 500 psia (3445 kPa). At block 704 a liquid refrigerant subcooling unit is provided at a first location. At block 706 liquid refrigerant is produced at a second location that is geographically separate from the first location. At block 708 the produced liquid refrigerant is transported to the first location. At block 710 the pressurized LNG stream is subcooled in the liquid refrigerant subcooling unit by exchanging heat between the pressurized LNG stream and at least one stream of the liquid refrigerant to thereby produce an LNG stream.
The steps depicted in Figure 7 are provided for illustrative purposes only and a particular step may not be required to perform the disclosed methodology. Moreover, Figure 7 may not illustrate all the steps that may be performed. The claims, and only the claims, define the disclosed system and methodology.
The aspects described herein have several advantages over known technologies. For example, the described aspects may significantly increase the capacity of a conventional mechanical refrigeration process without significantly increasing required power and footprint of the mechanical refrigeration process. For example, compared to known feed gas expander-based processes, the feed gas expander-based process coupled with LIN subcooling described herein can produced approximately 50% more LNG at an equivalent mechanical refrigeration power. The amount of LIN needed is approximately 0.26 ton of LIN for every ton of LNG produced. The reduced amount of LIN makes this technology particularly suitable for FLNG applications. Using the disclosed aspects, the 50% extra throughput through the feed gas expander-based process only increases the required volumetric flow to the low pressure compressor and the cryogenic heat exchanger load by approximately 10% respectively compared to known feed gas expander technologies.
It should be understood that the numerous changes, modifications, and alternatives to the preceding disclosure can be made without departing from the scope of the disclosure. The preceding description, therefore, is not meant to limit the scope of the disclosure. Rather, the scope of the invention is to be determined only by the appended claims and their equivalents. It is also contemplated that structures and features in the present examples can be altered, rearranged, substituted, deleted, duplicated, combined, or added to each other.

Claims

A method for producing liquefied natural gas (LNG), comprising:
directing a natural gas stream (302, 403) to a mechanical refrigeration unit (304) to liquefy the natural gas stream (302, 403) and form a pressurized liquefied natural gas (LNG) stream (306, 438) with a pressure greater than 50 psia (345 kPa) and less than 500 psia (3445 kPa), wherein the mechanical refrigeration unit (304) includes an expander-based refrigeration process;

providing a liquid refrigerant subcooling unit (308) at a first location;

producing liquid refrigerant at a second location that is geographically separate from the first location;

transporting the produced liquid refrigerant to the first location; and

subcooling the pressurized LNG stream (306, 438, 506, 608) in the liquid refrigerant subcooling unit (308) by exchanging heat between the pressurized LNG stream (306, 438, 506, 608) and at least one stream (310, 504, 602) of the liquid refrigerant to thereby produce an LNG stream (312, 510, 636) and a vaporized liquid refrigerant stream (314, 522, 648)

characterized by the following steps

using the vaporized liquid refrigerant stream to liquefy a second treated natural gas stream (514, 640) to produce an additional pressurized LNG stream (516); and

mixing the additional pressurized LNG stream (516, 642) with the pressurized LNG stream (506, 608) prior to the subcooling of the pressurized LNG stream (506, 608) with the liquid refrigerant.
The method of claim 1, wherein the liquid refrigerant subcooling unit (308) comprises
at least one heat exchanger (502, 610), or

at least one compressor and/or expander.
The method of any of claims 1-2, further comprising re-liquefying LNG boil-off gas using the liquid refrigerant.
The method of any of claims 1-3, wherein the liquid refrigerant and/or a liquid refrigerant boil-off gas is used to keep the mechanical refrigeration unit (304) and/or liquid refrigerant subcooling unit equipment cold during turndown and/or shutdown periods of the mechanical refrigeration unit (304).
The method of any of claims 1-4, wherein warm liquid refrigerant vapor is used to derime heat exchangers used to exchange heat.
The method of any of claims 1-5, further comprising:
transporting the LNG stream from the first location to the second location in a dual-purpose carrier (208a, 208b); and

after the LNG stream has been offloaded from the dual-purpose carrier (208a, 208b), transporting the liquid refrigerant from the second location to the first location in the dual purpose carrier (208a, 208b).
The method of any of claims 3-6, wherein the mechanical refrigeration unit (304) includes one of a single-mixed refrigerant process, a pure component cascade refrigerant process, or a dual-mixed refrigerant process.
The method of any of claims 1-7, wherein the pressurized LNG stream (306, 438, 506, 608) has a pressure greater than 100 psia (690 kPa) and less than 400 psia (2758 kPa).
The method of any of claims 1-8, wherein the pressurized LNG stream (306, 438, 506, 608) has a pressure greater than 200 psia (1379 kPa) and less than 300 psia (2068 kPa).
The method of any of claims 1-9, wherein the liquid refrigerant comprises liquid nitrogen (LIN), and further comprising producing the LIN by exchanging heat with LNG during LNG regasification.
The method of any of claims 1-10, further comprising:
directing pressurized LNG streams from a plurality of mechanical refrigeration units (304) to the liquid refrigerant subcooling unit (308) to produce at least one LNG stream.