Integration of a high-pressure feed gas process with a heat recovery steam generator for the production of liquefied natural gas

Abstract

A method for producing LNG. According to the method, a natural gas stream is compressed using first and second compressors. A cooler cools the natural gas stream, such that the second compressor produces a cooled, compressed natural gas stream, which is liquefied in a liquefaction process. The liquefaction process uses a refrigerant compressor configured to compress a refrigerant stream that is used to chill, condense, or liquefy the cooled, compressed natural gas stream. A heat recovery steam generator (HRSG) system is used to recover heat from a power source for the refrigerant compressor. A pressurized steam stream is generated from the recovered heat. At least one of the first and second compressors is powered using at least a portion of the pressurized steam stream.

Description

[Technical Field]

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS This application claims priority to U.S. Provisional Patent Application No. 63 / 053050, filed July 17, 2020, entitled HEAT RECOVERY STEAM GENERATION INTEGRATION WITH HIGH PRESSURE FEED GAS PROCESSES FOR THE PRODUCTION OF LIQUEFIED NATURAL GAS. This disclosure relates generally to the field of hydrocarbon processing plants. More particularly, this disclosure relates to the efficient design, construction, and operation of hydrocarbon processing plants, such as LNG processing plants. [Background technology]

[0002] This section is intended to introduce various aspects of art that may be related to the present disclosure. The discussion is intended to provide a framework to facilitate a better understanding of certain aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.

[0003] Liquefied natural gas (LNG) production is a rapidly growing means for supplying natural gas from abundant natural gas source locations to remote locations with strong demand for natural gas. The conventional LNG cycle includes: a) initial processing of the natural gas resource to remove contaminants such as water, sulfur compounds, and carbon dioxide; b) separation of some heavy hydrocarbon gases, e.g., propane, butane, pentane, etc., by various possible methods, including self-refrigeration, external refrigeration, lean oil, etc.; c) refrigeration of the natural gas essentially by external refrigeration at or near atmospheric pressure and about −160° C. to form liquefied natural gas; d) removal of light components, such as nitrogen and helium, from the LNG; e) transportation of the LNG product in ships or tankers designed for this purpose to points of sale; and f) repressurization and regasification of the LNG in a regasification plant to form a pressurized natural gas stream that can be distributed to natural gas consumers. Step (c) of the liquefaction process is typically achieved using a vapor compression or gas expansion cycle, both of which employ one or more compressors to increase refrigerant pressure and reject heat to the environment. In large-scale applications, these compressors are usually driven by one or more gas turbines. The fuel used to drive these gas turbines consists of fresh feed gas and flash gas slipstreams generated from LNG storage, loading, and sometimes from process feeds containing light impurities such as nitrogen gas. Extra fuel is often required to meet other process heating needs in LNG production facilities, such as feed gas heating, acid gas removal units and associated reboilers and / or fractionation columns, regeneration heat, etc. All these fuel requirements deplete the supply of feed gas that would otherwise be available for LNG production. Furthermore, combustion of feed gas generates more carbon dioxide emissions, thereby negatively impacting the carbon footprint of LNG production facilities. There is a need for a method of producing LNG that maximizes the amount of feed gas liquefied while minimizing the carbon footprint of the liquefaction process. Summary of the Invention

[0004] In one aspect, a method for producing liquefied natural gas (LNG) is provided. According to the method, a natural gas stream is provided from a natural gas source at a pressure less than 1,200 psia. The natural gas stream is compressed to a pressure of at least 1,500 psia using a first compressor and a second compressor. The natural gas stream is cooled between the first compressor and the second compressor, such that the second compressor produces a cooled compressed natural gas stream. The cooled compressed natural gas stream is liquefied in a liquefaction process. The liquefaction process uses a refrigerant compressor configured to compress a refrigerant stream that is used to chill, condense, or liquefy the cooled compressed natural gas stream. A heat recovery steam generator (HRSG) system is used to recover heat from a power source for the refrigerant compressor, and a pressurized steam stream is generated from the recovered heat. At least one of the first and second compressors is powered using at least a portion of the flow of compressed steam.

[0005] In another aspect, a system is provided for producing LNG from a natural gas stream. A first compressor and a second compressor compress the natural gas stream from a pressure of less than 1,200 psia (8.27 MPa) to a pressure of at least 1,500 psia (10.34 MPa). A heat exchanger is disposed between the first compressor and the second compressor. The heat exchanger cools the natural gas stream, such that the second compressor produces a cooled compressed natural gas stream. A liquefaction process liquefies the cooled compressed natural gas stream. The liquefaction process includes a refrigerant compressor that compresses a refrigerant stream used to chill, condense, or liquefy the cooled compressed natural gas stream. The refrigerant compressor is powered by a power source. A heat recovery steam generator (HRSG) system recovers heat from the power source of the refrigerant compressor, thereby generating a pressurized steam stream from the recovered heat. At least one of the first and second compressors is powered using at least a portion of the flow of compressed steam.

[0006] In yet another aspect, a method for producing LNG is provided. According to the method, a natural gas stream is provided and liquefied in a liquefaction process. The liquefaction process uses a first compressor and a second compressor to compress one or more refrigerants used to chill, condense, or liquefy the chilled natural gas stream. The first compressor is powered by a gas turbine and the second compressor is powered by a steam turbine. A heat recovery steam generator (HRSG) system is used to recover heat from the gas turbine and generate a pressurized steam stream from the recovered heat. The steam turbine is powered using at least a portion of the pressurized steam stream.

[0007] In yet another aspect, a system for producing LNG from a natural gas stream is provided. A liquefaction process liquefies the natural gas stream. The liquefaction process includes a first compressor and a second compressor that compress one or more refrigerants used to chill, condense, or liquefy the chilled natural gas stream. A gas turbine powers the first compressor. A steam turbine powers the second compressor. A heat recovery steam generator (HRSG) system recovers heat from the gas turbine and generates a pressurized steam stream from the recovered heat. The steam turbine is powered using at least a portion of the pressurized steam stream.

[0008] The present disclosure is susceptible to various modifications and alternative forms, and specific exemplary implementations thereof have been shown in the drawings and are described in detail herein. It should be understood, however, that the description herein of specific exemplary implementations is not intended to limit the disclosure to the particular forms disclosed herein. The present disclosure covers all modifications and equivalents as defined by the appended claims. It should also be understood that the drawings are not necessarily to scale, emphasis instead being placed upon clearly illustrating the principles of exemplary embodiments of the present invention. Moreover, certain dimensions may be exaggerated to help visually convey such principles. Furthermore, where considered appropriate, reference numerals may be repeated among the figures to indicate corresponding or similar elements. Furthermore, two or more blocks or elements shown separately or separately in the figures may be combined into a single functional block or element. Likewise, a single block or element illustrated in the figures may be realized as multiple steps or by multiple cooperating elements. The forms disclosed herein are illustrated by way of example, and not limitation, in the accompanying drawing figures, in which like reference numerals refer to like elements. [Brief explanation of the drawings]

[0009] [Figure 1] 1 is a schematic diagram of a high pressure compression and expansion (HPCE) module or system according to a known embodiment. [Figure 2] FIG. 1 is a schematic diagram of a system for producing LNG according to an embodiment of the present disclosure. [Figure 3] FIG. 1 is a schematic diagram of a system for producing LNG according to an embodiment of the present disclosure. [Figure 4] FIG. 1 is a schematic diagram of a system for producing LNG according to an embodiment of the present disclosure. [Figure 5] FIG. 1 is a schematic diagram of a system for producing LNG using multiple liquefaction trains according to an embodiment of the present disclosure. [Figure 6] FIG. 1 is a schematic diagram of a system for producing LNG according to an embodiment of the present disclosure. [Figure 7]FIG. 1 is a schematic diagram of a system for producing LNG according to an embodiment of the present disclosure. [Figure 8] FIG. 1 is a schematic diagram of a system for producing LNG according to an embodiment of the present disclosure. [Figure 9] FIG. 1 is a schematic diagram of a system for producing LNG according to an embodiment of the present disclosure. [Figure 10] 1 is a flowchart of a method according to an aspect of the present disclosure. [Figure 11] 1 is a flowchart of a method according to an aspect of the present disclosure. DETAILED DESCRIPTION OF THE INVENTION

[0010] term The words and phrases used herein should be understood and interpreted to have a meaning consistent with the understanding of those words and phrases by those skilled in the relevant art. A special definition of a term or phrase, i.e., a definition that is different from the ordinary and accustomed meaning as understood by those skilled in the art, is intended to be implied by consistent use of the term or phrase herein. To the extent that a term or phrase is intended to have a special meaning, i.e., a meaning other than the broadest meaning understood by those skilled in the art, such special or clarifying definition will be expressly set forth herein in a definitional manner that provides a special or clarifying definition for the term or phrase. For example, the following discussion contains a non-exhaustive list of definitions of some specific terms used in this disclosure (other terms may be defined or clarified in a definitional manner elsewhere herein). These definitions are intended to clarify the meaning of the terms used herein. Terms are used in a manner consistent with their ordinary meaning, but the definitions are nevertheless believed to be provided here for clarity.

[0011] A / an: As used herein, the articles "a" and "an" mean one or more when applied to any feature of the embodiments and implementations of the invention described and claimed herein. The use of "a" and "an" does not limit the meaning to a single feature unless such a limitation is specifically stated. The term "a" or "an" entity refers to one or more of that entity. Thus, the terms "a" (or "an"), "one or more," and "at least one" can be used interchangeably herein. About: As used herein, "about" refers to a degree of variation based at least in part on experimental error typical for the particular property identified. The degree of latitude afforded by the term "about" depends on the specific context and the particular property and is readily discernible by one of ordinary skill in the art. The term "about" is not intended to broaden or limit the equivalent extent to which a particular value may otherwise be obtained. Furthermore, unless otherwise stated, the term "about" expressly includes "exactly," consistent with the following discussion of ranges and numerical data.

[0012] And / or: The term "and / or" placed between a first entity and a second entity means (1) the first entity, (2) the second entity, and (3) one of the first entity and the second entity. Multiple elements listed with "and / or" should be construed in the same manner, i.e., "one or more" of the elements so conjoined. Other elements other than the elements specifically identified by the "and / or" clause may be present, whether related or unrelated to the specifically identified elements. Thus, as a non-limiting example, a reference to "A and / or B," when used in conjunction with an open-ended phrase, e.g., "comprising," can refer, in one embodiment, to A only (which may include elements other than B); in another embodiment, to B only (which may include elements other than A); or in yet another embodiment, to both A and B (which may include other elements). As used herein in the specification and claims, "or" should be understood to have the same meaning as "and / or" as defined above. For example, when separating items in a list, "or" or "and / or" shall be interpreted as inclusive, i.e., not only as the inclusion of at least one of a number or list of elements, but also as including more than one, and may include additional unlisted items. Terms clearly indicating the contrary, such as "only one of" or "exactly one of," or, when used in the claims, "consisting of," only refer to the inclusion of exactly one element of a number or list of elements. In general, the term "or" as used herein will be interpreted to indicate exclusive alternatives (i.e., "one or the other, but not both") only when preceded by exclusive terms such as "either," "one of," "only one of," or "exactly one of."

[0013] Any: The adjective "any" means any amount of one, some, or all indiscriminately. At Least: As used herein in the specification and claims, the phrase "at least one," with reference to a list of one or more elements, should be understood to mean at least one element selected from any one or more of the elements of the list of elements, but not necessarily including at least one of each and every element specifically listed within the list of elements, nor excluding any combinations of elements of the list of elements. This definition also allows for elements other than those specifically identified within the list of elements to which the phrase "at least one" refers, whether related or unrelated to the elements specifically identified. Thus, as a non-limiting example, "at least one of A and B" (or, equivalently, "at least one of A or B," or, equivalently, "at least one of A and / or B") can refer, in one embodiment, to including at least one A, and optionally including two or more A, and no B (and optionally including elements other than B); in another embodiment, to including at least one B, and optionally including two or more B, and no A (and optionally including elements other than A); and, in yet another embodiment, to including at least one A, and optionally including two or more A, and including at least one B, and optionally including two or more B (and optionally including other elements). The phrases "at least one," "one or more," and "and / or" are open-ended expressions that are both conjunction and disjunction operations. For example, the phrases "at least one of A, B, and C," "at least one of A, B, or C," "one or more of A, B, and C," "one or more of A, B, or C," and "A, B, and / or C" each mean A alone, B alone, C alone, A and B together, A and C together, B and C together, or A, B, and C together.

[0014] Comprising: In the claims and throughout this specification, all transitional phrases such as "comprising," "including," "carrying," "having," "containing," "involving," "holding," "consisting of," and the like, are to be understood to be open-ended, i.e., meaning including but not limited to. Only the transitional phrases "consisting of" and "consisting essentially of" are closed or semi-closed transitional phrases, respectively, as set forth in the U.S. Patent Office Manual of Patent Examining Procedure, Section 2111.03.

[0015] Coupled: Any use of the terms "connect," "mate," "couple," "couple" or any other term in any form describing an interaction between elements is not meant to limit the interaction to a direct interaction between the elements, but may also include indirect interactions between the described elements. Determining: "Determining" encompasses a wide variety of actions, and thus, "determining" may include calculating, operating, processing, deriving, considering, examining (e.g., examining a table, database, or another data structure), ascertaining, and the like. "Determining" may also include receiving (e.g., receiving information), accessing (e.g., accessing data in a memory), and the like. "Determining" may also include solving, selecting, choosing, establishing, and the like.

[0016] Embodiments: Throughout this specification, the terms "one embodiment," "one embodiment," "some embodiments," "one aspect," "one aspect," "some aspects," "some implementations," "one implementation," "one implementation," or similar constructions mean that a particular component, feature, structure, method, or characteristic described in connection with an embodiment, aspect, or implementation is included in at least one embodiment and / or implementation of the claimed subject matter. Thus, the appearances of the phrase "in one embodiment" or "in one embodiment" or "in some embodiments" (or "aspects" or "implementations") in various places throughout this specification are not necessarily all referring to the same embodiment and / or implementation. Furthermore, particular features, structures, methods, or characteristics may be combined in any suitable manner in one or more embodiments or implementations.

[0017] Exemplary: "Exemplary" is used exclusively herein to mean "serving as an example, instance, or illustration." Any embodiment described herein as "exemplary" is not necessarily to be construed as preferred or advantageous over other embodiments. Flowcharts: Example methods may be better appreciated with reference to flow charts or flowcharts. For purposes of simplicity, the example methods are shown and described as a series of blocks; however, it should be appreciated that the method is not limited by the order of the blocks, as in different embodiments, some blocks may occur in a different order than shown and described and / or concurrently with other blocks. Furthermore, fewer than all of the example blocks may be required to implement the example methods. In some instances, blocks may be combined, divided into multiple components, additional blocks may be used, etc.

[0018] May: The word "may" is used throughout this application in a permissive sense (i.e., have the possibility, can do) rather than a mandatory sense (i.e., must). Operably connected and / or coupled: Operably connected and / or coupled means directly or indirectly connected to transmit or conduct information, force, energy, or matter. Optimize: "optimal," "optimizing," "optimize," "optimality," "optimization" (and derivatives and other forms of these terms and linguistically related words and phrases), as used herein, are not intended to be limiting in the sense of requiring the present invention to find the best solution or make the best decision. Indeed, while a mathematically optimal solution may arrive at the best of all mathematically available possibilities, actual embodiments of optimization procedures, methods, models, and processes may work toward such a goal without actually achieving perfection. Accordingly, those skilled in the art with the benefit of this disclosure will recognize that these terms are more general in the context of the scope of the present invention. This term may describe one or more of: 1) working toward a solution that may be the best available solution, a preferred solution, or a solution that provides a tangible benefit within constraints; 2) successively improving; 3) refining; 4) searching for a high point or maximum for an objective; 5) processing to reduce a penalty function; 6) seeking to maximize one or more factors against competing and / or collaborative objectives in maximizing, minimizing, or otherwise controlling one or more other factors;

[0019] Order of Steps: In any method claimed herein that includes more than one step or action, it should also be understood that, unless expressly indicated to the contrary, the order of the method steps or actions is not necessarily limited to the order in which the method steps or actions are recited. Ranges: Concentrations, dimensions, amounts, and other numerical data may be presented herein in a range format. It should be understood that such range format is used merely for convenience and brevity and should be interpreted flexibly to include not only the numerical values ​​explicitly recited as range limits, but also all individual numerical values ​​or subranges encompassed within that range, as if each numerical value and subrange were explicitly recited. For example, a range of about 1 to about 200 should be interpreted not only to include the explicitly recited limits of 1 and about 200, but also to include individual sizes such as 2, 3, 4, etc., and subranges such as 10 to 50, 20 to 100, etc. Similarly, when numerical ranges are provided, it should be understood that such ranges are interpreted as providing literal support for claim limitations that recite only the lower value of the range and for claim limitations that recite only the upper value of the range. For example, a disclosed numerical range of 10 to 100 provides literal support for claims reciting "greater than 10" (without an upper limit) and claims reciting "less than 100" (without a lower limit).

[0020] As used herein, the term "hydrocarbon" refers to organic compounds that contain primarily, if not exclusively, the elements hydrogen and carbon. Examples of hydrocarbons include natural gas, petroleum, coal, and bitumen in any form that can be used as a fuel or upgraded to a fuel.

[0021] description Specific embodiments of the present disclosure are further described below by way of example. The following examples demonstrate certain specific forms of the subject matter disclosed herein, but they should not be construed as limiting its scope, but rather as contributing to a more complete description. Embodiments disclosed herein describe a process for cooling natural gas prior to a liquefaction process for the production of LNG by the addition of high-pressure compression and expansion processes to the feed gas. More specifically, the present invention describes a process for compressing a pretreated natural gas stream to a pressure greater than 2000 psia (13,790 kPa), or more preferably greater than 3000 psia (20,680 kPa). The hot compressed gas is cooled by heat exchange with the environment to form a compressed pretreated gas. The compressed pretreated gas may be expanded approximately isentropically to a pressure less than 3000 psia (20,680 kPa), or more preferably less than 2000 psia (13,790 kPa), to form a cooled pretreated gas, the pressure of which is less than that of the compressed pretreated gas. The cooled pretreated gas may be directed to one or more liquefaction trains, where the gas is further cooled to form LNG.

[0022] FIG. 1 illustrates a pre-cooling process as disclosed in U.S. Patent Application Publication No. 2017 / 0167786, the disclosure of which is incorporated herein by reference in its entirety. The pre-cooling process is referred to herein as a high-pressure compression and expansion (HPCE) process and is accomplished using a system designated by reference numeral 100. The HPCE system 100 may include a first compressor 102 that compresses a pre-treated natural gas stream 104 to form an intermediate-pressure gas stream 106. The first compressor 102, which may also be referred to herein as a feed compressor, is typically powered by a motor or gas turbine 103. The intermediate-pressure gas stream 106 may flow through a first heat exchanger 108, where it is cooled by indirect heat exchange with the environment to form a cooled intermediate-pressure gas stream 110. The first heat exchanger 108 may be an air-cooled or water-cooled heat exchanger. The cooled intermediate-pressure gas stream 110 may then be compressed in a second compressor 112 to form a high-pressure gas stream 114. The pressure of the high-pressure gas stream 114 may be greater than 2000 psi (13,790 kPa), or more preferably greater than 3000 psia (20,680 kPa). The high-pressure gas stream 114 may flow through a second heat exchanger 116, where it is cooled by indirect heat exchange with the environment to form a cooled high-pressure gas stream 118. The second heat exchanger 116 may be an air-cooled or water-cooled heat exchanger. The cooled high-pressure gas stream 118 may then be expanded in an expander 120 to form a chilled pretreated gas stream 122. The pressure of the cooled pre-treated gas stream 122 may be less than 3000 psia (20,680 kPa), or more preferably less than 2000 psia (13,790 kPa), and the pressure of the cooled pre-compressed gas stream 122 is less than the pressure of the cooled high-pressure gas stream 118. In a preferred embodiment, the second compressor 112 may be driven solely by the shaft power generated by the expander 120, as indicated by dashed line 124.

[0023] According to embodiments of the present disclosure, an HPCE system 100 may be used to compress and cool a feed stream for a natural gas liquefaction system. FIG. 2 illustrates this combination schematically. The HPCE system 100, as previously described, is shown delivering a cooled pretreated gas stream 122 to a natural gas liquefaction system 210 to produce liquefied natural gas (LNG) 212 therefrom. The natural gas liquefaction system 210 relies on a compressor 214 for a heating / cooling cycle of refrigerant streams 216, 218 used in the liquefaction process. A gas turbine 220 powers the compressor 214. Heat 222 produced by the gas turbine 220 may be captured by a heat recovery steam generator (HRSG) unit, shown schematically at 224. According to known principles, the HRSG unit 224 generates one or more streams 226, 228 of high-pressure heating steam from the heat 222 using direct or indirect heat exchange. Stream 226 may be present and may be used in a variety of ways, such as for heating, generating electricity, etc. Stream 228 is directed to steam turbine 102a configured to drive first compressor 102. Steam turbine 102a may be a condensing steam turbine with or without side extraction, or a back-pressure steam turbine. In such a configuration, steam turbine 102a may consume some or all of the steam produced by HRSG unit 224, depending on the process configuration, location, gas properties, and other factors. As an example, the thermal energy distribution is listed in Table 1 for a three-train, hot-climate LNG project with a nominal capacity of 3 MTA per train, using methane and nitrogen-cooled liquefaction modules and a single HPCE unit supplying feed gas to all three trains.

[0024] [Table 1]

[0025] As shown, the steam turbine 102a uses a large portion of the heat recovered and steam generated by the HRSG unit 224, eliminating the fuel gas required to drive the first compressor 102 from the HRSG unit and advantageously allowing excess heat capacity 226 to provide heat to the process, cover all process heating needs, or generate electricity. Thus, the need for an expensive steam power generation system is minimized or eliminated. Furthermore, some process heating needs can be provided by side-extracted steam 102b from the steam turbine 102a. This has two advantages: all steam used for heating is also used to deliver shaft power, and the associated steam vacuum condenser is smaller in size. Instead of using a condensing steam turbine, other types of steam turbines, including turbines using side extraction, or back-pressure steam steam turbines, including those for end-flash gas (EFG) compressors, may be used.

[0026] FIG. 3 illustrates a system and process for producing liquefied natural gas (LNG) according to an embodiment of the present disclosure. Feed gas (natural gas) enters one or more pretreatment modules 304 through an inlet line 302, which process the feed gas to remove contaminants. The pretreatment modules may include dehydration units to remove water from the feed gas. The pretreatment modules may also include scrubbers and / or flash tanks to remove other contaminants, such as sulfur compounds, carbon dioxide, and heavy hydrocarbons. The processed gas then passes from the pretreatment modules 304 to the HPCE system 100, as previously described. For brevity, a complete description of the HPCE system 100 will not be repeated. The output of the HPCE system 100 is a chilled pretreated gas stream 122, which is directed to a liquefaction system 310. The liquefaction system 310 illustrated in FIG. 3 is a single mixed refrigerant (SMR) liquefaction system, which uses a mixed refrigerant to liquefy a natural gas stream in a single refrigeration subprocess. A non-limiting example of a single mixed refrigerant liquefaction system is disclosed in commonly owned U.S. Patent Application Publication No. 2007 / 0227185, the disclosure of which is incorporated herein by reference in its entirety. Liquefaction system 310 uses heat exchanger 312 and MCR compression unit 314, each having two or more heat exchangers included therein. The cooled pretreated gas stream 122 is directed to heat exchanger 312, where it is cooled against mixed component refrigerant ("MCR") stream 318 in heat exchanger 312 and exits as cooled stream 316. In one embodiment, MCR stream 318 can be a mixture of ethane, propane, and isobutane. MCR stream 318 may contain between about 20 mol% and 80 mol% ethane, between about 10 mol% and 90 mol% propane, and between about 5 mol% and 30 mol% isobutane. Other components and proportions thereof may also be included in MCR stream 318.

[0027] Continuing with FIG. 3 , MCR stream 318 enters heat exchanger 312. At least a portion of MCR stream 318 is withdrawn from a first heat exchange area of ​​heat exchanger 312 as side stream 320. Side stream 320 is expanded to a first pressure using expansion device 322 to produce two-phase stream 324 (i.e., a stream having a vapor phase and a liquid phase). This first pressure may range from a minimum of 800 kPa, or 1,200 kPa, or 1,500 kPa to a maximum of 1,900 kPa, or 2,200 kPa, or 2,600 kPa. Accordingly, the temperature of two-phase stream 324 ranges from a minimum of 0° C., or 3° C., or 4° C. to a maximum of 6° C., or 10° C., or 15° C. Preferably, side stream 320 is expanded to a pressure of 1,600 kPa to 1,800 kPa and a temperature of 4° C. to 6° C.

[0028] Two-phase stream 324 is then separated in separator 326 to produce vapor stream 328 and liquid stream 330. Preferably, two-phase stream 324 is subjected to flash separation. Vapor stream 328 bypasses heat exchanger 312 and is sent directly to compression unit 314. Bypassing the refrigerant stream around the heat exchange area to the compression unit, problems associated with using two-phase refrigerants are eliminated. After being reduced in pressure and therefore cooled, liquid stream 330 returns to heat exchanger 312, where it is fully or partially evaporated due to the heat exchange within the heat exchanger. This fully or partially evaporated stream may have a vapor fraction of at least 85%, or at least 90%, or at least 99% by mass, with the remainder being the liquid phase fraction, exiting heat exchanger 312 as stream 332. Alternatively, stream 332 is a vapor stream with no liquid phase (i.e., fully evaporated). Stream 332 may be combined with vapor stream 328 from separator 326 to form recycle stream 334 that flows to compression unit 314 .

[0029] At least another portion of MCR stream 318 is withdrawn from the second heat exchange area of ​​heat exchanger 312 as side stream 336. Side stream 336 is expanded to a second pressure using expansion device 338 to produce stream 340 having a vapor phase and a liquid phase. This second pressure may range from a minimum of 250 kPa, or 400 kPa, or 500 kPa to a maximum of 600 kPa, or 700 kPa, or 850 kPa. Accordingly, the temperature of stream 340 ranges from a minimum of −60° C., or −50° C., or −40° C. to a maximum of −30° C., or −20° C., or −10° C. Preferably, side stream 336 is expanded to a pressure of 550 kPa to 570 kPa and a temperature of −35° C. to −45° C. Stream 340 is then separated in separator 342 to produce vapor stream 344 and liquid stream 346. Preferably, stream 340 is subjected to flash separation. Vapor stream 344 bypasses heat exchanger 312 and is sent directly to compression unit 314. The reduced-pressure, and thus cooled, liquid stream 346 returns to heat exchanger 312, where it is fully or partially vaporized due to the heat exchange therein. This fully or partially vaporized stream may have a vapor fraction of at least 85%, or at least 90%, or at least 99% by mass, with the remainder being a liquid fraction, and exits heat exchanger 312 as stream 348. Stream 348 may be combined with vapor stream 344 to form recycle stream 350, which flows to compression unit 314.

[0030] Yet another portion of MCR stream 318 is withdrawn from the third heat exchange area of ​​heat exchanger 312 as side stream 352. Side stream 352 is expanded to a third pressure using expansion device 354 to produce expanded stream 356 having a vapor phase and a liquid phase. In one or more specific embodiments, this third pressure ranges from a minimum of 80 kPa, or 120 kPa, or 150 kPa to a maximum of 180 kPa, or 200 kPa, or 250 kPa. Accordingly, the temperature of expanded stream 356 ranges from a minimum of −110° C., or −90° C., or −80° C. to a maximum of −60° C., or −50° C., or −30° C. Preferably, side stream 352 is expanded to a pressure of 160 kPa to 180 kPa and a temperature of −65° C. to −75° C.

[0031] Two-phase stream 356 is then separated in separator 358 to produce flash vapor stream 360 and saturated liquid stream 362. Preferably, two-phase stream 356 is subjected to flash separation. Vapor stream 360 bypasses heat exchanger 312 and is sent directly to compression unit 314. The reduced-pressure, and thus cooled, saturated liquid stream 362 returns to heat exchanger 312, where it is fully or partially evaporated due to the heat exchange within heat exchanger 312. This fully or partially evaporated refrigerant exits heat exchanger 312 as stream 364. In one or more specific embodiments, stream 364 has a vapor fraction of at least 85%, or at least 90%, or at least 99%, by mass, with the remainder being a liquid phase fraction. Stream 364 may be combined with vapor stream 364 from separator 358 to form recycle stream 366, which flows to compression unit 314.

[0032] According to aspects of the present disclosure, one or more of the expansion devices 322, 338, 354 may be any pressure reducing device. Exemplary expansion devices include, but are not limited to, valves, control valves, Joule Thompson valves, Venturi devices, liquid expanders, hydraulic turbines, etc. The expansion devices may be automatically actuated expansion valves or Joule Thompson style valves.

[0033] As noted above, vapor streams 328, 344, and 360 bypass heat exchanger 312 and are sent directly to compression unit 314. This bypass configuration avoids distribution issues associated with two-phase refrigerants. Furthermore, the two-phase, partially vaporized refrigerant exiting the heat exchange area is configured to reduce mechanical stresses within the heat exchange area. Mechanical stresses are a product of rapid temperature transitions between the volumes occupied by the liquid and vapor phases. The temperature transition from the liquid or two-phase fluid volume to the vapor volume can lead to stress failures during startup, shutdown, or upset, or can lead to fatigue failure of the exchanger. Therefore, refrigerant flow conditions are configured to allow for incomplete evaporation of refrigerant liquid streams 330, 346, and 362 without the inherent effects of mechanical stresses caused by rapid temperature gradients. To transition from a fully vaporized refrigerant system to a partially vaporized refrigerant system, the flow rate may be increased, the evaporation pressure may be changed, the refrigerant composition may be changed to include more components with higher boiling points, or any combination of these design parameters.

[0034] MCR compression unit 314 may include a single compression stage, or preferably includes multiple compression stages capable of operating at different pressure levels. Preferably, the suction of each compression stage corresponds to the pressure level of recycle streams 334, 350, 366. According to aspects of the present disclosure, the first compression stage includes suction knockout vessel 367 and compressor 368. The second compression stage includes suction knockout vessel 369, compressor 370, and discharge cooler or condenser 371. The third compression stage includes suction knockout vessel 372, compressor 373, and discharge cooler 374. In at least one specific embodiment, compression unit 314 further includes aftercooler or condenser 375.

[0035] Coolers 371, 374, and 375 may be any type of heat exchanger suitable for the process conditions described herein. Exemplary heat exchangers include, but are not limited to, shell-and-tube heat exchangers, core-in-kettle exchangers, and brazed aluminum plate-fin heat exchangers. Plant cooling water or air may be used as the heat transfer medium to cool the process fluid in the coolers. The bypassed flash vapor streams 328, 344, and 360 may cool the at least partially evaporated refrigerant streams 332, 348, and 364 exiting heat exchanger 312. As a result, the combined streams 334, 350, and 366 recycled to the suction to compression unit 314 are at a lower temperature, thereby reducing the duty requirements of discharge coolers 371, 374, and 375.

[0036] Referring more particularly to the compression unit, stream 376 exits suction knockout vessel 367 and is compressed by compressor 368. Output stream 377 of compressor 368 may have a pressure ranging from a minimum of 200 kPa, or 300 kPa, or 400 kPa to a maximum of 600 kPa, or 700 kPa, or 800 kPa. The temperature of output stream 377 ranges from a minimum of 5°C, or 10°C, or 15°C to a maximum of 20°C, or 25°C, or 30°C. Output stream 377 passes to suction knockout drum 369 and then to compressor 370, which forms part of the second compression stage. Output stream 378 exits compressor 370 and is cooled in discharge cooler 371 to produce stream 380. The pressure of product stream 378 may range from a minimum of 800 kPa, or 1,200 kPa, or 1,400 kPa, to a maximum of 1,800 kPa, or 2,000 kPa, or 2,500 kPa. The temperature of stream 380 ranges from a minimum of 15°C, or 25°C, or 35°C, to a maximum of 40°C, or 45°C, or 55°C. Stream 380 passes to suction knockout drum 372 and then to compressor 373, which forms part of the third compression stage. Product stream 381 exits compressor 373 and is cooled in discharge cooler 374 to produce stream 382. The pressure of product stream 381 ranges from a minimum of 1,600 kPa, or 2,400 kPa, or 2,900 kPa, to a maximum of 3,500 kPa, or 4,000 kPa, or 5,000 kPa. The temperature of product stream 381 ranges from a minimum of 40°C, or 50°C, or 60°C to a maximum of 100°C, or 120°C, or 150°C. In one or more specific embodiments, the temperature of stream 382 ranges from a minimum of 0°C, or 110°C, or 20°C to a maximum of 40°C, or 50°C, or 60°C. Stream 382 flows to condenser 375 to produce stream 383. The temperature of stream 383 ranges from a minimum of 0°C, or 10°C, or 20°C to a maximum of 40°C, or 45°C, or 55°C. Stream 383 flows to surge vessel 384 to provide residence time for operability considerations as the high pressure liquid refrigerant enters heat exchanger 312 as MCR stream 318.

[0037] Although compressors 368, 370, and 373 are shown as separate compressors, they may represent compression stages of a single compressor. In any event, one or more of compressors 368, 370, and 373 may be powered by one or more turbines. An exemplary method is illustrated in FIG. 3 , where a single shaft 385 connects the compressors to a gas turbine 386. Heat 387 generated by gas turbine 386 may be captured by HRSG unit 390. HRSG unit 390 generates one or more streams 392, 394 of high-pressure heating steam from heat 387 using direct or indirect heat exchange. Stream 392 may be used in various ways, such as for heating, generating electricity, etc. Stream 394 is directed to steam turbine 102a configured to drive first compressor 102. Steam turbine 102a may be a condensing steam turbine or another type of steam turbine as discussed herein. The steam turbine 102a uses most of the steam produced by the HRSG unit 390, eliminating the fuel gas needed to drive the first compressor 102 from the HRSG unit, and advantageously allows excess heat capacity 392 to provide heat to the process, achieving a near perfect energy balance. Additionally, some process heating needs can be provided by side-extracted steam 102b from the steam turbine 102a.

[0038] FIG. 4 illustrates a system and process for producing liquefied natural gas (LNG) according to another embodiment of the present disclosure. Feed gas (natural gas) enters one or more pretreatment modules 404 through an inlet line 402, which process the feed gas to remove contaminants. The pretreatment modules may include dehydration units to remove water from the feed gas. The pretreatment modules may also include scrubbers and / or flash tanks to remove other contaminants, such as sulfur compounds, carbon dioxide, and heavy hydrocarbons. The processed gas then passes from pretreatment module 404 to HPCE system 100, as previously described. For brevity, a complete description of HPCE system 100 will not be repeated. The output of HPCE system 100 is a cooled pretreated gas stream 422, which is directed to liquefaction system 410. The liquefaction system 410 illustrated in FIG. 4 is a dual mixed refrigerant liquefaction system that uses two refrigeration subprocesses (shown here as two separate mixed refrigerant cycles) in heat exchanger 412 to liquefy the chilled pre-treated gas stream. The warm mixed refrigerant circulating in warm mixed refrigerant cycle 414 chills the chilled pre-treated gas stream to a first, lower temperature, which can be between −50°F and −150°F (−45°C and −101°C), with the actual temperature being a process optimization variable. The cold mixed refrigerant circulating in cold mixed refrigerant cycle 416 further cools the chilled pre-treated gas stream to a final cryogenic temperature. The resulting cryogenic fluid 418 is then preferably reduced in pressure by a cryogenic turbine 420 and stored in an LNG storage tank 424 or transported as needed.

[0039] The warm mixed refrigerant may be composed primarily of ethane with small amounts of propane and isobutane. The warm mixed refrigerant enters heat exchanger 412 at 411 and is split into multiple portions 412a, 412b, and 412c. Each portion cools the chilled pretreated gas stream, exits the heat exchanger, is reduced in pressure by valves 426a, 426b, and 426c, re-enters the heat exchanger to further cool the chilled pretreated gas stream, and exits the heat exchanger to knock-out vessels 428a, 428b, and 428c, respectively. The outputs of knock-out vessels 428b and 428c are directed to the first two stages of first compressor 430 to pressures sufficient to fully condense the products against the available ambient cooling medium. The combined output of the first two stages of the first compressor is cooled in ambient cooler 432 and directed to knock-out vessel 428a. The output of knockout vessel 428a passes to first compressor third stage 434, which is separate from compressor 430 and is shown schematically as connected to compressor 430 by common shaft 436. The output of third stage 434 is cooled in ambient cooler 438 and sent to surge drum 440 which supplies heat exchanger stream 411, thereby completing warm mixed refrigerant cycle 414.

[0040] The cold mixed refrigerant may be composed primarily of methane with smaller amounts of ethane, nitrogen, and propane. The refrigeration duty of the cold mixed refrigerant, which enters the heat exchanger at 425 and is evaporated at a single pressure level, is used to cool the chilled pretreated gas stream 422 to ultra-low temperatures. The cold mixed refrigerant exiting the heat exchanger 412 is collected in a knock-out drum 444, expanded in a cold expander 446, and then re-enters the heat exchanger 412. The cold mixed refrigerant exiting the heat exchanger a second time enters a knock-out vessel 448 and is then compressed in two stages in a second compressor 450 to a pressure sufficient to fully condense it against the warm mixed refrigerant in the heat exchanger. The cold mixed refrigerant from the second compressor is cooled in ambient coolers 460, 462 before heading to the heat exchanger inlet 425, thereby completing the cold mixed refrigerant cycle 416.

[0041] The first and second compressors 430, 450 are driven by first and second gas turbines 466, 468, respectively. Heat 470, 472 generated by one or more of the gas turbines may be captured by an HRSG unit 472. The HRSG unit 472 uses direct or indirect heat exchange to generate one or more streams 474, 476 of high-pressure heated steam from the heat 470 and / or 472. Stream 474 may be used in a variety of ways, such as for heating, generating electricity, etc. Stream 476 is directed to a steam turbine 102a configured to drive the first compressor 102. The steam turbine 102a may be a condensing steam turbine or other types of steam turbines as discussed herein. The steam turbine 102a uses most of the steam produced by the HRSG unit 472, eliminating the fuel gas needed to drive the first compressor 102 from the HRSG unit, and advantageously allows excess heat capacity 474 to provide heat to the process, achieving a near perfect energy balance. Additionally, process heating needs can be provided by side-extracted steam 102b from the steam turbine 102a.

[0042] Embodiments of the present disclosure are applicable to a variety of liquefaction processes, including single mixed refrigerant liquefaction processes as shown in FIG. 3, high-pressure expander liquefaction processes, and dual mixed refrigerant liquefaction processes such as that shown in FIG. The combined liquefaction and HRSG capacity of embodiments of the present disclosure, as shown in Figures 2, 3, and / or 4, may include an LNG train, which may be combined with similar LNG trains, either in series or parallel, to maximize LNG production. Such a combination is illustrated in Figure 5, which shows a schematic diagram of an LNG plant 500. The LNG plant 500 includes at least two LNG trains, with first, second, and third LNG trains 502, 504, and 506 shown in Figure 5. The LNG trains may use any type of liquefaction process, including one or more compressors to compress a feed stream, a refrigerant, a chilled or condensed LNG stream, or other process stream. The LNG trains produce an LNG stream 508. The LNG plant 500 includes pre-processing equipment 512 that removes impurities from an LNG feed stream 510. The pre-processing equipment may include a dehydrator that removes moisture or water vapor from the feed stream. The pre-treatment equipment may also include one or more separators or scrubbing towers to remove other impurities, such as sulfur compounds, carbon dioxide, heavy hydrocarbons, etc. The resulting pre-treated feed gas vapor 514 is directed to an HPCE module 516, which is similar to the HPCE modules previously described herein. The HPCE module 516 is sized sufficiently to supply the cooled pre-treated gas stream to the first, second, and third LNG trains 502, 504, 506. The HRSG modules 520, 522, 524 included in each LNG train produce a combined stream of heating steam 526 for the steam turbines that power the steam compressors of the HPCE module 516, as previously described.

[0043] In another aspect of the present disclosure, the use of an HRSG unit may be integrated with one or more of the refrigerant cycles. For example, vapor generated from the HRSG unit may be used to directly drive a warm mix refrigerant compressor and / or a front-end auxiliary compressor. Depending on the amount of power (in the form of vapor) available from the HRSG unit, the compression load of a compressor associated with one refrigerant cycle may then be adjusted relative to the compression load of a compressor associated with another refrigerant cycle. FIG. 6 schematically illustrates an example of such integration. A gas stream 602 is liquefied by a natural gas liquefaction system 604, from which LNG 606 is produced. Similar to the liquefaction system 410 of FIG. 4, the liquefaction system 604 has first and second refrigerant loops 608, 610. Each of the refrigerant loops includes and relies on compressors 608a, 610a for the heating / cooling cycle of the respective refrigerant streams 612, 614, 616, 618 used in the liquefaction process. A gas turbine 608b powers a compressor 608a of the first refrigerant loop 608, and a steam turbine 610b powers a compressor 610b of the second refrigerant loop 610. Heat 620 generated by the gas turbine 608b can be captured by an HRSG unit 622, and steam 624 generated by the HRSG unit 622 can be used to power the steam turbine 610b. The compression load between compressor 608a (which may be a warm mixed refrigerant compressor) and compressor 610a (which may be a cold mixed refrigerant compressor) can be shifted as needed to account for available power from the steam generated in the HRSG. Additional steam 626 can be used for other processes within or outside of the liquefaction process shown in FIG. 6. Furthermore, embodiments of the present disclosure can enable the use of smaller drivers or the design of larger trains, potentially eliminating the need for a steam-to-power generation system. FIG. 7 illustrates another embodiment of the present disclosure in which heat 732 generated by a gas turbine 708 b of a first refrigerant loop 708 can be used to generate steam in an HRSG unit 722 .Heat 730 from other sources, such as combustion heaters, may also be used to generate steam 735 using the HRSG unit 722, thereby helping to balance the supply of steam needed to power the steam turbine 710b of the second refrigerant loop 710.

[0044] The configuration of FIG. 6 is shown in more detail in FIG. 8, which is a schematic diagram of a dual mixed refrigerant system 800 for producing LNG according to an embodiment of the present disclosure. System 800 is similar to the system and process shown in FIG. 4, but does not include HPCE system 100 of FIG. 4. System 800 includes a gas turbine 866 that powers a compressor 830 that is responsible for compressing the warm mixed refrigerant. System 800 also includes a steam turbine 868 that powers a compressor 850 that is responsible for compressing the cold mixed refrigerant. Heat 870 generated by steam turbine 866 is used to generate steam 876 in an HRSG unit 872, which is used to power steam turbine 868. Additional steam 877 may supplement steam 876.

[0045] FIG. 9 is an illustration of an HPCE system 901 combined with a high-pressure expander process (HPXP process) 900 and an HRSG unit 910 for liquefaction according to embodiments of the present disclosure, which is more fully described in commonly owned U.S. Patent Application Publication No. 2020 / 0064061, the disclosure of which is incorporated herein by reference in its entirety. The HPXP process 900 uses high pressure in a primary refrigeration loop 930 to eliminate the need for an external refrigerant and improve efficiency. The HPXP process 900 uses a high-pressure expander in a manner that distinguishes it from other expander cycles. A portion of the feed gas stream may be extracted and used as a refrigerant in either an open-loop or closed-loop refrigeration cycle (as shown) to cool the feed gas stream below its critical temperature. Alternatively, a portion of the LNG boil-off gas may be extracted and used as a refrigerant in a closed-loop refrigeration cycle to cool the feed gas stream below its critical temperature. This refrigeration cycle is referred to as the primary refrigeration loop 930. The primary refrigeration loop is followed by a sub-cooling loop 932 which acts to further cool the feed gas. Within the primary refrigeration loop, the refrigerant is compressed to a pressure above 1,500 psia, or more preferably to a pressure of approximately 3,000 psia. The refrigerant is then cooled against the ambient cooling medium (air or water) before expanding nearly isentropically to provide the cold refrigerant needed to liquefy the feed gas.

[0046] As in the previous embodiment, the natural gas stream may be treated to remove impurities, such as water, heavy hydrocarbons, and sour gas, if present, to produce a treated natural gas stream 902 suitable for liquefaction. Treated natural gas stream 902 may be directed to HPCE process 901, as previously described herein. The HPCE process provides a cooled pre-treated gas stream 926, which is directed to HPXP process 900. In expander loop 930, compression unit 934 compresses refrigerant stream 936 (which may be treated with a gas stream) to a pressure of about 10.3 MPa (1,500 psia) or greater, thus resulting in compressed refrigerant stream 938. Alternatively, refrigerant stream 936 may be compressed to a pressure of about 11.0 MPa (1,600 psia) or greater, or about 11.7 MPa (1,700 psia) or greater, or about 12.4 MPa (1,800 psia) or greater, or about 13.1 MPa (1,900 psia) or greater, or about 13.8 MPa (2,000 psia) or greater, or about 17.2 MPa (2,500 psia) or greater, or about 20.7 MPa (3,000 psia) or greater, thus providing compressed refrigerant stream 938. Compression unit 934 may include a compressor powered by a gas turbine 934a (which may include a steam turbine in other embodiments). After exiting compression unit 934, compressed refrigerant stream 938 passes through cooler 940 where it is cooled by indirect heat exchange with a suitable cooling fluid to provide compressed, cooled refrigerant stream 942. Chiller 940 may be of the type that provides water or air as the cooling fluid, although any type of chiller can be used. The temperature of cooled, compressed refrigerant stream 942 depends on ambient conditions and the cooling medium used and is typically between about 1.7°C (35°F) and about 40.6°C (105°F). Compressed, cooled refrigerant stream 942 then passes through expander 944, where it expands and is subsequently cooled to form expanded refrigerant stream 946. Expander 944 is a work expansion device, such as a gas expander, that generates work that can be extracted and used in the compression. Expanded refrigerant stream 946 passes through first heat exchanger 948 and provides at least a portion of the refrigeration duty of first heat exchanger 948.Upon exiting the first heat exchanger 948, the expanded refrigerant stream 946 is fed to a compression unit 950 for pressurization to form a refrigerant stream 936. The compression unit 950 may include a compressor powered by a steam turbine or a gas turbine 950a. Alternatively, the compressor of the compression unit 950 may be powered by the expander 944.

[0047] The cooled pretreated gas stream 926 flows through a first heat exchanger 948 where it is cooled, at least in part, by indirect heat exchange with the expanded refrigerant stream 946. After exiting the first heat exchanger 948, the cooled pretreated gas stream 926 passes through a second heat exchanger 952. The primary function of the second heat exchanger 952 is to subcool the cooled pretreated gas stream. Thus, in the second heat exchanger 952, the cooled pretreated gas stream 926 is subcooled by a subcooling loop 932 (described below) to produce a subcooled vapor stream 954. The subcooled vapor 954 is then expanded in an expander 956 to reduce its pressure and form a liquid fraction and a remaining vapor fraction. The expander 956 may be any pressure reducing device, including, but not limited to, a valve, a control valve, a Joule Thompson valve, a Venturi device, a liquid expander, a hydraulic turbine, or the like. The now lower pressure, partially liquefied subcooled stream 954 passes to a surge tank 958 where its liquefied fraction 960 is withdrawn from the process as LNG stream 962 having a temperature corresponding to the boiling point pressure. The remaining vapor fraction (flash vapor) stream 964 may be used as fuel to power a compressor unit.

[0048] In the sub-cooling loop 932, an expanded sub-cooled refrigerant stream 966 (preferably comprising nitrogen) exits the expander 968 and is drawn through the second and first heat exchangers 948, 952. The expanded sub-cooled refrigerant stream 966 is then sent to a compression unit 970 where it is re-compressed to a higher pressure and warmed. The compression unit 970 may include a compressor powered by a steam turbine or a gas turbine 970a. After exiting the compression unit 970, the re-compressed sub-cooled refrigerant stream 972 is cooled in a chiller 974, which may be of the same type as the chiller 940, although any type of chiller may be used. After cooling, the re-compressed sub-cooled refrigerant stream passes through the first heat exchanger 948 where it is further cooled by indirect heat exchange with the expanded refrigerant stream 946 and the expanded sub-cooled refrigerant stream 966. After exiting the first heat exchanger 948, the recompressed and cooled sub-cooled refrigerant stream is expanded through an expander 968 to provide a cooled stream which then passes through a second heat exchanger 952 to sub-cool and ultimately expand a portion of the feed gas stream to produce LNG.

[0049] According to aspects of the present disclosure, HRSG unit 910 may convert heat from any of turbines 934a, 950a, 970a (which are gas turbines) into steam that may be used to power any of turbines 934a, 950a, 970a, which are steam-driven turbines (or turbines 903a, 912a, which drive compressors 903, 912, respectively, if they are steam-driven turbines in HPCE system 901). The configuration illustrated in FIG. 9, in which only heat 976 from turbines 934a and 950a is converted to steam 978 for use in turbine 903a, is merely an example of a heat source and steam destination. Other combinations of heat sources and steam destinations in the system of FIG. 9 are possible and within the scope of the present disclosure.

[0050] 9 illustrates an embodiment of the present disclosure used in an HPXP process. The present disclosure may also be used in liquefaction processes that use other refrigeration sub-processes, such as feed gas expander-based LNG liquefaction as disclosed in commonly owned U.S. Patent Application Publication No. 2017 / 0167786, the disclosure of which is incorporated herein by reference in its entirety.

[0051] 10 is a flowchart illustrating a method 1000 for producing liquefied natural gas (LNG) from a natural gas stream according to an embodiment of the present disclosure. At block 1002, a natural gas stream is provided from a natural gas source at a pressure less than 1,200 psia. At block 1004, the natural gas stream is compressed to a pressure of at least 1,500 psia using a first compressor and a second compressor. At block 1006, the natural gas stream is cooled between the first compressor and the second compressor, such that the second compressor produces a cooled compressed natural gas stream. At block 1008, the cooled compressed natural gas stream is liquefied in a liquefaction process using a refrigerant compressor configured to compress a refrigerant stream used to chill, condense, or liquefy the cooled compressed natural gas stream. At block 1010, a heat recovery steam generator (HRSG) system is used to recover heat from a power source of the refrigerant compressor and generate a pressurized steam stream from the recovered heat. At block 1012, at least one of the first and second compressors is powered using at least a portion of the pressurized steam stream.

[0052] FIG. 11 is a flowchart illustrating a method 1100 for producing liquefied natural gas (LNG) according to an embodiment of the present disclosure. At block 1102, a natural gas stream is provided. At block 1104, the natural gas stream is liquefied in a liquefaction process. The liquefaction process uses a first compressor and a second compressor to compress one or more refrigerants used to chill, condense, or liquefy the chilled natural gas stream. At block 1106, the first compressor is powered by a gas turbine and the second compressor is powered by a steam turbine. At block 1108, a heat recovery steam generator (HRSG) system is used to recover heat from the gas turbine, and a pressurized steam stream is generated from the recovered heat. At block 1110, a steam turbine is powered using at least a portion of the pressurized steam stream.

[0053] Further illustrative, non-exclusive examples of systems and methods according to the present disclosure are presented in the following numbered items: It is within the scope of the present disclosure that the individual steps of the methods recited herein, including the following numbered items, may additionally or alternatively be referred to as "steps for" performing the recited action.

[0054] 1. A method for producing liquefied natural gas (LNG), comprising: providing a natural gas stream at a pressure less than 8.27 MPa (1,200 psia) from a source of natural gas; compressing the natural gas stream to a pressure of at least 1,500 psia, wherein the compression is performed using a first compressor and a second compressor; cooling the natural gas stream between the first compressor and the second compressor, such that the second compressor produces a cooled compressed natural gas stream; liquefying the cooled compressed natural gas stream in a liquefaction process, the liquefaction process using a refrigerant compressor configured to compress a refrigerant stream used to chill, condense or liquefy the cooled compressed natural gas stream; recovering heat from a power source of the refrigerant compressor using a heat recovery steam generator (HRSG) system and generating a pressurized steam stream from the recovered heat; and powering at least one of the first and second compressors using at least a portion of the stream of compressed steam. A method comprising:

[0055] 2. The method of claim 1, wherein the step of cooling the compressed natural gas stream comprises cooling the compressed natural gas stream in at least one heat exchanger that exchanges heat with the environment. 3. The method of item 2, wherein the liquefaction process includes a dual mixed refrigerant process that liquefies the natural gas stream using a combination of first and second refrigeration sub-processes, and the refrigerant compressor is a compressor for one of the refrigeration sub-processes. 4. The method according to item 3, further comprising a fourth compressor for providing compression for the second refrigeration sub-process, wherein the HRSG system recovers heat generated by the power source of the fourth compressor to further generate a stream of pressurized steam.

[0056] 5. The method of item 1, wherein the liquefaction process comprises a single mixed refrigerant process that liquefies the natural gas stream using a refrigeration sub-process cycle, and the refrigerant compressor is the compressor for the refrigeration sub-process. 6. The method according to item 1, wherein the liquefaction process comprises a high-pressure expansion process with a refrigeration cycle and a subcooling cycle, and the refrigerant compressor is a compressor for the refrigeration cycle or the subcooling cycle. 7. The method of any one of items 1 to 6, wherein the first and second compressors compress the natural gas stream to a pressure greater than 20.68 MPa (3,000 psia). 8. The method of any one of items 1 to 7, wherein the natural gas expander is a work-producing expander that expands a cooled, compressed natural gas stream to a pressure of less than 13.79 MPa (2,000 psia). 9. prior to the liquefying step, expanding the cooled compressed natural gas stream in at least one work-producing natural gas expander to a pressure less than 2,000 psia and equal to or less than the pressure at which the natural gas stream was compressed. 9. The method according to any one of items 1 to 8, further comprising:

[0057] 10. The method of claim 9, wherein the natural gas expander is mechanically coupled to the first compressor or the second compressor. 11. The method of any one of items 1 to 10, wherein the pressurized steam flow is directed to a steam turbine that powers the first compressor or the second compressor. 12. A steam turbine is Condensing steam turbines with or without side extraction, and back pressure steam turbine Item 12. The method according to item 11, wherein the method is one of the above. 13. The method of any one of items 1 to 12, wherein the liquefaction process includes two or more liquefaction modules, each of the two or more liquefaction modules having an HRSG system associated therewith, and wherein the first compressor is powered using at least a portion of the pressurized steam flow generated by the HRSG systems associated with the two or more liquefaction modules. 14. A system for producing liquefied natural gas (LNG) from a natural gas stream, comprising: a first compressor and a second compressor configured to compress the natural gas stream from a pressure of less than 1,200 psia to a pressure of at least 1,500 psia; a heat exchanger disposed between the first compressor and the second compressor, the heat exchanger configured to cool the natural gas stream such that the second compressor produces a cooled compressed natural gas stream; A liquefaction process configured to liquefy a cooled compressed natural gas stream, the liquefaction process including a refrigerant compressor configured to compress a refrigerant stream used to chill, condense or liquefy the cooled compressed natural gas stream, the refrigerant compressor being powered by a power source; and A heat recovery steam generator (HRSG) system configured to recover heat from a power source of a refrigerant compressor, thereby generating a pressurized steam stream from the recovered heat. Including, A system wherein at least one of the first and second compressors is powered using at least a portion of the flow of pressurized steam.

[0058] 15. The system of item 14, wherein the heat exchanger is configured to cool the compressed natural gas stream by exchanging heat with the environment. 16. The system of item 15, wherein the liquefaction process includes a dual mixed refrigerant process that liquefies the natural gas stream using a combination of first and second refrigeration subprocesses, and the refrigerant compressor is the compressor for one of the refrigeration subprocesses. 17. The system of item 16, further including a fourth compressor providing compression for the second refrigeration cycle, wherein the HRSG system is configured to recover heat generated by the power source of the fourth compressor to further generate a stream of pressurized steam. 18. The system of item 14, wherein the liquefaction process includes a single mixed refrigerant process that liquefies the natural gas stream using a refrigeration sub-process cycle, and the refrigerant compressor is the compressor for the refrigeration sub-process.

[0059] 19. The system according to item 14, wherein the liquefaction process includes a high-pressure expansion process with a refrigeration cycle and a subcooling cycle, and the refrigerant compressor is a compressor for the refrigeration cycle or the subcooling cycle. 20. The system of any one of items 14-19, wherein the first and second compressors are configured to compress the natural gas stream to a pressure greater than 20.68 MPa (3,000 psia). 21. The system of any one of items 14-20, wherein the natural gas expander is a work-producing expander configured to expand the cooled compressed natural gas stream to a pressure of less than 13.79 MPa (2,000 psia). 22. The system of any one of items 14 to 21, further including at least one work-producing natural gas expander disposed between the second compressor and the liquefaction process, the at least one work-producing natural gas expander configured to expand the cooled compressed natural gas stream to a pressure less than 13.79 MPa (2,000 psia) and less than or equal to the pressure at which the natural gas stream was compressed.

[0060] 23. The system of claim 22, wherein the natural gas expander is mechanically coupled to the first compressor or the second compressor. 24. The system of any one of items 14 to 23, further comprising a steam turbine operably connected to the first compressor or the second compressor, wherein the flow of pressurized steam is directed to the steam turbine. 25. A steam turbine Condensing steam turbines with or without side extraction, and back pressure steam turbine Item 25. The system according to item 24, wherein the system is one of: 26. The system of any one of items 14-25, wherein the liquefaction process includes two or more liquefaction modules, each of the two or more liquefaction modules having an HRSG system associated therewith, and wherein the first compressor is powered using at least a portion of the pressurized steam flow produced by the HRSG systems associated with the two or more liquefaction modules.

[0061] 27. A method for producing liquefied natural gas (LNG), comprising: providing a natural gas stream; liquefying a natural gas stream in a liquefaction process, the liquefaction process using a first compressor and a second compressor to compress one or more refrigerants used to chill, condense or liquefy the chilled natural gas stream; powering a first compressor with a gas turbine; powering a second compressor with a steam turbine; recovering heat from the gas turbine using a heat recovery steam generator (HRSG) system and generating a pressurized steam stream from the recovered heat; and using at least a portion of the flow of compressed steam to power a steam turbine. A method comprising: 28. Additional powering of a steam turbine using steam from a source other than a pressurized steam stream generated from heat from a gas turbine. 28. The method of claim 27, further comprising: 29. The method of claim 27, wherein the liquefaction process comprises a dual mixed refrigerant process that liquefies the natural gas stream using a combination of a first refrigerant cycle and a second refrigerant cycle, and the first compressor is a compressor for the first refrigerant cycle. 30. A steam turbine is Condensing steam turbines with or without side extraction, and back pressure steam turbine 28. The method according to Item 27, wherein the method is one of the above.

[0062] 31. Shifting the compression load between the first compressor and the second compressor according to power available from the HRSG system. 28. The method of claim 27, further comprising: 32. A system for producing liquefied natural gas (LNG) from a natural gas stream, comprising: A liquefaction process for liquefying a natural gas stream, the liquefaction process including a first compressor and a second compressor configured to compress one or more refrigerants used to chill, condense or liquefy the chilled natural gas stream; a gas turbine configured to power the first compressor; a steam turbine configured to power the second compressor; and A heat recovery steam generator (HRSG) system configured to recover heat from a gas turbine and generate a pressurized steam stream from the recovered heat. Including, A system in which a steam turbine is powered using at least a portion of the flow of pressurized steam.

[0063] 33. A system of item 32 in which steam from a source other than the pressurized steam stream generated from heat from a gas turbine is used to additionally power a steam turbine. 34. The system of item 32, wherein the liquefaction process comprises a dual mixed refrigerant process that liquefies the natural gas stream using a combination of a first refrigerant cycle and a second refrigerant cycle, and the first compressor is a compressor for the first refrigerant cycle. 35. A steam turbine is Condensing steam turbines with or without side extraction, and back pressure steam turbine Item 33. The system according to item 32, wherein the system is one of: [Industrial Applicability]

[0064] The apparatus and methods disclosed herein are applicable to the oil and gas industry. The present disclosure set forth above is believed to encompass multiple separate inventions having independent utilities. While each of these inventions is disclosed in its preferred form, the specific embodiments thereof disclosed and illustrated herein are susceptible to numerous variations and are not to be considered limiting. The subject matter of the inventions includes all novel and non-obvious combinations and subcombinations of the various elements, features, functions and / or properties disclosed herein. Similarly, when a claim recites "a" or "first" element or its equivalent, such claim should be understood to include the incorporation of one or more such elements without requiring or excluding more than one such element.

[0065] The following claims set forth certain combinations and subcombinations that are novel and non-obvious and are particularly directed to one of the inventions of this disclosure. Inventions embodied in other combinations and subcombinations of features, functions, elements and / or properties may be claimed through amendment of the present claims or the presentation of new claims in this or a related application. Such amendments or new claims, whether directed to a different invention or the same invention, and whether different, broader, narrower, or equal in scope to the original claims, are also deemed to fall within the scope of the inventive subject matter of this disclosure.

[0066] While the present invention has been described and illustrated by reference to specific embodiments, those skilled in the art will recognize that the invention itself is susceptible to variations not necessarily exemplified herein. For this reason, reference should be made solely to the appended claims for purposes of determining the true scope of the present invention.

Claims

1. 1. A method for producing liquefied natural gas (LNG), comprising: providing a natural gas stream at a pressure less than 8.27 MPa (1,200 psia) from a source of natural gas; compressing the natural gas stream to a pressure of at least 10.34 MPa (1,500 psia), wherein the compression is performed using a first compressor and a second compressor; cooling the natural gas stream compressed by the first compressor in at least one heat exchanger between the first compressor and the second compressor, such that the second compressor produces a cooled compressed natural gas stream; liquefying the cooled compressed natural gas stream in a liquefaction process, the liquefaction process using a refrigerant stream refrigerant compressor configured to compress a refrigerant stream used to further chill, condense or liquefy the cooled compressed natural gas stream, the refrigerant compressor being powered by a power source; recovering heat from a power source of the refrigerant compressor using a heat recovery steam generator (HRSG) system and generating a pressurized steam stream from the recovered heat; and using at least a portion of the stream of compressed steam to power at least one of the first and second compressors. A method comprising:

2. 2. The method of claim 1, wherein the step of cooling the compressed natural gas stream comprises cooling the compressed natural gas stream in at least one heat exchanger that exchanges heat with the environment, the liquefaction process may comprise a dual mixed refrigerant process that liquefies the natural gas stream using a combination of first and second refrigeration sub-processes, and further wherein the refrigerant compressor may be a compressor for one of the refrigeration sub-processes.

3. The method described in claim 2, wherein a fourth compressor provides compression for the second refrigeration sub-process, and the HRSG system recovers heat generated by the power source of the fourth compressor to further generate a flow of pressurized steam.

4. 10. The method of claim 1, wherein the liquefaction process comprises a single mixed refrigerant process that liquefies the natural gas stream using a refrigeration subprocess, and the refrigerant compressor is a compressor for the refrigeration subprocess.

5. 10. The method of claim 1, wherein the liquefaction process comprises a high-pressure expansion process with a refrigeration loop and a sub-cooling loop, and the refrigerant compressor is the compressor for the refrigeration loop or the sub-cooling loop.

6. 5. The method of any one of claims 1 to 4, wherein the first and second compressors compress the natural gas stream to a pressure greater than 20.68 MPa (3,000 psia).

7. A method according to any one of claims 1 to 6, wherein the cooling loop includes an expander, the expander being a work expansion device that expands the cooled compressed natural gas stream to a pressure of less than 13.79 MPa (2,000 psia).

8. The flow of compressed steam is directed to a steam turbine, which powers the first compressor or the second compressor, and the steam turbine Condensing steam turbines with or without side extraction, and back pressure steam turbine The method according to any one of claims 1 to 7, wherein the method is one of:

9. 9. The method of claim 1, wherein the liquefaction process includes two or more liquefaction modules, each having an HRSG system associated therewith, and wherein at least a portion of the pressurized steam flow produced by the HRSG systems is used to power a first compressor.

10. 1. A system for producing liquefied natural gas (LNG) from a natural gas stream, comprising: a first compressor and a second compressor configured to compress a natural gas stream from a pressure of less than 1,200 psia to a pressure of at least 1,500 psia; a heat exchanger disposed between the first compressor and the second compressor, the heat exchanger configured to cool the natural gas stream compressed by the first compressor such that the second compressor produces a cooled compressed natural gas stream; A natural gas liquefaction system configured to liquefy a cooled compressed natural gas stream, the liquefaction system including a refrigerant compressor configured to compress a refrigerant stream used to further chill, condense or liquefy the cooled compressed natural gas stream, the refrigerant compressor being powered by a power source; A heat recovery steam generator (HRSG) system configured to recover heat from a power source of a refrigerant compressor, thereby generating a pressurized steam stream from the recovered heat. Including, A system wherein at least one of the first and second compressors is powered using at least a portion of the flow of pressurized steam.

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