Patent Application
20240125549
The present invention relates to a method and system for removing natural gas liquids (NGLs) from a natural gas feed stream and for liquefying the natural gas feed stream so as to produce a liquefied natural gas (LNG) stream and a natural gas liquids (NGL) stream.
Removal of the heavy hydrocarbons (also referred to herein as “HHCs”), such as C6+ hydrocarbons (hydrocarbons having 6 or more carbon atoms) and aromatics (e.g. benzene, toluene, ethylbenzene and xylenes), from natural gas prior to liquefaction of the natural gas is often desirable in order to avoid freeze-out of these components in the heat exchangers used to liquefy the natural gas. C2 to C5+ hydrocarbons (hydrocarbons having 2 to or more carbon atoms), also referred to in the art as natural gas liquids (or “NGLs”), are typically also separated from natural gas because they have a relatively high market value.
Traditionally, removing NGLs (and HHCs) from a rich natural gas feed stream (a natural gas feed stream rich in said components) has involved use of a stand-alone front-end NGL extraction operating at low to medium pressure. Additional equipment is then required to increase the feed pressure in order to efficiently liquify the natural gas.
US patent application US 2018/0180354 A1 depicts a method and system for liquefying natural gas, in which the compressed refrigerant stream exiting the refrigerant compressor is split into first and second portions. The first portion of the compressed refrigerant is combined with the natural gas feed stream, before said natural gas feed stream is then precooled in a precooler, expanded in an expander and introduced into a phase separator (or the upper part of a demethaniser column) where it is separated into vapor and liquid fractions, the vapor fraction being withdrawn from the phase separator and warmed in a first heat exchanger before being routed to the refrigerant compressor. The second portion of the refrigerant stream is cooled in the first heat exchanger section before being further split into third and fourth portions, with the third portion being further cooled and liquefied in a second heat exchanger to provide the LNG product, and with the fourth portion being expanded in an expander and separated in a phase separator into vapor and liquid fractions, with the vapor fraction being withdrawn from the phase separator, warmed in the second heat exchanger, and then further warmed in the first heat exchanger before being routed to the refrigerant compressor.
Disclosed herein are methods and systems for removing NGLs from and liquefying a natural gas feed stream, in which a front-end natural gas liquids (NGL) unit is integrated with a natural gas liquefaction unit that uses an open loop refrigeration cycle. The Integrated approach disclosed herein can remove the need for feed compression equipment, while still achieving similar levels of natural gas liquids recovery and aromatics extraction to those achievable using a standalone front-end NGL unit. The open-loop refrigeration cycle also removes the need for equipment, piping, and instrumentation associated with refrigerant storage and injection in the liquefaction unit (since in the open-loop refrigerant cycle the feed serves as a continuous source of the refrigerant). Such reductions in equipment and operating complexity lead to reduced capital costs and increased operating efficiency.
Several preferred aspects of the methods and systems according to the present invention are outlined below.
Described herein are methods and systems for removing NGLs from and liquefying a natural gas feed stream so as to produce an LNG stream and an NGL stream.
As used herein and unless otherwise indicated, the articles “a” and “an” mean one or more when applied to any feature in embodiments of the present invention described in the specification and claims. The use of “a” and “an” does not limit the meaning to a single feature unless such a limit is specifically stated. The article “the” preceding singular or plural nouns or noun phrases denotes a particular specified feature or particular specified features and may have a singular or plural connotation depending upon the context in which it is used.
Where letters are used herein to identify recited steps of a method (e.g. (a), (b), and (c)), these letters are used solely to aid in referring to the method steps and are not intended to indicate a specific order in which claimed steps are performed, unless and only to the extent that such order is specifically recited.
Where used herein to identify recited features of a method or system, the terms “first”, “second”, “third” and so on, are used solely to aid in referring to and distinguishing between the features in question and are not intended to indicate any specific order of the features, unless and only to the extent that such order is specifically recited.
As used herein, the term “natural gas” encompasses also synthetic and/or substitute natural gases. The major component of natural gas is methane (which typically comprises at least 85 mole %, more often at least 90 mole %, and on average about 95 mole % of the feed stream). Other typical components of raw natural gas that may be present in smaller amounts include one or more “light components” (i.e. components having a lower boiling point than methane) such as nitrogen, helium, and hydrogen, and/or one or more “heavy components” (i.e. components having a higher boiling point than methane) such as carbon dioxide and other acid gases, moisture, mercury, and heavier hydrocarbons such as ethane, propane, butanes, pentanes, etc. However, prior to being liquefied the raw natural gas feed stream will be treated if and as necessary in order to reduce the levels of any heavy components that may be present down to such levels as are needed to avoid freezing or other operational problems in the heat exchanger section or sections in which the natural gas is to be cooled and liquefied.
As used herein, the term “liquefied natural gas” refers to natural gas that is in the liquid phase or, in relation to natural gas that is at a temperature and pressure above its critical point (i.e. that is a supercritical fluid), to natural gas that is at a density greater than its critical point density. Likewise, references to “liquefying” a natural gas refer to the conversion (typically by cooling) of a natural gas from vapor to liquid (i.e. from the gaseous to liquid phase) or, in relation to natural gas that is at a temperature and pressure above its critical point, to the act of increasing (typically by cooling) the density of the natural gas to a density greater than its critical point density.
As used herein, the term “indirect heat exchange” refers to heat exchange between two fluids where the two fluids are kept separate from each other by some form of physical barrier.
As used herein, the term “heat exchanger section” refers to a unit or a part of a unit in which indirect heat exchange is taking place between one or more streams of fluid flowing through the cold side of the heat exchanger section and one or more streams of fluid flowing through the warm side of the heat exchanger section, the stream(s) of fluid flowing through the cold side being thereby warmed, and the stream(s) of fluid flowing the warm side being thereby cooled (the terms “warm side” and “cold side” being purely relative). Unless otherwise indicated, a heat exchanger section may a heat exchanger section of any suitable type, such as but not limited to a heat exchanger section of a shell and tube, coil wound, or plate and fin type of heat exchanger.
As used herein, the terms “coil wound heat exchanger” and “coil wound heat exchanger unit” refer to a heat exchanger of the type known in the art, comprising one or more tube bundles encased in a shell casing. A “coil wound heat exchanger section” comprises one or more of said tube bundles, the “tube side” of said bundle(s), i.e. the interior of the tubes in the bundle(s), typically representing the warm side of said section and defining one or more passages (also referred to as tube circuits) through the section, and the “shell side” of said bundle(s), i.e. the space between and defined by the interior of the shell casing and exterior of the tubes, typically representing the cold side of said section and defining a single passage through the section. The shell side is almost always used as the cold side of the section, with the refrigerant providing cooling duty to the section being therefore passed through the shell side, because the shell side provides much lower flow resistance and allows for a much greater pressure drop than the tube side which makes passing expanded streams of cold refrigerant through the shell side much more effective and efficient. Coil wound heat exchangers are a compact design of heat exchanger known for their robustness, safety, and heat transfer efficiency, and thus have the benefit of providing highly efficient levels of heat exchange relative to their footprint. However, because the shell side defines only a single passage through the heat exchanger section it is not possible use more than one stream of refrigerant in the shell side of the coil wound heat exchanger section without said streams of refrigerant mixing in the shell side of said heat exchanger section.
As used herein, the term “flashing” (also referred to in the art as “flash evaporating”) refers to the process of reducing the pressure of a liquid (or supercritical or two-phase) stream so as to cool the stream and vaporize some of the liquid resulting in a colder, lower pressure two-phase mixture of vapor and liquid, the vapor present in this mixture also being referred to as the “flash gas”. As use herein, the phrase “flashing and separating” refers to the process of flashing a stream and separating the flash gas from the remaining liquid.
As used herein, the phrases “gaseous stream of refrigerant” and “gaseous refrigerant stream” refer to a stream of refrigerant where substantially all, and more preferably all of the stream is vapor (i.e. is in the gaseous phase). Preferably, the stream is at least 80 mole % vapor (i.e. has a vapor fraction of at least 0.8). More preferably the stream is at least 90 mole %, at least 95 mole %, or at least 99 mole % vapor.
As used herein, the term “expansion device” refers to any device or collection of devices suitable for expanding and thereby lowering the pressure of a fluid. Suitable types of expansion device for expanding a fluid include “isentropic” expansion devices, such as expanders (i.e. turbo-expanders) or hydraulic turbines, in which the fluid is expanded and the pressure and temperature of the fluid thereby lowered in a substantially isentropic manner (i.e. in a manner that generates works); and “isenthalpic” expansion devices, such as valves or other throttling devices, in which the fluid is expanded and the pressure and temperature of the fluid thereby lowered without the generating work.
As used herein, the term “separation device” refers to any device or collection of devices suitable for separating a two-phase (vapor and liquid) stream or mixture into separate vapor (gas) and liquid streams. Exemplary of separation devices include phase separators and distillation columns.
As used herein, the term “distillation column” refers to a column containing one or more separation sections, each separation section being composed of one or more separation stages (composed of devices such as packing or trays) that increase contact and thus enhance mass transfer between the upward rising vapor and downward flowing liquid inside the column such that the liquid and vapor streams exiting the column are not in equilibrium (the concentration of higher volatility components being increased in the upward rising vapor and the concentration of lower volatility components being increased in the downward flowing liquid). The term “overhead vapor” refers to the vapor that collects at the top of the column. The term “bottoms liquid” refers to the liquid that collects at the bottom of the column. The “top” of the column refers to the part of the column above the separation sections (i.e. at or above the top-most separation stage). The “bottom” of the column refers to the part of the column below the separation sections (i.e. at or below the bottom-most separation stage). An “intermediate location” of the column refers to a location between the top and bottom of the column, between two separation sections. The term “reflux” refers to a source of downward flowing liquid from the top of the column. The term “boil-up” refers to a source of upward rising vapor from the bottom of the column, typically generated by boiling (“re-boiling”) a portion of the bottoms liquid.
The term “phase separator” refers to a drum or other form of vessel in which a two-phase stream can separate into its constituent vapor and liquid phases where the liquid and vapor streams exiting the vessel are in equilibrium (there being no separation stages inside a phase separator).
Solely by way of example, various exemplary embodiments of the invention will now be described with reference to the Figures. In the Figures, where a feature is common to more than one Figure that feature has been assigned the same reference numeral. Unless a feature is specifically described as being different from other embodiments in which it is shown in the drawings, that feature can be assumed to have the same structure and function as the corresponding feature in the embodiment in which it is described. Moreover, if that feature does not have a different structure or function in a subsequently described embodiment, it may not be specifically referred to in the specification.
Referring to
A natural gas feed stream 100, containing also a mixture of NGLs and HHCs (including aromatics) and typically at ambient temperature and a high-pressure, typically between 50 and 100 bara and more preferably between 70 and 95 bara, is routed to a pretreatment section 101. Depending on the composition of the natural gas feed, the pretreatment of the natural gas feed stream 100 in the pretreatment section 101 can comprise treating the natural gas feed stream in an acid gas removal unit for removing H2S and CO2, a dehydration unit for removing water, and/or a mercury removal unit.
The pretreated natural gas feed stream 102 exiting the pretreatment section 101 is then precooled by passing at least a portion of the natural gas feed stream through the warm side of a first heat exchanger section 106A of a main heat exchanger, said at least a portion of the natural gas feed stream being precooled via indirect heat exchange with a combined natural gas vapor, first expanded refrigerant and second expanded refrigerant stream 152 (that will be described in more detail below) passing through the cold side of the first heat exchanger section 106A. In the illustrated embodiment this is done by splitting the pretreated natural gas feed stream 102 exiting the pretreatment section 101 into two streams, namely a bypass stream 108 consisting of between 20 and 60 percent and more preferably between 30 and 50 percent of the flow the pretreated natural gas feed stream 102 that bypasses the first heat exchanger section 106A, and a feed stream 104 consisting of the remainder of the of the flow the pretreated natural gas feed stream 102 that is passed through a circuit (i.e. one or more passages) in the warm side of the first heat exchanger section 106A and cooled to from a precooled feed stream 107 at a temperature of between −40° C. and −20° C., and more preferably between −35° C. and −25° C., that is then recombined with the bypass stream 108 and introduced into a high pressure (HP) phase separator 110.
The HP phase separator 110 operates at a pressure of between 50 and 100 bara, and more preferably between 70 and 95 bara. In the HP phase separator 110 the pretreated and precooled natural gas feed stream is separated into vapor and liquid phases. The vapor phase of the natural gas feed stream is withdrawn from the HP phase separator 110 as stream 111 and expanded in a first expander 112A forming an expanded stream 114 that is introduced into a distillation column 117 at a first intermediate location of the column, below separation section 117A of the column and above separation section 117B of the column. The liquid phase of the natural gas feed stream is withdrawn from the HP phase separator 110 as stream 115, expanded across a J-T valve and introduced into the distillation column 117 at a second intermediate location below separation section 117B of the column (which section is therefore positioned between the first and second intermediate locations) and above separation section 117C of the column.
The distillation column 117 preferably operates at a pressure of between 20 and 40 bara and more preferably between 25 and 30 bara. Reflux to the distillation column 117 is provided by a reflux stream 162 (which will be described in more detail below) that is expanded across a J-T valve and introduced into the top of the distillation column 117, above separation section 117A. Boil-up for the distillation column 117 is provided by re-boiling a portion of the distillation column bottoms liquid in a reboiler 118. Heating duty for re-boiling the portion of the bottoms liquid in the reboiler 118 can be provided by a stream of steam or another heat transfer fluid that is passed through and cooled in the reboiler via indirect heat exchange with the portion of the bottoms liquid. With certain feed compositions the reboiler 118 could, in an alternative embodiment, be integrated into the first heat exchanger section 106A, with the portion of the bottoms liquid being passed through and warmed in a circuit (i.e. one or more passages) in the cold side of the heat exchanger section 106A, the heating duty for re-boiling the portion of the bottoms liquid being in this case provided by one or more streams passing through the warm side of the first heat exchanger section 106A. In yet another embodiment, the reboiler 118 could be replaced or supplemented by injecting a warm process stream into the bottom of the distillation column 117.
Inside the distillation column 117, upward rising vapor from the natural gas feed stream (i.e. from streams 114 and 115) is brought into contact with downward flowing liquid from the reflux stream as they pass through the separation stages inside the distillation column 117, thereby “scrubbing” components heavier than methane from said upward rising vapor (i.e. removing at least some of said components of lower volatility than methane from the vapor). Likewise, downward flowing liquid from the natural gas feed stream is brought into contact with upward rising vapor from the bottom of the column as they pass through the separation stages inside the distillation column 117, thereby “stripping” methane and components lighter than methane from said downward flowing liquid (i.e. removing at least some of the methane and components of higher volatility than methane from the liquid). As such, the natural gas feed stream is separated inside the distillation column 117 into a methane-rich vapor fraction, collected as the distillation column overhead vapor, and a liquid fraction, enriched in hydrocarbons heavier than methane, collected as the distillation column bottoms liquid.
A NGL stream 119, formed of the distillation column bottoms liquid, is withdrawn from the bottom of the distillation column. The NGL stream 119 has a high aromatics content along with NGLs and HHCs, and is at a temperature of between 80° C. and 40° C. and more preferably between 70° C. and 50° C. The percentage of C3+ components from the natural gas feed stream 102 that are recovered in the NGL Stream 119 can be higher than 90 mol % (as calculated from the sum of molar flow rate of all C3+ components in the NGL stream 119 divided by the sum of the molar flow rate of all C3+ components in the natural gas feed stream 102).
A natural gas vapor stream 120, formed of the distillation column overhead vapor, is withdrawn from the top of the distillation column. The natural gas vapor stream 120 is at a temperature of between −90° C. and −60° C. and more preferably between −80° C. and −70° C., and typically contains less than 0.1 mol % of C5+ hydrocarbons (i.e. the sum of all C5+ hydrocarbons in the natural gas vapor stream 120 totals less than 0.1 mol % of the stream) and less than 1 mol ppm of aromatics (i.e. the sum of all aromatics in the natural gas vapor stream 120 totals less than 1 mol ppm of the stream).
A first expanded refrigerant stream 148 is passed through the cold side of a third heat exchanger section 106C of the main heat exchanger where it is warmed to a temperature of between −100° C. and −60° C. and more preferably between −90° C. and −70° C. The first expanded refrigerant stream 149 exiting the cold side of the third heat exchanger section 106C is then combined with the natural gas vapor stream 120 to form a combined natural gas vapor and first expanded refrigerant stream 150. The combined natural gas vapor and first expanded refrigerant stream 150 is passed through the cold side of a second heat exchanger section 106B of the main heat exchanger where it is warmed to a temperature of between −60° C. and −20° C. and more preferably between −50° C. and −30° C. The combined natural gas vapor and first expanded refrigerant stream 151 exiting the cold side of the second heat exchanger section 106B is then combined with a second expanded refrigerant stream 144 to form the combined natural gas vapor, first expanded refrigerant and second expanded refrigerant stream 152. The combined natural gas vapor, first expanded refrigerant and second expanded refrigerant stream 152 is then passed through the cold side of the first heat exchanger section 106A of the main heat exchanger where it is warmed to within a few degrees centigrade of the temperature of the pretreated natural gas feed stream 104 entering said heat exchanger section.
The combined natural gas vapor, first expanded refrigerant and second expanded refrigerant stream 122 exiting the cold side of the first heat exchanger section 106A is then sent to a compression system comprising a plurality of compression stages in order to be compressed to form a compressed refrigerant 142.
More specifically, the combined natural gas vapor, first expanded refrigerant and second expanded refrigerant stream 122 exiting the cold side of the first heat exchanger section 106A is first compressed a multi-stage refrigerant compressor 124, putting out for example 15,000 to 10,000 meters of head. In the illustrated embodiment, the multi-stage refrigerant compressor 124 has an intercooler 125 (which improves compression efficiency), although this may be excluded depending on equipment design and total head across the refrigerant compressor 124. The compressed stream 126 exiting the multi-stage refrigerant compressor is then cooled in aftercooler 127 before being split between and further compressed in three parallel compression stages 112B, 134B and 138B, and cooled in three associated aftercoolers 130, 135, and 139, forming three further compressed streams 131, 140, 136 that are then recombined to form the compressed refrigerant 142. The parallel compression stages 112B, 134B, 138B, associated aftercoolers 130, 135, and 139, multi-stage refrigerant compressor 124, and associated intercooler 125 and aftercooler 127 can all be run in multiple strings.
The compressed refrigerant 142, which is at a pressure of 100 to 80 bara, is then divided into several refrigerant streams 155, 143, 173, 182.
Stream 155, representing first and second portions of the compressed refrigerant 142, is passed through a circuit (i.e. one or more passages) in the warm side of the first heat exchanger section 106A (separately from the circuit through which the natural gas feed stream 104 is passed) and cooled to a temperature of between −40° C. and −20° C., and more preferably between −35° C. and −25° C., via indirect heat exchange with the combined natural gas vapor, first expanded refrigerant and second expanded refrigerant stream 152 passing through the cold side of said heat exchanger section. The resulting cooled stream 156 is then divided into said first and second portions of the compressed refrigerant, the second portion of the compressed refrigerant forming second cold refrigerant stream 164, consisting of between 90 and 70 percent and more preferably between 85 and 75 percent of the flow of stream 156, and the first portion of the compressed refrigerant forming stream 158 consisting of the remainder of the flow of stream 156. In an alternative embodiment, instead of being passed through and cooled in the warm side of the first heat exchanger section 106A as a single stream, the first and second portions of the compressed refrigerant could be taken as separate streams that are passed through and cooled in separate circuits in the warm side of the first heat exchanger section to form streams 158 and 164.
Stream 158, comprising the first portion of the compressed refrigerant, is passed through a circuit in the warm side of the second heat exchanger section 106B where it is further cooled via indirect heat exchange with the combined natural gas vapor and first expanded refrigerant stream 150 passing through the cold side of said heat exchanger section, and is then is passed through a circuit in the warm side of the third heat exchanger section 106C where it is further cooled via indirect heat exchange with the first expanded refrigerant stream 148 passing through the cold side of said heat exchanger section, forming a first cold refrigerant stream 159 that is withdrawn from the warm side of the third heat exchanger section 106C at a temperature of between −105° C. and −80° C. and more preferably between −100° C. and −90° C.
The first cold refrigerant stream 159 and the second cold refrigerant stream 164 are then expanded, combined and separated into vapor and liquid phases to form a first liquefied natural gas stream 160 from the liquid phase and the first expanded refrigerant stream 148 from the vapor phase.
More specifically, in the embodiment illustrated in
Stream 143, representing a third portion of the compressed refrigerant 142, is expanded in a third expander 138A to form the second expanded refrigerant stream 144 that is then combined with the combined natural gas vapor and first expanded refrigerant stream 151 to form the combined natural gas vapor, first expanded refrigerant and second expanded refrigerant stream 152 (as described above).
In the embodiment illustrated in
The first liquefied natural gas stream 160 is divided, with a first portion of the stream forming the reflux stream 162 that is pumped by reflux pump 163 to the distillation column 117 and then, as previous described, expanded across a J-T valve and introduced into the top of the distillation column 117 to provide reflux to the distillation column. The reflux stream 162 is at a temperature of between −105° C. and −80° C. and more preferably between −100° C. and −90° C., and consists of between 5 and 20 percent and more preferably between 10 and 15 percent of the flow of the first liquefied natural gas stream 160. In an alternative embodiment, instead of (or in addition to) forming the reflux stream 162 from a portion of the first liquefied natural gas stream 160 in the manner described above, the reflux stream could be from a portion of the liquid phase separated in the LP phase separator 147 by withdrawing a first portion of said liquid phase from the LP phase separator 147 as the first liquefied natural gas stream 160 and withdrawing a second portion of said liquid phase from the LP phase separator 147 as the reflux stream 162 (the first liquefied natural gas stream 160 and the reflux stream 162 being therefore withdrawn from the LP phase separator 147 as separate streams).
A second portion 166 of the first liquefied natural gas stream 160, consisting of the remainder of said stream, is flashed alongside a second set of liquefied natural gas streams 177, 186 and a third liquefied natural gas stream 199 to form a LNG product stream 192 and flash gas streams 171 and 181.
More specifically, the second portion of the first liquefied natural gas stream 160 forms stream 166 that is flashed across a J-T valve and introduced into a HP flash gas phase separator 167 where it is separated into vapor and liquid phases. The HP flash gas phase separator 167 operates at a pressure of 20 to 10 bara. A hydraulic turbine (not shown) can be used to extract work from stream 166 before it flashed and introduced into the HP flash gas phase separator 167. The vapor phase withdrawn from the HP flash gas phase separator 167 forms a first flash gas stream 169, and the liquid phase withdrawn from the HP flash gas phase separator 167 forms liquid stream 168 that is flashed across a J-T valve and introduced into a LP flash gas phase separator 178 where it is separated into vapor and liquid phases. The LP flash gas phase separator 178 operates at a pressure of 10 to 2 bara. The vapor phase withdrawn from the LP flash gas phase separator 178 forms a second flash gas stream 179, and the liquid phase withdrawn from the LP flash gas phase separator 178 forms the LNG product stream 192, which is sent to and stored in a LNG storage tank 193. An LNG pump (not shown) may be used to transfer the LNG product stream 192 to the LNG storage tank 193 if the pressure in the LP flash gas phase separator 178 does not provide enough driving force.
The first flash gas stream 169 is passed through and warmed in the cold side of first 170A and second 170B heat exchanger sections of a first flash gas heat exchanger, forming a warmed first flash gas stream 171. The second flash gas stream 179 is passed through and warmed in the cold side of first 180A and second 180B heat exchanger sections of a second flash gas heat exchanger, forming a warmed second flash gas stream 181.
The warmed first and second flash gas streams 171 and 181 are combined and compressed to form a compressed flash gas stream 189. In the embodiment illustrated in
A boil-off gas (BOG) stream 194, consisting of tank flash, boil-off gas, and vapor displacement, is withdrawn from the headspace of the LNG storage tank 193 and compressed and cooled in a BOG compressor 195 and associated aftercooler 196 to form a compressed BOG gas stream 197. Alternatively, depending on preferred operation, the LNG storage tank 193 may be operated at bubble point. In this case, the BOG stream 194 and associated BOG compressor 195 and associated aftercooler 196 may be eliminated, or the BOG stream 194 may consist only of vapor displacement with the BOG compressor 195 and associated aftercooler 196 being sized accordingly.
The compressed flash gas stream 189, 191 is combined with the compressed BOG gas stream 197 (when present) to form a recycle stream 198 that is passed through and cooled and liquefied the warm side of the first second and third heat exchanger sections 106A, 106B, 106C of the main heat exchanger to form the third liquefied natural gas stream 199 that is flashed across a J-T valve and introduced into the HP flash gas phase separator 167 where it is separated into vapor and liquid phases.
In an alternative embodiment, instead of being combined and then passed through the warm side of the first second and third heat exchanger sections 106A, 106B, 106C as a combined recycle stream 198, the compressed flash gas stream 189, 191 and the compressed BOG gas stream 197 may be passed through separate circuits in the warm side of the first second and third heat exchanger sections 106A, 106B, 106C to be cooled and liquefied separately before being combined. Additionally or alternatively, the cooled and liquefied compressed flash gas stream and compressed BOG gas stream (whether cooled and liquefied separately or as a combined stream) may be routed to and introduced into the LP phase separator 147 (and thus combined and separated with the first cold refrigerant stream 159 and the second cold refrigerant stream 164) to be separated into vapor and liquid phases, instead of being routed to and separated in the HP flash gas phase separator 167.
The refrigerant compressor 124, flash gas compressor 187, and (when present) BOG compressor 197 can be powered via any suitable means. In the embodiment illustrated in
Streams 173 and 182, together representing fourth and fifth portions of the compressed refrigerant 142, are cooled in the first and second flash gas heat exchangers via indirect heat exchange with the first and second flash gas streams.
More specifically, stream 173, representing part of the fourth and fifth portions of the compressed refrigerant is passed through and cooled in the warm side of the first heat exchanger section 170A of the first flash gas heat exchanger forming a precooled stream 174 that is then divided into stream 175 and stream 176. Stream 182, representing the other part of the fourth and fifth portions of the compressed refrigerant is passed through and cooled in the warm side of the first heat exchanger section 180A of the second flash gas heat exchanger forming a precooled stream 183 that is then divided into stream 184 and stream 185.
Streams 176 and 185 together represent the fourth portion of the compressed refrigerant. Stream 176 is passed through and further cooled and liquefied in the warm side of the second heat exchanger section 170B of the first flash gas heat exchanger, forming stream 177 of the second set of liquefied natural gas streams which stream is at a temperature of between −130° C. and −100° C. and more preferably between −120° C. and −110° C. and is flashed across a J-T valve and introduced into the HP flash gas phase separator 167 where it is separated into vapor and liquid phases. Stream 185 is passed through and further cooled and liquefied in the warm side of the second heat exchanger section 180B of the second flash gas heat exchanger, forming stream 186 of the second set of liquefied natural gas streams which stream is at a temperature of between −160° C. and −120° C. and more preferably between −150° C. and −130° C. and is flashed across a J-T valve and introduced into the LP flash gas phase separator 178 where it is separated into vapor and liquid phases.
Stream 175 and 184, which together represent the fifth portion of the compressed refrigerant are combined with stream 158 comprising the first portion of the compressed refrigerant prior to said stream being introduced into and passed through the warm side of the second heat exchanger section 106B of the main heat exchanger. In an alternative embodiment, streams 175 and 184 could be combined with the stream 158 after it has been passed through and cooled in the warm side of the second heat exchanger section 106B and prior to said stream being introduced into and passed through the warm side of the third heat exchanger section 106C of the main heat exchanger. Stream 175 consists of between 60 and percent and more preferably between 50 and 30 percent of the flow of precooled stream 174 exiting heat exchanger section 170A. Stream 184 consists of between 60 and 20 percent and more preferably between 50 and 30 percent of the precooled stream 183 exiting Exchanger 180A.
Stream 155, representing the first and second portions of the compressed refrigerant 142, preferably consists of between 50 and 60 percent of the flow of the compressed refrigerant 142. Stream 143, representing the third portion of the compressed refrigerant 142, preferably consists of between 30 and 40 percent of the flow of the compressed refrigerant 142. Streams 173 and 182, that each represent part of the fourth and fifth portions of the compressed refrigerant 142, each preferably consist of between 2 and 10 percent of the flow of the compressed refrigerant 142.
The first 106A, second 106B and third 106C first heat exchanger sections of the main heat exchanger may be heat exchanger sections of any type. In a preferred arrangement all three heat exchanger sections may be coil-wound heat exchanger sections, as for example illustrated in
In those embodiments where the first 106A, second 106B and third 106C heat exchanger sections of the main heat exchanger are heat exchanger sections of a type where the cold side of the heat exchanger sections can readily accommodate separate streams (such as for example heat exchanger sections of the plate fin type), the natural gas vapor stream, first expanded refrigerant stream and/or second expanded refrigerant stream need not be combined before being cooled, and can instead be cooled in separate circuits in the cold sides of the heat exchanger sections of the main heat exchanger before being combined prior to, during or after compression to form the compressed refrigerant 142.
The first 170A and second 170B heat exchanger sections of the first flash gas heat exchanger and the first 180A and second 180B heat exchanger sections of the second flash gas heat exchanger may also be heat exchanger sections of any type. In a preferred arrangement the heat exchanger sections may be coil-wound heat exchanger sections, some or all of the heat exchanger sections may also be heat exchanger sections of another type, such as for example heat exchanger sections of the shell and tube or plate fin type. The first 170A and second 170B heat exchanger sections of the first flash gas heat exchanger may be housed in a single unit (e.g. within the same shell casing in the case where they are coil-wound heat exchanger sections) or in separate units. Likewise, the first 180A and second 180B heat exchanger sections of the second flash gas heat exchanger may be housed in a single unit or in separate units. In alternative embodiments, the first flash gas heat exchanger and/or the second flash gas heat exchanger could consist of more (or fewer) heat exchanger sections.
Where the flash gas heat exchanger and the second flash gas heat exchanger are coil-wound heat exchangers, it is also possible to integrate these heat exchangers with the HP and LP flash gas phase separators, such as is illustrated in shown in
In the embodiment shown in
Similarly, in the embodiment shown in
As described above, in the arrangement shown in
In an alternative arrangement to that shown in
In an alternative arrangement to that shown in
In an alternative arrangement to that shown in
The method and system according to the first embodiment of the invention depicted in
In particular, the use of distillation column 117 to separate the natural gas feed stream, with the natural gas feed stream being introduced into the distillation column 117 below at least one separation section (117A) thereof, provides for improved recovery of NGLs and aromatics as compared to the use of only a phase separator or stripping column (i.e. a distillation column having no reflux stream and no separation stages above the location at which the natural gas feed stream is introduced into the distillation column). The use of only a phase separator results in poor recovery of NGLs and aromatics from the natural gas feed. Since NGLs are a high value commodity, their loss into the LNG Product is financially inefficient, and where the natural gas feed has a high aromatics content inadequate removal of the aromatics will result in freeze-out of these components in the main heat exchanger and thus a stoppage in operation. The use of only a stripping column may achieve higher NGL recovery than the use of a phase separator but may still leave the natural gas feed with a high content of aromatics. Conversely, by using, in the manner shown in
The use (in the manner illustrated in
Producing the LNG product by flashing the liquefied natural gas stream 166 obtained from the LP phase separator 147, with associated recovery of cold from the flash gas in flash gas heat exchangers and recycling of the flash gas, also improves the efficiency of the process (by reducing the amount of cooling that needs to be provided in the main heat exchanger).
Using the first heat exchanger section 106A of the main heat exchanger to precool the natural gas feed stream 102 prior to said stream being expanded and separated eliminates the need for separate heat exchanger units for precooling the natural gas feed stream, thereby simplifying the design and reducing plot space. In addition, the use of HP phase separator 110 to then separate the precooled natural gas feed stream into liquid and vapor phases, with the vapor phase being expanded in first expander 112A and the liquid phase being expanded across a J-T valve before the introduction of the precooled natural gas feed stream into the distillation column 117, improves expander efficiency and simplifies expander design as compared to using an expander designed to expand or produce a stream having both liquid and vapor phases (the use of the HP phase separator 110 also adding another theoretical stage of separation and thus further improving NGL recovery).
The combination of the natural gas vapor stream 120 and first expanded refrigerant stream 149 to form the combined stream 150 that is warmed in the cold side of the second heat exchanger section 106B of the main heat exchanger, and the further combination of said combined stream 150 with the second expanded refrigerant stream 144 to form the combined stream 152 that is further warmed in the cold side of the first heat exchanger 106A of the main heat exchanger, means that the refrigerant compressor 124 has to deal with only one inlet stream 122 (formed of the combined and warmed natural gas vapor, first expanded refrigerant and second expanded refrigerant streams), thereby allowing the design of the refrigerant compressor 124 to be significantly simplified. Moreover, it allows the first and second heat exchanger sections 106A and 106B to be coil wound heat exchanger sections, since they then do not have to receive streams that need to be kept separate on the cold side of said heat exchanger sections. As noted above, coil wound heat exchangers are a compact design of heat exchanger known for their robustness, safety, and heat transfer efficiency, and thus have the benefit of providing highly efficient levels of heat exchange relative to their footprint. However, because the shell side defines only a single passage through the heat exchanger section it is not possible use more than one stream of refrigerant in the shell side of the coil wound heat exchanger section without said streams of refrigerant mixing in the shell side of said heat exchanger section.
The operation of the first expander 112A and first compression stage 112B as respectively the expander and compressor portions of a first compander, the second expander 134A and second compression stage 134B as respectively the expander and compressor portions of a second compander, and the third expander 138A and third compression stage 138B as respectively the expander and compressor portions of a third compander, with the outlet of the multistage refrigerant compressor 124 connecting to and feeding into the inlets of the compressor portions, also provides additional efficiency.
Referring now to
The method and system depicted in
The use of this additional feed stream 213 to the distillation column 217, cooled in the manner described above, can further improve the NGL recovery and reduce the specific power of the process.
All of the variations, alternative embodiments and alternative arrangements described with reference to the embodiment depicted in
Referring now to
The method and system depicted in
Referring now to
The method and system depicted in
More specifically, in the method and system of
Referring now to
The method and system depicted in
More specifically, in the method and system of
Referring now to
The method and system depicted in
Referring now to
The method and system depicted in
More specifically, in the method and system of
By compressing the natural gas feed stream before expansion, the arrangement depicted in
Referring now to
The method and system depicted in
In a similar manner to the embodiment shown in
In the specific arrangement shown in
In such an arrangement it would, in an alternative embodiment, be possible to integrate the LP phase separator 847 with the coil wound heat exchanger unit containing the third heat exchanger section 806C (in the particular embodiment illustrated in
In this example, a method and system for cooling and liquefying natural gas as depicted in
Table 1 shows stream data from a simulated example. In this example, the multi-stage refrigerant compressor 124 had two stages and was operated in two strings with each string having an approximate gas horsepower of 48.8 MW. The flash gas compressor 187 and BOG compressor 195 had an approximate gas horsepower of 36.6 MW and 12.0 MW, respectively. In the simulated process, 90 mole % of C3+ components from the natural gas feed are recovered in the NGL stream 119 withdrawn from the bottom of the distillation column 117.
It will be appreciated that the invention is not restricted to the details described above with reference to the preferred embodiments but that numerous modifications and variations can be made without departing from the spirit or scope of the invention as defined in the following claims.
