Patent Application
20060086139
1. Field of the Invention
This invention relates to a method and apparatus for liquefying natural gas. In another aspect, the invention concerns an method and apparatus for providing liquid reflux to a refluxed heavies removal column of a liquefied natural gas (LNG) facility.
2. Description of the Prior Art
The cryogenic liquefaction of natural gas is routinely practiced as a means of converting natural gas into a more convenient form for transportation and storage. Such liquefaction reduces the volume of the natural gas by about 600-fold and results in a product which can be stored and transported at near atmospheric pressure.
Natural gas is frequently transported by pipeline from the supply source of supply to a distant market. It is desirable to operate the pipeline under a substantially constant and high load factor but often the deliverability or capacity of the pipeline will exceed demand while at other times the demand may exceed the deliverability of the pipeline. In order to shave off the peaks where demand exceeds supply or the valleys when supply exceeds demand, it is desirable to store the excess gas in such a manner that it can be delivered when demand exceeds supply. Such practice allows future demand peaks to be met with material from storage. One practical means for doing this is to convert the gas to a liquefied state for storage and to then vaporize the liquid as demand requires.
The liquefaction of natural gas is of even greater importance when transporting gas from a supply source which is separated by great distances from the candidate market and a pipeline either is not available or is impractical. This is particularly true where transport must be made by ocean-going vessels. Ship transportation in the gaseous state is generally not practical because appreciable pressurization is required to significantly reduce the specific volume of the gas. Such pressurization requires the use of more expensive storage containers.
In order to store and transport natural gas in the liquid state, the natural gas is preferably cooled to −240° F. to −260° F. where the liquefied natural gas (LNG) possesses a near-atmospheric vapor pressure. Numerous systems exist in the prior art for the liquefaction of natural gas in which the gas is liquefied by sequentially passing the gas at an elevated pressure through a plurality of cooling stages whereupon the gas is cooled to successively lower temperatures until the liquefaction temperature is reached. Cooling is generally accomplished by indirect heat exchange with one or more refrigerants such as propane, propylene, ethane, ethylene, methane, nitrogen, carbon dioxide, or combinations of the preceding refrigerants (e.g., mixed refrigerant systems). A liquefaction methodology which is particularly applicable to the current invention employs an open methane cycle for the final refrigeration cycle wherein a pressurized LNG-bearing stream is flashed and the flash vapors (i.e., the flash gas stream(s)) are subsequently employed as cooling agents, recompressed, cooled, combined with the processed natural gas feed stream and liquefied thereby producing the pressurized LNG-bearing stream.
In most LNG facilities it is necessary to remove heavy components (e.g., benzene, toluene, xylene, and/or cyclohexane) from the processed natural gas stream in order to prevent freezing of the heavy components in downstream heat exchangers. It is known that refluxed heavies columns can provide significantly more effective and efficient heavies removal than non-refluxed columns. However, many existing LNG facilities were originally constructed with non-refluxed heavies removal columns. Thus, it would be desirable to retrofit existing LNG facilities employing non-refluxed heavies removal columns with refluxed heavies removal columns.
One problem with retrofitting an existing LNG facility with a refluxed heavies removal column is the lack of availability of a suitable reflux stream. The reflux stream to a heavies removal column must be a low-temperature, liquid, methane-rich stream. It is not economically feasible to use existing liquified methane-rich steams of conventional LNG facilities as reflux to the heavies removal column because such liquid streams are typically at low pressures. A cryogenic pump would be required to transport these existing low-pressure, methan-rich streams to the heavies removal column. It is well know that cryogenic pumps are very expensive, and the cost of employing an additional cryogenic pump in an LNG facility would likely outweigh the benefits of switching from a non-refluxed to a refluxed heavies removal column.
If an existing high-pressure, methane-rich stream could be employed as the reflux stream to the heavies removal column, the need for a cryogenic pump could be obviated because the elevated pressure of the steam could be used to transport it to the heavies removal column. In existing LNG facilities, however, such high-pressure, methane-rich streams are not liquid streams, and current LNG facilities do not have the excess cooling capacity to liquify such high-pressure, methane-rich streams.
It is, therefore, an object of the present invention to provide a method and apparatus for providing a methane-rich liquid reflux stream to a heavies removal column in an LNG facility.
A further object of the invention is to provide a method and apparatus that adds cooling capacity to an existing LNG facility at minimal expense.
Still another object of the invention is to provide an apparatus that adds cooling capacity to an existing LNG facility and occupies minimal plot space in the LNG facility.
It should be understood that the above objects are exemplary and need not all be accomplished by the invention claimed herein. Other objects and advantages of the invention will be apparent from the written description and drawings.
Accordingly, one aspect of the present invention concerns
Another aspect of the present invention concerns
A further aspect of the present invention concerns
A preferred embodiment of the present invention is described in detail below with reference to the attached drawing figures, wherein:
A cascaded refrigeration process uses one or more refrigerants for transferring heat energy from the natural gas stream to the refrigerant and ultimately transferring said heat energy to the environment. In essence, the overall refrigeration system functions as a heat pump by removing heat energy from the natural gas stream as the stream is progressively cooled to lower and lower temperatures. The design of a cascaded refrigeration process involves a balancing of thermodynamic efficiencies and capital costs. In heat transfer processes, thermodynamic irreversibilities are reduced as the temperature gradients between heating and cooling fluids become smaller, but obtaining such small temperature gradients generally requires significant increases in the amount of heat transfer area, major modifications to various process equipment, and the proper selection of flow rates through such equipment so as to ensure that both flow rates and approach and outlet temperatures are compatible with the required heating/cooling duty.
As used herein, the term open-cycle cascaded refrigeration process refers to a cascaded refrigeration process comprising at least one closed refrigeration cycle and one open refrigeration cycle where the boiling point of the refrigerant/cooling agent employed in the open cycle is less than the boiling point of the refrigerating agent or agents employed in the closed cycle(s) and a portion of the cooling duty to condense the compressed open-cycle refrigerant/cooling agent is provided by one or more of the closed cycles. In the current invention, a predominately methane stream is employed as the refrigerant/cooling agent in the open cycle. This predominantly methane stream originates from the processed natural gas feed stream and can include the compressed open methane cycle gas streams. As used herein, the terms “predominantly”, “primarily”, “principally”, and “in major portion”, when used to describe the presence of a particular component of a fluid stream, shall mean that the fluid stream comprises at least 50 mole percent of the stated component. For example, a “predominantly” methane stream, a “primarily” methane stream, a stream “principally” comprised of methane, or a stream comprised “in major portion” of methane each denote a stream comprising at least 50 mole percent methane.
One of the most efficient and effective means of liquefying natural gas is via an optimized cascade-type operation in combination with expansion-type cooling. Such a liquefaction process involves the cascade-type cooling of a natural gas stream at an elevated pressure, (e.g., about 650 psia) by sequentially cooling the gas stream via passage through a multistage propane cycle, a multistage ethane or ethylene cycle, and an open-end methane cycle which utilizes a portion of the feed gas as a source of methane and which includes therein a multistage expansion cycle to further cool the same and reduce the pressure to near-atmospheric pressure. In the sequence of cooling cycles, the refrigerant having the highest boiling point is utilized first followed by a refrigerant having an intermediate boiling point and finally by a refrigerant having the lowest boiling point. As used herein, the terms “upstream” and “downstream” shall be used to describe the relative positions of various components of a natural gas liquefaction plant along the flow path of natural gas through the plant.
Various pretreatment steps provide a means for removing undesirable components, such as acid gases, mercaptan, mercury, and moisture from the natural gas feed stream delivered to the LNG facility. The composition of this gas stream may vary significantly. As used herein, a natural gas stream is any stream principally comprised of methane which originates in major portion from a natural gas feed stream, such feed stream for example containing at least 85 mole percent methane, with the balance being ethane, higher hydrocarbons, nitrogen, carbon dioxide, and a minor amount of other contaminants such as mercury, hydrogen sulfide, and mercaptan. The pretreatment steps may be separate steps located either upstream of the cooling cycles or located downstream of one of the early stages of cooling in the initial cycle. The following is a non-inclusive listing of some of the available means which are readily known to one skilled in the art. Acid gases and to a lesser extent mercaptan are routinely removed via a sorption process employing an aqueous amine-bearing solution. This treatment step is generally performed upstream of the cooling stages in the initial cycle. A major portion of the water is routinely removed as a liquid via two-phase gas-liquid separation following gas compression and cooling upstream of the initial cooling cycle and also downstream of the first cooling stage in the initial cooling cycle. Mercury is routinely removed via mercury sorbent beds. Residual amounts of water and acid gases are routinely removed via the use of properly selected sorbent beds such as regenerable molecular sieves.
The pretreated natural gas feed stream is generally delivered to the liquefaction process at an elevated pressure or is compressed to an elevated pressure generally greater than 500 psia, preferably about 500 psia to about 3000 psia, still more preferably about 500 psia to about 1000 psia, still yet more preferably about 600 psia to about 800 psia. The feed stream temperature is typically near ambient to slightly above ambient. A representative temperature range being 60° F. to 150° F.
As previously noted, the natural gas feed stream is cooled in a plurality of multistage cycles or steps (preferably three) by indirect heat exchange with a plurality of different refrigerants (preferably three). The overall cooling efficiency for a given cycle improves as the number of stages increases but this increase in efficiency is accompanied by corresponding increases in net capital cost and process complexity. The feed gas is preferably passed through an effective number of refrigeration stages, nominally two, preferably two to four, and more preferably three stages, in the first closed refrigeration cycle utilizing a relatively high boiling refrigerant. Such relatively high boiling point refrigerant is preferably comprised in major portion of propane, propylene, or mixtures thereof, more preferably the refrigerant comprises at least about 75 mole percent propane, even more preferably at least 90 mole percent propane, and most preferably the refrigerant consists essentially of propane. Thereafter, the processed feed gas flows through an effective number of stages, nominally two, preferably two to four, and more preferably two or three, in a second closed refrigeration cycle in heat exchange with a refrigerant having a lower boiling point. Such lower boiling point refrigerant is preferably comprised in major portion of ethane, ethylene, or mixtures thereof, more preferably the refrigerant comprises at least about 75 mole percent ethylene, even more preferably at least 90 mole percent ethylene, and most preferably the refrigerant consists essentially of ethylene. Each cooling stage comprises a separate cooling zone. As previously noted, the processed natural gas feed stream is preferably combined with one or more recycle streams (i.e., compressed open methane cycle gas streams) at various locations in the second cycle thereby producing a liquefaction stream. In the last stage of the second cooling cycle, the liquefaction stream is condensed (i.e., liquefied) in major portion, preferably in its entirety, thereby producing a pressurized LNG-bearing stream. Generally, the process pressure at this location is only slightly lower than the pressure of the pretreated feed gas to the first stage of the first cycle.
Generally, the natural gas feed stream will contain such quantities of C2+ components so as to result in the formation of a C2+ rich liquid in one or more of the cooling stages. This liquid is removed via gas-liquid separation means, preferably one or more conventional gas-liquid separators. Generally, the sequential cooling of the natural gas in each stage is controlled so as to remove as much of the C2 and higher molecular weight hydrocarbons as possible from the gas to produce a gas stream predominating in methane and a liquid stream containing significant amounts of ethane and heavier components. An effective number of gas/liquid separation means are located at strategic locations downstream of the cooling zones for the removal of liquids streams rich in C2+ components. The exact locations and number of gas/liquid separation means, preferably conventional gas/liquid separators, will be dependant on a number of operating parameters, such as the C2+ composition of the natural gas feed stream, the desired BTU content of the LNG product, the value of the C2+ components for other applications, and other factors routinely considered by those skilled in the art of LNG plant and gas plant operation. The C2+ hydrocarbon stream or streams may be demethanized via a single stage flash or a fractionation column. In the latter case, the resulting methane-rich stream can be directly returned at pressure to the liquefaction process. In the former case, this methane-rich stream can be repressurized and recycle or can be used as fuel gas. The C2+ hydrocarbon stream or streams or the demethanized C2+ hydrocarbon stream may be used as fuel or may be further processed, such as by fractionation in one or more fractionation zones to produce individual streams rich in specific chemical constituents (e.g., C2, C3, C4 and C5+).
The pressurized LNG-bearing stream is then further cooled in a third cycle or step referred to as the open methane cycle via contact in a main methane economizer with flash gases (i.e., flash gas streams) generated in this third cycle in a manner to be described later and via sequential expansion of the pressurized LNG-bearing stream to near atmospheric pressure. The flash gasses used as a refrigerant in the third refrigeration cycle are preferably comprised in major portion of methane, more preferably the flash gas refrigerant comprises at least 75 mole percent methane, still more preferably at least 90 mole percent methane, and most preferably the refrigerant consists essentially of methane. During expansion of the pressurized LNG-bearing stream to near atmospheric pressure, the pressurized LNG-bearing stream is cooled via at least one, preferably two to four, and more preferably three expansions where each expansion employs an expander as a pressure reduction means. Suitable expanders include, for example, either Joule-Thomson expansion valves or hydraulic expanders. The expansion is followed by a separation of the gas-liquid product with a separator. When a hydraulic expander is employed and properly operated, the greater efficiencies associated with the recovery of power, a greater reduction in stream temperature, and the production of less vapor during the flash expansion step will frequently more than off-set the higher capital and operating costs associated with the expander. In one embodiment, additional cooling of the pressurized LNG-bearing stream prior to flashing is made possible by first flashing a portion of this stream via one or more hydraulic expanders and then via indirect heat exchange means employing said flash gas stream to cool the remaining portion of the pressurized LNG-bearing stream prior to flashing. The warmed flash gas stream is then recycled via return to an appropriate location, based on temperature and pressure considerations, in the open methane cycle and will be recompressed.
The liquefaction process described herein may use one of several types of cooling which include but are not limited to (a) indirect heat exchange, (b) vaporization, and (c) expansion or pressure reduction. Indirect heat exchange, as used herein, refers to a process wherein the refrigerant cools the substance to be cooled without actual physical contact between the refrigerating agent and the substance to be cooled. Specific examples of indirect heat exchange means include heat exchange undergone in a shell-and-tube heat exchanger, a core-in-kettle heat exchanger, and a brazed aluminum plate-fin heat exchanger. The physical state of the refrigerant and substance to be cooled can vary depending on the demands of the system and the type of heat exchanger chosen. Thus, a shell-and-tube heat exchanger will typically be utilized where the refrigerating agent is in a liquid state and the substance to be cooled is in a liquid or gaseous state or when one of the substances undergoes a phase change and process conditions do not favor the use of a core-in-kettle heat exchanger. As an example, aluminum and aluminum alloys are preferred materials of construction for the core but such materials may not be suitable for use at the designated process conditions. A plate-fin heat exchanger will typically be utilized where the refrigerant is in a gaseous state and the substance to be cooled is in a liquid or gaseous state. Finally, the core-in-kettle heat exchanger will typically be utilized where the substance to be cooled is liquid or gas and the refrigerant undergoes a phase change from a liquid state to a gaseous state during the heat exchange.
Vaporization cooling refers to the cooling of a substance by the evaporation or vaporization of a portion of the substance with the system maintained at a constant pressure. Thus, during the vaporization, the portion of the substance which evaporates absorbs heat from the portion of the substance which remains in a liquid state and hence, cools the liquid portion. Finally, expansion or pressure reduction cooling refers to cooling which occurs when the pressure of a gas, liquid or a two-phase system is decreased by passing through a pressure reduction means. In one embodiment, this expansion means is a Joule-Thomson expansion valve. In another embodiment, the expansion means is either a hydraulic or gas expander. Because expanders recover work energy from the expansion process, lower process stream temperatures are possible upon expansion.
The flow schematic and apparatus set forth in
To facilitate an understanding of
Referring to
The propane gas from chiller 2 is returned to compressor 18 through conduit 306. This gas is fed to the high-stage inlet port of compressor 18. The remaining liquid propane is passed through conduit 308, the pressure further reduced by passage through a pressure reduction means, illustrated as expansion valve 14, whereupon an additional portion of the liquefied propane is flashed. The resulting two-phase stream is then fed to an intermediate stage propane chiller 22 through conduit 310, thereby providing a coolant for chiller 22. The cooled feed gas stream from chiller 2 flows via conduit 102 to a knock-out vessel 10 wherein gas and liquid phases are separated. The liquid phase, which is rich in C3+ components, is removed via conduit 103. The gaseous phase is removed via conduit 104 and then split into two separate streams which are conveyed via conduits 106 and 108. The stream in conduit 106 is fed to propane chiller 22. The stream in conduit 108 is employed as a stripping gas in refluxed heavies removal column 60 to aid in the removal of heavy hydrocarbon components from the processed natural gas stream, as discussed in more detail below with reference to
As illustrated in
As illustrated in
After cooling in indirect heat exchange means 44, the methane-rich stream is removed from high-stage ethylene chiller 42 via conduit 116. The stream in conduit 116 is then carried to a feed inlet of heavies removal column 60 wherein heavy hydrocarbon components are removed from the methane-rich stream, as described in further detail below with reference to
As previously noted, the gas in conduit 154 is fed to main methane economizer 74 wherein the stream is cooled via indirect heat exchange means 97. A portion of the cooled stream from heat exchange means 97 is then further cooled in indirect heat exchange means 98. The resulting cooled stream is removed from methane economizer 74 via conduit 158 and is thereafter combined with the heavies-depleted vapor stream exiting the top of heavies removal column 60, delivered via conduit 5, 119, and 120, and fed to a low-stage ethylene condenser 68. In low-stage ethylene condenser 68, this stream is cooled and condensed via indirect heat exchange means 70 with the liquid effluent from low-stage ethylene chiller 54 which is routed to low-stage ethylene condenser 68 via conduit 226. The condensed methane-rich product from low-stage condenser 68 is produced via conduit 122. The vapor from low-stage ethylene chiller 54, withdrawn via conduit 224, and low-stage ethylene condenser 68, withdrawn via conduit 228, are combined and routed, via conduit 230, to ethylene economizer 34 wherein the vapors function as a coolant via indirect heat exchange means 58. The stream is then routed via conduit 232 from ethylene economizer 34 to the low-stage inlet of ethylene compressor 48.
As noted in
The pressurized LNG-bearing stream, preferably a liquid stream in its entirety, in conduit 122 is preferably at a temperature in the range of from about −200 to about −50° F., more preferably in the range of from about −175 to about −100° F., most preferably in the range of from −150 to −125° F. The pressure of the stream in conduit 122 is preferably in the range of from about 500 to about 700 psia, most preferably in the range of from 550 to 725 psia. The stream in conduit 122 is directed to main methane economizer 74 wherein the stream is further cooled by indirect heat exchange means/heat exchanger pass 76 as hereinafter explained. It is preferred for main methane economizer 74 to include a plurality of heat exchanger passes which provide for the indirect exchange of heat between various predominantly methane streams in the economizer 74. Preferably, methane economizer 74 comprises one or more plate-fin heat exchangers. The cooled stream from heat exchanger pass 76 exits methane economizer 74 via conduit 124. It is preferred for the temperature of the stream in conduit 124 to be at least about 10° F. less than the temperature of the stream in conduit 122, more preferably at least about 25° F. less than the temperature of the stream in conduit 122. Most preferably, the temperature of the stream in conduit 124 is in the range of from about −200 to about −160° F. The pressure of the stream in conduit 124 is then reduced by a pressure reduction means, illustrated as expansion valve 78, which evaporates or flashes a portion of the gas stream thereby generating a two-phase stream. The two-phase stream from expansion valve 78 is then passed to high-stage methane flash drum 80 where it is separated into a flash gas stream discharged through conduit 126 and a liquid phase stream (i.e., pressurized LNG-bearing stream) discharged through conduit 130. The flash gas stream is then transferred to main methane economizer 74 via conduit 126 wherein the stream functions as a coolant in heat exchanger pass 82. The predominantly methane stream is warmed in heat exchanger pass 82, at least in part, by indirect heat exchange with the predominantly methane stream in heat exchanger pass 76. The warmed stream exits heat exchanger pass 82 and methane economizer 74 via conduit 128.
The liquid-phase stream exiting high-stage flash drum 80 via conduit 130 is passed through a second methane economizer 87 wherein the liquid is further cooled by downstream flash vapors via indirect heat exchange means 88. The cooled liquid exits second methane economizer 87 via conduit 132 and is expanded or flashed via pressure reduction means, illustrated as expansion valve 91, to further reduce the pressure and, at the same time, vaporize a second portion thereof. This two-phase stream is then passed to an intermediate-stage methane flash drum 92 where the stream is separated into a gas phase passing through conduit 136 and a liquid phase passing through conduit 134. The gas phase flows through conduit 136 to second methane economizer 87 wherein the vapor cools the liquid introduced to economizer 87 via conduit 130 via indirect heat exchanger means 89. Conduit 138 serves as a flow conduit between indirect heat exchange means 89 in second methane economizer 87 and heat exchanger pass 95 in main methane economizer 74. The warmed vapor stream from heat exchanger pass 95 exits main methane economizer 74 via conduit 140, is combined with the first nitrogen-reduced stream in conduit 406, and the combined stream is conducted to the intermediate-stage inlet of methane compressor 83.
The liquid phase exiting intermediate-stage flash drum 92 via conduit 134 is further reduced in pressure by passage through a pressure reduction means, illustrated as a expansion valve 93. Again, a third portion of the liquefied gas is evaporated or flashed. The two-phase stream from expansion valve 93 are passed to a final or low-stage flash drum 94. In flash drum 94, a vapor phase is separated and passed through conduit 144 to second methane economizer 87 wherein the vapor functions as a coolant via indirect heat exchange means 90, exits second methane economizer 87 via conduit 146, which is connected to the first methane economizer 74 wherein the vapor functions as a coolant via heat exchanger pass 96. The warmed vapor stream from heat exchanger pass 96 exits main methane economizer 74 via conduit 148, is combined with the second nitrogen-reduced stream in conduit 408, and the combined stream is conducted to the low-stage inlet of compressor 83.
The liquefied natural gas product from low-stage flash drum 94, which is at approximately atmospheric pressure, is passed through conduit 142 to a LNG storage tank 99. In accordance with conventional practice, the liquefied natural gas in storage tank 99 can be transported to a desired location (typically via an ocean-going LNG tanker). The LNG can then be vaporized at an onshore LNG terminal for transport in the gaseous state via conventional natural gas pipelines.
As shown in
Referring now to
Referring again to
As used herein, the term “vapor/liquid hydrocarbon separation point” or simply “hydrocarbon separation point” shall be used to identify a point of separation between the vapor and liquid phases of a hydrocarbon-containing stream based on the number of carbon atoms in the hydrocarbon molecules of the phases. When the hydrocarbon separation point is represented by the formula CX(X+1), then a predominant molar portion of CX− hydrocarbon molecules are present in the vapor phase while a predominant molar portion of C(X+1)+ hydrocarbon molecules are present in the liquid phase. For example, if the hydrocarbon separation point of a certain two-phase hydrocarbon-containing stream is C4/5, then a predominant portion (i.e., more than 50 mole percent) of the C5+ hydrocarbons are present in the liquid phase while a predominant molar portion of the C4− hydrocarbons are present in the vapor phase. In other words, if the hydrocarbon separation point is C4/5, the vapor phase would contain more than 50 mole percent of the C4 hydrocarbons present in the two-phase stream, more than 50 mole percent of the C3 hydrocarbons present in the two-phase stream, more than 50 mole percent of the C2 hydrocarbons present in the two-phase stream, and more than 50 mole percent of the C1 hydrocarbons present in the two-phase stream, while the liquid phase would contain more than 50 mole percent of the C5, C6, C7, C8 etc. hydrocarbons present in the two-phase stream.
During normal operation of operation, the stream entering feed inlet 69 of heavies removal column 60 preferably has a hydrocarbon separation point which can be represented as follows: CY/(Y+1), wherein Y is an integer in the range of from 2 to 10. More preferably, Y is in the range of from 4 to 8, still more preferably in the range of from 5 to 7, and most preferably Y is 6. Preferably, Y is at least 1 greater than X. Most preferably, Y is 2 greater than X. When the feed to inlet 69 of heavies removal column 60 has the above-described hydrocarbon separation point, optimal heavies removal can be achieved during normal operation.
During the normal operational mode, it is preferred for the temperature of the reflux stream entering heavies removal column 60 via reflux inlet 66 to be cooler than the temperature of the feed stream entering heavies removal column 60 via feed inlet 69, more preferably at least about 5° F. cooler, still more preferably at least about 15° F. cooler, and most preferably at least 35° F. cooler. Preferably, the temperature of the reflux stream entering reflux inlet 66 of heavies removal column 60 is in the range of from about −160 to about −100° F., more preferably in the range of from about −145 to about −120° F., most preferably in the range of from −138 to −125° F. It is preferred for the temperature of the stripping gas stream entering heavies removal column 60 via stripping gas inlet 73 to be warmer than the temperature of the feed stream entering heavies removal column 60 via feed inlet 69, more preferably at least about 5° F. warmer, still more preferably at least about 20° F. warmer, and most preferably at least 40° F. warmer. Preferably, the temperature of the stripping gas stream entering stripping gas inlet 66 of heavies removal column 60 is in the range of from about −75 to about −0° F., more preferably in the range of from about −60 to about −15° F., most preferably in the range of from −40 to −30° F.
Referring now to
Upper and lower heat exchangers 400,402 include respective shells 408,410 and cores 412,414. Heat exchangers 400,402 are operable to facilitate indirect heat transfer between a shell-side fluid received in the shells 408,410 and a core-side fluid received in the cores 412,414. Upper and lower heat exchanger 400,402 preferably have a substantially similar configuration. The specific configuration of upper and lower vertical core-in-kettle heat exchangers will be describe in detail below with reference to
As shown in
Referring again to
The gaseous/vaporized ethylene refrigerant in lower shell 410 exits lower heat exchanger 502 via lower shell outlet 438 and is conducted to economizer 404 via conduit 440. This gaseous ethylene refrigerant stream is then employed as a cooling fluid in a first heat exchange pass 442 of economizer 404. In first heat exchange pass 442, the refrigerant steam is warmed via indirect heat exchange with the refrigerant streams in second and third heat exchange passes 444,446. The resulting warmed refrigerant stream from first heat exchange pass 442 is conducted via conduit to 155 to the low-stage inlet of ethylene compressor 48 (
The gaseous/vaporized ethylene refrigerant in upper shell 408 exits upper heat exchanger 500 via an upper vapor shell outlet 448 and is conducted to economizer 404 via conduit 450. This gaseous ethylene refrigerant stream is then employed as a cooling fluid in a fourth heat exchange pass 452 of economizer 404. In fourth heat exchange pass 452, the refrigerant steam is warmed via indirect heat exchange with the refrigerant streams in second and third heat exchange passes 444,446. The resulting warmed refrigerant stream from fourth heat exchange pass 452 is conducted via conduit to 157 to the high-stage inlet of ethylene compressor 48 (
Referring now to
Core 604 of heat exchanger 600 is disposed in internal volume 614 of shell 602 and is partially submerged in the liquid shell-side fluid (A). Core 604 receives a core-side fluid (B) and facilitates indirect heat transfer between the core side fluid (B) and the shell-side fluid (A). A core-side fluid inlet 622 extends through sidewall 606 of shell 602 and is fluidly coupled to an inlet header 624 of core 604 to thereby provide for introduction of the core-side fluid feed stream (Bin) into core 604. A core-side fluid outlet 626 is fluidly coupled to an outlet header 628 of core 604 and extends through sidewall 606 of shell 602 to thereby provide for the discharge of the core-side fluid (Bout) from core 604.
As perhaps best illustrated in
As illustrated in
Referring to
In
In a preferred embodiment of the present invention, heat exchanger 600 is a vertical core-in-kettle heat exchanger and core 604 is a brazed-aluminum, plate-fin core. As used herein, the term “core-in-kettle heat exchanger” shall denote a heat exchanger operable to facilitate indirect heat transfer between a shell-side fluid and a core-side fluid, wherein the heat exchanger comprises a shell for receiving the shell-side fluid and a core disposed in the shell for receiving the core-side fluid, wherein the core defines a plurality of spaced-apart core-side fluid passageways and the shell-side fluid is free to circulate through discrete shell-side passageways defined between the core-side passageways. One distinguishing feature between a core-in-kettle heat exchanger and a shell-and-tube heat exchanger is that a shell-and-tube heat exchanger does not have discrete shell-side passageways between the tubes. The discrete shell-side passageways of a core-in-kettle heat exchanger allow it to take full advantage of the thermosiphon effect. As used herein, the term “vertical core-in-kettle heat exchanger” shall denote a core-in-kettle heat exchanger having a shell that comprises a substantially cylindrical sidewall extending along a central sidewall axis wherin the central sidewall axis is maintained in a substantially upright position.
In one embodiment of the present invention, the LNG production systems illustrated in
The preferred forms of the invention described above are to be used as illustration only, and should not be used in a limiting sense to interpret the scope of the present invention. Obvious modifications to the exemplary embodiments, set forth above, could be readily made by those skilled in the art without departing from the spirit of the present invention.
The inventors hereby state their intent to rely on the Doctrine of Equivalents to determine and assess the reasonably fair scope of the present invention as pertains to any apparatus not materially departing from but outside the literal scope of the invention as set forth in the following claims.
