Abstract:
A single LNG facility, and operating method therefor, capable of efficiently producing LNG products that meet the varying specifications of different LNG markets.

Description:
RELATED APPLICATIONS 
     This application claims the priority benefit under 35 U.S. C. Section 119(e) of U.S. Provisional Patent Application Ser. No. 60/698,402, filed Jul. 12, 2005, the entire disclosure of which is incorporated herein by reference. 
    
    
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     This invention relates to a method and apparatus for liquefying natural gas. In another aspect, the invention concerns an improved liquefied natural gas (LNG) facility capable of efficiently supplying LNG products meeting significantly different product specifications. 
     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 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 the past, LNG facilities have been designed and operated to provide LNG to a single market in a specific region of the world. As global demand for LNG increases, it would be advantageous for a single LNG facility to be able to supply LNG to multiple markets in different regions of the world. However, natural gas specifications vary greatly throughout the world. Typically, these natural gas specifications include criteria such as heating value, Wobbe index, methane content, ethane content, C 3+  content, and inerts content. 
     Existing LNG facilities are optimized to produce LNG meeting a certain set of specifications for a single market. Thus, changing the operating parameters of an LNG facility in an effort to make LNG that would meet the non-design specifications of a different market creates significant operating inefficiencies in the facility. These operating inefficiencies associated with producing LNG for non-design specifications generally makes it economically unfeasible to serve more than one market with a single LNG facility. 
     OBJECTS AND SUMMARY OF THE INVENTION 
     It is, therefore, an object of the present invention to provide a single LNG facility capable of efficiently producing LNG that can meet significantly different specifications of two or more markets. 
     A further object of the invention is to provide a method of operating the LNG facility for producing multi-specification LNG. 
     It should be understood that the above-listed objects are only exemplary, and not all the objects listed above need be accomplished by the invention described and claimed herein. 
     Accordingly, one aspect of the present invention concerns a method of supplying LNG of varying high heating value (HHV) via a single LNG facility. The method includes the following steps: (a) using the LNG facility to produce initial LNG having an HHV less than about 1,150 BTU/SCF; (b) cooling a spiking fluid having an HHV greater than about 1,500 BTU/SCF to a temperature less than about −100° C., wherein at least a portion of the cooling is provided by the LNG facility; and (c) combining at least a portion of the initial LNG and at least a portion of the cooled spiking fluid to thereby provide spiked LNG having a higher HHV than the initial LNG. 
     Another aspect of the present invention concerns a method including the following steps: (a) removing an initial LNG stream having a higher heating value (HHV) less than 1,150 BTU/SCF from a first LNG tank; (b) combining a spiking fluid having an HHV greater than 1,500 BTU/SCF with the removed initial LNG stream to thereby form a spiked LNG stream; and (c) introducing at least a portion of the spiked LNG stream into a second LNG tank. 
     A further aspect of the present invention concerns a facility for producing LNG from natural gas. The facility includes the following components: (a) a first refrigeration cycle employing a first refrigerant to cool the natural gas via indirect heat exchange; (b) a first distillation column for receiving at least a portion of the natural gas cooled by the first refrigeration cycle and separating the cooled natural gas into a first relatively more volatile fraction and a first relatively less volatile fraction; (c) a second refrigeration cycle employing a second refrigerant to further cool at least a portion of the first relatively more volatile fraction to thereby produce initial LNG; (d) a first tank for receiving and storing at least a portion of the initial LNG; (e) a second tank for receiving and storing a spiking fluid formed at least partly from the first relatively less volatile fraction; and (f) a mixing chamber fluidly coupled to and disposed outside of the first and second tanks, wherein the mixing chamber permits mixing of fluids from the first and second tanks. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWING FIGURES 
         FIG. 1  is a simplified flow diagram of a cascaded refrigeration process for producing LNG to meet various specifications of different markets, particularly illustrating a system that stores a high-BTU spiking fluid at relative low temperature and then cools the spiking fluid to near-LNG temperature as it is combined with LNG. 
         FIG. 2  is a simplified flow diagram of an alternative embodiment of a cascade refrigeration process for producing LNG to meet various specifications of different markets, particularly illustrating a system where the spiking fluid is cooled to near-LNG temperature prior to storing. 
         FIG. 3  is a simplified flow diagram of an alternative embodiment of a cascade refrigeration process for producing LNG to meet various market specifications, particularly illustrating a system where additional heat exchange passes are added to components of the main refrigeration cycles to provide cooling of the spiking fluid. 
     
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT 
     Although the present invention is described herein primarily with reference to a cascade refrigeration process, it should be understood that, in light of the present disclosure, the invention could readily be adapted for use in other refrigeration processes (e.g., a mixed refrigerant process). A cascaded refrigeration process uses one or more refrigerants to transfer heat energy from a natural gas stream to the refrigerants, and ultimately transferring the 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 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 employed in the open cycle is less than the boiling point of the refrigerant employed in the closed cycle and a portion of the cooling duty to condense the compressed open-cycle refrigerant is provided by one or more of the closed cycles. In one embodiment of the present invention, a predominately methane stream is employed as the refrigerant in the open cycle. This predominantly methane stream is preferably derived from the processed natural gas feed stream and can include 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 is comprised of 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 comprised of 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 refrigeration cycle, a multistage ethane or ethylene refrigeration cycle, and an open-end methane refrigeration 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 liquified natural gas (LNG) facility along the main flow path of natural gas through the facility. 
     Various pretreatment steps can be provided to remove certain undesirable components, such as acid gases, mercaptans, 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 mercaptans are routinely removed via a chemical reaction 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. (10-65° C.). 
     As previously noted, the natural gas feed stream is cooled in a plurality of multistage refrigeration cycles (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 a 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. 
     The pressurized LNG-bearing stream is then further cooled in a third refrigeration cycle referred to as the open methane cycle via contact in a main methane economizer (heat exchanger) with flash gases (i.e., flash gas streams) generated in this third cycle via sequential expansion of the pressurized LNG-bearing stream to near atmospheric pressure. The flash gases 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. 
     Generally, the natural gas feed stream fed to the LNG facility will contain such quantities of C 2+  components so as to result in the formation of a C 2+  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 C 2  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 C 2+  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 C 2+  composition of the natural gas feed stream, the desired BTU content of the LNG product, the value of the C 2+  components for other applications, and other factors routinely considered by those skilled in the art of LNG plant and gas plant operation. The C 2+  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 C 2+  hydrocarbon stream or streams or the demethanized C 2+  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., C 2 , C 3 , C 4 , and C 5+ ). 
     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 schematics set forth in  FIGS. 1-3  represent preferred embodiments of an inventive LNG facility capable of supplying LNG that meets two or more significantly different specifications. Those skilled in the art will recognize that  FIGS. 1-3  are schematics only and, therefore, many items of equipment that would be needed in a commercial plant for successful operation have been omitted for the sake of clarity. Such items might include, for example, compressor controls, flow and level measurements and corresponding controllers, temperature and pressure controls, pumps, motors, filters, additional heat exchangers, and valves, etc. These items would be provided in accordance with standard engineering practice. 
     To facilitate an understanding of  FIGS. 1-3 , the following numbering nomenclature was employed. Items numbered 1 through 99 are process vessels and equipment which are associated with the liquefaction process. Items numbered 100 through 199 correspond to flow lines or conduits which contain predominantly methane streams. Items numbered 200 through 299 correspond to flow lines or conduits which contain predominantly ethylene streams. Items numbered 300 through 399 correspond to flow lines or conduits which contain predominantly propane streams. Items numbered 400 though 499 correspond to flow lines or conduits whose contents may vary significantly depending upon the mode of operation of the LNG facility. 
     Referring to  FIG. 1 , gaseous propane is compressed in a multistage (preferably three-stage) compressor  18  driven by a gas turbine driver (not illustrated). The three stages of compression preferably exist in a single unit although each stage of compression may be a separate unit and the units mechanically coupled to be driven by a single driver or combination of drivers. Upon compression, the compressed propane is passed through conduit  300  to a cooler  20  where it is cooled and liquefied. A representative pressure and temperature of the liquefied propane refrigerant prior to flashing is about 100° F. (38° C.) and about 190 psia. The stream from cooler  20  is passed through conduit  302  to a pressure reduction means, illustrated as expansion valve  12 , wherein the pressure of the liquefied propane is reduced, thereby evaporating or flashing a portion thereof. The resulting two-phase product then flows through conduit  304  into a high-stage propane chiller  2  wherein gaseous methane refrigerant introduced via conduit  152 , natural gas feed introduced via conduit  100 , and gaseous ethylene refrigerant introduced via conduit  202  are respectively cooled via indirect heat exchange means  4 ,  6 , and  8 , thereby producing cooled gas streams respectively produced via conduits  154 ,  102 , and  204 . 
     The vaporized propane gas from chiller  2  is returned to the high-stage inlet port of compressor  18  through conduit  306 . 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 separation equipment  10  wherein gas and liquid phases are separated. The liquid phase, which can be rich in C 3+  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  becomes the stripping gas to first distillation column  60 , discussed in more detail below. Ethylene refrigerant from chiller  2  is introduced to chiller  22  via conduit  204 . In chiller  22 , the feed gas stream, also referred to herein as a methane-rich stream, and the ethylene refrigerant streams are respectively cooled via indirect heat transfer means  24  and  26 , thereby producing cooled methane-rich and ethylene refrigerant streams via conduits  110  and  206 . The vaporized portion of the propane refrigerant in chiller  22  is separated and passed through conduit  311  to the intermediate-stage inlet of compressor  18 . Liquid propane refrigerant from chiller  22  is removed via conduit  314 , flashed across a pressure reduction means, illustrated as expansion valve  16 , and then fed to a low-stage propane chiller/condenser  28  via conduit  316 . 
     As illustrated in  FIG. 1 , the methane-rich stream flows from intermediate-stage propane chiller  22  to the low-stage propane chiller  28  via conduit  110 . In chiller  28 , the methane-rich stream is cooled via indirect heat exchange means  30 . In a like manner, the ethylene refrigerant stream flows from the intermediate-stage propane chiller  22  to low-stage propane chiller  28  via conduit  206 . In the latter, the ethylene refrigerant is totally condensed or condensed in nearly its entirety via indirect heat exchange means  32 . The vaporized propane is removed from low-stage propane chiller  28  and returned to the low-stage inlet of compressor  18  via conduit  320 . 
     As illustrated in  FIG. 1 , the methane-rich stream exiting low-stage propane chiller  28  is introduced into high-stage ethylene chiller  42  via conduit  112 . Ethylene refrigerant exits low-stage propane chiller  28  via conduit  208  and is preferably fed to a separation vessel  37  wherein light components are removed via conduit  209  and condensed ethylene is removed via conduit  210 . The ethylene refrigerant at this location in the process is generally at a temperature of about −24° F. (−31° C.) and a pressure of about 285 psia. The ethylene refrigerant then flows to an ethylene economizer  34  wherein it is cooled via indirect heat exchange means  38 , removed via conduit  211 , and passed to a pressure reduction means, illustrated as an expansion valve  40 , whereupon the refrigerant is flashed to a preselected temperature and pressure and fed to high-stage ethylene chiller  42  via conduit  212 . Vaporized ethylene is removed from chiller  42  via conduit  214  and routed to ethylene economizer  34  wherein the vapor functions as a coolant via indirect heat exchange means  46 . The ethylene vapor is then removed from ethylene economizer  34  via conduit  216  and fed to the high-stage inlet of ethylene compressor  48 . The ethylene refrigerant which is not vaporized in high-stage ethylene chiller  42  is removed via conduit  218  and returned to ethylene economizer  34  for further cooling via indirect heat exchange means  50 , removed from ethylene economizer via conduit  220 , and flashed in a pressure reduction means, illustrated as expansion valve  52 , whereupon the resulting two-phase product is introduced into a low-stage ethylene chiller  54  via conduit  222 . 
     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 a first fractionation column  60 . In column  60 , the feed stream introduced is separated into a first relatively more volatile vapor stream exiting column  60  via conduit  119  and a first relatively less volatile liquid stream exiting column  60  via conduit  114 . Typically, the overhead vapor stream in conduit  119  contains primarily methane (preferably &gt;85 mole % methane), while the bottoms liquid stream in conduit  114  contains primarily C 2+  hydrocarbons. The separation/distillation in first fractionation column  60  is facilitated by the introduction of a stripping gas stream, via conduit  108 , and a reflux stream, via conduit  159 , into column  60 . 
     Conduit  114  carries the bottoms liquid stream from first fractionation column  60  to a second fractionation column  67 . In column  67 , the stream introduced via conduit  114  is separated into a second relatively more volatile vapor stream exiting column  67  via conduit  121  and a second relatively less volatile liquid stream exiting the bottom of column  67 . Typically, the overhead vapor stream in conduit  119  contains primarily methane and/or ethane, while the bottoms liquid stream contains primarily C 2+  or C 3+  hydrocarbons. In one embodiment of the present invention, the overhead vapor stream in conduit  121  is subsequently combined with a second stream in conduit  128 , and the combined stream fed to the high-stage inlet port of the methane compressor  83 . 
     The bottoms liquid stream from second fractionation column  67  is introduced into a third fractionation column  21 . In column  21 , this stream is separated into a third relatively more volatile vapor stream exiting column  21  via conduit  401  and a third relatively less volatile liquid stream exiting the bottom of column  21 . Typically, the overhead vapor stream in conduit  401  contains primarily ethane and/or propane, while the bottoms liquid stream contains primarily C 3+  or C 4+  hydrocarbons. 
     The bottoms liquid stream from third fractionation column  21  is then introduced into a fourth fractionation column  23 . In column  23 , this stream is separated into a fourth relatively more volatile vapor stream exiting column  23  via conduit  403  and a fourth relatively less volatile liquid stream exiting the bottom of column  23  via conduit  405 . Typically, the overhead vapor stream in conduit  403  contains primarily propane and/or butane, while the bottoms liquid stream contains primarily C 4+  or C 5+  hydrocarbons. In a preferred embodiment of the present invention, the overhead streams in conduits  401  and  403  are combined in conduit  407  to form a spiking fluid which can be stored in a spiking fluid storage tank  25 . 
     It should be noted that while four fractionation columns  60 , 67 , 21 , 23  are illustrated in  FIG. 1  and described above, various embodiments of the present invention may employ more fractionation columns or less fractionation columns. Further, the manner in which the fractionation columns  60 , 67 , 21 , 23  are operated may be varied to significantly alter the compositions of the streams exiting the columns. For example, the pressure and/or temperature of the streams flowing between fractionation columns  60 , 67 , 21 , 23  can be adjusted to facilitate the desired separation. In addition, it is possible for the spiking fluid stored in storage tank  25  to be formed from more or less than the two streams ( 401  and  403 ) illustrated in  FIG. 1 , so long as the spiking fluid has the properties/composition that will be described in detail below (See, Table 1). 
     The gas exiting high-stage propane chiller  2  via conduit  154  is fed to main methane economizer  74  wherein the stream is cooled via indirect heat exchange means  97 . A first portion of the stream cooled in heat exchange mean  97  is removed from methane economizer  74  via conduit  155 , introduced into high-stage ethylene chiller  44  for cooling via indirect heat exchange means  43 , removed from chiller  44  via conduit  157 , introduced into low-stage ethylene chiller  54  where it is condensed in indirect heat exchange means  56 , and routed to first distillation column  60  via conduit  159  for use as a liquid reflux stream. A second portion of the cooled stream from heat exchange means  97  is then further cooled in indirect heat exchange means  98 . The resulting further cooled stream is removed from methane economizer  74  via conduit  158  and is thereafter combined with the methane-rich overhead vapor stream exiting the top of first fractionation column  60  via conduit  119 . The combined stream is fed to an ethylene condenser  68  via conduit  120 . In ethylene condenser  68 , this methane-rich 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 ethylene condenser  68  via conduit  226 . The condensed methane-rich product from low-stage condenser  68  is produced via conduit  122 . The vaporized ethylene from low-stage ethylene chiller  54 , withdrawn via conduit  224 , and 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 illustrated in  FIG. 1 , the compressor effluent from vapor introduced via the low-stage side of ethylene compressor  48  is removed via conduit  234 , cooled via inter-stage cooler  71 , and returned to compressor  48  via conduit  236  for injection with the high-stage stream present in conduit  216 . Preferably, the two-stages are a single module although they may each be a separate module and the modules mechanically coupled to a common driver. The compressed ethylene product from compressor  48  is routed to a downstream cooler  72  via conduit  200 . The product from cooler  72  flows via conduit  202  and is introduced, as previously discussed, to high-stage propane chiller  2 . 
     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. (−130° C. to −45° C.), more preferably in the range of from about −175 to about −100° F. (−115° C. to −73° C.), most preferably in the range of from −150 to −125° F. (−100° C. to −85° C.). 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 . 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  and 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  is 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  and is conducted to the low-stage inlet of compressor  83 . The liquefied natural gas (LNG) product from low-stage flash drum  94 , which is at approximately atmospheric pressure, is pumped via cryogenic pump  47  through conduit  142  to a first LNG storage tank  99 . 
     As shown in  FIG. 1 , the high, intermediate, and low stages of compressor  83  are preferably combined as single unit. However, each stage may exist as a separate unit where the units are mechanically coupled together to be driven by a single driver. The compressed gas from the low-stage section passes through an inter-stage cooler  85  and is combined with the intermediate pressure gas in conduit  140  prior to the second-stage of compression. The compressed gas from the intermediate stage of compressor  83  is passed through an inter-stage cooler  84  and is combined with the high pressure gas provided via conduits  121  and  128  prior to the third-stage of compression. The compressed gas (i.e., compressed open methane cycle gas stream) is discharged from high stage methane compressor through conduit  150 , is cooled in cooler  86 , and is routed to the high pressure propane chiller  2  via conduit  152  as previously discussed. The stream is cooled in chiller  2  via indirect heat exchange means  4  and flows to main methane economizer  74  via conduit  154 . The compressed open methane cycle gas stream from chiller  2  which enters the main methane economizer  74  undergoes cooling via flow through indirect heat exchange means  97 . A first portion of the resulting cooled stream is withdrawn from methane economizer  74  via conduit  155 , while a second portion of the cooled stream is further cooled in heat exchange means  98 , as described above. 
     As discussed above, a spiking fluid can be generated by one or more fractionation columns (e.g., fractionation columns  60 , 67 , 21 , 23 ) of the LNG facility. This spiking fluid is preferably comprised of at least 50 mole percent C 2 -C 5  hydrocarbons and has a higher heating value (HHV) of at least 1,500 BTU/SCF (British Thermal Units per Standard Cubic Foot). Table 1, below, provides preferred values for various properties and components of the initial spiking fluid that can be stored in storage tank  25  illustrated in  FIG. 1 . 
     
       
         
               
             
               
               
               
               
             
               
               
               
               
             
           
               
                 TABLE 1 
               
             
             
               
                   
               
               
                 Initial Spiking Fluid 
               
             
          
           
               
                   
                 Preferred 
                 More Preferred 
                 Most Preferred 
               
               
                 Property/Component 
                 Value 
                 Value 
                 Value 
               
               
                   
               
             
          
           
               
                 High Heating Value 
                 &gt;1,500 
                 1,750-8,000 
                 2,000-5,000 
               
               
                 (BTU/SCF) 
               
               
                 Methane (C 1 ) (mole %) 
                 &lt;50 
                 &lt;25 
                 &lt;10 
               
               
                 C 2 -C 5  (mole %) 
                 &gt;50 
                 &gt;80 
                 &gt;95 
               
               
                 C 2 -C 4  (mole %) 
                 &gt;50 
                 &gt;75 
                 &gt;90 
               
               
                 C 2 -C 3  (mole %) 
                 &gt;50 
                 &gt;70 
                 &gt;85 
               
               
                 Temperature (° C.) 
                 &gt;−120 
                 −110 to 20  
                 −80 to −20 
               
               
                 Pressure (bar) 
                 0.5-5 
                 0.9 to 1.5 
                 ~Atmospheric 
               
               
                   
               
             
          
         
       
     
     In accordance with one embodiment of the present invention at least a portion of the spiking fluid generated in the LNG facility is combined with at least a portion of the initial LNG generated in the facility to thereby form a spiked LNG having a significantly different composition and/or significantly different properties than the initial LNG in tank  99 . 
     The initial LNG produced from the LNG facility preferably has a relatively low heating value so that subsequent combination with the spiking fluid provides spiked LNG having an increased heating value verses the initial LNG. Table 2, below, provides preferred values for various properties and components of the initial LNG that can be stored in LNG storage tank  99  illustrated in  FIG. 1 . 
     
       
         
               
             
               
               
               
               
             
               
               
               
               
             
               
               
               
               
             
           
               
                 TABLE 2 
               
             
             
               
                   
               
               
                 Initial LNG 
               
             
          
           
               
                   
                 Preferred 
                 More Preferred 
                 Most Preferred 
               
               
                 Property/Component 
                 Value 
                 Value 
                 Value 
               
               
                   
               
             
          
           
               
                 High Heating Valve 
                 &lt;1,150 
                   850-1,100 
                   925-1,025 
               
               
                 (BTU/SCF) 
               
               
                 Methane (C 1 ) (mole %) 
                 &gt;80 
                 85-98 
                 87.5-95   
               
               
                 Ethane (C 2 ) (mole %) 
                 &lt;10 
                 &lt;8 
                 &lt;6 
               
               
                 C 3+  (mole %) 
                 &lt;6 
                 &lt;4 
                 &lt;3 
               
               
                 Butane (C 4 ) (mole %) 
                 &lt;4 
                 &lt;2 
                 &lt;1 
               
               
                 Pentane (C 5 ) (mole %) 
                 &lt;2 
                 &lt;1 
                 &lt;0.5 
               
               
                 Inerts (mole %) 
                 &lt;8 
                 &lt;6 
                 &lt;4 
               
               
                 Temperature (° C.) 
                 &lt;−170 
                 −140 to −165 
                 −155 to −162 
               
             
          
           
               
                 Pressure (bar) 
                 0.5-5 
                 0.9 to 1.5 
                 ~Atmospheric 
               
               
                   
               
             
          
         
       
     
     Referring to  FIG. 1 , the initial LNG in LNG storage tank  99  can be directly loaded onto a ocean-going vessel (not shown) via cryogenic pump  49 , conduit  143 , and conduit  145 . Initial LNG from storage tank  99  can be transported on the ocean-going vessel to a distant market that has relatively low natural gas heating value specifications. Thus, when operated in a first mode, the LNG facility is capable of supplying LNG meeting relatively low heating value specifications. 
     If it is desired for the LNG facility to supply LNG to a market requiring a higher heating value product, the LNG facility can be operated in a second mode that includes pumping LNG from storage tank  99  through conduit  147  to a mixing chamber  43 . In mixing chamber  43  the initial LNG is mixed with spiking fluid from tank  25  to produce spiked LNG that is then transported via conduit  149  to a spiked LNG tank  45 . In one embodiment of the present invention, spiked LNG tank is a tank located on an ocean-going vessel. If spiked LNG tank  45  is a tank of an ocean-going vessel, then no additional land-based LNG storage tank is needed for the high heating value spiked LNG product. In another embodiment, spiked LNG tank  45  is a land-base storage tank. When spiked LNG tank is a land-based tank, both initial and spiked LNG can be stored on-site, and loaded onto one or more ocean-going vessels as required. 
     In order for the LNG facility depicted in  FIG. 1  to make spiked LNG, the spiking fluid is pumped with pump  51  from spiking fluid storage tank  25  to spiking fluid heat exchanger  27  via conduit  409 . Cooling of the spiking fluid is provided by indirect heat transfer between the spiking fluid in heat exchange means  29  and the refrigerant(s)/cooling agent(s) in heat exchange means  31 ,  33 , and  35 . In heat exchange means  29  of heat exchanger  27 , the spiking fluid is preferably cooled by at least about 20° C., more preferably about 25 to about 200° C., and most preferably 50 to 100° C. 
     The refrigerant(s) used to cool the spiking fluid in heat exchanger  27  preferably originates from elsewhere in the LNG facility. More preferably the refrigerant(s) employed in heat exchanger  27  is formed primarily of propane, ethane, ethylene, and/or methane. Most preferably, the refrigerant employed in heat exchange means  31  is the predominately ethane and/or ethylene refrigerant of the LNG facility&#39;s ethylene refrigeration cycle. In one embodiment, a portion of the ethylene refrigerant in conduit  220  is split off, carried by conduit  240  to heat exchanger  27 , passed through heat exchange means  31 , and returned via conduit  242  to conduit  232  of the main ethylene refrigeration circuit. Most preferably, the refrigerants employed in heat exchange means  33  and  35  are predominately methane streams originating from the initial LNG produced by the LNG facility. In one embodiment, a portion of the initial LNG pumped through conduit  142  can be split off and carried through conduit  105 . The LNG stream in conduit is split into two streams which are carried via conduits  107 , 111  to heat exchange means  35 , 33 , respectively. The warmed streams from heat exchange means  33 , 35  are then transported via conduits  113 , 115  and combined with the flash gas streams in conduits  136 , 144 , respectively. 
     The cooled spiking fluid exiting heat exchanger  27  via conduit  411  preferably has a temperature of less than about −100° C., more preferably less than about −125° C., and most preferably less than about −140° C. The cooled spiking fluid in conduit  411  and the initial LNG in conduit  147  are mixed/combined in mixing chamber  43 . Mixing chamber  43  can take a variety of forms. It is preferred for mixing chamber to be located outside of tanks  25 ,  99 , and  45 . More preferably, mixing chamber  43  is simply defined by a conduit carrying the initial LNG from initial LNG tank  99  to spiked LNG tank  45 , said conduit having an opening therein for introduction of the cooled spiking fluid. The ratio of the amount of spiking fluid to the amount of initial LNG combined in mixing chamber  43  can be adjusted to provide a spiked LNG product meeting higher heating value (HHV) specifications. Further, addition of the spiking fluid to the initial LNG can be carried out in an intermittent or pulsed manner, so long as the time-averaged ratio of initial LNG to spiking fluid provides the desired spiked LNG product. The term “time-averaged” is used herein to denote the amount of time required to substantially fill spiked LNG tank  45 . Preferably, the time-averaged weight ratio of initial LNG to spiking fluid introduced into mixing chamber is in the range of from about 2:1 to about 100:1, more preferably in the range of from about 3:1 to about 75:1, and most preferably in the range of from 5:1 to 50:1. Preferably, the time-averaged HHV of the spiked LNG is at least about 2 percent greater than the HHV of the initial LNG, more preferably at least about 5 percent greater, and most preferably at least 8 percent greater. In addition, it is preferred for the time-averaged HHV of the spiked LNG to be at least about 10 BTU/SCF greater than the HHV of the initial LNG, more preferably in the range of from about 20 to about 400 BTU/SCF greater, and most preferably in the range of from 40 to 200 BTU/SCF greater. 
       FIG. 2  illustrates an alternative embodiment of the present invention. The embodiment illustrated in  FIG. 2  is similar to the embodiment illustrated in  FIG. 1 ; however, in the embodiment of  FIG. 2 , spiking fluid storage tank  25  is located downstream of spiking fluid heat exchanger  27  so that the spiking fluid is cooled prior to storage. The temperature of the cooled spiking fluid stored in storage tank  25  is preferably the same as the temperatures of the “cooled spiking fluid” described above with reference to  FIG. 1 . In the embodiment illustrated in  FIG. 2 , the cooled spiking fluid is stored in tank  25  at a temperature close to the temperature of the initial LNG in initial LNG tank  99 . Preferably, the cooled spiking fluid in spiking fluid storage tank  25  has a temperature within about 50° C. of the temperature of the initial LNG in initial LNG storage tank  99 , more preferably within about 25° C., and most preferably within 10° C. When it is desired to provide spiked LNG to spiked LNG tank  45 , the spiking fluid pump  51  pumps the cooled spiking fluid to the mixing chamber  43  via conduit  409  and initial LNG pump  49  pumps the initial LNG to mixing chamber  43  via conduit  147 . The spiked LNG then flows from mixing chamber  43  to spiked LNG tank  45  via conduit  149 . As mentioned above, spiked LNG tank  45  can either be a permanent land-based storage tank or a storage tank located on an ocean-going vessel. Most preferably, spiked LNG tank  45  is located on an ocean-going vessel. 
       FIG. 3  illustrates an alternative embodiment of the present invention. The embodiment illustrated in  FIG. 3  is similar to the embodiment illustrated in  FIG. 2 , in that the spiking fluid is cooled to near-LNG temperature prior to storage in spiking fluid storage tank  25 . However, in the embodiment of  FIG. 3 , the manner in which the initial spiking fluid is cooled is significantly different than the manner shown in  FIGS. 1 and 2 .  FIG. 3  illustrates an embodiment where cooling of the initial spiking fluid is carried out in additional cores added to existing vessels of the LNG facility. In particular, the initial spiking fluid in conduit  407  is cooled in additional heat exchange cores  47   a,b,c  located in propane chillers  2 , 22 , 28 , respectively. After cooling via indirect heat exchange with the refrigerant in propane chillers  2 , 22 , 28 , the partially-cooled spiking fluid in conduit  415  is cooled in additional heat exchange cores  49   a,b,c  located in ethylene chillers  42 , 54 , 68 , respectively. After cooling via indirect heat exchange with the refrigerant in ethylene chillers  42 , 54 , 68 , the further-cooled spiking fluid in conduit  417  is cooled in heat exchange cores  51   a,b,c  located in methane flash drums  80 , 92 , 94 , respectively. The resulting cooled spiking fluid in conduit  419  preferably has the same temperature as the “cooled spiking fluid” described above with reference to  FIGS. 1 and 2 . 
     In the embodiment illustrated in  FIG. 3 , spiking fluid heat exchanger  27  is optional. If the temperature of the cooled spiking fluid stored in spiking fluid storage tank  25  is very close the temperature of the initial LNG in tank  99 , then spiking fluid heat exchanger  27  is not needed. However, if the temperature of the cooled spiking fluid stored in spiking fluid storage tank  25  is substantially greater than the temperature of the initial LNG in tank  99 , then spiking fluid heat exchanger  27  is needed. When spiking fluid heat exchanger  27  is not utilized, spiked LNG is produced by pumping the cooled spiking fluid from spiking fluid storage tank  25  directly to the mixing chamber  43  via conduit  409 . In mixing chamber  43 , the cooled spiking fluid is mixed with the initial LNG pumped from LNG storage tank  99  via conduit  147  to thereby produce spiked LNG. When spiking fluid heat exchanger  27  is utilized, the cooled spiking fluid exiting spiking fluid storage tank  25  via conduit  409  is further cooled in heat exchange means  29  via indirect heat exchange with LNG in heat exchange means  33 , 35 . The further-cooled spiking fluid is then directed to mixing chamber  43  for combining with initial LNG from initial LNG storage tank  99 . Spiked LNG exits mixing chamber  43 , and is transported to spiked LNG tank  45  via conduit  149 . As mentioned above, the spiked LNG tank  45  can either be a permanent land-based storage tank or a storage tank located on an ocean-going vessel. Most preferably, spiked LNG tank  45  is located on an ocean-going vessel. 
     In an alternative embodiment similar to the embodiment illustrated in  FIG. 3 , flash drums  92  and/or  94  can be equipped with one or more additional heat exchange passes that receive the spiking fluid from conduit  409  and return the spiking fluid to conduit  411 . In such an embodiment, spiking fluid heat exchanger  27  is eliminated, and cooling of the spiking fluid from spiking fluid storage tank  25  is provided by indirect heat exchange with the flashed fluids (i.e., predominately methane flash vapors and/or LNG) in flash drums  92  and/or  94 . When spiking fluid heat exchanger  27  is eliminated, heat exchange means  33 , 35  and conduits  105 , 107 , 111 , 113 , 115  are also eliminated. 
     One key advantage of the LNG facilities illustrated in  FIGS. 1-3  are their ability to be readily switched back and forth between a first mode for producing low HHV LNG and a second mode for producing high HHV (spiked) LNG. The LNG facilities of  FIGS. 1-3  thus provide an efficient and economical system for supplying LNG which can meet significantly varying product specifications. 
     In one embodiment of the present invention, the LNG production systems illustrated in  FIGS. 1-3  are simulated on a computer using conventional process simulation software. Examples of suitable simulation software include HYSYS™ from Hyprotech, Aspen Plus® from Aspen Technology, Inc., and PRO/II® from Simulation Sciences Inc. 
     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.