Abstract:
The invention is an absorption process for recovering C 2+  components from a pressurized liquid mixture comprising C 1  and C 2+ . The pressurized liquid mixture is at least partially vaporized by heating the liquid mixture in a heat transfer means. The heat transfer means provides refrigeration to an absorption medium that is used in treating the vaporized mixture in an absorption zone. The vaporized mixture is passed to an absorption zone that produces a first stream enriched in C 1  and a second stream enriched in C 2+  components. The pressurized liquid mixture is preferably pressurized liquid natural gas (PLNG) having an initial pressure above about 1,724 kPa (250 psia) and an initial temperature above −112° C. (−170° F.). Before being vaporized, the pressurized liquid mixture is preferably boosted in pressure to approximately the desired operating pressure of the absorption zone.

Description:
RELATED U.S. APPLICATION DATA 
     This application claims the benefit of U.S. Provisional Application No. 60/302,123, filed Jun. 29, 2001. 
    
    
     FIELD OF THE INVENTION 
     This invention relates to a process for recovering ethane and heavier hydrocarbons from pressurized liquefied gas mixture comprising methane and heavier hydrocarbons. 
     BACKGROUND OF THE INVENTION 
     Because of its clean burning qualities and convenience, natural gas has become widely used in recent years. Many sources of natural gas are located in remote areas, great distances from any commercial markets for the gas. Sometimes a pipeline is available for transporting produced natural gas to a commercial market. When pipeline transportation is not feasible, produced natural gas is often processed into liquefied natural gas (which is called “LNG”) for transport to market. 
     The source gas for making LNG is typically obtained from a crude oil well (associated gas) or from a gas well (non-associated gas). Associated gas occurs either as free gas or as gas in solution in crude oil. Although the composition of natural gas varies widely from field to field, the typical gas contains methane (C 1 ) as a major component. The natural gas stream may also typically contain ethane (C 2 ), higher hydrocarbons (C 3+ ), and minor amounts of contaminants such as carbon dioxide (CO 2 ), hydrogen sulfide, nitrogen, dirt, iron sulfide, wax, and crude oil. The solubilities of the contaminants vary with temperature, pressure, and composition. At cryogenic temperatures, CO 2 , water, other contaminants, and certain heavy molecular weight hydrocarbons can form solids, which can potentially plug flow passages in cryogenic equipment. These potential difficulties can be avoided by removing such contaminants and heavy hydrocarbons. 
     Commonly used processes for transporting remote gas separate the feed natural gas into its components and then liquefy only certain of these components by cooling them under pressure to produce liquefied natural gas (“LNG”) and natural gas liquid (“NGL”). Both processes liquefy only a portion of a natural gas feed stream and many valuable remaining components of the gas have to be handled separately at significant expense or have to be otherwise disposed of at the remote area. 
     In a typical LNG process, substantially all of the hydrocarbon components in the natural gas that are heavier than propane (some butane may remain), all “condensates” (for example, pentanes and heavier molecular weight hydrocarbons) in the gas, and essentially all of the solid-forming components (such as CO 2  and H 2 S) in the gas are removed before the remaining components (e.g. methane, ethane, and propane) are cooled to cryogenic temperature of about −160° C. The equipment and compressor horsepower required to achieve these temperatures are considerable, thereby making any LNG system expensive to build and operate at the producing or remote site. 
     In a NGL process, propane and heavier hydrocarbons are extracted from the natural gas feed stream and are cooled to a low temperature (above about −70° C.) while maintaining the cooled components at a pressure above about 100 kPa in storage. One example of a NGL process is disclosed in U.S. Pat. No. 5,325,673 in which a natural gas stream is pre-treated in a scrub column in order to remove freezable (crystallizable) C 5+  components. Since NGL is maintained above −40° C. while conventional LNG is stored at temperatures of about −160° C., the storage facilities used for transporting NGL are substantially different, thereby requiring separate storage facilities for LNG and NGL which can add to overall transportation cost. 
     It has also been proposed to transport natural gas at temperatures above −112° C. (−170° F.) and at pressures sufficient for the liquid to be at or below its bubble point temperature. This pressurized liquid natural gas is referred to as “PLNG” to distinguish it from LNG, which is transported at near atmospheric pressure and at a temperature of about −162° C. (−260° F.). Exemplary processes for making PLNG are disclosed in U.S. Pat. No. 5,950,453 (R. R. Bowen et al.); U.S. Pat. No. 5,956,971 (E. T. Cole et al.); U.S. Pat. No. 6,016,665 (E. T. Cole et al.); and U.S. Pat. No. 6,023,942 (E. R. Thomas et al.). Because PLNG typically contains a mixture of low molecular weight hydrocarbons and other substances, the exact bubble point temperature of PLNG is a function of its composition. For most natural gas compositions, the bubble point pressure of the natural gas at temperatures above −112° C. will be above about 1,380 kPa (200 psia). One of the advantages of producing and shipping PLNG at a warmer temperature is that PLNG can contain considerably more C 2+  components than can be tolerated in most LNG applications. 
     Depending upon market prices for ethane, propane, butanes, and the heavier hydrocarbons, it may be economically desirable to transport the heavier products with the PLNG and to sell them as separate products. This separation of the PLNG into component products is preferably performed once the PLNG has been transported to a desired import location. A need exists for an efficient process for separating the C 2+  components from the PLNG. 
     SUMMARY 
     The invention is an absorption process for recovering C 2+  components from a pressurized liquid mixture comprising C 1  and C 2+ . The pressurized liquid mixture is at least partially vaporized by heating the liquid mixture in a heat transfer means. The heat transfer means provides refrigeration to an absorption medium that is used in treating the vaporized mixture in an absorption zone. The vaporized mixture is passed to an absorption zone that produces a first stream enriched in C 1  and a second stream enriched in C 2+  components. The pressurized liquid mixture is preferably pressurized liquid natural gas (PLNG) having an initial pressure above about 1,724 kPa (250 psia) and an initial temperature above −112° C. (−170° F.). Before being vaporized, the pressurized liquid mixture is preferably boosted in pressure to approximately the desired operating pressure of the absorption zone. 
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS 
     The present invention and its advantages will be better understood by referring to the following detailed description and the attached drawings. 
     FIG. 1 is a schematic flow diagram of one embodiment of a separation process for removing ethane and heavier components from PLNG. 
     FIG. 2 is a schematic flow diagram of one embodiment of an indirect heat exchange means for vaporizing PLNG using the heat of lean oil used in a separation process for removing ethane and heavier components from PLNG. 
     FIG. 3 is a schematic flow diagram of a second embodiment of an indirect heat exchange means for vaporizing PLNG using the heat of lean oil used in a separation process for removing ethane and heavier components from PLNG. 
     The drawings illustrate a specific embodiment of practicing the method of this invention. The drawings are not intended to exclude from the scope of the invention other embodiments that are the result of normal and expected modifications of the specific embodiment. Most of the required subsystems such as pumps, valves, flow stream mixers, control systems, and fluid level sensors have been deleted from the drawings for the purposes of simplicity and clarity of presentation. 
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     The following description makes use of several terms often used in the industry which are defined as follows to aid the reader in understanding the invention. 
     “Lean oil” is a hydrocarbon liquid used as an absorption media and circulated in contact with a vaporized multi-component gas containing methane and C 2+  hydrocarbons to absorb one or more components of the multi-component gas that are heavier than methane, preferably the C 2+  hydrocarbons. The composition of the lean oil can vary depending on the temperature and pressure under which the absorption occurs and the composition of the multi-component gas. The oil may be charged to the separation process and/or it may be accumulated from the heaviest components absorbed from the gas. 
     “Rich oil” is a relative term since there are degrees of richness, but it is the lean oil after it has contacted the multi-component gas and has absorbed within it C 2+ . The rich oil is typically denuded of the absorbed components by fractionation and becomes lean again to be recirculated. 
     “Natural gas” means gas used in producing PLNG, which can be gas obtained from a crude oil well (associated gas) and/or from a gas well (non-associated gas). Associated gas occurs either as free gas or as gas in solution in crude oil. Although the composition of natural gas varies widely from field to field, the typical gas contains methane (C 1 ) as a major component. The natural gas stream may also typically contain ethane (C 2 ), higher hydrocarbons (C 3+ ), and minor amounts of contaminants such as carbon dioxide (CO 2 ), hydrogen sulfide, nitrogen, dirt, iron sulfide, wax, and crude oil. The solubilities of the contaminants vary with temperature, pressure, and composition. If the natural gas stream contains heavy hydrocarbons that could freeze out during liquefaction or if the heavy hydrocarbons are not desired in PLNG because of compositional specifications or their value as natural gas liquids (NGLs), the heavy hydrocarbons are typically removed by a fractionation process prior to liquefaction of the natural gas to PLNG. 
     Referring to FIG. 1, a schematic is shown of one embodiment of practicing the process of the present invention. PLNG, preferably at a temperature above 250 psia (1723 kPa), enters the separation process through line  10  and is preferably boosted in pressure by pump  110 . The pressurized liquid is preferably passed through a pre-heater  111  wherein the PLNG can be pre-heated against various materials, including environmental streams such as air, seawater, or a glycol-water mixture. The PLNG stream is preferably preheated by pre-heater  111  as a means of obtaining a desired feed gas temperature to absorber  116 . While pre-heater  111  is optional, depending on the composition of lean oil used in the separation process, pre-heater  111  can also help reduce the potential for the freezing out of certain heavier lean oil components, if present, in the lean oil being cooled by the PLNG in heat-exchange means  112 . The desired temperature of the PLNG entering the absorber  116  depends on process configuration, PLNG composition, and the lean oil composition being used in the separation process. At least a portion of PLNG stream  12  is heated by passing through a heat-exchange means  112  for vaporizing at least part of the PLNG. If the heat-exchange means  112  is a plate-fin exchanger used in the configuration shown in FIG. 1, PLNG stream  12  is preferably separated to comply with the thermal stress limitations of the exchanger. If the heat-exchange means  112  is a plate-fin exchanger used in an indirect heating configuration shown in FIG. 2, which will be described in more detail hereafter, all of the PLNG stream may be passed through the heat-exchange means  112 . The thermodynamic properties of the indirect heat exchange medium used in the process (for example, ethane) can prevent potentially unacceptably high thermal stresses in the heat-exchange means  112 . In FIG. 3, the u-tube heat exchange system  300  also uses an indirect heat exchange medium that can protect the heat exchangers from potentially destructive thermal stresses. The heating of the PLNG in heat-exchange means  112  cools lean oil stream  100 , which is used in the separation process as described in more detail later in this description. The at least partially vaporized stream is then passed to liquid-vapor separator  114 . Vapor stream  16  and liquid stream  17 , if any, are passed from separator  114  to absorber  116 . Also entering absorber  116 , at the upper end thereof, is a lean absorber liquid stream  52 , referred to herein as “lean oil.” In the absorber  116 , the vapor stream  16  rises to the top of absorber  116 , encountering a stream of lean oil traveling downward over bubble-caps, trays, or similar separation devices. The absorber  116  operates at conditions that cause the lean oil to remove (absorb) the C 2+  components from the vapor stream  16  that enters absorber  116 . The rich lean oil and condensed hydrocarbon liquids (stream  17 ) mix in the bottom of absorber  116  prior to being routed to a primary rich oil demethanizer  120  (“PROD”) or to a rich oil demethanizer  124  (“ROD”). Although the separation process shown in FIG. 1 illustrates two demethanizer columns  120  and  124 , the invention is not limited to two demethanizers. For example, a PROD may be omitted if a reboiler (not shown) is used in the bottom of the lean oil absorber  116  (sometimes referred to as a “reboiled absorber”) to reject a portion of the methane in the rich lean oil in the bottom of the absorber  116 . A methane enriched stream  18  is withdrawn from absorber  116  as a product stream while rich oil containing C 2+  is withdrawn from the bottom of the absorber  116  as stream  20 . Stream  20  is boosted in pressure by pump  118  and passed to primary rich oil demethanizer  120 . Demethanizer  120  operates under conditions that produce a methane enriched overhead vapor stream  26 , which is recycled by being combined with vapor stream  12  before being introduced to the separator  114 . A portion of the rich oil at the lower end of primary rich oil demethanizer  120  is withdrawn and heated in heat exchanger  119  against lean oil stream  100 . Rich oil from the bottom of primary rich oil demethanizer  120  can be depressurized and cooled by a liquid expander  122 , such as a turbo-expander, and passed as stream  30  to rich oil demethanizer  124 . A reboiler side stream  36  is withdrawn from rich oil demethanizer  124  and cross-exchanged in heat exchanger  126  with liquid stream  34  exiting the bottom of rich oil demethanizer  124 . Lean oil stream  50  is introduced into the upper portion of rich oil demethanizer  124  in order to reabsorb C 2+  components that are flashed up demethanizer  124  by reboilers (not shown). It would be understood by those skilled in the art that primary rich oil demethanizer  120  and rich oil demethanizer  124  would have conventional reboilers, which are not shown in the drawings for the sake of simplicity. A methane rich overhead stream  32  is passed to accumulator  130  where it is used to presaturate lean oil stream  42  with methane. Mixed stream  44  may optionally be trim-chilled using any cooling means  129  such as a conventional propane closed-loop chiller or by indirect cooling against PLNG feed stream  10 . A methane-rich vapor stream  46  exits the accumulator  130  for any suitable use such as a source of fuel for providing power required for the separation process. Also exiting the accumulator  130  is a liquid lean oil stream  48  which is separated into two lean oil streams  50  and  52  and boosted in pressure by pumps  132  and  134 , respectively. 
     Rich oil stream  34  is passed through heat exchanger  126  and passed through liquid expander  140 , which cools and decreases the pressure of the rich oil. Regulator valves  138  and  136  are used to regulate flow of rich oil stream  34  into flash tank  150 . For operational reasons, regulator valve  136 , normally in the open position, can be closed and regulator valve  138 , normally in the closed position, can be opened to allow rich oil to bypass expander  140 . Flash tank  150  operates under conditions to cause the rich oil to separate into an overhead vapor stream  62  enriched in C 2+ , primarily C 2  to C 4  components, and a liquid stream  64  enriched in lean oil. The liquid stream  64  is passed through heat exchanger  152  wherein it is heated. Liquid stream  72  exiting heat exchanger  152  is passed through regulator valve  153  and is passed into still  156 . Overhead vapor stream  62  from the flash tank  150  is passed through a regulator valve  154  and then introduced into still  156 . Still  156  fractionates the rich oil into an overhead vapor stream  67  enriched in ethane and heavier hydrocarbons contained in the rich oil and a liquid bottoms stream  70  that is enriched in lean oil. Lean oil stream  70  is boosted in pressure by pump  158  and passed through heat exchanger  152  wherein the lean oil is cooled by heat exchange against the liquid stream  64 . From heat exchanger  152 , the lean oil (stream  98 ) is further cooled by cooler  160 . Stream  99  exiting cooler  160  is combined with stream  94  and passed to heat exchanger  119  to provide reboiling duty. Stream  100  exiting heat exchanger  119  is passed to heat-exchange means  112  to provide the heat needed to vaporize at least part of PLNG stream  12 , so that the feed to absorber  116  is at the desired cold temperature for the absorption process. Heat-exchange means  112  thereby also provides refrigeration duty for the lean oil used in the separation process. At least a portion of cooled lean oil stream  101  is recycled by being combined with stream  32  and passed to accumulator  130 . A portion of stream  101  is preferably withdrawn from stream  101  as stream  86  and passed through heat exchanger  162  which provides cooling for vapor stream  67  exiting still  156 . Lean oil stream  92  exiting heat exchanger  162  is cooled by cooler  164  and boosted in pressure by pump  166  to approximately the same pressure as stream  99 . Lean oil make-up stream  97  can introduce lean oil to the separation process that will inevitably be lost during operations since the methane rich stream  18  and C 2+  product stream  80  produced by the separation process will contain small amounts of lean oil. 
     Overhead vapor stream  67  is cooled in heat exchanger  162  and passed to an accumulator  168 . A vapor stream  80  rich in C 2+  hydrocarbons is removed from the top of accumulator  168  as a product stream  80  and a liquid stream  78  are removed from the accumulator, pressure enhanced by pump  170 , and a portion thereof is recycled as stream  82 , passed through control valve  172 , and returned to the top of the distillation column  156 . A portion of the liquid stream  78  may be removed from the process as liquid petroleum gas (LPG) product stream  79 . 
     The lean oil composition can be easily tailored by persons skilled in the art to avoid components that could potentially freeze up in the PLNG heat-exchange means  112 . In addition, the temperature of the PLNG stream  12  being vaporized can be adjusted using modified open rack vaporizers to preclude the freezing out of lean oil components. In addition, indirect heating/cooling systems can be employed to eliminate freezing of lean oil components in the process using an indirect heat exchange system, non-limiting examples of which are illustrated in FIGS. 2 and 3. 
     FIG. 2 illustrates a schematic flow diagram of an alternative embodiment of a heat exchange system for vaporizing PLNG stream  11  using the heat of lean oil that is used in the separation process for absorbing C 2+  from methane. The heat exchange system  200  of FIG. 2 can replace the heat-exchange means  112  of FIG.  1 . Referring to FIG. 2, PLNG stream  11  is passed through heat exchanger  201  wherein the PLNG is heated by a closed-loop heat exchange medium that circulates between heat exchanger  201  and heat exchanger  202 . The heat exchange medium (stream  200 ) is cooled as it passes through heat exchanger  201  and it is passed as stream  210  to accumulator  211 . Liquid heat exchange medium is withdrawn from the bottom of accumulator  211  and passed to a second accumulator  212 . Liquid heat exchange medium is withdrawn from accumulator  212  and passed through heat exchanger  202  wherein the heat exchange medium cools lean oil  100  as it passes through heat exchanger  202 . The warmed heat exchange medium exiting heat exchanger  202  is passed back to accumulator  212  and vapor overhead from accumulator  212  is withdrawn and recycled through heat exchanger  201  for recooling and condensing. The vertical movement of refrigerant through heat exchanger  202  occurs as a result of vaporization of the refrigerant and the subsequent reduction in bulk density of the fluid in the heat exchanger, a process sometimes called “thermosiphoning.” The refrigerant level in accumulator  212  provides the driving force for maintaining refrigerant flow into the bottom of exchanger  202 , and the partial vaporization of the refrigerant in the exchanger lifts the refrigerant out of the exchanger and back into accumulator  212 . Unvaporized liquid refrigerant falls into the lower half of accumulator  212 , and the vaporized portion of the refrigerant stream flows out the top of accumulator  212  and into the top of exchanger  201 . In exchanger  201 , the refrigerant vapor stream  210  is liquefied again by cooling against PLNG stream  12 . The reliquefied refrigerant flows by gravity back into accumulator  211 . Level control valve  213  can be opened as necessary to maintain the desired level in accumulator  212 . A low level override valve  213  in liquid line connecting accumulator  211  and accumulator  212  prevents the level in accumulator  211  from falling to an undesirable level. Before it becomes necessary to override and close valve  213 , accumulator  211  can open  214  to make up refrigerant from any suitable source. Liquid in accumulator vessel  211  traps out the refrigerant vapor flowing from accumulator  212  and forces it to flow into exchanger  201  the refrigerant vapor is condensed. Persons skilled in the art will recognize that the relative elevation of the two vessels  211  and  212  and the two heat exchangers  201  and  202  would be important to ensure proper hydraulics of the process. 
     The heat-transfer medium that may be used in the heat exchange system of FIG. 2 is preferably in liquid form during its circulation through heat exchangers  201  and  202  to provide a transfer of both sensible heat and latent heat alternately to and from the heat-transfer medium. It is also preferable that a heat-transfer medium be used that goes through at least partial phase changes during circulation through heat exchangers  201  and  202 , with a resulting transfer of latent heat. 
     The preferred heat-transfer medium, in order to have a phase change, is preferably liquefiable at a temperature above the boiling temperature of the PLNG, such that the heat-transfer medium will be condensed during passage through heat exchanger  201 . The heat-transfer medium can be a pure compound or a mixture of compounds of such composition that the heat-transfer medium will condense over a range of temperatures above the vaporizing temperature range of the PLNG. 
     Although commercial refrigerants may be used as heat-transfer mediums in heat exchange system  200 , hydrocarbons having 1 to 6 carbon atoms per molecule, including propane, ethylene, ethane, and methane, and mixtures thereof, are preferred heat-transfer mediums, particularly since they are normally present in at least minor amounts in natural gas and therefore are readily available. 
     FIG. 3 illustrates a schematic flow diagram of still another embodiment of a heat exchange system for vaporizing at least a portion of the PLNG using the heat of lean oil that is used in the system. The heat exchange system  300  of FIG. 3 can replace the heat-exchange means  112  of FIG.  1 . In FIG. 3, PLNG stream  11  is passed through a conventional u-tube heat exchanger  301 . A heat-transfer medium is circulated in a closed-loop cycle between heat exchanger  301  and heat exchanger  302 . Vaporized heat-transfer medium (represented by arrows  303 ) is introduced into the u-tube bundle of heat exchanger  301 . The heat-transfer medium heats the PLNG that is circulated in the u-tube bundle  304 . The heat-transfer medium exiting the heat exchanger  301  is passed to an accumulator  305 . Overhead vapor is withdrawn from accumulator  305  and is recycled as stream  307  to the heat exchanger  301 . Liquid heat-transfer medium is withdrawn from the bottom of accumulator  305 , passed to kettle-type heat exchanger  302 . The liquid heat-transfer medium in heat exchanger  302  cools the lean oil  100 , thereby vaporizing the heat-transfer medium. The vaporized heat-transfer medium is recycled as stream  308  back to heat exchanger  301  for re-cooling. The heat-transfer medium in heat exchange system  300  may be the same as that used in heat exchange system  200  described previously with respect to the embodiment shown in FIG.  2 . 
     EXAMPLE 
     A simulated mass and energy balance was carried out to illustrate one embodiment of the invention as described by FIG. 1, and the results are set forth in Table 1 and Table 2 below. The data in the Tables were obtained using a commercially available process simulation program called HYSYS™, version 1.5 (available from Hyprotech Ltd. of Calgary, Canada). However, other commercially available process simulation programs can be used to develop the data, including for example HYSIM™, PROII™, and ASPEN PLUS™, which are familiar to persons skilled in the art. The data presented in Tables 1 and 2 are offered to provide a better understanding of the present invention, but the invention is not to be construed as unnecessarily limited thereto. The temperatures, pressures, and flow rates are not to be considered as limitations of the invention which can have many variations in temperatures, pressures, and flow rates in view of the teachings herein. It is within the expertise of those skilled in the art to choose proper operating conditions for the absorber  116 , demethanizers  120  and  124 , flash tank  150  and still  156  for a given flow rate, temperature, and composition of a feed stream to the separation process. 
     One of the benefits of practicing the method of the present invention is that the refrigeration inherent in a PLNG stream can be recovered by modifying a conventional lean oil plant design (including existing plants) to enable the lean oil plant to recover C 2+  hydrocarbons (LPG products) from the PLNG stream. The refrigeration recovered from the PLNG stream can be utilized in the lean oil process to substantially reduce, and potentially eliminate, the need for an external refrigeration system, such as propane cooler. Another advantage of the present invention is that the vaporization of the PLNG stream can be accomplished by the lean oil process with minimal pressure loss using relatively low cost pump horsepower. Therefore, there are minimal recompression requirements associated with the process of the present invention. 
     
       
         
               
               
               
               
               
             
               
               
               
               
               
             
           
               
                   
                 TABLE 1 
               
               
                   
                   
               
               
                   
                 Stream # 
                 Temperature 
                 Pressure 
                 Molar Flow 
               
               
                   
                 (FIG. 1) 
                 (° C.) 
                 (bar) 
                 (kg mole/h) 
               
               
                   
                   
               
             
             
               
                   
               
             
          
           
               
                   
                 10 
                 −95.56 
                 23.39 
                 39,720. 
               
               
                   
                 11 
                 −89.28 
                 79.29 
                 39,720. 
               
               
                   
                 12 
                 −63.89 
                 78.46 
                 39,720. 
               
               
                   
                 13 
                 −63.89 
                 78.46 
                 23,830. 
               
               
                   
                 14 
                 −8.30 
                 78.46 
                 15,890. 
               
               
                   
                 16 
                 −42.80 
                 70.64 
                 56,300. 
               
               
                   
                 17 
                 0 
                 0 
                 0 
               
               
                   
                 18 
                 −28.26 
                 69.84 
                 31,880. 
               
               
                   
                 20 
                 −40.94 
                 70.33 
                 30,360. 
               
               
                   
                 24 
                 −40.75 
                 72.39 
                 30,360. 
               
               
                   
                 26 
                 −40.18 
                 71.71 
                 16,580. 
               
               
                   
                 28 
                 37.78 
                 72.05 
                 13,770. 
               
               
                   
                 30 
                 20.67 
                 36.20 
                 13,770. 
               
               
                   
                 32 
                 −42.12 
                 34.47 
                 4,403. 
               
               
                   
                 34 
                 72.03 
                 34.96 
                 15,010. 
               
               
                   
                 42 
                 −45.56 
                 34.89 
                 8,072. 
               
               
                   
                 44 
                 −45.56 
                 33.65 
                 12,480. 
               
               
                   
                 46 
                 −45.56 
                 33.65 
                 980.8 
               
               
                   
                 48 
                 −45.56 
                 33.65 
                 11,490. 
               
               
                   
                 50 
                 −45.49 
                 35.51 
                 5,638. 
               
               
                   
                 52 
                 −44.24 
                 72.39 
                 5,857. 
               
               
                   
                 54 
                 51.33 
                 34.27 
                 15,010. 
               
               
                   
                 58 
                 46.55 
                 22.75 
                 15,010. 
               
               
                   
                 62 
                 46.55 
                 22.75 
                 1,230. 
               
               
                   
                 64 
                 46.55 
                 22.75 
                 13,780. 
               
               
                   
                 66 
                 39.59 
                 15.86 
                 1,230. 
               
               
                   
                 67 
                 75.69 
                 15.17 
                 8,659. 
               
               
                   
                 69 
                 −1.111 
                 14.89 
                 8,659. 
               
               
                   
                 70 
                 199.7 
                 15.65 
                 8,072. 
               
               
                   
                 72 
                 121.1 
                 21.93 
                 13,780. 
               
               
                   
                 74 
                 116.6 
                 15.86 
                 13,780. 
               
               
                   
                 78 
                 −1.111 
                 14.89 
                 1,722. 
               
               
                   
                 80 
                 −1.111 
                 14.89 
                 6,938. 
               
               
                   
                 82 
                 −0.5449 
                 22.75 
                 1,722. 
               
               
                   
                 84 
                 −0.4745 
                 19.99 
                 1,722. 
               
               
                   
                 86 
                 −45.56 
                 34.89 
                 3,802. 
               
               
                   
                 92 
                 52.20 
                 34.06 
                 3,802. 
               
               
                   
                 93 
                 48.89 
                 33.72 
                 3,802. 
               
               
                   
                 94 
                 49.07 
                 37.58 
                 3,802. 
               
               
                   
                 96 
                 203.6 
                 41.37 
                 8,072. 
               
               
                   
                 98 
                 100.2 
                 40.54 
                 8,072. 
               
               
                   
                 99 
                 48.89 
                 36.75 
                 8,072. 
               
               
                   
                 100  
                 48.96 
                 36.75 
                 11,870. 
               
               
                   
                 101  
                 −45.56 
                 34.89 
                 11,870. 
               
               
                   
                   
               
             
          
         
       
     
     
       
         
               
               
               
             
               
               
               
               
               
               
               
               
               
             
               
               
               
               
               
               
               
               
               
             
           
               
                   
                 TABLE 2 
               
             
             
               
                   
                   
               
               
                   
                 Streams # corresponding to Fig. 1 (Mole Fractions) 
                   
               
             
          
           
               
                 Components 
                 10 
                 24 
                 32 
                 50 
                 52 
                 69 
                 80 
                 100 
               
               
                   
               
             
          
           
               
                 Methane 
                 0.7976 
                 0.5624 
                 0.9760 
                 0.2897 
                 0.2897 
                 0.0126 
                 0.0153 
                 0.0000 
               
               
                 Ethane 
                 0.1994 
                 0.3038 
                 0.0187 
                 0.0345 
                 0.0342 
                 0.9140 
                 0.9774 
                 0.0400 
               
               
                 Propane 
                 0.0001 
                 0.0002 
                 0.0000 
                 0.0001 
                 0.0001 
                 0.0007 
                 0.0005 
                 0.0001 
               
               
                 i-Butane 
                 0.0001 
                 0.0002 
                 0.0000 
                 0.0002 
                 0.0002 
                 0.0011 
                 0.0005 
                 0.0003 
               
               
                 n-Butane 
                 0.0001 
                 0.0002 
                 0.0000 
                 0.0003 
                 0.0003 
                 0.0014 
                 0.0005 
                 0.0004 
               
               
                 n-Hexane 
                 0.0000 
                 0.0015 
                 0.0000 
                 0.0077 
                 0.0070 
                 0.0276 
                 0.0013 
                 0.0100 
               
               
                 n-Heptane 
                 0.0000 
                 0.0472 
                 0.0000 
                 0.2423 
                 0.2430 
                 0.0006 
                 0.0000 
                 0.3461 
               
               
                 n-Octane 
                 0.0000 
                 0.0008 
                 0.0000 
                 0.0041 
                 0.0041 
                 0.0000 
                 0.0000 
                 0.0058 
               
               
                 C6p* 
                 0.0000 
                 0.0000 
                 0.0000 
                 0.0001 
                 0.0001 
                 0.0003 
                 0.0000 
                 0.0001 
               
               
                 C7p* 
                 0.0000 
                 0.0803 
                 0.0001 
                 0.4128 
                 0.4130 
                 0.0385 
                 0.0009 
                 0.5881 
               
               
                 C8p* 
                 0.0000 
                 0.0016 
                 0.0000 
                 0.0063 
                 0.0063 
                 0.0000 
                 0.0000 
                 0.0090 
               
               
                 Nitrogen 
                 0.0014 
                 0.0018 
                 0.0051 
                 0.0019 
                 0.0019 
                 0.0031 
                 0.0035 
                 0.0000 
               
               
                 CO 2   
                 0.0013 
                 0.0000 
                 0.0000 
                 0.0000 
                 0.0000 
                 0.0000 
                 0.0000 
                 0.0000 
               
               
                   
               
             
          
         
       
     
     A person skilled in the art, particularly one having the benefit of the teachings of this patent, will recognize many modifications and variations to the specific process disclosed above. For example, a variety of temperatures and pressures may be used in accordance with the invention, depending on the overall design of the system and the composition, temperature, and pressure of the liquefied natural gas, and the PLNG being fed to a separation system of the present invention can provide cooling for other fluid streams used in the separation process in addition to cooling lean oil stream  100  as illustrated in the process depicted in FIG.  1 . As discussed above, the specifically disclosed embodiments and examples should not be used to limit or restrict the scope of the invention, which is to be determined by the claims below and their equivalents.