Process for recovering ethane and heavier hydrocarbons from methane-rich pressurized liquid mixture

Abstract
The invention is an absorption process for recovering C2+ components from a pressurized liquid mixture comprising C1 and C2+. 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 C1 and a second stream enriched in C2+ 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




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.



Claims
  • 1. An absorption method for recovery of C2+ components from a pressurized liquid mixture containing C1 and C2+, comprising:(a) vaporizing at least part of the pressurized liquid mixture by heating the pressurized liquid mixture in a heat transfer means, said heat transfer means cooling an absorption medium; and (b) treating the vaporized stream in an absorption zone with the absorption medium to produce a first stream enriched in C1 and a second stream enriched in C2+ components.
  • 2. The method of claim 1 wherein the pressurized liquid mixture is pressurized liquid natural gas (PLNG).
  • 3. The method of claim 1 wherein the pressurized liquid mixture has an initial pressure above about 1,724 kPa (250 psia) and an initial temperature between about −80° C. (−112° F.) and −112° C. (−170° F.).
  • 4. The method of claim 1 wherein the absorption medium is lean oil.
  • 5. The method of claim 1 wherein the absorption medium is pre-saturated with methane prior to treatment step (b).
  • 6. The method of claim 1 wherein the heat exchange relationship uses a heat-transfer medium being in heat exchange relationship with the liquid mixture in a first heat exchanger and the heat transfer medium being in heat exchange relationship with the absorption stream in a second heat exchanger.
  • 7. The method of claim 1 wherein the heat exchange relationship uses at least one heat exchanger in which the liquid mixture is in indirect contact with the absorption medium.
  • 8. The method of claim 1 further comprises, before passing the pressurized liquid mixture in heat exchange relationship with a heat-transfer stream, heating the liquid mixture by heat exchange relationship with at least one of air, fresh water, and sea water.
  • 9. The method of claim 1 further comprises, after passing the pressurized liquid mixture in heat exchange relationship with a heat-transfer stream, further heating the liquid mixture by heat exchange relationship with at least one of air, fresh water, and sea water.
  • 10. A method for separating C2+ components from a pressurized liquid mixture comprising C1 and C2+, the method comprising:(a) heating the pressurized liquid mixture to at least partially vaporize the liquid mixture, thereby producing a vapor stream; (b) contacting the vapor stream with an absorbent medium that preferentially absorbs C2+ components from the vapor stream; (c) recovering a C1-rich stream substantially depleted of C2+; (d) separating the extracted C2+ components from the absorption medium containing the same; (e) cooling at least part of the absorption medium by heat exchange relationship against the pressurized liquid mixture, thereby providing heat for at least partially vaporizing the liquid mixture; and (f) recycling the cooled absorption medium to absorb additional amounts of C2+ components.
RELATED U.S. APPLICATION DATA

This application claims the benefit of U.S. Provisional Application No. 60/302,123, filed Jun. 29, 2001.

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Number Name Date Kind
2181302 Keith, Jr. et al. Nov 1939 A
2849371 Gilmore Aug 1958 A
2857018 Partridge et al. Oct 1958 A
2959540 Cahn et al. Nov 1960 A
3214890 Sterrett Nov 1965 A
3347621 Papadopoulos et al. Oct 1967 A
3555837 McClintock Jan 1971 A
3574089 Forbes Apr 1971 A
3633371 Davison Jan 1972 A
4009097 Ward Feb 1977 A
4072604 Ward Feb 1978 A
4575387 Larue et al. Mar 1986 A
4693731 Tarakad et al. Sep 1987 A
4738699 Apffel Apr 1988 A
4747858 Gottier May 1988 A
4883515 Mehra et al. Nov 1989 A
5325673 Durr et al. Jul 1994 A
5685170 Sorensen Nov 1997 A
5687584 Mehra Nov 1997 A
5950453 Bowen et al. Sep 1999 A
5956971 Cole et al. Sep 1999 A
6016665 Cole et al. Jan 2000 A
6023942 Thomas et al. Feb 2000 A
Provisional Applications (1)
Number Date Country
60/302123 Jun 2001 US