Patent Publication Number: US-6712880-B2

Title: Cryogenic process utilizing high pressure absorber column

Description:
This application claims the benefits of provisional patent applications, U.S. Ser. No. 60/272,417, filed on Mar. 1, 2001 and U.S. Ser. No. 60/274,069, filed on Mar. 7, 2001, both incorporated by reference. 
    
    
     BACKGROUND OF THE INVENTION 
     1. Technical Field 
     This invention relates to cryogenic gas processes for separating multi-component gaseous hydrocarbon streams to recover both gaseous and liquid compounds. More particularly, the cryogenic gas processes of this invention utilize a high pressure absorber. 
     2. Background and Prior Art 
     In most plants, gas processing capacity is generally limited by the horsepower available for recompression of the pipeline sales gas stream. The feed gas stream is typically supplied at 700-1500 psia and expanded to a lower pressure for separation of the various hydrocarbon compounds. The methane-rich stream produced is typically supplied at about 150-450 psia and is recompressed to pipeline sales gas specifications of 1000 psia or above. This pressure difference accounts for the major portion of the horsepower requirement of a cryogenic gas processing plant. If this pressure difference can be minimized, then more recompression horsepower will be available, thereby allowing increased plant capacity of existing gas processing plants. Also, the process of the invention may offer reduced energy requirements for new plants. 
     Cryogenic expansion processes produce pipeline sales gas by separating the natural gas liquids from hydrocarbon feed gas streams. 
     In the prior art cryogenic processes, a pressurized hydrocarbon feed gas stream is separated into constituent methane, ethane (C 2 ) compounds and/or propane (C 3 ) compounds via a single column or a two-column cryogenic separation schemes. In single column schemes, the feed gas stream is cooled by heat exchange contact with other process streams or external refrigeration. The feed gas stream may also be expanded by isentropic expansion to a lower pressure and thereby further cooled. As the feed stream is cooled, high pressure liquids are condensed to produce a two-phase stream that is separated in one or more cold separators into a high pressure liquid stream and a methane-rich vapor stream in one or more cold separators. These streams are then expanded to the operating pressure of the column and introduced to one or more feed trays of the column to produce a bottom stream containing C 2  compounds and/or C 3  compounds and heavier compounds and an overhead stream containing methane and/or C 2  compounds and lighter compounds. Other single column schemes for separating high pressure hydrocarbon streams are described in U.S. Pat. Nos. 5,881,569; 5,568,737; 5,555,748; 5,275,005 to Campbell et al; U.S. Pat. No. 4,966,612 to Bauer; U.S. Pat. Nos. 4,889,545; 4,869,740 to Campbell; and U.S. Pat. No. 4,251,249 to Gulsby. 
     Separation of a high pressure hydrocarbon gaseous feed stream may also be accomplished in a two-column separation scheme that includes an absorber column and a fractionation column that are typically operated at very slight positive pressure differential. In the two-column separation scheme for recovery of C 2+  and/or C 3+  natural gas liquids, the high pressure feed is cooled and separated in one or more separators to produce a high pressure vapor stream and a high pressure liquid stream. The high pressure vapor stream is expanded to the operating pressure of the fractionation column. This vapor stream is supplied to the absorber column and separated into an absorber bottom stream and an absorber overhead vapor stream containing methane and/or C 2  compounds along with trace amounts of nitrogen and carbon dioxide. The high pressure liquid stream from the separators and the absorber bottom stream are supplied to a fractionation column. The fractionation column produces a fractionation column bottom stream which contains C 2+  compounds and/or C 3+  compounds and a fractionation column overhead stream which may be condensed and supplied to the absorber column as reflux. The fractionation column is typically operated at a slight positive pressure differential above that of the absorber column so that fractionation column overheads may flow to the absorber column. In many of the two-column systems, upsets occur that cause the fractionation column to pressure up, particularly during startup. Pressuring up of the fractionation column poses safety and environmental threats, particularly if the fractionation column is not designed to handle the higher pressure. Other two-column schemes for separating high pressure hydrocarbon streams are described in U.S. Pat. No. 6,182,469 to Campbell et al.; U.S. Pat. No. 5,799,507 to Wilkinson et at.; U.S. Pat. No. 4,895,584 to Buck et al.; U.S. Pat. No. 4,854,955 to Campbell et al.; U.S. Pat. No. 4,705,549 to Sapper; U.S. Pat. No. 4,690,702 to Paradowski et al.; U.S. Pat. No. 4,617,039 to Buck; and U.S. Pat. No. 3,675,435 to Jackson et al. 
     U.S. Pat. No. 4,657,571 to Gazzi discloses another two-column separation scheme for separating high pressure hydrocarbon gaseous feed streams. The Gazzi process utilizes an absorber and fractionation column that operate at higher pressures than the two-column schemes discussed above. However, the Gazzi process operates with the absorber pressure significantly greater than the fractionation column pressure, as opposed to most two-column schemes that operate at a slight pressure differential between the two vessels. Gazzi specifically teaches the use of a dephlegmator within the fractionation column to strip the feedstreams of a portion of the heavy constituents to provide a stripping liquid for use in the absorber. Gazzi&#39;s tower operating pressures are independent of each other. The separation efficiency of the individual towers is controlled by individually altering the operating pressure of each tower. As a result of operating in this manner, the towers in the Gazzi process must operate at very high pressures in order to achieve the separation efficiency desired in each tower. The higher tower pressures require higher initial capital costs for the vessels and associated equipment since they have to be designed for higher pressures than for the present process. 
     It is known that the energy efficiency of the single column and two-column separation schemes may be improved by operating such columns at higher pressure, such as in the Gazzi patent. When operating pressures are increased, however, separation efficiency and liquid recovery are reduced, often to unacceptable levels. As column pressures increase, the column temperatures also increase, resulting in lower relative volatilities of the compounds in the columns. This is particularly true of the absorber column where the relative volatility of methane and gaseous impurities, such as carbon dioxide, approach unity at higher column pressure and temperature. Also, the number of theoretical stages in respective columns will have to increase in order to maintain separation efficiency. However, the impact of the residue gas compression costs prevails above other cost components. Therefore, the need exists for a separation scheme that operates at high pressures, such as pressures above about 500 psia, yet maintains high hydrocarbon recoveries at reduced horsepower consumption. 
     Earlier patents have addressed the problem of reduced separation efficiency and liquid recovery, typically, by introducing and/or recycling ethane-rich streams to the column. U.S. Pat. No. 5,992,175 to Yao discloses a process for improving recovery of C 2+  and C 3+  natural gas liquids in a single column operated at pressures of up to 700 psia. Separation efficiency is improved by introducing to the column a stripping gas rich in C 2  compounds and heavier compounds. The stripping gas is obtained by expanding and heating a liquid condensate stream removed from below the lowest feed tray of the column. The two-phase stream produced is separated with the vapors being compressed and cooled and recycled to the column as a stripping gas. However, this process has unacceptable energy efficiency due to the high recompression duty that is inherent in one-column schemes. 
     U.S. Pat. No. 6,116,050 to Yao discloses a process for improving the separation efficiency of C 3+  compounds in a two-column system, having a demethanizer column, operated at 440 psia, and a downstream fractionation column, operated at 460 psia. In this process, a portion of a fractionation column overhead stream is cooled, condensed and separated with the remaining vapor stream combined with a slip stream of pipeline gas. These streams are cooled, condensed and introduced to the demethanizer column as an overhead reflux stream to improve separation of C 3  compounds. Energy efficiency is improved by condensing the overhead stream by cross exchange with a liquid condensate from a lower tray of the fractionation column. This process operates at less than 500 psia. 
     U.S. Pat. No. 4,596,588 to Cook discloses a process for separating a methane-containing stream in a two-column scheme, which includes a separator operating at a pressure that, is greater than that of a distillation column. Reflux to the separator may be obtained from one of the following sources: (a) compressing and cooling the distillation column overhead vapor; (b) compressing and cooling the combined two-stage separator vapor and distillation column overhead vapor; and (c) cooling a separate inlet vapor stream. This process also appears to operate at less than 500 psia. 
     Heretofore, there has not been a cryogenic process for separating multi-compound gaseous hydrocarbon streams to recover both gaseous and liquid compounds in one or more high pressure columns. Therefore, the need exists for a two-column scheme for separating a high pressure, multi-compound stream wherein the pressure of an absorber is substantially greater than and at a predetermined differential pressure from the pressure of a downstream fractionation column that improves energy efficiency, while maintaining separation efficiency and liquid recovery. 
     The present invention disclosed herein meets these and other needs. The goals of the present invention are to increase energy efficiency, provide a differential pressure between the absorber and fractionation columns, and to protect the fractionation column from rising pressure during startup of the process. 
     SUMMARY OF THE INVENTION 
     The present invention includes a process and apparatus for separating a heavy key component from an inlet gas stream containing a mixture of methane, C 2  compounds, C 3  compounds and heavier compounds wherein an absorber is operated at a pressure that is substantially greater than the fractionation column pressure and at a specific or predetermined differential pressure between the absorber and the fractionation column. The heavy key component can be C 3  compounds and heavier compounds or C 2  compounds and heavier compounds. The differential pressure in this process is about 50 psi to 350 psi between the absorber and the fractionation column. 
     An inlet gas stream containing a mixture of methane, C 2  compounds, C 3  compounds and heavier compounds is cooled, at least partially condensed and separated in a heat exchanger, a liquid expander, vapor expander, an expansion valve or combinations thereof, to produce a first vapor stream and a first liquid stream. The first liquid stream may be expanded and supplied to a fractionation column along with a fractionation feed stream and a fractionation reflux stream. These feed streams may be supplied to a middle portion of the fractionation column and warmed by heat exchange contact with residue gas, inlet gas, absorber overhead stream, absorber bottom stream and combinations thereof in an apparatus such as consisting of a heat exchanger and a condenser. The fractionation column produces a fractionation overhead vapor and a fractionation bottom stream. The first vapor stream is supplied to an absorber along with an absorber reflux stream to produce an absorber overhead stream and an absorber bottom stream. 
     At least a portion of the fractionation overhead stream is at least partially condensed and separated to produce a second vapor stream and the fractionation reflux stream. The second vapor stream is compressed to essentially about the absorber pressure to produce a compressed second vapor stream that is at least partially condensed by heat exchange contact with one or more process streams such as the absorber bottom stream, the absorber overhead stream, at least a portion of the first liquid stream or combinations thereof. The compressed second vapor stream contains a major portion of the methane in the fractionation feed stream and second fractionation feed stream. When the heavy key component is C 3  compounds and heavier compounds, then the compressed second vapor stream additionally contains a major portion of the C 2  compounds in the fractionation feed stream and second fractionation feed stream. This stream is then supplied to the absorber as an absorber feed stream. The absorber overhead stream may be removed as a residue gas stream containing substantially all of the methane and/or C 2  compounds and a minor portion of C 3  or C 2  compounds. Such residue gas stream is then compressed to pipeline specifications of above about 800 psia. The fractionation bottom stream can be removed as a product stream containing substantially all of the C 3  compounds and heavier compounds and a minor portion of the methane and C 2  compounds. 
     In this invention, the absorber pressure is above about 500 psia. The apparatus for separating the heavy key component from an inlet gas stream containing a mixture of methane, C 2  compounds, C 3  compounds and heavier compounds, includes a cooling means. When the heavy key component is C 3  compounds and heavier compounds, an apparatus for separating the heavy key component from an inlet gas stream comprises a cooling means for at least partially condensing the inlet gas stream to produce a first vapor stream and a first liquid stream; a fractionation column for receiving the first liquid stream, a fractionation feed stream and a second fractionation feed stream, the fractionation column produces a fractionation bottom stream and a fractionation overhead vapor stream; a condenser for at least partially condensing the overhead vapor stream to produce a second vapor stream and a fractionation reflux stream; an absorber for receiving at least a portion of the first vapor stream and an absorber feed stream, the absorber produces an absorber overhead stream and a second fractionation feed stream, the absorber having a pressure that is substantially greater than and at a predetermined differential pressure from the fractionation column pressure; a compressor for compressing the second vapor stream essentially to absorber pressure to produce a compressed second vapor stream; a condensing means for at least partially condensing the compressed second vapor stream to produce the absorber feed stream; and whereby the fractionation bottom stream contains a majority of heavy key components and heavies. 
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS 
     So that the manner in which the features, advantages and objects of the invention, as well as others which will become apparent, may be understood in more detail, more particular description of the invention briefly summarized above may be had by reference to the embodiment thereof which is illustrated in the appended drawings, which form a part of this specification. It is to be noted, however, that the drawings illustrate only a preferred embodiment of the invention and is therefore not to be considered limiting of the invention&#39;s scope as it may admit to other equally effective embodiments. 
     FIG. 1 is a simplified flow diagram of a cryogenic gas separation process that incorporates the improvements of the present invention and configured for improved recovery of C 3  compounds and heavier compounds. 
     FIG. 2 is an alternate embodiment of the process in FIG. 1 wherein a third feed stream is fed to the fractionation column. 
     FIG. 3 is an alternate embodiment of the process in FIG. 1 that includes a mechanical refrigeration system. 
     FIG. 4 is an alternate embodiment of the process in FIG. 3 that includes an internal fractionation column condenser. 
     FIG. 5 is an alternate embodiment of the process in FIG. 4 that includes improved heat integration through the use of a mechanical refrigeration system. 
     FIG. 6 is a simplified flow diagram of a cryogenic gas separation process that incorporates the improvements of the present invention and is configured for improved recovery of C 2  compounds and heavier compounds. 
     FIG. 6 a  is an alternate embodiment of the process in FIG. 6 that includes a split feed stream that supplies the high pressure absorber and the fractionation tower. 
     FIG. 7 is an alternate embodiment of this invention for improved recovery of C 2  compounds and heavier compounds that includes supplying the high pressure absorber with recycled residue gas reflux and/or feed streams and a split inlet gas feed stream. 
     FIG. 7 a  is an alternate embodiment of the process in FIG. 7 that includes a cold absorber and supplying the cold absorber with split inlet gas feed streams. 
     FIG. 8 is an alternate embodiment of the process in FIG. 7 that includes supplying the high pressure absorber with recycle gas reflux and/or feed streams, but without the split feed inlet gas streams. 
    
    
     DETAILED DESCRIPTION OF PREFERRED EMBODIMENT 
     Natural gas and hydrocarbon streams, such as refinery and petrochemical plants&#39; off gases, include methane, ethylene, ethane, propylene, propane, butane and heavier compounds in addition to other impurities. Pipeline sales of natural gas is comprised mostly of methane with varying amounts of other light compounds, such as hydrogen, ethylene and propylene. Ethane, ethylene and heavier compounds, referred to as natural gas liquids, must be separated from such natural gas streams to yield natural gas for pipeline sales. A typical lean natural gas stream contains approximately 92% methane, 4% ethane and other C 2  compounds, 1% propane and other C 3  compounds, and less than 1% of C 4  and heavier compounds in addition to small amounts of nitrogen, carbon dioxide and sulfur-containing compounds, based on molar concentrations. The amounts of C 2  compounds and heavier compounds and other natural gas liquids are higher for rich natural gas streams. In addition, refinery gas may include other gases, including hydrogen, ethylene and propylene. 
     As used herein, the term “inlet gas” means a hydrocarbon gas that is substantially comprised of 85% by volume methane, with the balance being C 2  compounds, C 3  compounds and heavier compounds as well as carbon dioxide, nitrogen and other trace gases. The term “C 2  compounds” means all organic compounds having two carbon atoms, including aliphatic species such as alkanes, olefins, and alkynes, particularly, ethane, ethylene, acetylene and the like. The term “C 3  compounds” means all organic compounds having three carbon atoms, including aliphatic species such as alkanes, olefins, and alkynes, and, in particular, propane, propylene, methyl-acetylene and the like. The term “heavier compounds” means all organic compounds having four or more carbon atoms, including aliphatic species such as alkanes, olefins, and alkynes, and, in particular, butane, butylene, ethyl-acetylene and the like. The term “lighter compounds” when used in connection with C 2  or C 3  compounds means organic compounds having less than two or three carbon atoms, respectively. As discussed herein, the expanding steps, preferably by isentropic expansion, may be effectuated with a turbo-expander, Joules-Thompson expansion valves, a liquid expander, a gas or vapor expander or the like. Also, the expanders may be linked to corresponding staged compression units to produce compression work by substantially isentropic gas expansion. 
     The detailed description of preferred embodiments of this invention is made with reference to the liquefaction of a pressurized inlet gas, which has an initial pressure of about 700 psia at ambient temperature. Preferably, the inlet gas will have an initial pressure between about 500 to about 1500 psia at ambient temperature. 
     Referring now to FIGS. 1 through 5 of the drawings, a preferred embodiment of the cryogenic gas separation process of the present invention is shown configured for improved recovery of C3 compounds and heavier compounds. This process utilizes a two-column system that includes an absorber column and a sequentially-configured or downstream fractionation column. Absorber  18  is an absorber column having at least one vertically spaced tray, one or more packed beds, any other type of mass transfer device, or a combination thereof. Absorber  18  is operated at a pressure P that is substantially greater than and at a predetermined differential pressure from a sequential configured or downstream fractionation column. The predetermined differential pressure between the high pressure absorber and the fractionation column is about 50 psi-350 psi in all embodiments of the invention. An example of this differential pressure would be if the absorber pressure is 800 psig, then the fractionation column pressure could be 750 psig to 450 psig, depending upon the differential pressure chosen. The preferable differential pressure is typically 50 psi. Fractionation column  22  is a fractionation column having at least one vertically spaced chimney tray, one or more packed bed or a combination thereof. 
     A pressurized inlet hydrocarbon gas stream  40 , preferably a pressurized natural gas stream, is introduced to cryogenic gas separation process  10  for improved recovery of C 3  compounds and heavier compounds at a pressure of about 900 psia and ambient temperature. Inlet gas stream  40  is typically treated in a treatment unit (not shown) to remove acid gases, such as carbon dioxide, hydrogen sulfide, and the like, by known methods such as desiccation, amine extraction or the like. In accordance with conventional practice in cryogenic processes, water has to be removed from inlet gas streams to prevent freezing and plugging of the lines and heat exchangers at the low temperatures subsequently encountered in the process. Conventional dehydration units are used which include gas desiccants and molecular sieves. 
     Treated inlet gas stream  40  is cooled in front end exchanger  12  by heat exchange contact with a cooled absorber overhead stream  46 , absorber bottom stream  45  and cold separator bottom stream  44 . In all embodiments of this invention, front end exchanger  12  may be a single multi-path exchanger, a plurality of individual heat exchangers, or combinations thereof. The high pressure cooled inlet gas stream  40  is supplied to cold separator  14  where a first vapor stream  42  is separated from a first liquid stream  44 . 
     The first vapor stream  42  is supplied to expander  16  where this stream is isentropically expanded to the operating pressure P 1  of absorber  18 . The first liquid stream  44  is expanded in expander  24  and then supplied to front end exchanger  12  and warmed. Stream  44  is then supplied to a mid-column feed tray of fractionation column  22  as a first fractionation feed stream  58 . Expanded first vapor stream  42   a  is supplied to a mid-column or lower feed tray of absorber  18  as a first absorber feed stream. 
     Absorber  18  is operated at a pressure P 1  that is substantially greater than and at a predetermined differential pressure from a sequential configured or downstream fractionation column. The absorber operating pressure P may be selected on the basis of the richness of the inlet gas as well as the inlet gas pressure. For lean inlet gas having lower NGL content, the absorber may be operated at relatively high pressure that approaches inlet gas pressure, preferably above about 500 psia. In this case, the absorber produces a very high pressure overhead residue gas stream that requires less recompression duty for compressing such gas to pipeline specifications. For rich inlet gas streams, the absorber pressure P is from at least above 500 psia. In absorber  18 , the rising vapors in first absorber feed stream  42  a are at least partially condensed by intimate contact with falling liquids from absorber feed stream  70  thereby producing an absorber overhead stream  46  that contains substantially all of the methane, C 2  compounds and lighter compounds in the expanded vapor stream  42   a . The condensed liquids descend down the column and are removed as absorber bottom stream  45 , which contains a major portion of the C 3  compounds and heavier compounds. 
     Absorber overhead stream  46  is removed to overhead exchanger  20  and is warmed by heat exchange contact with absorber bottom stream  45 , fractionation column overhead stream  60  and compressed second vapor stream  68 . Compressed second vapor stream  68  contains a major portion of the methane in the fractionation feed stream and second fractionation feed stream. When the heavy key component is C 3  compounds and heavier compounds, then the compressed second vapor stream  68  contains a major portion of the C 2  compounds in the fractionation feed stream and second fractionation feed stream. Stream  45  is expanded and cooled in expander  23  prior to entering overhead exchanger  20 . (Alternatively, a portion of first liquid stream  44  may be supplied to the overhead exchanger  20  as stream  44   b  to provide additional cooling to these process streams before being supplied to the front end exchanger  12  as stream  53 . Upon leaving overhead exchanger  20 , stream  53  can either be fed into the fractionation column  22  or combined with stream  58 .) Absorber overhead stream  46  is further warmed in front end exchanger  12  and compressed in booster compressor  28  to a pressure of above about 800 psia or pipeline specifications to form residue gas  50 . Residue gas  50  is a pipeline sales gas that contains substantially all of the methane and C 2  compounds in the inlet gas, and a minor portion of C 3  compounds and heavier compounds. Absorber bottom stream  45  is further cooled in front end exchanger  12  and supplied to a feed tray of a middle portion of fractionation column  22  as a second fractionation column feed stream  48 . By virtue of the predetermined high pressure differential between absorber  18  and fractionation column  22 , the absorber bottom stream  48  may be supplied to the fractionation column  22  without a pump. 
     Fractionation column  22  is operated at a pressure P 2  that is lower than and at a predetermined differential pressure DP from a sequential configured or upstream absorber column, preferably where P 2  is above about 400 psia for such gas streams. For illustrative purposes, if P 2  is 400 psia and DP is 150 psi, then P 1  is 550 psia. The fractionation column feed rates, as well as temperature and pressure profiles, may be selected to obtain an acceptable separation efficiency of the compounds in the liquid feed streams, as long as the set differential pressure between the fractionation column and the absorber is maintained. In fractionation column  22 , first feed stream  48  and second feed stream  58  are supplied to one or more mid-column feed trays to produce a bottom stream  72  and an overhead stream  60 . The fractionation column bottom stream  72  is cooled in bottoms exchanger  29  to produce an NGL product stream that contains substantially all of the heavy key components and heavies. A portion of fractionation column bottom stream  72   a  can be refluxed back to fractionation column  22  as shown in FIGS. 1-5. 
     Fractionation column overhead stream  60  is at least partially condensed in overhead condenser  20  by heat exchange contact with absorber overhead and bottom streams  46 ,  45  and/or first liquid portion stream  53 . The at least partially condensed overhead stream  62  is separated in overhead separator  26  to produce a second vapor stream  66  that contains a major portion of methane, C2 and lighter compounds and a liquid stream that is returned to fractionation column  22  as fractionation reflux stream  64 . Fractionation reflux stream  64  can be pumped to fractionation column  22  by using pump  25  as shown in FIGS. 1-3. The second vapor stream  66  is supplied to overhead compressor  27  and compressed essentially to the operating pressure P of absorber  18 . The compressed second vapor stream  68  is at least partially condensed in overhead exchanger  20  by heat exchange contact with absorber overhead and bottom streams  46 ,  45  and/or first liquid portion stream  53 . The condensed and compressed second vapor stream is supplied to absorber  18  as reflux stream  70 . The compressed second vapor stream contains a major portion of the methane in the fractionation feed streams. When the heavy key component is C3 compounds and heavier compounds, then the compressed second vapor stream contains a major portion of the C2 compounds in the fractionation feed streams. 
     By way of example, the molar flow rates of the pertinent streams in FIG. 1 are shown in Table I as follows: 
     
       
         
           
               
             
               
                 TABLE I 
               
             
            
               
                   
               
               
                 Stream Flow Rates - Lb. Moles/Hr. 
               
            
           
           
               
               
               
               
               
               
               
               
               
            
               
                   
                   
                   
                   
                   
                   
                   
                   
                 Pressure 
               
               
                 Stream 
                 CO 2   
                 N 2   
                 C 1   
                 C 2   
                 C 3   
                 C 4+   
                 Total 
                 psia 
               
               
                   
               
            
           
           
               
               
               
               
               
               
               
               
               
            
               
                 40 
                 123 
                 114 
                 18,777 
                 2,237 
                 806 
                 635 
                 22,692 
                 1,265 
               
               
                 42 
                 111 
                 111 
                 17,696 
                 1,901 
                 586 
                 273 
                 20,677 
                 1,255 
               
               
                 48 
                 29 
                 3 
                 1,663 
                 1,001 
                 586 
                 273 
                 3,554 
                 483 
               
               
                 50 
                 123 
                 114 
                 18,777 
                 2,184 
                 8 
                 0 
                 21,206 
                 1,265 
               
               
                 58 
                 12 
                 3 
                 1,081 
                 336 
                 221 
                 362 
                 2,016 
                 453 
               
               
                 60 
                 41 
                 6 
                 2,744 
                 1,284 
                 8 
                 0 
                 4,084 
                 425 
               
               
                 70 
                 41 
                 6 
                 2,744 
                 1,284 
                 8 
                 0 
                 4,084 
                 558 
               
               
                 72 
                 0 
                 0 
                 0 
                 53 
                 798 
                 635 
                 1,486 
                 435 
               
               
                   
               
            
           
         
       
     
     FIG. 2 depicts a variation to the process in FIG.  1 . Here, the absorber bottom stream  45  is expanded in expander  23  and at least partially condensed in overhead exchanger  20 , forming stream  45   a . Stream  45   a  consists of a liquid and a vapor hydrocarbon phase, which is separated in vessel  30 . The liquid phase stream  45   b  is split into two streams,  45   c  and  45   d . Stream  45   d  is fed directly to the fractionation column  22  without any further heating. Stream  45   c  can very between 0% to 100% of stream  45   b . The vapor stream  45   e  from vessel  30  is combined with stream  45   c  and is further heated in front end exchanger  12  by heat exchange contact with inlet gas stream  40  before entering the fractionation column  22 . 
     FIGS. 3 through 5 show alternate preferred embodiments of this invention. In FIG. 3, a mechanical refrigeration system  33  is used to at least partially condense fractionation column overhead stream  60  to produce an at least partially condensed stream  62 . The at least partially condensed stream  62  is separated in separator  26 , as noted above. Such mechanical refrigeration systems include propane refrigerant-type systems.—In FIG. 4, an internal condenser  31  within fractionation column  22  is used to at least partially condense fractionation column overhead using stream  46 . The absorber overhead stream  46  is warmed by heat exchange in the internal condenser and emerges as internal condenser outlet stream  76 , which is warmed by heat exchange contact with other process streams in front end exchanger  12 . FIG. 5 depicts the same process shown in FIG. 4, but with the addition of the mechanical refrigeration system from the process depicted in FIG. 3, which can be used as an external refrigeration system for the internal condenser. In this embodiment, absorber bottoms stream  45  is cooled in overhead exchanger  20  and front end exchanger  12  and then expanded in expander  23  prior to being sent to fractionation column  22  as a mid column feed stream  78 . In all embodiments, the fractionation bottom stream contains substantially all of the heavies. 
     FIGS. 6 through 8 show still another preferred embodiment of the cryogenic gas separation process of the present invention, configured for improved recovery of C 2  compounds and heavier compounds. This process utilizes a similar two-column system, as noted above. Pressurized inlet hydrocarbon gas stream  40 , preferably a pressurized natural gas stream, is introduced to cryogenic gas separation process  100  operating in C 2  recovery mode at a pressure of about 900 psia and ambient temperature. Treated inlet gas  40  is divided into to streams  40   a ,  40   b . Inlet gas stream  40   a  is cooled in front end exchanger  12  by heat exchange contact with stream  150 , which is formed by warming absorber overhead stream  146  in overhead exchanger  20 . 
     Inlet gas stream  40   b  is used to provide heat to side reboilers  32   a ,  32   b  of fractionation column  22  and is cooled thereby. Stream  40   b  is first supplied to lower side reboiler  32   b  for heat exchange contact with liquid condensate  127  that is removed from a tray below the lowest feed tray of fractionation column  22 . Liquid condensate  127  is thereby warmed and redirected back to a tray below that from which it was removed. Stream  40   b  is next supplied to upper side reboiler  32   a  for heat exchange contact with liquid condensate  126  that is removed from a tray below the lowest feed tray of fractionation column  22  but above the tray from which liquid condensate  127  was removed. Liquid condensate  126  is thereby warmed and redirected back to a tray below that from which it was removed, but above the tray from which liquid condensate  127  was removed. Stream  40   b  is cooled and at least partially condensed and then recombined with cooled stream  40   a . The combined streams  40   a ,  40   b  are supplied to cold separator  14  that separates these streams, preferably, by flashing off a first vapor stream  142  from a first liquid stream  144 . First liquid stream  144  is expanded in expander  24  and supplied to a mid-column feed tray of fractionation column  22  as a first fractionation feed stream  158 . A slip stream  144   a  from first liquid stream  144  can be combined with second expanded vapor stream  142   b  and supplied to overhead exchanger  20 . 
     At least a portion of first vapor stream  142  is expanded in expander  16  and then supplied to absorber  18  as an expanded vapor stream  142   a . The remaining portion of first vapor stream  142 , second expanded vapor stream  142   b , is supplied to overhead condenser  20  and is at least partially condensed by heat exchange contact with other process streams, noted below. The at least partially condensed second expanded vapor stream  142   b  is supplied to a middle region of absorber  18  after being expanded in expander  35 , preferably as second absorber feed stream  151 , which is rich in C 2  compounds and lighter compounds. 
     Absorber  18  produces an overhead stream  146  and a bottom stream  145  from the expanded vapor stream  142   a , a second absorber feed stream  151 , and absorber feed stream  170 . 
     In absorber  18 , the rising vapors in the expanded vapor stream  142   a  and second absorber feed stream  151 , discussed below, are at least partially condensed by intimate contact with falling liquids from absorber feed stream  170  thereby producing an absorber overhead stream  146  that contains substantially all of the methane and lighter compounds in the expanded vapor stream  142   a  and second expanded vapor stream  142   b . The condensed liquids descend down the column and are removed as absorber bottom stream  145  that contains a major portion of the C 2  compounds and heavier compounds. 
     Absorber overhead stream  146  is removed to overhead exchanger  20  and is warmed by heat exchange contact with second expanded vapor stream  142   b  and compressed second vapor stream  168 . Absorber overhead stream  146  is further warmed in front end exchanger  12  as stream  150  and compressed in expander-booster compressors  28  and  25  to a pressure of at least above about 800 psia or pipeline specifications to form residue gas  152 . Residue gas  152  is a pipeline sales gas that contains substantially all of the methane in the inlet gas and a minor portion of C 2  compounds and heavier compounds. Absorber bottom stream  145  is expanded and cooled in expansion means, such as expansion valve  23 , and supplied to a mid-column feed tray of fractionation column  22  as a second fractionation feed stream  148 . By virtue of the high pressure differential between absorber  18  and fractionation column  22 , the absorber bottom stream  145  may be supplied to the fractionation column  22  without a pump. 
     Fractionation column  22  is operated at a pressure that is substantially lower than of absorber  18 , preferably above about 400 psia. The fractionation column feed rates as well as temperature and pressure profiles may be selected to obtain an acceptable separation efficiency of the compounds in the liquid feed streams, as long as the set differential pressure between the fractionation column and the absorber is maintained, i.e., 150 psi. First feed stream  158  and second fractionation feed stream  148  are supplied at one or more feed trays near a middle portion of fractionation column  22  to produce a bottom stream  172  and an overhead stream  160 . The fractionation column bottom stream  172  can be cooled to produce an NGL product stream that contains a majority of the heavy key component and heavies. 
     Fractionation column overhead stream  160  is supplied to overhead compressor  27  and compressed essentially to the operating pressure P of absorber  18  as compressed second vapor stream  168 . Compressed second vapor stream  168  is at least partially condensed in overhead condenser  20  by heat exchange contact with absorber overhead stream  146  and second expanded vapor stream  142   b . The at least partially condensed overhead stream  168  is sent to absorber  18  as second absorber feed stream  151 . 
     By way of example, the molar flow rate of the pertinent streams of FIG. 6 are shown in Table II as follows. 
     
       
         
           
               
             
               
                 TABLE II 
               
             
            
               
                   
               
               
                 Stream Flow Rates - Lb. Moles/Hr. 
               
            
           
           
               
               
               
               
               
               
               
               
               
            
               
                   
                   
                   
                   
                   
                   
                   
                   
                 Pressure, 
               
               
                 Stream 
                 N 2   
                 CO 2   
                 C 1   
                 C 2   
                 C 3   
                 C 4+   
                 Total 
                 psia 
               
               
                   
               
            
           
           
               
               
               
               
               
               
               
               
               
            
               
                   40 
                 82.1 
                 287.1 
                 16,913.0 
                 1,147.2 
                 520.8 
                 186.9 
                 19,137.0 
                 1290 
               
               
                 142 
                 82.1 
                 287.1 
                 16,913.0 
                 1,147.2 
                 520.8 
                 186.9 
                 19,137.0 
                 1270 
               
               
                 142a 
                 60.6 
                 212.1 
                 12,494.1 
                 847.4 
                 384.7 
                 138.0 
                 14,137.0 
                 550 
               
               
                 142b 
                 21.4 
                 75.0 
                 4,418.9 
                 299.7 
                 136.1 
                 48.8 
                 5,000.0 
                 1270 
               
               
                 148 
                 5.1 
                 192.7 
                 3,440.9 
                 1,078.7 
                 524.3 
                 187.2 
                 5,428.8 
                 375 
               
               
                 151 
                 5.1 
                 49.9 
                 3,421.1 
                 101.3 
                 7.2 
                 0.4 
                 3,584.9 
                 550 
               
               
                 152 
                 82.1 
                 144.2 
                 16,893.1 
                 169.7 
                 3.7 
                 0.1 
                 17,293.0 
                 1315 
               
               
                 160 
                 5.1 
                 49.9 
                 3,421.4 
                 101.3 
                 7.2 
                 0.4 
                 3,585.1 
                 360 
               
               
                 170 
                 21.4 
                 75.0 
                 4,418.9 
                 299.7 
                 136.1 
                 48.8 
                 5,000.0 
                 550 
               
               
                 172 
                 — 
                 142.8 
                 19.5 
                 977.4 
                 517.1 
                 186.8 
                 1,843.7 
                 365 
               
               
                   
               
            
           
         
       
     
     FIGS. 6 a  through  8  show other preferred embodiments of the cryogenic gas separation process for improved recovery of C2 compounds and heavier compounds in which the high pressure absorber receives streams rich in C2 compounds and lighter compounds to improve separation efficiency. FIG. 6 a  contains another embodiment of the process shown in FIG.  6 . In FIG. 6 a , a cold absorber  114  with one or more mass transfer stages is used instead of a cold separator  14 . Feed stream  40  is split into two separate feed streams  40   a  and  40   b  in this process variation. Stream  40   a  is cooled in front end exchanger  12  by heat exchange contact with the absorber overheads stream  150  and emerges as stream  40   c . Stream  40   b  is cooled in the reboilers  32   a  and  32   b  by heat exchange contact with streams  126  and  127  respectively and emerges as stream  40   d . The colder of the two streams,  40   c  and  40   d , is fed to the top of the cold absorber  14  with the warmer of the two streams,  40   c  and  40   d , being fed to the bottom of the cold absorber  14 . Additionally, at least a portion of the first liquid stream  144  can be split as stream  144   a  and combined with the second expanded vapor stream  142   b  discussed above. 
     FIG. 7 depicts an alternative to the cryogenic C 2 + recovery process shown in FIG.  6 . Here, the first vapor stream  142  from the cold separator  14  passes through expander  16  as expanded vapor stream  142   a  without splitting prior to entering the expander  16 . Expanded vapor stream  142   a  is fed to the lower portion of absorber  18  in its entirety, instead of being split into expanded vapor stream  142   a  and second expanded vapor stream  142   b . The absorber  18  also is supplied with a second absorber feed stream  151 . The second absorber feed stream  151  is produced by taking a slip stream of the residue gas  152 , heating it in overhead exchanger  20 , expanding it in expander  35  and supplying it to absorber  18  as second absorber feed stream  151 . The absorber feed stream  170  remains the same as in FIG.  6 . 
     FIG. 7 a  contains another embodiment of the process shown in FIG.  7 . In FIG. 7 a , a cold absorber  114  with one or more mass transfer stages is used instead of a cold separator  14 . Feed stream  40  is split into two separate feed streams  40   a  and  40   b  in this particular embodiment of the process. Stream  40   a  is cooled in front end exchanger  12  by heat exchange contact with the absorber overhead stream  150  and emerges as stream  40   c . Stream  40   b  is cooled in the reboilers  32   a  and  32   b  by heat exchange contact with streams  126  and  127  respectively and emerges as stream  40   d . The colder of the two streams,  40   c  and  40   d , is fed to the top of the cold absorber  114  with the warmer of the two streams,  40   c  and  40   d , being fed to the bottom of the cold absorber  114 . 
     FIG. 8 depicts a further embodiment of the C2+ recovery process. In this particular process embodiment, the inlet gas stream  40  is cooled in front end exchanger  12  and fed to cold separator  14 . The first vapor stream  142  is expanded in expander  16  and fed to absorber  18  as expanded vapor stream  142   a . Expanded vapor stream  142   a  is fed to the lower portion of absorber  18  in its entirety, as opposed to being split into streams  142   a  and  142   b  as in previously discussed embodiments. Two other absorber feed streams exist in the present embodiment of the process. Fractionation column overhead vapor stream  160  is compressed and expanded in compressor  27  to the same pressure as the absorber  18  and exits as compressed second vapor stream  168 . Fractionation bottom stream contains substantially all of the heavy key component. Compressed second vapor stream  168  is at least partially condensed in overhead exchanger  20  and fed to absorber  18  as second absorber feed stream  151 . A second expanded vapor stream  151 ′ of residue gas stream  152  is heated in reboilers  32   a  and  32   b , at least partially condensed in overhead exchanger  20 , and expanded to the same pressure as the absorber  18  in expander  35 , and fed to the absorber  18 . 
     There are significant advantages to the present invention wherein the absorber operating pressure is substantially greater than and at a predetermined differential pressure from a sequentially configured or downstream fractionation column for recovery of C 2  compounds and/or C 3  compounds and heavier compounds. First, the recompression horsepower duty may be decreased, thereby increasing gas processing throughput. This is particularly true for high pressure inlet gas. Recompression horsepower duty is mostly attributable to expansion of the inlet gas to the lower, operating pressure of the absorber. The residue gas produced in the absorber is then recompressed to pipeline specifications. By increasing the absorber operating pressure, less gas compression is needed. In addition to the lower recompression horsepower duty requirements for the gases, other advantages exist. The overhead compressor controls the pressure of the fractionation column  22 , which prevents the fractionation column from pressuring up, particularly during startup of the process. The absorber pressure is allowed to rise and acts like a buffer to protect the fractionation column, which increases the safety in operating the fractionation column. Since the fractionation column of the current invention can be designed for operating pressures lower than the prior art, initial capital costs for the column are reduced. Another advantage over the prior art is that the overhead compressor will maintain the column within the proper operating range, i.e., avoiding upset, since there is not a loss of separation efficiency. 
     Second, the present invention allows for more adjustment of the temperature and pressure profile of a sequentially configured or downstream fractionation column to optimize separation efficiency and heat integration. In the case of a rich inlet gas stream, the present invention allows the fractionation column to be operated at lower pressure and/or lower temperature for improved separation of C 2  compounds and/or C 3  compounds and heavier compounds. Also, operating the fractionation column at a lower pressure reduces the heat duty of the column. Heat energy contained in various process stream may be used for fractionation column side reboiler duty or overhead condenser duty or to pre-cool inlet gas streams. 
     Third, energy and heat integration of the separation process is improved by operating the absorber at higher pressure. The energy contained in high pressure liquid and vapor streams from the absorber, for example, may be tapped by coupling isentropic expansion steps, such as in a turbo expander, with gas compression steps. 
     Finally, the invention allows for the elimination of liquid pumps between the absorber and the fractionation column and the capital cost associated with such. All streams between the columns may flow by the pressure differentials between the columns. 
     While the present invention has been described and/or illustrated with particular reference to the process for the separation of gaseous hydrocarbons compounds, such as natural gas, it is noted that the scope of the present invention is not restricted to the embodiment(s) described. It should be apparent to those skilled in the art that the scope of the invention includes other methods and applications using other equipment or processes than those specifically described. Moreover, those skilled in the art will appreciate that the invention described above is susceptible to variations and modifications other than those specifically described. It is understood that the present invention includes all such variations and modifications which are within the spirit and scope of the invention. It is intended that the scope of the invention not be limited by the specification, but be defined by the claims set forth below.