Abstract:
Increasing the economic and environmental compatibility in treatment processes in sour gas production. For 25 yr, Mobil Erdgas Erdoel GmbH (MEEG) has been treating considerable amounts of sour gas in N. Germany. In 9 fields with different gas qualities, there are ca 30 producing wells. The main processes of the sour gas production and treatment are described. The gas is dried at the well site and if the reservoir pressure is not sufficient, compressed for transportation to the central processing facility. In most cases the use of sulfur solvents is necessary at the wells. Natural gas scrubbers for the total removal of hydrogen sulfide and Claus units with downstream units to obtain sulfur are utilized. To increase the environmental compatibility and economics, a number of secondary processes have been introduced for emission control; glycol stripping; and the Purisol, Selexol, Sulfinol, and Claus processes.

Description:
FIELD OF THE INVENTION 
     The invention relates generally to fluid separation and, more particularly, an Integrated Gasification Combined Cycle (IGCC) system for generating electricity and/or steam as well as isolating multiple components from a synthesis gas stream. 
     BACKGROUND OF THE INVENTION 
     Gasification is a commercially proven technology that efficiently converts petroleum coke, coal, heavy oil streams and even natural gas into synthesis gas through a non-combustion, partial oxidation reaction. 
     Synthesis gas can be used as a cleaner-burning fuel for gas turbines, such as in an IGCC system, to produce electricity and/or steam. In addition to generating electricity and/or steam, synthesis gas can also be used to generate hydrogen for use in heavy oil upgraders and hydroprocessing units in a refinery. Further, synthesis gas components such hydrogen, carbon monoxide, carbon dioxide and nitrogen constitute the basic building blocks of may valuable chemical products such as oxo-alcohols, methanol, ammonia, Fischer-Tropsch liquids, e.g., ultra-low sulfur diesel, plastics and chemical fertilizers. 
     The raw synthesis gas stream is typically subjected to one or more separation processes depending on the type of products to be produced by the IGCC system. One gas separation process which is generally necessary in an IGCC system is the selective removal of sulfur compounds such as carbonyl sulfide and hydrogen sulfide from the raw synthesis gas. 
     The removal of such sulfur-containing compounds is desirable for many reasons, depending in part upon the intended use of the final gas product. Since a large percentage of the produced synthesis gas is typically used as fuel in a gas turbine, the presence of sulfur-containing compounds is generally objectionable because of one or more concerns such as, involving: safety, corrosion and pollution as well as the unpleasant odor commonly associated with the sulfur-containing compounds. Additionally, such sulfur-containing compounds can have a deleterious effect on downstream equipment and systems used for the production of hydrogen and other chemicals. 
     One separation technique used to remove sulfur-containing compounds from the raw synthesis gas stream involves contacting the raw synthesis gas stream with a solvent to selectively absorb the sulfur-containing compounds. However, as the liquid solvent selectively absorbs sulfur compounds from the raw synthesis gas stream, it also co-absorbs carbon dioxide. The co-absorbed carbon dioxide, if not removed upstream of a sulfur recovery unit such as, for example, a Claus unit, can negatively impact the capital and operating costs of the sulfur recovery unit. Advantageously, recovery of the co-absorbed carbon dioxide results in additional power generation. 
     Using nitrogen to strip co-absorbed carbon dioxide from the liquid solvent presents advantages over using treated, i.e., sulfur-free, synthesis gas. For example, hydrogen losses from the sulfide absorption unit are minimized if nitrogen is used. 
     Although nitrogen is readily available from an air separation unit supplying the oxygen required for gasification, the purity of the nitrogen stream used for stripping typically needs to be upgraded from about 97% to 99.9% by volume. Further, depending on where the nitrogen is being utilized within the sulfide absorption unit, compression may be required. As will be appreciated by those skilled in the art, the production or even procurement of the high-purity, compressed nitrogen which is generally required to effectively strip carbon dioxide from the liquid solvent can detrimentally add to the expense associated with the production of desired product gases. 
     Additional processes for removing sulfur-containing compounds and/or carbon dioxide from gas streams are described in U.S. Pat. No. 3,362,133 to Kutsher et al., U.S. Pat. No. 4,330,305 to Kuessner et al., U.S. Pat. No. 5,861,051 to Critchfield et al., and U.S. Pat. No. 6,203,599 to Schubert et al. 
     In addition to a sulfide absorption unit, a synthesis gas processing block typically also includes one or more purification and/or recovery units such as, for example, a sulfur recovery unit and hydrogen separation and purification units. Such purification and/or recovery units generally produce byproduct or waste streams which may contain residual levels of the components desirably isolated by the purification and/or recovery units such as, for example, carbon dioxide, hydrogen and sulfur-containing compounds. Typically, such byproduct or waste streams, depending upon chemical composition, may be recycled into the synthesis gas processing block, off-gassed or combusted as fuel. The fate of such byproduct or waste streams may largely depend upon the costs, both monetary and in terms of energy expenditures, needed to recover the residual levels of desirable compounds. 
     Thus, there is a need and a demand for processing schemes that improve the efficiency and economics of separating at least hydrogen sulfide and carbon dioxide from a fluid stream. 
     There is a further need and a demand for processes for separating at least hydrogen sulfide and carbon dioxide from a fluid stream having reduced dependence upon external gas inputs. 
     There is an additional need and a demand for processes for the separation of hydrogen sulfide and carbon dioxide from a fluid stream which are effective to result in an increased recovery of desired and/or beneficial gases from process byproduct or waste streams. 
     SUMMARY OF THE INVENTION 
     A general objective of the invention is to provide an improved processing scheme and arrangement for generating power and/or steam, and/or producing hydrogen and other industrially useful chemical components from a fluid stream, such as a gasifier effluent stream in an integrated gasification combined cycle (IGCC) system. 
     A more specific objective of the invention is to overcome one or more of the problems described above. 
     The general object of the invention can be attained, at least in part, through a processing scheme for separating carbon dioxide from a fluid stream including at least hydrogen sulfide, carbon dioxide and hydrogen. In accordance with one embodiment, such a processing scheme involves contacting the fluid stream with a solvent in an absorbent zone to form a hydrogen sulfide-rich solvent stream and a sulfur-free fluid stream. The hydrogen sulfide-rich solvent stream contains at least hydrogen sulfide and a first portion of the carbon dioxide. The sulfur-free fluid stream includes at least hydrogen and a second portion of the carbon dioxide. The processing scheme further involves contacting at least one first gas permeable membrane element in a first membrane separation zone with a first portion of the sulfur-free fluid stream to produce a hydrogen-enriched permeate stream and a first non-permeate stream containing at least carbon dioxide. A first portion of the first non-permeate stream contacts at least one second gas permeable membrane element in a second membrane separation zone to produce a carbon dioxide-enriched permeate stream and a second non-permeate stream. At least a portion of the second non-permeate stream contacts the hydrogen sulfide-rich solvent stream in a carbon dioxide stripping zone to produce a hydrogen sulfide-enriched solvent stream and a carbon dioxide-enriched fluid stream. 
     The prior art generally fails to provide a processing scheme and arrangement that is as economical and efficient in generating power, steam, hydrogen and/or other industrially beneficial compounds as may be desired compared to conventional processes such as may be used in IGCC systems. 
     In accordance with another embodiment, a processing scheme for separating hydrogen sulfide and carbon dioxide from a fluid stream containing at least hydrogen sulfide, carbon dioxide and hydrogen involves contacting the fluid stream with a solvent in an absorption zone to produce a hydrogen sulfide-rich solvent stream and a sulfur-free fluid stream. The hydrogen sulfide-rich solvent stream includes at least hydrogen sulfide and a first portion of the carbon dioxide. The sulfur-free fluid stream includes at least hydrogen and a second portion of the carbon dioxide. The processing scheme further involves contacting at least one hollow fiber membrane element in a first membrane separation zone with a first portion of the sulfur-free fluid stream to produce a hydrogen-enriched permeate stream and a first non-permeate stream containing at least carbon dioxide. A first portion of the first non-permeate stream is treated by contacting at least one spiral wound membrane element in a second membrane separation zone to produce a carbon dioxide-enriched permeate stream and a second non-permeate stream. The second non-permeate stream contains less than five percent by volume carbon dioxide. The processing scheme still further involves treating the hydrogen-enriched permeate stream in a pressure swing adsorption unit to produce a purified hydrogen stream and a pressure swing adsorption tail gas stream. The hydrogen sulfide-rich solvent stream is treated by contacting the hydrogen sulfide-rich solvent stream with at least a portion of the second non-permeate stream in a carbon dioxide stripping zone to produce a hydrogen sulfide-enriched solvent stream and a carbon dioxide-enriched fluid stream. The hydrogen sulfide-enriched solvent stream is treated in a hydrogen sulfide stripping zone to produce a hydrogen sulfide-depleted solvent stream and a hydrogen sulfide-enriched fluid stream. The hydrogen sulfide-enriched fluid stream is treated in a sulfur recovery unit to produce an elemental sulfur stream and a sulfur recovery tail gas stream. The processing scheme additionally involves combining at least a portion of the pressure swing adsorption tail gas stream with the sulfur recovery tail gas stream to produce a combined tail gas stream. At least a first portion of the combined tail gas stream is combined with the fluid stream containing at least hydrogen sulfide, carbon dioxide and hydrogen prior to entering the absorption zone. 
     In accordance with a further embodiment, a processing scheme for separating hydrogen sulfide and carbon dioxide from a fluid stream containing at least hydrogen sulfide, carbon dioxide and hydrogen involves contacting the fluid stream with a physical solvent in an acid gas separation zone to produce at least a sulfur-free fluid stream, a carbon dioxide-enriched fluid stream and a hydrogen sulfide-enriched fluid stream. The sulfur-free fluid stream includes at least hydrogen and a first portion of the carbon dioxide. The hydrogen sulfide-enriched fluid stream includes at least hydrogen sulfide. The processing scheme further involves contacting at least one gas permeable membrane element in a membrane separation zone with a first portion of the sulfur-free fluid stream to produce at least a hydrogen-enriched permeate stream and a non-permeate stream. At least a portion of the hydrogen-enriched permeate stream is treated in a pressure swing adsorption unit to produce a purified hydrogen stream and a pressure swing adsorption tail gas stream. The hydrogen sulfide-enriched fluid stream is treated in a sulfur recovery unit to produce an elemental sulfur stream and a sulfur recovery tail gas stream. The processing scheme additionally involves combining at least a portion of the pressure swing adsorption tail gas stream with the sulfur recovery tail gas stream to produce a combined tail gas stream. The combined tail gas stream is compressed in a compression zone to produce a compressed tail gas stream. At least a first portion of the compressed tail gas stream is combined with the fluid stream to produce a combined fluid stream which is subsequently treated in the acid gas separation zone. 
     The invention further comprehends a system for separating hydrogen sulfide and carbon dioxide from a fluid stream containing at least hydrogen sulfide, carbon dioxide and hydrogen. The system includes an absorbent zone wherein a solvent contacts the fluid stream to produce a hydrogen sulfide-rich solvent stream containing at least hydrogen sulfide and a first portion of the carbon dioxide, and a sulfur-free fluid stream containing at least hydrogen and a second portion of the carbon dioxide. The system further includes at least one membrane separation zone. The at least one membrane zone includes at least one gas permeable membrane element wherein a first portion of the sulfur-free fluid stream contacts the at least one gas permeable membrane element to produce a hydrogen-enriched permeate stream and a non-permeate stream. The system also includes a pressure swing adsorption unit wherein at least a portion of the hydrogen-enriched permeate stream is treated to produce a purified hydrogen stream and a pressure swing adsorption tail gas stream. The system additionally includes a carbon dioxide stripping zone wherein at least a portion of the non-permeate stream contacts the hydrogen sulfide-rich solvent to produce a carbon dioxide-enriched fluid stream and a hydrogen sulfide-enriched solvent stream, and a hydrogen sulfide stripping zone wherein at least a portion of the hydrogen sulfide-enriched solvent is treated to produce a hydrogen sulfide-depleted solvent and a hydrogen sulfide-enriched fluid stream. The system further includes a sulfur recovery unit wherein at least a portion of the hydrogen sulfide-enriched fluid stream is treated to produce an elemental sulfur stream and a sulfur recovery tail gas stream. 
     Other objectives and advantages will be apparent to those skilled in the art from the following detailed description taken in conjunction with the appended claims and drawings. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a simplified schematic of an improved processing scheme for the separation of hydrogen sulfide and carbon dioxide from a fluid stream containing at least hydrogen sulfide carbon dioxide and hydrogen in accordance with one embodiment. 
         FIG. 2  is a simplified schematic of an improved processing scheme for the separation of hydrogen sulfide and carbon dioxide from a fluid stream containing at least hydrogen sulfide carbon dioxide and hydrogen in accordance with another embodiment. 
         FIG. 3  is a simplified schematic of an improved processing scheme for the separation of hydrogen sulfide and carbon dioxide from a fluid stream containing at least hydrogen sulfide carbon dioxide and hydrogen in accordance with a further embodiment. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     Integrated gas combined cycle (IGCC) processes generally include several separation, recovery and/or purification processes to treat a fluid stream containing at least hydrogen sulfide, carbon dioxide and hydrogen produced from the gasification of a hydrocarbon-containing feedstock in a gasifier. 
       FIG. 1  schematically illustrates a processing scheme  110  for separating hydrogen sulfide and carbon dioxide from a fluid stream  112  containing at least hydrogen sulfide, carbon dioxide and hydrogen. The processing scheme  110  involves contacting the fluid stream  112  with a solvent  113  in an absorption zone  114  to produce a sulfur-free fluid stream  116  containing at least hydrogen and a first portion of the carbon dioxide, and a hydrogen sulfide-rich solvent stream  115  containing at least hydrogen sulfide and a second portion of the carbon dioxide. As used herein the term “sulfur-free fluid stream” refers to a fluid stream containing less than about I ppm by volume hydrogen sulfide. In accordance with certain embodiments, the sulfur-free fluid stream  116  includes or contains about 35% to about 50% by volume hydrogen. 
     The solvent  113  employed within the absorption zone  114  may be any material which selectively absorbs hydrogen sulfide. Solvents which can be employed in the absorption zone may include, but are not limited to, solvents such as dialkyl ethers of polyethylene glycols such as dimethyl ethers of polyethylene glycols, diethyl ethers of polyethylene glycols, methyl isopropyl ethers of polyethylene glycols and combinations thereof, mono- or diethanolamine, methyldiethanolamine, and promoted methyldiethanolamine solutions such as mixtures of methyldiethanolamine and 2-(2-aminoethoxy)ethanol. The properties and uses of such solvents are more fully described in U.S. Pat. No. 6,203,599 to Schubert et al., U.S. Pat. No. 4,330,305 to Kuessner et al., U.S. Pat. No. 3,362,133 to Kutsher et al., and U.S. Pat. No. 5,861,051 to Critchfield et al.; the contents of each of these patents are hereby incorporated by reference. In accordance with certain embodiments, the solvent employed in the absorption zone  114  includes a dimethyl ether of polyethylene glycol. 
     The processing scheme  110  further involves treating at least a first portion  117  of the sulfur-free fluid stream  116  by contacting at least one first gas permeable membrane element in a first membrane separation zone  118  with the first portion  117  to produce a hydrogen-enriched permeate stream  120  and a first non-permeate stream  122  containing at least carbon dioxide. Such treatment in the first membrane separation zone  118  generally includes a gas membrane separation unit wherein the hydrogen and, in certain embodiments, select additional components contained in the first portion  117  of the sulfur-free fluid stream  116  permeate through the at least one gas permeable membrane element and are collected to produce the hydrogen-enriched permeate stream  120 . Components of the first portion  117  of the sulfur-free fluid stream  116  which do not permeate through the at least one gas permeable membrane element are collected and exit the first membrane separation zone  118  as the first non-permeate stream  122 . In accordance with certain embodiments, the hydrogen-enriched permeate stream  120  may include or contain about 70% to about 90% by volume hydrogen. 
     In accordance with certain embodiments, the first membrane separation zone  118  can include at least one hollow fiber gas permeable membrane element. In accordance with other embodiments, the first membrane separation zone  118  can include a multitude of hollow fiber gas permeable membrane elements connected to form separation arrays. Such separation arrays can generally desirably be employed in industrial installations wherein larger volumes of feedstock are processed. Materials and processes for forming and utilizing hollow fiber gas permeable membrane elements are more fully described in, for example, commonly assigned U.S. Pat. No. 5,411,721 to Doshi et al., the contents of which are hereby incorporated by reference. 
     A first portion  123  of the first non-permeate stream  122  is treated in a second membrane separation zone  124  wherein the first portion  123  contacts at least one second gas permeable membrane element to produce a carbon dioxide-enriched permeate stream  126  and a second non-permeate stream  128  (e.g., a carbon dioxide-lean non-permeate stream). In accordance with certain embodiments, up to about 10% by volume of the first non-permeate stream  122 , i.e., the first portion  123 , can be fed to the second membrane separation zone  124 . 
     Such treatment in the second separation membrane zone  124  generally includes a gas membrane separation unit wherein the carbon dioxide and, in certain embodiments, select additional components contained in the first portion  123  of the first non-permeate stream  122  permeate through the at least one gas permeable membrane element and are collected to produce the carbon dioxide-enriched permeate stream  126 . Components of the first portion  123  of the first non-permeate stream  122  which do not permeate through the at least one gas permeable membrane element are collected and exit the second membrane separation zone  124  as the second non-permeate stream  128 . In accordance with certain embodiments, the second non-permeate stream  128  includes or contains less than about 5% by volume carbon dioxide. In accordance with certain other embodiments, the second non-permeate stream  128  includes or contains less than about 3% by volume carbon dioxide. 
     In accordance with certain embodiments, the second membrane separation zone  124  can include at least one spiral wound gas permeable membrane element. In accordance with other embodiments, the second membrane separation zone  124  can include a multitude of spiral wound gas permeable membrane elements connected to form separation arrays. Such separation arrays can generally be employed in processing schemes wherein in large volumes of feedstock may be processed. Materials and processes for forming and utilizing spiral wound gas permeable membrane elements are more fully described in, for example, commonly assigned U.S. Pat. No. 4,608,060 to Kulprathipanja et al. and commonly assigned U.S. Pat. No. 5,702,503 to Tang; the contents of each of these patents are hereby incorporated by reference. 
     The second non-permeate stream  128 , or at least a select portion thereof, is used to remove the co-absorbed carbon dioxide in the hydrogen sulfide-rich solvent stream  115 . Typically, the co-absorbed carbon dioxide in the hydrogen sulfide-rich solvent stream  115  is desorbed by heating said solvent stream  115  to a desired temperature and then contacting the heated hydrogen sulfide-rich solvent stream  115  with the second non-permeate stream  128 , or a select portion thereof, in a carbon dioxide stripping zone  130 . Generally, the carbon dioxide which has been stripped from the hydrogen sulfide-rich solvent stream  115  is absorbed by the second non-permeate stream  128  to produce a carbon dioxide-enriched fluid stream  132  and a hydrogen sulfide-enriched solvent stream  134 . 
     In accordance with certain embodiments, at least one of a second portion  119  of the sulfur-free fluid stream  116 , a second portion  125  of the first non-permeate stream  122 , the carbon dioxide-enriched permeate stream  126  and the carbon dioxide-enriched fluid stream  132  can be subsequently combusted in a gas turbine  136  to generate an electrical power output  138 . 
     In accordance with other embodiments, the hydrogen-enriched permeate stream  120  may be subsequently treated in a pressure swing adsorption (PSA) unit  140  to produce a purified hydrogen stream  142  and a pressure swing adsorption tail gas stream  144 . Such pressure swing adsorption unit  140  generally operates by adsorbing light gases such as carbon monoxide, methane, and carbon dioxide from the hydrogen-enriched permeate stream  120  onto a fixed bed of adsorbents. Adsorption of impurities occurs at a relatively high pressure. Hydrogen is adsorbed in only small amounts and can, therefore, be recovered as the purified hydrogen stream  142  at high pressure and purity after passing thorough the adsorbent bed. Typical purities for pressure swing adsorption hydrogen product streams range from 99 to 99.999% by volume. Regeneration of the adsorbent bed can be accomplished by reducing the pressure on the adsorbent to desorb the impurities into the pressure swing adsorption tail gas stream  144 . In a processing scheme such as the one depicted in  FIG. 1 , the pressure swing adsorption unit  140  is typically operated at feed pressures ranging from about 1,825 kPa (about 265 psia) to about 2,520 kPa (about 365 psia). The purified hydrogen product  142  is collected at a pressure of about 70 kPa (about 10 psia) less than feed, and the pressure swing adsorption tail gas stream  144  is typically collected at a pressure of about 138 kPa (about 20 psia). In accordance with certain embodiments, the first non-permeate stream  120  can be compressed prior to entering the pressure swing adsorption unit  140 . 
     Generally, such pressure swing adsorption units operate on a cyclic basis, with individual adsorber vessels cycled between adsorption and desorption steps. Multiple adsorbers are used in order to provide constant product and tail gas flows. Adsorbents are selected based on the type and quantity of impurities present in the feed stream and also the required degree of removal of such impurities. Such pressure swing adsorption units and their operation are more fully described, for example, in commonly assigned U.S. Pat. No. 4,964,888 to Miller and commonly assigned U.S. Pat. No. 6,210,466 to Whysall et al.; the contents of each of these patents are hereby incorporated by reference. 
     In accordance with further embodiments, the hydrogen sulfide-enriched solvent stream  134  may be treated in a hydrogen sulfide stripping zone  146  to produce a hydrogen sulfide-depleted solvent stream  148  and a hydrogen sulfide-enriched fluid stream  150 . Generally, such treatment in the hydrogen sulfide stripping zone  146  involves a separation unit wherein the hydrogen sulfide-enriched solvent stream  134  is heated to strip the hydrogen sulfide from the solvent and produce the hydrogen sulfide depleted-solvent stream  148 . Advantageously or beneficially, the sulfur-depleted solvent stream  148  may be combined with the solvent  113  in the absorption zone  114 . 
     In accordance with certain further embodiments, the hydrogen sulfide-enriched fluid stream  150  may be treated in a sulfur recovery unit  152  to produce an elemental sulfur stream  154  and sulfur recovery tail gas stream  156 . Such sulfur recovery unit  152  can be, for example, a Claus unit. In a Claus unit, hydrogen sulfide is first oxidized with air at high temperatures, i.e., in a range of about 1000° C. to about 1400° C., to produce elemental sulfur and sulfur dioxide. However, some of the hydrogen sulfide remains unreacted. This remaining hydrogen sulfide is then reacted catalytically, in two to three stages, with the formed sulfur dioxide to produce more elemental sulfur and water. A small amount of hydrogen sulfide remains in the produced sulfur recovery tail gas stream  156 . 
     Advantageously or beneficially, the sulfur recovery tail gas stream  156  may be compressed in a compression train  158  to produce a compressed tail gas stream  160 . At least a portion, such as a first portion  162 , of the compressed tail gas stream  160  can be combined with the fluid stream  112  and the resulting combined stream  164  can be treated in the absorption zone  114  to recover or remove additional compounds via the process or processes described above. 
     Alternatively or additionally, all or at least a portion of the compressed tail gas stream  160  can be combined with a feed stream  166  and treated in a water shift reactor unit  168 . For example, in accordance with certain embodiments, particularly embodiments in which increased production of hydrogen and/or carbon dioxide is desired, a second portion  170  of the compressed tail gas stream  160  can be combined with the feed stream  166  to form a combined feed stream  172 . The combined feed stream  172  can then be treated in the water shift reactor  168  to provide the fluid stream  112 . 
     In accordance with certain embodiments, the feed stream  166  can include a raw synthesis gas produced from gasification of petroleum coke, coal, heavy oil streams and/or natural gas. 
     In accordance with another embodiment, as shown in  FIG. 2 , a processing scheme  210 , similar to the processing scheme  110  illustrated in  FIG. 1 , for separating hydrogen sulfide and carbon dioxide from a fluid stream  212  including at least hydrogen sulfide, carbon dioxide and hydrogen involves an absorption zone  214 , a first membrane separation zone  218 , a second membrane separation zone  224 , a carbon dioxide stripping zone  230 , a gas turbine  236 , a pressure swing adsorption unit  240 , a hydrogen sulfide stripping zone  246  and a sulfur recovery zone  252 . 
     Similar to the processing scheme  110 , the processing scheme  210  also involves contacting the fluid stream  212  with a solvent  213  in the absorbent zone  214  to produce a hydrogen sulfide-rich solvent stream  215  and a sulfur-free fluid stream  216  such as by the separation process described above in connection with the absorption zone  114 , as shown in  FIG. 1 . 
     At least a first portion  217  of the sulfur-free fluid stream  216  is treated, such as by the separation process described in conjunction with the first membrane separation zone  118 , as shown in  FIG. 1 , in the first membrane separation zone  218  to produce a hydrogen-enriched permeate stream  220  and a first non-permeate stream  222 . A first portion  223  of the first non-permeate stream  222  is subsequently treated, such as by the separation process described above in connection with the second membrane separation zone  124 , as shown in  FIG. 1 , in the second membrane separation zone  224  to produce a carbon dioxide-enriched permeate stream  226  and a second non-permeate stream  228 . In accordance with certain embodiments, up to about 10% by volume of the first non-permeate stream  222 , i.e., the first portion  223 , may be fed to the second membrane separation zone  224 . 
     The second non-permeate stream  228 , or a select portion thereof, contacts the hydrogen sulfide-rich solvent stream  215  in the carbon dioxide stripping zone  230  to produce a carbon dioxide-enriched fluid stream  232  and a hydrogen sulfide-enriched solvent stream  234  such as by the separation process described above in conjunction with the carbon dioxide stripping zone  130 , as shown in  FIG. 1 . 
     The hydrogen-enriched permeate stream  220 , or a select portion thereof, is treated in the pressure swing adsorption unit  240  to produce a purified hydrogen stream  242  and a pressure swing adsorption tail gas stream  244  such as by the separation process described above in conjunction with the pressure swing adsorption unit  140 , as shown in  FIG. 1 . In accordance with certain embodiments, the pressure swing adsorption tail gas stream  244  can be provided at a pressure of about 138 kPa to about 172 kPa (about 20 to about 25 psia). In accordance with certain other embodiments, the hydrogen-enriched permeate stream  220  can be compressed prior to entering the pressure swing adsorption unit  240 . 
     The hydrogen sulfide-enriched solvent stream  234  is subsequently treated in the hydrogen sulfide stripping zone  246  to produce a hydrogen sulfide-depleted solvent stream  248  and a hydrogen sulfide-enriched fluid stream  250  such as by the separation process described above in conjunction with the hydrogen sulfide stripping zone  146 , as shown in  FIG. 1 . The hydrogen sulfide-depleted solvent stream  248  may be subsequently utilized in the absorption zone  214 . 
     The hydrogen sulfide-enriched fluid stream  250  is treated in the sulfur recovery zone  252  to produce an elemental sulfur stream  254  and a sulfur recovery tail gas stream  256  such as by the process described above in conjunction with the sulfur recovery zone  152 , as shown in  FIG. 1 . 
     In accordance with certain embodiments, one or more of a second portion  219  of the sulfur-free fluid stream  216 , a second portion  225  of the first non-permeate stream  222 , the carbon dioxide-enriched permeate stream  226 , and the carbon dioxide-enriched fluid stream  232  can be combusted in the gas turbine  236  to produce an electrical power output  238 . 
     The processing scheme  210  further involves combining at least a portion of the pressure swing adsorption tail gas stream  244 , i.e., a first portion  245 , with the sulfur recovery tail gas stream  256  to produce a combined tail gas stream  260  which can be subsequently treated in the absorption zone  214 . For example, in accordance with certain embodiments, the combined tail gas stream  260  may be compressed in a compression train  258  to produce a compressed tail gas stream  262  at least a portion of which, i.e., a first portion  264 , can be combined with the fluid stream  212 . The resulting combined fluid stream  266  can be then be fed to the absorption zone  214 . In accordance with certain embodiments, a second portion  247  of the pressure swing adsorption tail gas stream  244  can be removed or drawn off the processing scheme  210  for use in another process or processing unit. 
     Alternatively or additionally, all or at least a portion of the compressed tail gas stream  262  can be combined with a feed stream  268  and treated in a water shift reactor unit  270 . For example, in accordance with certain embodiments, particularly embodiments in which increased production of hydrogen and/or carbon dioxide is desired, a second portion  272  of the compressed tail gas stream  262  can be combined with the feed stream  268  to provide a combined feed stream  274 . The combined feed stream  274  can be treated in the water shift reactor unit  270  to provide the fluid stream  212 . 
     In accordance with a further embodiment, as shown in  FIG. 3 , a processing scheme  310  for separating hydrogen sulfide and carbon dioxide from a fluid stream  312  containing at least hydrogen sulfide, carbon dioxide and hydrogen involves contacting the fluid stream  312  with a physical solvent  313  in an acid gas separation zone  314  to produce a sulfur-free fluid stream  316  containing at least hydrogen and a portion of the carbon dioxide, a carbon dioxide-enriched fluid stream  318 , and a hydrogen sulfide-enriched fluid stream  320  including at least hydrogen sulfide. Such streams  316 ,  318  and  320 , respectively, can be produced, for example, using the separation processes described above in conjunction with the absorption zone  114 , the carbon dioxide stripping zone  130 , and the hydrogen sulfide stripping zone  146 , as shown in  FIG. 1 . 
     A first portion  317  of the sulfur-free fluid stream  316  is subsequently treated in a membrane separation zone  322  by contacting at least one gas permeable membrane element to produce a hydrogen-enriched permeate stream  324  and a non-permeate stream  326  such as by the separation processes described above in conjunction with the first and/or second membrane separation zones,  118  and  124 , respectively, as shown in  FIG. 1 . 
     At least a portion of the hydrogen-enriched permeate stream  324  is treated in a pressure swing adsorption unit  328  to produce a purified hydrogen stream  330  and a pressure swing adsorption tail gas stream  332  such as by the separation process described above in conjunction with the pressure swing adsorption unit  140 , as shown in  FIG. 1 . In accordance with certain embodiments, the hydrogen-enriched permeate stream  324  can be compressed prior to entering the pressure swing adsorption unit  328 . 
     The processing scheme  310  further involves treating at least a portion of the hydrogen sulfide-enriched fluid stream  320  in a sulfur recovery unit  334  to produce an elemental sulfur stream  336  and a sulfur recovery tail gas stream  338  such as by the separation process described above in conjunction with the sulfur recovery unit  152 , as shown in  FIG. 1 . 
     At least a portion of the pressure swing adsorption tail gas  332  is combined with the sulfur recovery tail gas stream  338  to produce a combined tail gas stream  342 . At least a portion of the combined tail gas stream  342  can be compressed in a compression train  344  to produce a compressed tail gas stream  360 . At least a portion of compressed tail gas stream  360 , such as, for example a first portion  362 , can be combined with the fluid stream  312  to form a combined fluid stream  364  which may be treated in the acid gas separation zone  314  to recover or remove additional compounds per the process or processes described above in conjunction with processing scheme  110 , as shown in  FIG. 1 . 
     Alternatively or additionally, all or at least a portion of the compressed tail gas stream  360  can be combined with a feed stream  366  and treated in a water shift reactor unit  368 . For example, in accordance with certain embodiments, particularly embodiments in which increased production of hydrogen and/or carbon dioxide is desired, a second portion  370  of the compressed tail gas stream  360  can be combined with the feed stream  366  to form a combined feed stream  372 . The combined feed stream  372  can be treated in the water shift reactor  368  to provide the fluid stream  312 . 
     In accordance with certain embodiments, the acid gas separation zone  314  can include an absorption zone  346 , a carbon dioxide stripping zone  348  and a hydrogen sulfide stripping zone  350  for separating carbon dioxide and hydrogen sulfide from the fluid stream  312 . For example, the processing scheme  310  can further involve contacting the physical solvent  313  in the absorption zone  346  with the fluid stream  312  and/or combined fluid stream  364  to produce the sulfur-free fluid stream  316  and a hydrogen sulfide-rich solvent stream  354  containing at least hydrogen sulfide and a portion of the carbon dioxide. Such fluid streams  316  and  354 , respectively, can be produced using the separation process as described above in conjunction with the absorption zone  114 , as shown in  FIG. 1 . 
     The hydrogen sulfide-rich solvent stream  354  is treated in the carbon dioxide stripping zone  348  by contacting the hydrogen sulfide-rich solvent stream  354  with a sweeping gas stream  356  to produce the carbon dioxide-enriched fluid stream  318  and a hydrogen sulfide-enriched solvent stream  358 . Such fluid streams  318  and  358 , respectively, can be produced using the process as described above in conjunction with carbon dioxide stripping zone  130 , as shown in  FIG. 1 . 
     In accordance with certain embodiments, one or more of a second portion  319  of the sulfur-free fluid stream  316 , at least a portion of the non-permeate stream  326 , and the carbon dioxide-enriched fluid stream  318  can be combusted in the gas turbine  340  to produce an electrical power output  343 . 
     In accordance with certain embodiments, the sweeping gas stream  356  may be supplied from an external source such as, for example, from an air separation unit (not shown) which may be employed to produce an oxygen stream for an associated gasifier in an IGCC process. 
     In accordance with certain other embodiments, a portion of the non-permeate stream  326  can be used to supply the sweeping gas stream  356 . In accordance with certain embodiments, up to about 10% by volume of the non-permeate stream  326  can be used to supply the sweeping gas stream  356 . In accordance with such embodiments, the membrane separation zone  322  is advantageously and/or beneficially configured such that carbon dioxide entering the membrane separation zone  322  via the first portion  317  of the sulfur-free stream  316  permeates through the at least one gas separation membrane element and is collected in the hydrogen-enriched permeate stream  328  and the portion of the non-permeate stream  326  fed to the carbon dioxide stripping zone  348  includes less than about 5% volume, and, in accordance with certain embodiments, less than about 3% by volume, carbon dioxide. 
     In accordance with certain further embodiments, the membrane separation zone  322  can include at least one hollow fiber gas permeable membrane element connected in series with at least one spiral wound gas permeable membrane element. For example, the membrane separation zone  322  can include first and second membrane separation zones such as, for example, first membrane separation zone  118  and second membrane separation zone  124 , as shown in  FIG. 1 , wherein the non-permeate stream  326  is treated in the second membrane separation zone to produce a non-permeate stream suitable for use as the sweeping gas stream  356 . 
     In accordance with certain embodiments, the hydrogen sulfide-enriched solvent stream  358  is treated in the hydrogen sulfide stripping zone  350  to produce a hydrogen sulfide-depleted solvent stream  352  and the hydrogen sulfide-enriched fluid stream  320 . In accordance with certain further embodiments, the hydrogen sulfide-depleted solvent stream  352  may be combined with the solvent stream  313  and utilized in the absorption zone  346 . Such fluid streams  352  and  320 , respectively, can be produced by the process described above in conjunction with the hydrogen sulfide stripping zone  146 , as shown in  FIG. 1 . 
     As described above, the invention provides improved processes for separating hydrogen sulfide and carbon dioxide from a fluid stream containing at least hydrogen sulfide, carbon dioxide and hydrogen which employ at least portions of byproduct streams produced in the system. The invention further provides improved processes for separating hydrogen sulfide and carbon dioxide from a fluid stream containing at least hydrogen sulfide, carbon dioxide and hydrogen which recycles at least portions of select waste or byproduct streams to improve recovery of desirable products such as, for example, carbon dioxide and hydrogen. 
     As detailed herein, improvements and benefits realizable through the practice of such improved processes include, advantageously and/or economically employing one or more byproduct or waste streams produced by the process to support or facilitate certain steps within the process. 
     The invention illustratively disclosed herein suitably may be practiced in the absence of any element, step, part, component, or ingredient which is not specifically disclosed herein. 
     While in the foregoing detailed description of this invention has been described in relation to certain preferred embodiments thereof, and many details have been set forth for purposes of illustration, it will be apparent to those skilled in the art that the invention is susceptible to additional embodiments and that certain of the details described herein can be varied considerably without departing from the basic principles of the invention.