Patent Publication Number: US-6702936-B2

Title: Method of and apparatus for upgrading and gasifying heavy hydrocarbon feeds

Description:
BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     The present invention relates to a method of and apparatus for upgrading heavy hydrocarbon feeds. In particular, the method and apparatus include gasification of heavy high-carbon content by-products produced by the upgrading of the heavy hydrocarbon feeds. 
     2. Description of the Prior Art 
     Many types of heavy crude oils contain high concentrations of sulfur compounds, organo-metallic compounds and heavy, non-distillable fractions called asphaltenes which are insoluble in light paraffins such as normal pentane. Because most petroleum products used for fuel must have a low sulfur content to comply with environmental regulations and restrictions, the presence of sulfur compounds in the non-distillable fractions reduces their value to petroleum refiners and increases their cost to users of such fractions as fuel or raw material for producing other products. It is desirable to remove the non-distillable fractions, or asphaltenes, from the oil because not only do the non-distillable fractions contain high amounts of sulfur, the asphaltenes tend to solidify and foul subsequent processing equipment. Removal of the asphaltenes also tends to reduce the viscosity of the oil. 
     Solvent extraction of asphaltenes is used to process crude and produces deasphalted oil (DAO) which is subsequently further processed into more desirable products. The deasphalting process typically involves contacting a heavy oil with a solvent. The solvent is typically an alkane such as propane, butane and pentane. The solubility of the solvent in the heavy oil decreases as the temperature increases. A temperature is selected wherein substantially all the paraffinic hydrocarbons go into solution, but where a portion of the resins and asphaltenes precipitate. Because the solubility of the asphaltenes is low in the oil-solvent mixture, the asphaltenes will precipitate out and are further separated from the DAO. 
     In order to increase the saleability of these hydrocarbons, refiners must resort to various expedients for removing sulfur compounds. A conventional approach for removing sulfur compounds in distillable fractions of crude oil is catalytic hydrogenation in the presence of molecular hydrogen at moderate temperature and pressure. While this approach is cost effective in removing sulfur from distillable oils, problems arise when the feed includes metal-containing asphaltenes. Specifically, the presence of the metal-containing asphaltenes results in catalyst deactivation by reason of the coking tendency of the asphaltenes, and the accumulation of metals on the catalyst. 
     Many proposals thus have been made for dealing with non-distillable fractions of crude oil and other heavy hydrocarbons, include residual oil which contain sulfur and other metals. And while many are technically viable, they appear to have achieved little or no commercialization due in large part to the high cost of the technology involved. Usually such cost takes the form of increased catalyst contamination by the metals and/or carbon deposition resulting from the attempted conversion of the asphaltene fractions. 
     One way that refineries have attempted to receive more value from heavy hydrocarbons including asphaltenes has been to gasify them. U.S. Pat. No. 4,938,862 to Visser et al. discloses a process for thermal cracking residual hydrocarbon oils involving feeding the oil and a synthetic gas to a thermal cracker, separating the cracked products into various streams including a cracked residue stream, separating the cracked residue stream into an asphaltene-rich stream and an asphaltene-poor stream, then gasifying the asphaltene rich stream to produce syngas which is fed to the thermal cracker. 
     Likewise, U.S. Pat. No. 6,241,874 to Wallace et al. discloses extracting asphaltenes through with a solvent and gasifying the asphaltenes in the presence of oxygen. Heat from the gasification of the asphaltenes is used to help recover some of the solvent used in extracting the asphaltenes. 
     Further, U.S. Pat. No. 5,958,365 to Liu discloses processing heavy crude oil by distilling the same, solvent deasphalting the oil, and further processing the heavy hydrocarbons to produce hydrogen. The hydrogen is used to treat the deasphalted oil fraction and distillate hydrocarbon fractions obtained from the heavy crude oil. 
     However, there still remains a need for a cost-effective and commercially viable method of extracting more value out of asphaltenes produced in refineries. 
     BRIEF SUMMARY OF THE INVENTION 
     Applicants have unexpectedly developed an apparatus for producing sweet synthetic crude from a heavy hydrocarbon feed comprising: 
     a) an upgrader for receiving said heavy hydrocarbon feed and producing a distillate fraction including sour products, and high-carbon content by-products; 
     b) a gasifier for receiving said high-carbon content by-products and producing synthetic fuel gas and sour by-products; 
     c) a hydroprocessing unit for receiving said sour by-products and hydrogen gas, thereby producing gas and said sweet crude; and 
     d) a hydrogen recovery unit for receiving said synthetic fuel gas and producing further hydrogen gas and hydrogen-depleted synthetic fuel gas, said further hydrogen gas being supplied to said hydroprocessing unit. 
     Applicants have further developed a method for producing sweet synthetic crude from a heavy hydrocarbon feed comprising: 
     a) upgrading said heavy hydrocarbon feed in an upgrader and thereby producing a distillate feed including sour products, and high-carbon content by-products; 
     b) gasifying in a gasifier said high-carbon content by-products and producing synthetic fuel gas and sour by-products; 
     c) hydroprocessing said sour products along with hydrogen gas, thereby producing gas and said sweet crude; and 
     d) recovering hydrogen in a hydrogen recovery unit from said synthetic fuel gas and producing further hydrogen gas and hydrogen-depleted synthetic fuel gas, and supplying said further hydrogen gas to said hydroprocessing unit. 
     Furthermore, Applicants have unexpectedly developed an apparatus for producing sweet synthetic crude from a heavy hydrocarbon feed comprising: 
     a) an upgrader comprising: 
     I. a distillation column for receiving said heavy hydrocarbon feed and producing a distillate fraction, and a non-distilled fraction containing sulfur, asphaltene and metals; 
     II a solvent deasphalting unit for processing said non-distilled fraction and producing a deasphalted oil stream and an asphaltene stream, an outlet of said deasphalting unit containing said deasphalted oil being connected to an inlet of a thermal cracker and wherein said asphaltene stream comprises said high-carbon by-products; 
     III said thermal cracker thermally cracking said deasphalted oil and forming a thermally cracked stream; 
     b) a gasifier for gasifying said asphaltenes in the presence of air or oxygen and producing ash and a gas mixture: 
     c) a scrubber which receives said gas mixture and water and produces sour water and a clean sour gas mixture; 
     d) a first gas processor which receives said clean sour gas mixture and produces a sweet synthetic fuel gas, said first gas processor comprises: 
     I a solvent contactor which receives lean solvent from a solvent regenerator and said clean sour gas mixture and produces a sweet product and rich solvent; 
     II said solvent regenerator receiving said rich solvent and producing said lean solvent and acid gas; 
     III a sulfur recovery unit which receives said acid gas and produces sulfur and a sulfur-depleted gas which is vented to the atmosphere; and 
     IV a liquid recovery unit which receives said sweet product and produces sweet gas, sour water and light liquid hydrocarbons; 
     e) a hydroprocessing unit for receiving said sour products and hydrogen gas, thereby producing gas and said sweet crude, said hydroprocessing unit comprising: 
     I a hydroprocessor which receives said distillate feed and hydrogen gas and produces a high-pressure hydroprocessed product; 
     II a first flash vessel which receives said high-pressure hydroprocessed product and produces high pressure sour gas and high pressure flashed product; 
     III a second flash vessel which receives said high pressure flashed product and produces low pressure sour gas and low pressure flashed product; 
     IV a stripper which receives said low pressure flashed product and steam and produces low pressure sour gas, sour water and sweet synthetic crude; 
     V a first solvent contactor in fluid communication with a first solvent regenerator and containing a clean solvent, said first solvent contactor receiving said high pressure high pressure sour gas from said first flash vessel and producing sweet recycle gas which is fed to said hydroprocessor and sour solvent, said first solvent regenerator receiving said sour solvent and producing said clean solvent which is fed to said first solvent contactor and hydrogen sulfide and ammonia; and 
     VI a second solvent contactor in fluid communication with a second solvent regenerator and containing clean solvent, said second solvent contactor receiving said low pressure sour gas from said second flash vessel and from said stripper and producing fuel gas and sour solvent, said second solvent regenerator receiving said sour solvent and producing said clean solvent which is fed to said second solvent contactor.; and 
     f) a hydrogen recovery unit for receiving said synthetic fuel gas and producing further hydrogen gas and hydrogen-depleted synthetic fuel gas, said further hydrogen gas being supplied to said hydroprocessing unit. 
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS 
     Embodiments of the present inventive subject matter are described by way of example and with reference to the accompanying drawings wherein: 
     FIG. 1 is a block diagram of an embodiment of the present inventive subject matter wherein a heavy hydrocarbon feed is input into an upgrader; 
     FIG. 2 is a block diagram of another embodiment of the present inventive subject matter; 
     FIG. 3 is a block diagram of a hydroprocessing apparatus useful in the present inventive subject matter; 
     FIG. 4 is a block diagram of a gasifier apparatus useful in the present inventive subject matter; 
     FIG. 5 is a block diagram of a gas processing/sweetening apparatus useful in the present inventive subject matter; and 
     FIG. 6 is a block diagram of a water treatment apparatus useful in the present inventive subject matter. 
    
    
     DETAILED DESCRIPTION OF THE EMBODIMENTS 
     The present inventive subject matter is drawn to a method of and apparatus for upgrading a heavy hydrocarbon feed in which heavy, high-carbon content by-products are gasified. As used herein, the term “sour” refers to product streams, gas streams and water streams that contain a high content of sulfur, hydrogen sulfide, and/or ammonia. The term “sweet” is used to denote product streams, gas streams and water streams that are substantially free from sulfur and hydrogen sulfide. 
     As used herein, the term “syngas” refers to a synthetic fuel gas. More particularly, “syngas” is a mixture of hydrogen, carbon monoxide, carbon dioxide, hydrogen sulfide, and small amounts of other compounds. For the purposes of this application, “syngas” and “synthetic fuel gas” are herein synonymous and used interchangeably. 
     The expression “line” as used herein refers to lines or conduits that connect different elements of the apparatus of the present inventive subject matter. “Line” includes, without limitation, conduits, streams, and the other items which may be used to transfer material from one element to another element. 
     “Gas processing unit” or “gas processor” refer to equipment arranged to remove hydrogen sulfide, ammonia and other impurities from a sour gas mixture. This is synonymous with a “gas sweetening unit” and the terms are used herein interchangeably. 
     Turning now to the figures, FIG. 1 is a block diagram of one embodiment of the present inventive subject matter. Numeral  10  designates an apparatus for producing a sweet synthetic crude product from a heavy hydrocarbon feed. Heavy hydrocarbon feed in line  12  is fed to upgrader  14 . In upgrader  14 , the heavy hydrocarbon feed is upgraded to produce gas in line  16 , sour products in line  18  and high-carbon content by-products in line  20 . Optionally, gas in line  16  may be fed to a gas processing unit as detailed below with respect to FIG.  5 . Upgrader  14  may be constructed and arranged in accordance with FIG. 2, or upgrader  14  may be another other apparatus which takes a heavy hydrocarbon feed and produces a more commercially attractive range of products therefrom. 
     Sour products in line  18  are fed to hydroprocessing unit  22  along with hydrogen gas in line  24 . Hydroprocessing unit  22  may be a hydrocracking unit or a hydrotreating unit, depending upon the temperatures and pressures at which the hydroprocessing unit is run. Running hydroprocessing unit  22  as a hydrocracking unit will result in a lower boiling point range for the sweet synthetic crude. The sour products and hydrogen gas react in hydroprocessing unit  22  producing sweet synthetic crude in line  28  and gas in line  26 . Optionally, gas in line  26  may be fed to a gas processing unit as detailed below with respect to FIG.  5 . 
     High-carbon content by-products from upgrader  14  are fed in line  20  to gasifier  32 . The high-carbon content by-products are gasified in gasifier  32  in the presence of steam and oxygen (not shown). The amount of oxygen added to gasifier  32  is limited so that only partial oxidation of the hydrocarbons in the high-carbon content by-products occurs. The gasification process converts the high-carbon content by-products into syngas in line  36  and sour by-products in line  34 . Some or all of the syngas in line  36  is then fed to hydrogen recovery unit  42 , where hydrogen gas is removed from the syngas, thereby producing hydrogen-depleted syngas in line  44  and hydrogen gas in line  30 . The hydrogen gas in line  30  is fed to hydroprocessing unit  22  for reaction with the sour products in line  18 . 
     In an optional embodiment of the present inventive subject matter, some or all of the syngas in line  36  is optionally fed to carbon monoxide (CO) shift reactor  40  before being fed to hydrogen recovery unit  42 . CO shift reactor  40  is a well-known piece of apparatus wherein the syngas in line  36  is partially reacted with steam (not shown) to form hydrogen gas and carbon dioxide. The hydrogen gas is then separated in hydrogen recovery unit  42  as is described above. 
     In a further optional embodiment of the present inventive subject matter, some or all of the syngas in line  36  may be fed directly to line  44  via line  46 , thus by-passing CO shift reactor  40  and hydrogen recovery unit  42 . The syngas in line  46  is then combined with the syngas in line  44 . 
     Turning now to FIG. 2, numeral  100  represents another embodiment of an apparatus for producing sweet synthetic crude from a heavy hydrocarbon feed. Apparatus  100  comprises distillation column  114  which receives heavy hydrocarbon feed from line  112 . Optionally, heavy hydrocarbon feed in line  112  may be heated (not shown) prior to being fed to distillation column  114 . Distillation column  114  may be operated at near-atmospheric pressure or, by the use of two separate vessels, at an ultimate pressure that is subatmospheric. Fractionation takes place within distillation column  114  producing gas stream  120 , one or more distillate streams shown as combined stream  116 , which is substantially asphaltene-free and metal-free, and non-distilled fraction in line  132 . In an optional embodiment, gas stream  120  may be fed to gas processing unit  158  which is detailed below with respect to FIG.  5 . 
     All or a portion of the distillate fraction in line  116  is fed to hydroprocessing unit  122  along with hydrogen gas in line  124 . Hydroprocessing unit  122  may be a hydrocracking unit or a hydrotreating unit, depending upon the temperatures and pressures at which the hydroprocessing unit is run. Running hydroprocessing unit  122  as a hydrocracking unit will result in a lower boiling point range for the sweet synthetic crude. The sour products and hydrogen gas react in hydroprocessing unit  122  producing sweet synthetic crude in line  128  and gas in line  126 . Optionally, gas in line  126  may be fed to gas processing unit  160  as detailed below with respect to FIG.  5 . Further still, it is an option of the present inventive subject matter that gas processing units  158  and  160  are the same apparatus, and gas in lines  120  and  126  will be simultaneously fed to the gas processing unit. 
     Non-distilled fraction in line  132  is applied to solvent deasphalting (SDA) unit  134  for processing the non-distilled fraction and producing deasphalted oil (DAO) in line  136  and high-carbon content by-products, or asphaltenes, in line  142 . The high-carbon content by-products contain asphaltenes as well as other high-carbon content materials. SDA unit  134  is conventional in that it utilizes a recoverable light hydrocarbon including propane, butane, pentane, hexane and mixtures thereof for separating the non-distilled fraction into DAO stream  136  and high-carbon content by-product stream  142 . The concentration of metals in DAO stream  136  produced by SDA unit  134  is substantially lower than the concentration of metals in non-distilled fraction applied to SDA unit  134 . In addition, the concentration of metals in high-carbon content by-products stream  142  is substantially higher than the concentration of metals in DAO stream  136 . DAO stream  136  is then fed to thermal cracker  138  where heat is applied. The heat applied to DAO stream in thermal cracker  138 , and the DAO residence time in thermal cracker  138 , serve to thermally crack the deasphalted oil. Thermal cracking involves the application of heat to break molecular bonds and crack heavy, high boiling point range, long-chain hydrocarbons into lighter fractions. The thermally cracked product in line  140  is fed back to distillation column  114 , where the distillable parts of the cracked product in line  140  is separated and recovered as part of gas stream  120  and distillate stream  116 . 
     In addition, thermal cracker  138  may contain catalyst to aid in thermal cracking the DAO. The catalyst can reside in thermal cracker  138 , but is preferably in the form of an oil dispersible slurry carried by the relevant feed stream. The catalyst promotes cracking of DAO stream  136 . The catalyst is preferably a metal selected from the group consisting of Groups IVB, VB, VIB, VIIB and VIII of the Periodic Table of Elements and mixtures thereof. The most preferred catalyst is molybdenum. 
     High-carbon content by-products which contain asphaltenes from SDA unit  134  are fed in line  142  to gasifier  144 . The high-carbon content by-products are gasified in gasifier  144  in the presence of steam and oxygen (not shown). The amount of oxygen added to gasifier  144  is limited so that only partial oxidation of the hydrocarbons in the high-carbon content by-products occurs. The gasification process converts the high-carbon content by-products into syngas in line  146  and sour by-products in line  154 . Some or all of the syngas in line  146  is then fed to hydrogen recovery unit  150 , where hydrogen gas is removed from the syngas, thereby producing hydrogen-depleted syngas in line  152  and hydrogen gas in line  130 . The hydrogen gas in line  130  is fed to hydroprocessing unit  122  for reaction with the distillate products in line  116 . Optionally, syngas from gasifier  144  may be used as syngas fuel in line  156 . 
     In an optional embodiment of the present inventive subject matter, some or all of the syngas in line  146  is fed to carbon monoxide (CO) shift reactor  141  before being fed to hydrogen recovery unit  150 . CO shift reactor  141  is a well-known piece of apparatus wherein the syngas in line  146  is partially reacted with steam (not shown) to form hydrogen gas and carbon dioxide. The hydrogen gas is then separated in hydrogen recovery unit  150  as is described above. 
     In a further optional embodiment of the present inventive subject matter, some or all of the syngas in line  146  may be fed directly to line  152  via line  162 , thus by-passing CO shift reactor  141  and hydrogen recovery unit  150 . The syngas in line  162  is then combined with the syngas in line  152 . 
     While it is shown in FIG. 2 that the distillate fractions from distillation column  114  are combined in stream  116 , the present inventive subject matter also contemplates a configuration (not shown) in which the various distillate streams are not combined. The individual distillate streams are then fed to individual hydroprocessing units in which the individual distillate streams are hydroprocessed in accordance with the hydroprocessing units described herein. 
     FIG. 3 represents an example of a hydroprocessing unit which may be employed in the apparatuses of FIGS. 1 and 2 above. Numeral  200  depicts a hydroprocessing unit in which distillate stream  116  is applied to hydroprocessor  208 . Hydroprocessor  208  is a reaction vessel in which heat and pressure are added to the distillate fraction, thereby producing a high-pressure hydroprocessed product present in line  210 . Hydroprocessor  208  may be run as a hydrotreating unit or as a hydrocracking unit. As is known, a hydrotreating unit is run at less severe temperatures and pressures than a hydrocracking unit, resulting in a hydrotreated product that has a wider boiling point range than a hydrocracked product that has a narrow boiling point range. For example, if hydroprocessor  208  is run as a hydrotreater, the pressure inside the reaction vessel may be on the order of 1000 pounds per square inch (psi). On the other hand, if hydroprocessor  208  is operated as a hydrocracker, the pressure may be as high as 3000 psi. 
     The high-pressure hydroprocessed product in line  210  is fed to first flash vessel  212  wherein the high-pressure hydroprocessed product is separated into high pressure sour gas and high pressure flashed product. High pressure flash product is fed via line  214  to second flash vessel  228 . Second flash vessel  228  separates the high pressure flash product into low pressure sour gas in line  236  and a low pressure flashed product in line  232 . Low pressure flashed product in line  232  is fed to stripper  238  along with steam from line  234 . Stripper  238  strips impurities from low pressure flashed product using steam, thereby producing low pressure sour gas in line  240  which is combined with low pressure sour gas in line  236 , sweet synthetic crude in line  128  and sour water in line  244 . Additional intermediate or low pressure flash vessels may be added to improve the recovery of heat or hydrogen in the system. 
     Low pressure sour gas in lines  236  and  240  (which is combined with line  236 ) is then fed to a gas sweetening apparatus. In particular, low pressure sour gas in line  236  is fed to solvent contactor  246 , a vessel in which the low pressure sour gas is contacted with a solvent. The solvent, which may be a chemical solvent or a physical solvent, is used to remove hydrogen sulfide and other impurities from the low pressure sour gas, thus sweetening the low pressure sour gas. Preferably, the solvent is an amine-based chemical solvent. Solvent contactor  246  is in fluid communication with solvent regenerator  248 . Solvent contactor  248  receives lean solvent (solvent that does not contain hydrogen sulfide or other impurities) from solvent regenerator  248  via line  250 . The lean solvent is contacted with the low pressure sour gas in solvent contactor  246 , whereby the hydrogen sulfide and other impurities are absorbed by the solvent. The rich solvent (containing the hydrogen sulfide and other impurities) is then fed back to solvent regenerator  248  via line  252 , where the impurities are removed from the solvent, thereby producing lean, or clean, solvent, and removed from the gas sweetening apparatus via line  254 . Clean fuel gas is removed from solvent contactor  246  via line  256 . 
     High pressure sour gas from first flash vessel  212  is removed from the vessel via line  216 . The high pressure sour gas may be used as a recycle gas and fed to hydroprocessor  208 . Preferably, high pressure sour gas in line  216  is first sweetened using gas sweetening apparatus  230 . Gas sweetening apparatus  230  comprises solvent contactor  218  and solvent regenerator  220 . High pressure sour gas in line  216  is fed to solvent contactor  218 , a vessel in which the high pressure sour gas is contacted with a solvent. The solvent, which may be a chemical solvent or a physical solvent, is used to remove hydrogen sulfide and other impurities from the high pressure sour gas, thus sweetening the high pressure sour gas. Preferably, the solvent is an amine-based chemical solvent. Solvent contactor  218  is in fluid communication with solvent regenerator  220 . Solvent contactor  218  receives lean solvent (solvent that does not contain hydrogen sulfide or other impurities) from solvent regenerator  220  via line  222 . The lean solvent is contacted with the low pressure sour gas in solvent contactor  218 , whereby the hydrogen sulfide and other impurities are absorbed by the solvent. The rich solvent (containing the hydrogen sulfide and other impurities) is then fed back to solvent regenerator  220  via line  224 , where the impurities are removed from the solvent, thereby producing lean, or clean, solvent, and the impurities are removed from the gas sweetening apparatus via line  226 . Clean gas is removed from solvent contactor and recycled back to hydroprocessor  208 . 
     In a preferred embodiment of the present inventive subject matter, solvent regenerators  248  and  220  are the same piece of apparatus, receiving the rich solvent from and supplying the lean solvent to both solvent contactors  246  and  218 . 
     In a further optional embodiment of the present inventive subject matter, high pressure sour gas in line  216  is fed to third flash vessel  260  along with water from line  264 . The water acts to remove ammonia and other impurities from the high pressure sour gas before the high pressure sour gas is fed to hydroprocessor  208  or gas sweetening apparatus  230 . Sour water and further high pressure flashed product are produced in flash vessel  260 . Sour water exits flash vessel  260  via line  266 , while further high pressure flashed product exits flash vessel  260  via line  262  and is combined with high pressure flashed product from flash vessel  212  in line  214 . 
     While the above describes gas sweetening apparatus usable with the hydroprocessing unit, further gas sweetening apparatus as described below with respect to FIG. 5 may also be used. 
     FIG. 4 depicts an example of a gasifier unit which may be employed in the apparatuses of FIGS. 1 and 2 above. Numeral  300  depicts a gasifying apparatus in which high-carbon content upgrading by-products, including asphaltenes, are applied to gasifier  302 . Gasifier  302  is a reaction vessel equipped with a burner to promote a reaction between the high-carbon content upgrading by-products from line  304  with air or oxygen supplied by line  306 . The amount of air or oxygen supplied to gasifier  302  is limited so that only a partial oxidation of the high-carbon content by-product occurs. The gasification process in gasifier  302  results in the production of syngas comprising hydrogen, carbon monoxide, carbon dioxide, hydrogen sulfide and small amounts of other compounds. Also produced by gasifier  302  is ash or slag, which is removed from gasifier  302  via line  308 . 
     The syngas exiting gasifier  302  via line  310  is at an elevated temperature. The syngas is fed to quench/scrubber  312 , to which water is also added via line  314 , wherein the water cools the syngas and removes some of the hydrogen sulfide, ammonia and other impurities in the form of sour water. The sour water is removed from quench/scrubber  312  via line  316 . The cooled syngas mixture is then fed to gas processing unit  320  via line  318  wherein the cooled syngas mixture is sweetened by the removal of further hydrogen sulfide and other impurities. Gas processing/sweetening unit  318  may be as described above with respect to FIG. 3, or may take the configuration as described below with respect to FIG.  5 . Sweet syngas exits gas processing unit  320  via line  322 . 
     Other optional embodiments are available for the gasifier configuration depicted in FIG.  4 . In one optional embodiment, the gas mixture leaving quench/scrubber  312  via line  318  is fed to gas processing unit  332 . As is the case with gas processing unit  320 , gas processing unit  332  may be as described above with respect to FIG. 3, or may take the configuration as described below with respect to FIG.  5 . The product of gas processing unit  332  is transported via line  334  to CO shift reactor  336 . CO shift reactor  336  is a well-known piece of apparatus wherein the syngas in line  334  is partially reacted with steam from line  340  to form hydrogen gas and carbon dioxide. The syngas, hydrogen gas and carbon dioxide may then be fed via line  338  to membrane  344  prior to being fed via line  346  to pressure swing absorber  348 . Pressure swing absorber  348  separates hydrogen gas from other gases through physical separation. Hydrogen gas exits via line  352 , and the remaining sweet syngas is combined with the sweet syngas in line  322  via line  350 . Optionally, the syngas, hydrogen gas and carbon dioxide from CO shift reactor  336  may be fed directly to pressure swing absorber  348  via line  342 . 
     In another optional embodiment, the gas mixture leaving quench/scrubber  312  via line  318  is fed to CO shift reactor  324 . CO shift reactor  324  is a well-known piece of apparatus wherein the syngas in line  318  is partially reacted with steam (not shown) to form hydrogen gas and carbon dioxide. The syngas, hydrogen gas and carbon dioxide from CO shift reactor  324  is applied via line  326  to gas processing unit  328 . As is the case with gas processing units  320  and  332 , gas processing unit  328  may be as described above with respect to FIG. 3, or may take the configuration as described below with respect to FIG.  5 . Hydrogen gas produced and separated in gas processing unit  328  is removed via line  330 , while sweet syngas produced and separated in gas processing unit  328  is removed via line  354 . 
     In a further optional embodiment, the gas syngas in line  310  is applied to once-through steam generator  360  along with water from line  362 . Once-through steam generator  360  is an apparatus that accepts low quality water containing a high degree of dissolved solids. Utilizing heat in the syngas in line  310 , once-through steam generator  360  partially vaporizes the water from line  362 , forming saturated steam and water. The saturated steam and water exit once-through steam generator  360  via line  364 . An advantage of using once-through steam generator  360  is that only about 80% of the water from line  362  is vaporized, with the remaining water containing the dissolved solids present in the water. This allows lower quality water to be used in generating saturated steam and keeps the dissolved solids from depositing on the walls of once-through steam generator  360 . It is contemplated within the scope of the present inventive subject matter that the saturated steam generated by once-through steam generator be used as a source to meet steam requirements through out the apparatus as described herein. 
     Turning now to FIG. 5, numeral  400  refers to a gas processing/sweetening unit to be used in accordance with the present inventive subject matter. As has been discussed above, the gas processing/sweetening unit described with reference to FIG. 5 is but one possible embodiment of an apparatus useful for removing hydrogen sulfide and other impurities from various gas streams located throughout the apparatus of the present inventive subject matter. In apparatus  400 , the sour gas mixture is supplied to solvent contactor  404  via line  402 . However, one of ordinary skill in the art will recognize that solvent contactor  404  is equivalent to other solvent contactors already described herein with reference to other figures. For example, solvent contactor  404  is equivalent, and therefore interchangeable with solvent contactor  246  of FIG.  3 . Likewise, line  402  which supplies sour gas to solvent contactor  404  is equivalent with line  236  which supplies sour gas to solvent contactor  246  in FIG.  3 . 
     Returning to apparatus  400  in FIG. 5, solvent contactor  404  is a vessel in which the sour gas is contacted with a solvent. The solvent, which may be a chemical solvent or a physical solvent, is used to remove hydrogen sulfide and other impurities from the sour gas, thus sweetening the sour gas. Preferably, the solvent is an amine-based chemical solvent. Solvent contactor  404  is in fluid communication with solvent regenerator  410 . Solvent contactor  404  receives lean solvent (solvent that does not contain hydrogen sulfide or other impurities) from solvent regenerator  410  via line  408 . The lean solvent is contacted with the sour gas in solvent contactor  404 , whereby the hydrogen sulfide, ammonia and other impurities are absorbed by the solvent. The rich solvent (containing the hydrogen sulfide and other impurities) is then fed back to solvent regenerator  410  via line  406 , where the impurities are removed from the solvent by the addition of heat or, alternatively, by a pressure drop through the solvent regeneration vessel, thereby producing lean, or clean, solvent. Acid gas containing the hydrogen sulfide and other impurities exit hydrogen regenerator  410  via line  414 . The acid gas is applied to sulfur recovery unit  416  in which the sulfur is removed from the acid gas. The sulfur exits sulfur recovery unit  416  via line  418 . The de-sulfurized gas is released to the atmosphere via line  420 , or may optionally be recycled to solvent contactor  404  via recycle line  432 . 
     Clean product is removed from solvent contactor  404  via line  422 . The clean product is fed to liquid recovery unit  424  wherein clean products are further separated. Sweet gas exits liquid recovery unit  424  via line  430 , while sweet liquid products such as, for example, liquid propane, liquid butane, etc. exit liquid recovery unit  424  via line  428 . Sour water, containing the vast majority of the remaining impurities, exits liquid recovery unit  424  via line  426 . 
     FIG. 6 illustrates an apparatus for treating the sour water produced by the various components of the present inventive subject matter. As is described above, a number of the components produce sour water as a by-product of the process used with the apparatus. Numeral  500  refers to an apparatus for treating the sour water produced within the various pieces of apparatus found in FIGS. 1-5. In particular, sour water is delivered to stripper  504  from the upgrader apparatus via line  154 , from the hydroprocessing unit via line  244  and from the gasifier apparatus via line  316 . Optionally, lines  154 ,  244  and  316  are combined into line  502 , which feeds the sour water to stripper  504 . However, the present inventive subject matter also contemplates the individual lines being fed directly to stripper  504  (not shown). 
     Stripper  504  utilizes steam from line  518  to strip the impurities from the water. The stripped water exits stripper  504  via line  506  and may be used throughout the process, or may be injected into the ground. Acid gas containing the hydrogen sulfide, ammonia and other impurities exit the stripper via line  508 . The ammonia is optionally separated and removed from the acid gas via line  516 . The acid gas is fed to sulfur recovery unit  510  wherein the sulfur is separated from the remaining gases. The sulfur exits sulfur recovery unit  510  via line  512 , while the de-sulfurized gas is release as an emission via line  514 . 
     The inventive subject matter being thus described, it will be obvious that the same may be varied in many ways. Such variations are not to be regarded as a departure from the spirit and scope of the inventive subject matter, and all such modifications are intended to be included within the scope of the following claims.