Abstract:
A system and method for efficiently removing hydrogen sulfide from a natural gas feed stream to produce a Stinson Process feed stream and an acid gas stream. A first solvent separates the majority of the carbon dioxide and hydrocarbons from the hydrogen sulfide in the natural gas feed to produce the Stinson feed stream. By removing the majority of the hydrogen sulfide prior to feeding the Stinson Process, a carbon dioxide stream suitable for use in flooding operations may be produced with the Stinson Process. The system and method also increase the concentration of hydrogen sulfide in the acid gas stream, making it suitable for sulfur recovery operations. The system and method are particularly suitable for natural gas feed streams containing 0.5%-20% hydrogen sulfide and at least 20% carbon dioxide. Operation in an anhydrous mode with the addition of nitrogen aids in solvent recovery for recycling.

Description:
BACKGROUND OF THE INVENTION 
       [0001]    1. Field of the Invention 
         [0002]    This invention relates to a system and method for removing hydrogen sulfide from carbon dioxide, methane and other components of natural gas streams being processed into a sales gas stream. The system and method of the invention are particularly suitable to separate carbon dioxide and hydrogen sulfide when the Stinson Process is utilized for removing high concentrations of carbon dioxide and hydrogen sulfide from natural gas streams containing nitrogen. 
         [0003]    2. Description of Related Art 
         [0004]    Hydrogen sulfide and carbon dioxide contamination are frequently encountered problems in the production of natural gas. Transporting pipelines typically do not accept natural gas containing more than about 4% CO 2  and 4 ppm hydrogen sulfide. Hydrogen sulfide is particularly problematic because it is extremely toxic to humans and is corrosive in nature. Allowing hydrogen sulfide to remain in process streams can be harmful to piping and other equipment. As such, it is desirable to remove H 2 S from the produced gas early in the processing. 
         [0005]    Known methods of removing H 2 S and CO 2  from natural gas streams include chemical solvents and physical solvents. These technologies have been well tested in the natural gas industry and the strengths and weaknesses of various chemical components used in these processes are well known to those in the industry. One such physical solvent that is well established in the industry is Selexol from Dow Chemical. With a typical Selexol process, the feed gas contacts the Selexol in a first absorber, where the majority of the CO 2  and H 2 S in the feed stream are removed into the solvent. The CO 2  and H 2 S are then separated through one or more reduced pressure separators and a stripper to produce a CO 2  and H 2 S rich “acid gas” vapor stream and a “Lean” Selexol stream to be recycled back to the inlet absorber where it removes more CO 2  and H 2 S from incoming gas. Utilization of conventional Selexol technology is used where the CO 2  concentrations are generally in the 10 to 20 percent range and are used in preference to chemical processes based on the comparative installation cost and the cost of operation. 
         [0006]    Another known method for removing both CO 2  and H 2 S from natural gas is known as the Stinson Process, as described in U.S. Pat. No. 7,883,569 and the patents related thereto. The Stinson Process takes a dehydrated feed stream containing around 70% CO 2 , 20% CH 4 , 7% N 2 , and 3.5% H 2 S and produces a processed gas stream containing around 3% N 2 , 97% CH 4 , and 0.03% H 2 S and a liquid waste stream containing around 94% CO 2  and 5% H 2 S. The CO 2  and H 2 S are removed from the feed stream using a fractionating column, with the bottom stream containing primarily CO 2  and some H 2 S and an overhead stream containing 31% CO 2  and less than 2% H 2 S. The overhead stream from the fractionating column is then processed using a methanol absorption tower to separate additional CO 2  and H 2 S and produce an intermediate processed gas stream (containing around 69% methane) as the overhead stream from the absorption tower, which is then processed through a separator to remove nitrogen and helium, resulting in a processed gas stream containing around 97% CH 4  and around 0.03% H 2 S. This processed gas stream is then typically passed through a molecular sieve to scrub the 300 ppm H 2 S down to an acceptable pipeline level of less than 4 ppm for sales gas. The methanol is then recovered using a flash chamber and a methanol stripper tower, with the recovered methanol being recycled back to the methanol absorption tower. The overhead streams from the flash chamber and methanol stripper contain CO 2 , CH 4 , and H 2 S and are recycled back to feed the fractionating column. The liquid waste stream from the fractionating column, which contains around 94% CO 2  and 5% H 2 S may be injected into an underground well, avoiding some of the environmental concerns associated with releasing CO 2  and H 2 S to the atmosphere. 
       SUMMARY OF THE INVENTION 
       [0007]    The system and method disclosed herein facilitate the economically efficient and selective removal of H 2 S from a feed gas stream containing methane and CO 2  using a solvent. The system and method of the invention are particularly suitable for integrated use in connection with the Stinson Process for removing CO 2 , wherein the solvent used to remove the H 2 S is different from the solvent used to remove CO 2  and the majority of the H 2 S is removed upstream from the CO 2  removal. Natural gas processing using the prior art Stinson Process, with around 3.5% H 2 S in the feed stream, generally results in a sales gas (hydrocarbon) stream containing no CO 2  (or less than 4 ppm CO 2 ) and around 4 ppm of H 2 S, and a CO 2  waste stream containing around 47,000 ppm H 2 S. The methanol stripping in the Stinson Process will reduce the level of H 2 S from 3.5% in the feed to around 0.03% (300 ppm), which is further reduced to 4 ppm or less after passing through a molecular sieve to produce an acceptable sales gas. While the amount of H 2 S in the sales gas stream may be within pipeline specifications, the amount in the waste stream limits the ability to use the CO 2  waste stream for flooding operations. Typically, the H 2 S specification for CO 2  flood streams is less than 100 ppm. Removing the majority of the H 2 S upstream of the Stinson Process according to the invention increases the overall process efficiencies, including a reduction in operating costs through fuel savings, while allowing production of a processed CO 2  stream from the Stinson Process that is well within specifications for allowing use of that stream in flooding operations. The processed CO 2  stream can also be delivered to the pipeline as a liquid stream, which has significant cost savings over injecting as a vapor. By reducing the H 2 S level in the Stinson Process feed to a preferable level less than 50 ppm, it may be unnecessary to use a molecular sieve after the Stinson Process to achieve a sales gas stream with an acceptable H 2 S level, which may offset some of the capital costs associated with the invention and saves on operating costs. Additionally, the use of two different solvents, a first solvent to remove H 2 S and a second solvent to remove CO 2 , where the solubility of H 2 S relative to CO 2  in the first solvent is greater than the relative solubility in the second solvent, further increases the efficiencies of the overall process. 
         [0008]    Through the use of the invention, the 3.5% (35,000 ppm) H 2 S typically found in the Stinson Process feed stream is substantially reduced. According to the invention, the processed gas stream that feeds the Stinson Process fractionating column preferably contains less than 50 ppm (0.005%) of H 2 S, but may contain up to 150 ppm or more H 2 S depending on the amount of H 2 S in the gas stream feeding the system of the invention, although the amount of H 2 S is still significantly less than the 35,000 ppm in a typical Stinson feed stream. Consequently, only trace amounts of H 2 S are present in the final sales gas (hydrocarbon) stream and in the processed CO 2  stream using the H 2 S removal methods according to the invention integrated with the Stinson Process. Additionally, the concentrated CO 2  waste stream in the typical Stinson Process has around 94% CO 2  and 5% H 2 S, which is too much H 2 S to allow use of the CO 2  in flooding operations, but not enough H 2 S to allow for recovery of sulfur—making it truly a waste stream. By first reducing the H 2 S level in the Stinson feed according to the invention, the processed CO 2  stream produced from the Stinson Process fractionating column has sufficiently low levels of H 2 S to permit use in flooding operations. Additionally, the acid gas stream of the present invention contains 0.5%-50% (or more) H 2 S, but preferably contains at least 30% H 2 S. The amount of H 2 S in the acid gas stream will depend on the amount of H 2 S in the stream that feeds the system of the invention. The preferred higher concentration levels for H 2 S in the acid gas stream of the present invention make that stream suitable for feeding a Claus Process to recover sulfur from the H 2 S, if desired. Thus the use of the invention integrated with the Stinson Process allows reuse of what would otherwise be waste streams with prior art processes. Alternatively, the volume of the acid gas stream according to the invention is relatively smaller than a traditional Stinson Process acid gas (CO 2  waste) stream, making it easier to dispose of the H 2 S if further processing is not desired. 
         [0009]    According to one embodiment of the invention, a system and method are disclosed for strategically integrating an H 2 S removal system into a typical Stinson Process operation. The feed stream that normally feeds the fractionating column (after passing through dehydration beds and a heat exchanger) in the Stinson Process is first processed through the H 2 S removal system of the present invention. After preferably being dehydrated, the feed stream passes through an absorber, where H 2 S is selectively absorbed by the use of DEPG (dimethyl ether polyethylene glycol, available from Dow Chemical under the trademark SELEXOL®) or a similar solvent. Most preferably, the removal operation is anhydrous. The vapor stream exiting the absorber is the Stinson Process feed stream that preferably feeds directly to the fractionating column in the Stinson Process and then being processed as disclosed in U.S. Pat. No. 7,883,569, which is incorporated herein by reference. The liquid stream exiting the absorber then feeds a series of separators and a stripper to recover the DEPG solvent and produce an acid gas stream preferably containing around 50% CO 2  and around 30-40% H 2 S. 
         [0010]    According to another embodiment of the invention, nitrogen is fed to the stripper to enhance separation of the DEPG from the CO 2  and H 2 S. Preferably, the nitrogen is supplied from an onsite Nitech™ NRU (such as that described in U.S. Pat. No. 5,141,544), to provide enhanced efficiencies; but other sources of nitrogen may be used. Typically, water or steam is used to regenerate the DEPG. The addition of nitrogen to the stripper enhances the recovery of the DEPG when operating in an anhydrous mode, according to a preferred embodiment of the invention. Additionally, an anhydrous operation results in further cost savings, since lower cost metals may be used in equipment fabrication. 
         [0011]    There are several advantages to the system and method disclosed herein not previously achievable by those of ordinary skill in the art using existing technologies. These advantages include, for example, the system and method allow for the CO 2  stream produced through the Stinson Process to be within pipeline specifications for use in flooding operations, rather than be treated as a waste stream requiring disposal. The system and method also allow for removal of the corrosive H 2 S prior to processing in the Stinson Process and results in an acid gas stream having sufficiently high concentration of H 2 S to allow further processing for recovery of sulfur, if desired. By integration with common utilities utilized by the Stinson Process, the cost of new equipment is reduced. Because the H 2 S is highly soluble in the methanol used in the Stinson Process, the removal of the H 2 S prior to the Stinson Process will enhance the removal of CO 2  in the Stinson Process. Additionally, the system and method of the invention require low regeneration of heat, using only 30%-50% of the energy required for conventional technologies to separate out H 2 S. The system and method of the invention are particularly well suited for feed streams containing 20% or more CO 2 . 
         [0012]    Although the present system and method has the disadvantage of higher capital costs associated with additional equipment for the H 2 S removal, the costs of such are sufficiently offset by the savings in having a usable Stinson Process CO 2  stream and savings in operating costs achieved by strategically placing the H 2 S removal upstream of the Stinson Process to take advantage of inter-operational efficiencies. 
         [0013]    Those of ordinary skill in the art will appreciate upon reading this disclosure that references to separation of H 2 S, CO 2 , and methane used herein refer to processing natural gas feed streams containing additional components to produce various multi-component product streams containing large amounts of the particular desired component, but not necessarily pure streams of any particular component. Additionally, those of ordinary skill in the art will understand that streams that are described herein as liquid or vapor streams are not necessarily purely in a liquid or gaseous state, but may be primarily present as a liquid or gas. Those of ordinary skill in the art will also appreciate upon reading this disclosure that additional processing sections for removing various components or contaminants that are present in the feed stream or intermediate streams, can also be included in the system and method of the invention, depending upon factors such as, for example, the origin and intended disposition of the product streams and the amounts of such other gases, impurities or contaminants as are present in the streams. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0014]    The system and method of the invention are further described and explained in relation to the following drawings wherein: 
           [0015]      FIG. 1  is a simplified process flow diagram illustrating principal processing stages of an embodiment of a system and method for removing H 2 S; 
           [0016]      FIG. 2  is a more detailed process flow diagram illustrating the processing stages of a preferred embodiment of a system and method for removing H 2 S. 
       
    
    
     DESCRIPTION OF PREFERRED EMBODIMENTS 
       [0017]      FIG. 1  depicts the basic processing stages of the system and method according to a preferred embodiment of the invention. The system  10  comprises processing equipment that is inserted into typical natural gas processing operations upstream of the fractionating column used in the Stinson Process. System  10  of the invention includes an absorber  20 , a scrubber  30 , a primary separator  60 , a secondary separator  90 , and a stripper  100 . System  10  also includes a DPEG processing block  130 , which includes pumps and heat exchangers as more fully described in relation to  FIG. 2 . A gas feed stream, comprising methane, hydrogen sulfide, and carbon dioxide is preferably dehydrated using known methods, such as a standard molecular sieve style water removal process, prior to entering system  10  as feed stream  12 . Feed stream  12  contains methane, at least 20% CO 2 , and at least 0.5% H 2 S. Preferably, feed stream  12  contains 15%-25% methane, at least 50% CO 2 , and most preferably 60%-80% CO 2 , 0.5%-20% H 2 S, and most preferably 3%-6% H 2 S, and 5%-15% nitrogen, although other feed stream compositions may be used with the invention. Feed stream  12  is fed into absorber  20 . A DPEG feed stream  14  is also fed to absorber  20  to facilitate removal of H 2 S from the gas feed stream  12 . Overhead stream  16 , preferably comprising around 50 ppm H 2 S or less exits absorber  20  and is the feed stream to the fractionating column of the Stinson Process. Because feed stream  12  was preferably dehydrated prior to feeding absorber  20 , it is not necessary to dehydrate overhead stream  16  prior to feeding the Stinson Process. It may be desirable to pass overhead stream  16  through a heat exchanger prior to feeding the fractionating column of the Stinson Process or stream  16  may be fed directly to the fractionating column. 
         [0018]    Bottom stream  26  is combined with a first carbon dioxide recycle stream  84  to feed scrubber  30 . Carbon dioxide recycle stream  84  comprises primarily CO 2 , with some H 2 S and small amounts of other compounds. Vapor stream  54  is recycled from the scrubber  30  back to a bottom level of the absorber  20 . Liquid stream  32  exits scrubber  30  and feeds primary separator  60 . Carbon dioxide recycle vapor stream  84  and liquid stream  62  exit primary separator  60 . Liquid stream  62  feeds secondary separator  90 . Vapor stream  92  and liquid stream  106  exit secondary separator  90  to feed stripper  100 . A nitrogen feed stream  160  may also be fed to a bottom level of stripper  100 , if desired. Stripper  100  purifies the DPEG from the feed streams to recycle it back to the DPEG processing block  130  via stream  118 . Acid gas stream  126 , preferably containing 35%-55% carbon dioxide, 5%-15% nitrogen, and 30%-50% hydrogen sulfide, exits stripper  100  as the overhead stream and may either be disposed of or may be feed to a Claus process to recover sulfur, if desired. 
         [0019]    A preferred embodiment of system  10  is depicted in greater detail in  FIG. 2 . Referring to  FIG. 2 , a 200 MMSCFD feed stream  12  containing approximately 19.5% methane, 7% nitrogen, 3.7% H 2 S, and 69.1% CO 2  at 79.9° F. and 671.9 psia feeds a middle stage of absorber  20 . The water content in stream  12  is extremely low, and most preferably zero, as it has first been dehydrated by means of a molecular sieve unit according to a preferred embodiment of the invention. Absorber  20  is also fed at an upper stage by a first solvent feed stream  14  and at a lower stage by a recycle stream  54 . A Stinson Process feed stream  16  exits as the overhead stream from absorber  20 . Bottoms stream  22  exits the bottom of absorber. 
         [0020]    Stinson Process feed stream  16  comprises approximately 21.5% methane, 7.7% nitrogen, 0.002% H 2 S, and 70% CO 2  at 95.4° F. and 670.1 psia. Stinson Process feed stream  16  preferably contains between 60%-70% of the total amount of CO 2  fed into absorber  20  and at least 80% of the CO 2  in feed stream  12 . After exiting absorber  20 , Stinson Process feed stream  16  is then preferably fed to the Stinson Process. As disclosed in U.S. Pat. No. 7,833,569, the Stinson Process feed stream (stream  16  according to the present invention), passes through a heat exchanger before entering a fractionating column. Typically, the Stinson Process feed stream is also dehydrated prior to entering the fractionating column. Because the feed stream  12  is dehydrated prior to entering absorber  20  according to a preferred embodiment of the invention, it is not necessary to dehydrate Stinson Process feed stream  16  prior to feeding the Stinson Process fractionating column. The vapor stream from the fractionating column and a second solvent feed stream (preferably methanol) feed an absorption tower, with a processed gas stream exiting as the vapor stream from the absorption tower. This vapor stream then becomes the final sales gas stream after passing through a molecular sieve in a typical Stinson Process, although it is not necessary to use a molecular sieve to achieve acceptable levels of H 2 S in the sales gas stream when the Stinson feed stream is processed according to the invention. The liquid stream from the absorption tower then feeds a flash chamber, with the liquid stream from the flash chamber feeding a methanol stripper. The vapor streams from the flash chamber and stripper are carbon dioxide recycle streams, comprising primarily carbon dioxide and some methane and hydrogen sulfide along with trace amounts of other compounds that feed back into the fractionating column. The liquid stream from the stripper is a solvent recycle stream that feeds back into the solvent feed stream. The liquid stream from the fractionating column in the typical Stinson Process is a CO 2  waste stream that is injected into an underground well. However, the high CO 2  and low H 2 S concentrations in feed stream  16  according to the invention result in the processed CO 2  stream in the Stinson Process (stream no. 60 in the Stinson &#39;569 patent) having an H 2 S concentration well within pipeline specification for use in CO 2  flooding operations, so that the CO 2  stream may be reused and does not require immediate disposal. Most preferably, the Stinson Process fractionating column bottoms stream comprises at least 90% CO 2  and less than 4 ppm H 2 S when the fractionating column is fed with stream  16  according to the invention. The Stinson Process system, and preferred parameters for operation, are more fully described in the &#39;569 patent. 
         [0021]    Referring again to  FIG. 2 , DEPG (such as Selexol®) is a preferred solvent for use in solvent feed stream  14  according to the invention because of its higher affinity for H 2 S over CO 2 . The solubility of H 2 S in DEPG is around nine times greater than that of CO 2 , allowing the bulk of the CO 2  in feed stream  12  to pass through absorber  20  and exit as Stinson Process feed stream  16 . Preferably, stream  16  contains more than 80% of the CO 2  present in feed stream  12  and more than 60% of the total CO 2  fed to absorber  20  by feed stream  12  and recycle stream  54 . Although DEPG is a preferred solvent, other solvents may be used within the scope of the invention. Additionally, the preferred solvent for use in the Stinson Process is methanol, but other solvents may be used with that process according to the invention. Most preferably, the first solvent used in absorber  20  is different from the second solvent used in the Stinson Process, with the solubility of H 2 S relative to CO 2  in the second solvent being less than the relative solubility in the first solvent. System  10  is also preferably operated in an anhydrous mode, with no water being added to the first solvent feed or added to stripper  100  (discussed below). 
         [0022]    Bottom stream  22  exits the bottom of absorber  20 , containing approximately 0.007% methane, negligible nitrogen, 36.6% DEPG, 7.9% H 2 S, and 55.4% CO 2  at 110.1° F. and 672.1 psia. Bottom stream  22  passes through liquid level control valve  24 , exiting the valve as stream  26  at 86° F. and 310 psia. The liquid entering valve  24  is capable of cooling by the well-known Joule-Thomson effect. Stream  26  is mixed with stream  84  in mixer  86 , exiting as combined stream  28  containing approximately 29.95% DEPG, 7.8% H 2 S, and 62.1% CO 2 . Combined stream  28  feeds scrubber  30 , where the majority of the CO 2  is separated for recycling back to absorber  20 . Overhead vapor stream  42  and bottom liquid stream  32  exit scrubber  30  containing approximately 60.5% and 39.5%, respectively, of the CO 2  fed to scrubber  30 . Overhead stream  42  also contains approximately 4% H 2 S and a negligible amount of DEPG, while bottom stream  32  contains approximately 10.3% H 2 S and 49.3% DEPG. Overhead stream  42  is compressed by compressor  44 , exiting as stream  46  at 236.9° F. and 700 psia. Compressor  44  receives energy, designated as energy stream Q-10. Stream  46  then passes through heat exchanger  48 , exiting as stream  54  cooled to at 110° F. Heat exchanger  48  releases heat, designated by energy stream Q-12. Stream  54 , a carbon dioxide recycle stream, is fed into a bottom stage of absorber  20 . Stream  54  contains approximately 95.9% CO 2  and 4% H 2 S at 695 psia. 
         [0023]    Bottom stream  32  exits scrubber  30  and passes through liquid level valve  34 , exiting as stream  36  having the pressure reduced from 305 psia to 120 psia and a drop in temperature of approximately 20° F. Stream  36  passes through heat exchanger  38 , which receives energy (designated as energy stream Q-14) released from heat exchanger  148 , and exits as stream  40  having been warmed from 66.5° F. to 93.4° F. Stream  40  feeds primary flash gas separator  60 , with vapor stream  72  and liquid stream  62  exiting the separator  60 . Vapor stream  72 , another carbon dioxide recycle stream containing approximately 92.6% CO 2 , and 7.2% H 2 S at 93.4° F. and 115 psia passes through compressor  74  exiting as stream  76  at 266.6° F. and 315 psia. Compressor  74  is supplied with energy designated as energy stream Q-20. Stream  76  passes through heat exchanger  78  where it is cooled to 110° F. as stream  84 . Heat exchanger  78  releases heat energy designated as energy stream Q-30. Stream  84  is then mixed with stream  26  in mixer  86  to feed scrubber  30  as combined stream  28 . 
         [0024]    Liquid stream  62 , containing approximately 18.1% CO 2 , 11.6% H 2 S, and 70.2% DEPG at 93.4° F. and 115 psia, passes through level control valve  68 , exiting the valve as partially vaporized stream  70  with a pressure drop of approximately 48 psi. Stream  70  feeds secondary flash gas separator  90 , exiting as vapor stream  92  and liquid stream  106 , both streams at 87.4° F. and 65 psia. Vapor stream  92 , containing 89.7% CO 2  and 10.1% H 2 S feeds an upper stage of stripper  100 . Liquid stream  106 , containing 11.6% CO2, 11.7% H2S and 76.6% DEPG is split by splitter  104  into streams  94  and  102 . Stream  102  feeds stripper  100 . Stream  94  passes through heat exchanger  96 , exiting as stream  98  having been heated to 288.2° F. and partially vaporized. Stream  98  feeds an intermediate stage of stripper  100 . Optionally, a nitrogen feed stream  160 , containing near 100% N 2  at 80° F. and 25 psia, may also feed a lower stage of stripper  100 . The addition of nitrogen feed stream  160  to stripper may result in increased recovery of the DEPG solvent. In the simulation example described herein, stream  160  has a flow rate of 2.5 MMSCFD. 
         [0025]    Stripper  100  strips the DEPG from the other components so that the DEPG may be recycled back to absorber  20 . Bottom liquid stream  108 , containing 99.9% DEPG at 297.8° F. and 17.5 psia, exits stripper  100  and is pumped by pump  110 , exiting as stream  112  at 65 psia. Pump  110  receives energy designated as energy stream Q-24. Stream  112  passes through heat exchanger  96  for heat transfer with stream  94 . Stream  112  exits heat exchanger  96  as stream  118  at a temperature of 105.6° F. Stream  118  enters a makeup block  134  where additional DEPG may be added or bled off via streams  132  or  136 . Stream  138  exits the makeup block  134  containing approximately 99.9% DEPG, no water, and small amounts of nitrogen and hydrogen sulfide at around 105.6° F. and 60 psia. Stream  138  is pumped through pump  140 , supplied by energy designated as energy stream Q-22. Stream  142  exits pump  140  with the pressure increased to 715 psia. Stream  142  passes through heat exchanger  144  and exits as stream  146  cooled to 110° F. Stream  146  then passes through second and third heat exchangers,  148  and  152 , ultimately exiting as DEPG feed stream  14  having a temperature of 40° F. and a pressure of 700 psia. Stream  14  feeds an upper stage of absorber  20 . Heat exchangers  144 ,  148 , and  152  release heat energy designated as energy streams Q-26, Q-14, and Q-28, respectively. 
         [0026]    Overhead vapor (or acid gas) stream  126  exits stripper  100  containing 53.9% CO 2 , 34.4% H 2 S and 11.5% N 2  at a temperature of 80.7° F. and a pressure of 15.5 psia. Acid gas stream  126  may be properly disposed of or may feed other processing equipment to recover sulfur. 
       Example 
       [0027]    The flow rates, temperatures and pressures of various simulation flow streams referred to in connection with the discussion of the system and method of the invention in relation to  FIG. 2  for a feed gas stream flow rate of approximately 200 MMSCFD and containing 7% nitrogen, 19.5% methane, 69.1% CO 2 , and 3.7% H 2 S appear in Table 1 below. The values for the energy streams referred to in connection with the discussions of the system and method of the invention in relation to  FIG. 2  appear in Table 2 below. The values discussed herein and in the tables below are approximate values. 
         [0000]    
       
         
               
             
               
               
               
               
               
               
               
               
               
             
               
               
               
               
               
               
               
               
               
             
           
               
                 TABLE 1 
               
             
             
               
                   
               
               
                 FLOW STREAM PROPERTIES 
               
             
          
           
               
                 Stream  
                   
                   
                   
                   
                   
                 Flow 
                   
                   
               
               
                 Ref. 
                   
                 % 
                 % 
                   
                 % 
                 Rate 
                 Temp. 
                 Press. 
               
               
                 No. 
                 % N 2    
                 CO2 
                 H2S 
                 % CH 4    
                 DEPG 
                 (lbmol/h) 
                 (deg. F) 
                 (psia) 
               
               
                   
               
             
          
           
               
                 12 
                 7 
                 69.1  
                 3.7 
                 19.5 
                 0 
                 21956 
                 79.9 
                 671.9 
               
               
                 14 
                 0.098 
                 0 
                 0.012 
                 0 
                 99.89  
                 4889.3 
                 40 
                 700 
               
               
                 16 
                 7.7 
                 70 
                 0.002  
                 21.5 
                 neg 
                 19889.1  
                 95.4 
                 670.1 
               
               
                 22 
                 neg 
                 55.4  
                 7.9  
                 0.007 
                 36.6 
                 13350.3 
                 110.1 
                 672.1 
               
               
                 26 
                 neg 
                 55.4  
                 7.9  
                 0.007  
                 36.6 
                 13350.3 
                 86 
                 310 
               
               
                 28 
                 neg 
                 62.1  
                 7.8 
                 0.006 
                 30 
                 16306.5  
                 87 
                 310 
               
               
                 32 
                 neg 
                 40.3  
                 10.3 
                 0.0005 
                 49.3 
                 9910.3 
                 86.6 
                 305 
               
               
                 36 
                 neg 
                 40.3  
                 10.3 
                 0.0005 
                 49.3 
                 9910.3 
                 66.5 
                 120 
               
               
                 40 
                 neg 
                 40.3  
                 10.3 
                 0.0005 
                 49.3 
                 9910.3 
                 93.4 
                 115 
               
               
                 42 
                 neg 
                 95.9  
                 3.98 
                 0.014 
                 neg 
                 6396.2 
                 86.6 
                 305 
               
               
                 46 
                 neg 
                 95.9  
                 3.98 
                 0.014  
                 neg 
                 6396.2 
                 236.9 
                 700 
               
               
                 54 
                 neg 
                 95.9  
                 3.98 
                 0.014  
                 neg 
                 6396.2 
                 110 
                 695 
               
               
                 62 
                 neg 
                 18.1  
                 11.6  
                 neg 
                 70.2 
                 6954.6 
                 93.4 
                 115 
               
               
                 70 
                 neg 
                 18.1  
                 11.6  
                 neg 
                 70.2 
                 6954.6 
                 87.7 
                 67 
               
               
                 72 
                 neg 
                 92.6  
                 7.2  
                 0.0017 
                 neg 
                 2955.7 
                 93.4 
                 115 
               
               
                 76 
                 neg 
                 92.6 
                 7.2 
                 0.0017 
                 neg 
                 2955.7 
                 266.6 
                 315 
               
               
                 84 
                 neg 
                 92.6 
                 7.2 
                 0.0017 
                 neg 
                 2955.7 
                 110 
                 310 
               
               
                 92 
                 neg 
                 89.7  
                 10.1 
                 0.0003 
                 neg 
                 582.1 
                 87.4 
                 65 
               
               
                 94 
                 neg 
                 11.6  
                 11.7 
                 neg 
                 76.6 
                 5735.3 
                 87.4 
                 65 
               
               
                 98 
                 neg 
                 11.6  
                 11.7 
                 neg 
                 76.6 
                 5735.3 
                 288.2 
                 60 
               
               
                 102 
                 neg 
                 11.6  
                 11.7 
                 neg 
                 76.6 
                 637.3 
                 87.4 
                 65 
               
               
                 106 
                 neg 
                 11.6 
                 11.7 
                 neg 
                 76.6 
                 6372.5 
                 87.4 
                 65 
               
               
                 108 
                 0.098 
                 neg 
                 0.017 
                 0 
                 99.88 
                 4889.6 
                 297.8 
                 17.5 
               
               
                 112 
                 0.098 
                 neg 
                 0.017 
                 0 
                 99.88 
                 4889.6 
                 298.2 
                 65 
               
               
                 118 
                 0.098 
                 neg 
                 0.017 
                 0 
                 99.88 
                 4889.6 
                 105.6 
                 60 
               
               
                 126 
                 11.5 
                 53.9  
                 34.4 
                 neg 
                 0.0001 
                 2339.6 
                 80.7 
                 15.5 
               
               
                 132 
                 0 
                 0 
                 0 
                 0 
                 100 
                 0 
                 100 
                 115 
               
               
                 136 
                 0.098 
                 neg 
                 0.017 
                 0 
                 99.88 
                 0.029 
                 105.6 
                 60 
               
               
                 138 
                 0.098 
                 neg 
                 0.017 
                 0 
                 99.88 
                 4889.5 
                 105.6 
                 60 
               
               
                 142 
                 0.098 
                 0 
                 0.012 
                 0 
                 99.88 
                 4889.3 
                 110.5 
                 715 
               
               
                 146 
                 0.098 
                 0 
                 0.012 
                 0 
                 99.88 
                 4889.3 
                 110 
                 710 
               
               
                 150 
                 0.098 
                 0 
                 0.012 
                 0 
                 99.88 
                 4889.3 
                 72.5 
                 705 
               
               
                 160 
                 100 
                 0 
                 0 
                 0 
                 0 
                 274.5 
                 80 
                 25 
               
               
                   
               
             
          
         
       
     
         [0000]    
       
         
               
             
               
               
               
               
               
             
               
               
               
               
               
             
           
               
                 TABLE 2 
               
             
             
               
                   
               
               
                 ENERGY STREAM REPORT 
               
             
          
           
               
                 Energy 
                   
                   
                   
                   
               
               
                 Stream 
               
               
                 Reference 
                 Energy Rate 
                 Power 
               
               
                 Numeral 
                 (MMBtu/h) 
                 (hp) 
                 From 
                 To 
               
               
                   
               
             
          
           
               
                 Q-10 
                   
                 3027.2 
                 — 
                 Compressor 
               
               
                   
                   
                   
                   
                 44 
               
               
                 Q-12 
                 9.78 
                   
                 Heat 
                 — 
               
               
                   
                   
                   
                 Exchanger 
               
               
                   
                   
                   
                 48 
               
               
                 Q-14 
                 25.34 
                   
                 Heat 
                 Heat 
               
               
                   
                   
                   
                 Exchanger 
                 Exchanger 
               
               
                   
                   
                   
                 148 
                 38 
               
               
                 Q-18 
                 25 
                 9825.4 
                 — 
                 Stripper 100 
               
               
                 Q-20 
                   
                 1768.2 
                 — 
                 Compressor 
               
               
                   
                   
                   
                   
                 74 
               
               
                 Q-22 
                   
                 1587.3 
                 — 
                 Pump 140 
               
               
                 Q-24 
                   
                 126.5 
                 — 
                 Pump 110 
               
               
                 Q-26 
                 0.33 
                   
                 Heat 
                 — 
               
               
                   
                   
                   
                 Exchanger 
               
               
                   
                   
                   
                 144 
               
               
                 Q-28 
                 21.1 
                   
                 Heat 
                 — 
               
               
                   
                   
                   
                 Exchanger 
               
               
                   
                   
                   
                 152 
               
               
                 Q-30 
                 4.74 
                   
                 Heat 
                 — 
               
               
                   
                   
                   
                 Exchanger 
               
               
                   
                   
                   
                 78 
               
               
                   
               
             
          
         
       
     
         [0028]    Those of ordinary skill in the art will appreciate upon reading this disclosure that the values discussed above are based on the particular parameters and composition of the feed stream in the Example, and that the values can differ depending upon differences in operating conditions and upon the parameters and composition of the feed stream  12 . Those of ordinary skill in the art will also appreciate upon reading the disclosure in light of the accompanying drawings that alterations and modifications of the invention may be made and it is intended that the scope of the invention disclosed herein be limited only by the broadest interpretation of the appended claims to which the inventor is legally entitled.