Abstract:
A method of hydrogen and methane recovery from syngas from a gasifier is provided. Then directing a raw syngas stream from an acid gas removal system to a CO and methane removal system. Then returning the CO and methane stream to the gasifier, and exporting the hydrogen stream as a product. 
     This method may include exchanging heat between a raw syngas stream from an acid gas removal system, a separated CO and methane stream, a separated hydrogen stream and a liquid nitrogen stream in a heat exchanger. Then directing the cooled raw syngas stream to a cryogenic Then returning the warmed separated CO and methane stream to the gasifier, and exporting the vaporized nitrogen stream as product.

Description:
BACKGROUND 
       [0001]    Hydrogen is most often manufactured using natural gas as a feedstock through the steam methane reforming process. With the current high prices of natural gas it is preferred to manufacture hydrogen from lower cost sources of fuel such as residual fuels. Residual fuels from refineries consist of petroleum coke, visbreaker tar, pitch from deasphalting processes, vacuum residues, atmospheric residues and similar fuels. Coal is also a desirable low cost fuel that can be used to produce hydrogen. 
         [0002]    The typical method of producing hydrogen from residual fuels or coal is to gasify it by partially oxidizing it by contact with oxygen and steam or water at elevated temperatures to form a syngas. The syngas consists of hydrogen, carbon monoxide, methane and carbon dioxide. Higher quantities of hydrogen are usually produced by further reacting the syngas with steam over a catalyst to promote the water gas shift reaction of carbon monoxide and steam to hydrogen and carbon dioxide. 
         [0003]    After the removal of acid gases such as hydrogen sulfide and carbon dioxide in processes such as amine contactors, Selexol or Rectisol units, the hydrogen still needs to be purified. Hydrogen can be further purified to remove residual amounts of Carbon monoxide through a catalytic reaction to form methane (methanation) and water. This will produce a final product hydrogen stream with about 97% purity. The remaining composition is methane, nitrogen and argon. If higher purity hydrogen (&gt;99%) is desired, the hydrogen is further processed through a Pressure Swing Adsorption (PSA). Due to the limits of PSA technology, the typical hydrogen recovery is about 87-90%. 
         [0004]      FIG. 1  shows a typical hydrogen production from a gasifier with methanation for the final hydrogen purification as known in the prior art. For this process, the hydrogen recovery is near 100%, but the purity is limited by the purity of the oxygen coming in and the degree of conversion in the shift reactor. Typical purity would be about 97%. The disadvantage of this process is that hydrogen purity is significantly lower than that expected by refiners. Refiners have designed their processes for 99.9% purity hydrogen that can be obtained from a PSA. The lower purity is a disadvantage for using methanation as the final purification of the hydrogen. 
         [0005]      FIG. 2  shows a typical hydrogen production from a gasifier with PSA for hydrogen purification as known in the prior art. With a PSA, recovery of hydrogen is limited to about 87-90% for production of 99.9% purity hydrogen. In order to increase the recovery of hydrogen, a recycle compressor can be added to route the tail gas back to the PSA. With recycle, the recovery can be increased to about 92-95%. The ultimate recovery is limited by the amount of purge that needs to be taken to remove the methane, and residual carbon monoxide (from the gasifier and shift reactions), and nitrogen and argon that are brought in with the oxygen. 
         [0006]    The present invention provides a process for producing pure hydrogen and recovering methane from gasifier syngas. 
       SUMMARY 
       [0007]    In one embodiment of the present invention a method of hydrogen purification and methane recovery from syngas from a gasifier is provided. This method includes directing a raw syngas stream from an acid gas removal system, the raw syngas stream comprising CO, methane, water, and hydrogen stream to a CO and methane removal system, thereby producing pure hydrogen stream and a stream comprising CO and methane. This method also includes returning the CO and methane stream to the gasifier, and exporting the hydrogen stream as a product. 
     
    
     
       BRIEF DESCRIPTION OF THE FIGURES 
         [0008]      FIG. 1  illustrates a typical hydrogen production from a gasifier with methanation for the final hydrogen purification as known in the prior art. 
           [0009]      FIG. 2  illustrates a typical hydrogen production from a gasifier with PSA for hydrogen purification as known in the prior art. 
           [0010]      FIG. 3  illustrates one embodiment of the present invention, utilizing a cryogenic CO and Methane removal system. 
           [0011]      FIG. 4  illustrates one embodiment of the present invention, utilizing cryogenic separation and a TSA. 
       
    
    
     DESCRIPTION OF PREFERRED EMBODIMENTS 
       [0012]    Turning now to  FIG. 3 , the invention is a process for production of hydrogen  317  from residual fuels  301 . In the present invention, feedstock for the hydrogen production unit  301  can be refinery residues such as petroleum coke, visbreaker tar, pitch from deasphalting processes, vacuum residues, atmospheric residues and similar fuels or coal. The feed  301  is combined with oxygen  302  produced in an Air Separation Unit (ASU) (not shown). The purity of the ASU is adjusted in order to be in the range of 99% to 99.98% Oxygen. 99.5% Oxygen may be preferred considering power consumption in the ASU. 
         [0013]    The oxygen  302  and the feed  301  are fed to the gasifier reactor  304 . In some processes solid feeds are combined with water  303  to form a slurry. In other processes, solid or liquid feeds  301  are combined with steam  303  and oxygen  302  and fed to the gasifier reactor  304 . In the gasifier reactor  304  the feed is converted to a raw syngas  305  comprised of hydrogen, carbon monoxide, carbon dioxide, methane, water and hydrogen sulfide. Residual argon and nitrogen coming in with the oxygen will also be present in the syngas. In some gasification processes, the syngas flows to a heat exchanger to produce steam (not shown). In other gasification process, the syngas is quenched directly with water to cool it down (not shown). Solids can be removed as a slag or through filtration of the resulting water. 
         [0014]    The raw syngas  305  if then fed to a shift converter  306  where it is contacted with a catalyst to promote the water gas shift reaction. For quench systems, no additional steam is necessary for the shift reaction. If the syngas is used to produce steam in a heat exchanger, steam will need to be injected into the syngas upstream of the shift converter. The CO shift is done in multiple stages with intercooling between the two stages. 
         [0015]    The residual CO at the outlet of the last stage is in the range of 0.2 to 2%. The product of the shift reactor will be mostly hydrogen, carbon dioxide, hydrogen sulfide, methane, residual carbon monoxide and the argon and nitrogen that entered with the oxygen and excess water. The shifted syngas is cooled down by indirect heat exchange  307 . Indirect contact heat exchanger  307  then transfers heat indirectly between the BFW or other process streams  318  (not shown) and the hot shifted syngas stream thereby producing a cooled, shifted syngas stream and steam or other elevated temperature process streams  308 . The cooled, shifted syngas stream is then fed to the acid gas removal (AGR) system  309  where excess water  312 , carbon dioxide  310 , and hydrogen sulfide  311  are removed, and raw hydrogen stream  313  is produced. If additional dryers are necessary, they may be added to the system as required by one skilled in the art. 
         [0016]    Raw hydrogen stream  313  will contain un-shifted carbon monoxide, methane and mostly hydrogen along with residual nitrogen and argon. Methanol is the preferred solvent (e.g. Rectisol Process) for acid gas removal. When using methanol, the syngas stream is cooled to low temperatures, about −40° to about −60° C. There are other solvents such as Selexol and MDEA used for acid gas removal. The Selexol solvent operates in the range of about +10° to about −20° C., while MDEA based solvent run at ambient temperatures. 
         [0017]    After acid gas removal, the vapor stream  313  containing hydrogen, methane, CO and residual argon and nitrogen is further purified by passing it over an adsorbent  314  at the low temperatures where the CO and methane are adsorbed. A multiple bed temperature-swing-adsorption (TSA)  314  unit may be used to remove the impurities. Methane is removed down to less than 1000 ppm, preferably below 100 ppmv. CO is removed down below 10 ppmv, preferably below 1 ppmv. 
         [0018]    TSA  314  may be regenerated by either direct or indirect heat exchange with a warm fluid stream. In embodiments where TSA  314  is regenerated by direct heat exchange, the warm fluid stream may be, but is not limited to, a slip stream of hydrogen product gas In embodiments where TSA  314  is regenerated by indirect heat exchange, the warm fluid stream may be, but is not limited to, steam, ambient air, or the warm gas stream entering the AGR system. 
         [0019]    Whereas, in the current state-of-the-art, the typical acid gas removal system (such as the Rectisol process) has an inlet gas stream at approximately ambient temperature, and a treated outlet gas stream also at approximately ambient temperature, the internal process is at temperature of about −40° to about −60° C. Typically if a temperature swing adsorption (TSA) unit is located downstream of the acid gas removal system, the ambient (or above ambient) temperature gas stream must again be cooled to approximately this same low temperature. One important aspect of the present invention is the thermal integration of the TSA with the AGR. According to the present invention, the low temperature TSA process is performed after the AGR process, but before the treated gas leaves the AGR system at ambient temperature. This improves the overall thermodynamic efficiency of the plant, among other things. This integration may be performed by any way known in the art. 
         [0020]    Adsorption at cryogenic temperature in adsorbent  314  is a key part of this invention. The adsorption temperature range can be between about −100° to about +10° C. For methanol based acid gas removal processes (for example the Rectisol process), the gas out of the CO2 absorber is between about −40° and about −60° C., and can be sent directly to the TSA unit. Integration of cryogenic adsorption with chilled methanol acid gas removal process is also an important feature of this invention. The purified hydrogen at the outlet of TSA is sent back to the acid gas removal process for recovery of cold, as shown in  FIG. 5 . For other processes, such as Selexol or MDEA, the gas out of the absorber may have to be chilled down to the desired range of −40 to −60° C. before it is fed to the TSA unit. 
         [0021]    Turning now to  FIG. 4 , the invention is a process for production of hydrogen  426  from residual fuels  401 . In the present invention, feedstock for the hydrogen production unit  401  can be refinery residues such as petroleum coke, visbreaker tar, pitch from deasphalting processes, vacuum residues, atmospheric residues and similar fuels or coal. The feed  401  is combined with oxygen  402  produced in an Air Separation Unit (ASU)  422 . The purity of the oxygen  402  from ASU  422  is adjusted in order to be in the range of 99% to 99.98% Oxygen. 99.5% Oxygen may be preferred considering power consumption in the ASU. 
         [0022]    The oxygen  402  and the feed  401  are fed to the gasifier reactor  404 . In some processes solid feeds are combined with water  403  to form a slurry. In other processes, solid or liquid feeds  401  are combined with steam  403  and oxygen  408  and fed to the gasifier reactor  404 . In the gasifier reactor  404  the feed is converted to a raw syngas  405  comprised of hydrogen, carbon monoxide, carbon dioxide, methane and hydrogen sulfide. Residual argon and nitrogen coming in with the oxygen will also be present in the syngas. In some gasification processes, the syngas flows to a heat exchanger to produce steam (not shown). In other gasification process, the syngas is quenched directly with water to cool it down (not shown). Solids can be removed as a slag or through filtration of the resulting water. 
         [0023]    The raw syngas  405  if then fed to a shift converter  406  where it is contacted with a catalyst to promote the water gas shift reaction. For quench systems, no additional steam is necessary for the shift reaction. If the syngas is used to produce steam in a heat exchanger, steam will need to be injected into the syngas upstream of the shift converter. The CO shift is done in multiple stages with intercooling between the two stages. 
         [0024]    The residual CO at the outlet of the last stage is in the range of 0.2 to 2%. The product of shift reactor  406  will be mostly hydrogen, carbon dioxide, hydrogen sulfide, methane, residual carbon monoxide and argon and nitrogen that entered with the oxygen and excess water. The shifted syngas is cooled down by indirect heat exchange  407 . Indirect contact heat exchanger  407  then transfers heat indirectly between the BFW or other process streams  427  and the hot shifted syngas stream thereby producing a cooled, shifted syngas stream and steam or other elevated temperature process streams  408 . 
         [0025]    The cooled, shifted syngas stream is then fed to the acid gas removal system  409  where excess water  412 , carbon dioxide  410 , and hydrogen sulfide  411  are removed. The resulting hydrogen stream  413  will contain un-shifted carbon monoxide, methane and mostly hydrogen along with residual nitrogen and argon. 
         [0026]    Methanol is the preferred solvent (e.g. Rectisol Process) for use in acid gas removal system  409 . When using methanol, the syngas stream is cooled to low temperatures, about −40 to −60° C. There are other solvents such as Selexol and MDEA used for acid gas removal. The Selexol solvent operates in the range of between about +10° and about −20° C., while MDEA based solvent run at ambient temperatures. 
         [0027]    After acid gas removal, the vapor stream  413 , containing hydrogen, methane, CO and residual argon and nitrogen is cooled to cryogenic temperatures (approximately −160° C.) by indirect heat exchange in heat exchanger  414 , against liquid nitrogen  424  from ASU  422  and with CO and Methane  417  from separation and TSA  416 . The preferred cryogenic temperature, to TSA  416 , would be between about −200° to about −60° C. The stream  416  temperature must be kept above the freezing temperature of methane at the given conditions for  416 . 
         [0028]    After cooling, vapor stream  415  is further purified by passing it over an adsorbent  416  at the low temperatures where the CO and methane are adsorbed. A multiple bed temperature-swing-adsorption (TSA) unit  416  may be used to remove the impurities. The cold waste gas (or purge gas) stream  421  containing hydrogen, nitrogen, argon, and CO may be sent to a boiler (not shown) or other source of combustion after recovery of cold in  414 . Methane is removed down to less than 1000 ppm, preferably below 100 ppmv. CO is removed down below 10 ppmv, preferably below 1 ppmv. 
         [0029]    Adsorption at cryogenic temperature in separation and TSA unit  416  is a key part of this invention. The adsorption temperature range can be about −200° to about −60° C. For methanol based acid gas removal processes, the gas out of the CO2 absorber is between about −40° and about −60° C., and can be sent directly to the TSA unit. Integration of cryogenic adsorption with chilled methanol acid gas removal process is also an important feature of this invention. The purified CO+methane stream  417  at the outlet of TSA  416  may be sent back to the acid gas removal process  409  for recovery of cold. For other processes, such as Selexol or MDEA, the gas out of the absorber may have to be chilled down to the desired range of about −40° to −60° C. before it is fed to the TSA unit. An interchanger that exchanges cold between the incoming gas and effluent from the TSA will reduce the load on the refrigeration unit. 
         [0030]    Methanol wash and Selexol processes remove water along with acid gases. Dew point of the effluent from acid wash has to be kept in mind, as it should be lower than the adsorption temperature of the TSA unit. A drier may be required between the acid gas removal and cryogenic adsorption unit for removal of moisture and any residual CO2 that could freeze. The chilling of the gas can also be done by integrating it with ASU  422 . 
         [0031]    The CO and Methane stream  417  that is separated in separation unit  416  is sent to heat exchanger  414 , where it exchanges heat with pure hydrogen stream  426 , impure hydrogen steam  413  and liquid nitrogen stream  424 . Resulting CO and Methane stream  418  may be compressed in compressor  419  and sent to gasifier  404 . Nitrogen stream  424 , from air separation unit  422 , is sent to heat exchanger  414  where it is heated and vaporized, resulting in product gaseous nitrogen steam  425 . 
         [0032]    Once the adsorbent is loaded with impurities, it is taken off line and the impure hydrogen stream is switched to a regenerated bed of adsorbent. To regenerate the adsorbent, a stream of warm pure hydrogen is passed over the adsorbent bed to heat it up. As the adsorbent heats up, CO and methane and any argon, nitrogen and hydrogen present are desorbed from the adsorbent. The effluent from the regeneration is compressed and returned to the gasifier where the methane is converted to CO and Hydrogen. 
         [0033]    Hydrogen recovery for this process is 90-100% with purity of 99.0 to 99.99% requirements. The ultimate purity is determined by the argon and nitrogen impurities coming in with the oxygen, and the extent of argon and N2 removal in the TSA. The recycle of methane and CO recovered in the TSA unit increases the overall hydrogen capacity of the unit for the same amount of residue fuel being gasified. 
         [0034]    In a variation of the previous embodiment, the regeneration gas from the TSA is not recycled back to the gasifier, but is instead used as fuel for a process heater or a boiler raising steam (not shown). In this case the purity of this hydrogen can exceed 99.99%. The hydrogen recovery is dependent on the amount of impurities (Argon and Nitrogen) coming in with the oxygen, but can be as high as 95-99.9% with high purity oxygen.