Patent Publication Number: US-8968685-B2

Title: Fuel processing system and related methods

Description:
TECHNICAL FIELD 
     The present disclosure relates to a system and a method of producing methanol. More specifically, embodiments of the present disclosure relate to a system and a method of converting a mixture of air and logistical fuel into a liquid product comprising methanol. 
     BACKGROUND 
     Methanol, the simplest alcohol, is a commodity chemical that is used in a wide range of applications. For example, methanol may be used in the production of other chemicals (e.g., formaldehyde, gasoline, dimethyl ether), as a biological food source for bacteria (e.g., to support sewage treatment facilities), and as a fuel source for a direct methanol fuel cell (DMFC). 
     The production of substantially pure methanol has been known since 1661 when Robert Boyle produced it through the distillation of boxwood. Since that time, the production of methanol has expanded, and today methanol is generally produced on a very large scale. Conventional methanol production facilities can produce 1000 metric tons of methanol per day. For example, a methanol production facility in Al Jubail, Saudi Arabia, has been reported to produce approximately 850,000 tons per year of methanol. Such production of methanol is typically facilitated through the catalyst-assisted steam reformation of natural gas or coal to form synthesis gas. The synthesis gas is then reacted over a catalyst at high pressure at conversions typically less than 20%. Large facilities require recycle loops. However, preparing methanol using conventional production methods at small scales is not commercially feasible. The produced methanol may then be conventionally distributed as demand requires. 
     However, in certain, specialized situations the use of conventional methanol production processes may not be a viable option. Such situations may, for example, include scenarios where the transport or delivery of methanol is in some way precluded and/or where the on-site production of methanol through conventional fuels (e.g., natural gas, coal) is not possible. A non-limiting example of such a situation may be current U.S. military operations. 
     In 1988, the U.S. Army adopted a so-called “single fuel forward” initiative generally mandating the use of only one fuel in its operations. That fuel is currently a kerosene-based fuel known as Jet Propellant 8 (JP-8). Disadvantageously, the initiative is not readily compatible with some methanol-based technologies that may be of interest to the U.S. military, including DMFCs. DMFCs, which attempt to harness the theoretical 6100 W h/kg at 25° C. energy density of methanol, have been examined as a potential replacement for the numerous batteries (rechargeable and non-rechargeable) currently used in U.S. military operations. A methanol-containing DMFC cartridge typically offers more stored power than a battery, and using DMFCs may reduce various logistical and transportation concerns currently associated with the use of batteries. 
     Therefore, in at least some specialized situations, there remains a need for a portable fuel processing system that uses a logistical fuel, such as JP-8, to manufacture methanol products. Such a system may bridge the gap between the methanol that may be required and the logistical fuel that may be available. 
     BRIEF SUMMARY 
     Embodiments described herein include systems for producing methanol from a logistical fuel, and related methods. For example, in accordance with one embodiment described herein, a fuel processing system may comprise a fuel injection system configured to combine a logistical fuel and ambient air to produce a logistical fuel and air mixture, a synthesis gas production system positioned downstream of the fuel injection system and configured to convert the logistical fuel and air mixture to synthesis gas, and a methanol synthesis system positioned downstream of the synthesis gas production system and configured to convert the synthesis gas to a crude methanol liquid. 
     In additional embodiments, a method of manufacturing a liquid product comprising methanol may comprise combining a logistical fuel and ambient air to produce a logistical fuel and air mixture, converting the logistical fuel and air mixture into synthesis gas comprising carbon monoxide and hydrogen, converting the synthesis gas to a crude methanol liquid, processing the crude methanol liquid to produce a purified methanol liquid, and directing at least the purified methanol liquid into a dispensing valve to generate the liquid product comprising methanol and water. 
     In yet additional embodiments, a method of manufacturing a fuel for use in a direct methanol fuel cell may comprise processing a logistical fuel and ambient air to produce a purified methanol liquid, combining the purified methanol liquid with water to produce a liquid product, and delivering the liquid product into at least one empty direct methanol fuel cell cartridge. 
    
    
     
       BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS 
       While the specification concludes with claims particularly pointing out and distinctly claiming that which is regarded as the invention, advantages of the invention can be more readily ascertained from the following detailed description when read in conjunction with the accompanying drawings in which: 
         FIG. 1  is a simplified block flow diagram of a fuel processing system for converting a logistical fuel and air into a methanol product, in accordance with embodiments of the present disclosure. 
         FIG. 2  is a schematic view of the fuel processing system of  FIG. 1 , in accordance with an embodiment of the present disclosure. 
         FIG. 3  is a schematic view of an embodiment of a synthesis gas production system portion of the fuel processing system of  FIG. 1 . 
         FIG. 4  is a schematic view of an embodiment of a synthesis gas production system portion of the fuel processing system of  FIG. 1 . 
         FIG. 5  is a schematic view of an embodiment of a synthesis gas production system portion of the fuel processing system of  FIG. 1 . 
         FIG. 6  is a schematic view of an embodiment of a methanol synthesis system portion of the fuel processing system of  FIG. 1 . 
         FIG. 7  is a schematic view of an embodiment of a methanol synthesis system portion of the fuel processing system of  FIG. 1 . 
         FIG. 8  is a schematic view of an embodiment of a methanol refusing system portion of the fuel processing system of  FIG. 1 . 
         FIGS. 9 and 10  are perspective views of a portion of the fuel processing system of  FIG. 2 , lacking a methanol storage and delivery system. 
     
    
    
     DETAILED DESCRIPTION 
     The following description provides specific details, such as catalyst types, fuel compositions, and processing conditions (e.g., temperatures, pressures, flow rates, etc.) in order to provide a thorough description of embodiments of the present disclosure. However, a person of ordinary skill in the art will understand that the embodiments of the present disclosure may be practiced without employing these specific details. Indeed, the embodiments of the present disclosure may be practiced in conjunction with conventional systems and methods employed in the industry. In addition, only those process components and acts necessary to understand the embodiments of the present disclosure are described in detail below. A person of ordinary skill in the art will understand that some process components (e.g., pipelines, line filters, valves, temperature detectors, flow detectors, pressure detectors, and the like) are inherently disclosed herein and that adding various conventional process components and acts would be in accord with the present disclosure. The drawings accompanying the present application are for illustrative purposes only, and are not meant to be actual views of any particular material, device, or system. Additionally, elements common between figures may retain the same numerical designation. 
     Methods and systems of producing methanol from a logistical fuel are described. The logistical fuel is reformed to synthesis gas, which is converted to methanol. The systems and methods of embodiments of the present disclosure may be used to produce methanol at a small-scale, such as about 0.1 metric ton per day, rather than producing large amounts of methanol as is done by conventional systems and methods. The methanol produced by the methods and systems of embodiments of the present disclosure may be produced at the point-of-use, rather than at a remote facility. 
       FIG. 1  is a simplified block diagram of a fuel processing system  100  in accordance with the present disclosure. The fuel processing system  100  functions to convert ambient air  20  and a logistical fuel (i.e., a liquid logistical fuel stream  12 ) into a liquid product  138  that includes methanol. The fuel processing system  100  may include a fuel injection system  102 , optionally, a heat exchanger  104 , a synthesis gas production system  106 , a methanol synthesis system  108 , optionally, a methanol refining system  110 , and, optionally, a methanol storage and delivery system  112 . The fuel processing system  100  may be sized and configured to produce a desired output of the liquid product  138 , such as within the range of from about 1.0 L/hr to about 50.0 L/hr, or from about 7.5 L/hr to about 14.5 L/hr. The logistical fuel may include at least one of JP-8, Jet-A, JP-4, JP-5, kerosene, naphtha, diesel, marine, gasoline, and other hydrocarbon fuels. In one embodiment, the logistical fuel is JP-8. JP-8 is a kerosene-based jet fuel and includes icing inhibitors, corrosion inhibitors, antioxidants, lubricants, biocides, thermal stability agents, and antistatic agents. The kerosene includes C 9 -C 16  hydrocarbon compounds, such as a mixture of isooctane, methylcyclohexane, m-xylene, cyclooctane, decane, butylbenzene, 1,2,4,5-tetramethylbenzene, tetralin, dodecane, 1-methylnaphthalene, tetradecane, and hexadecane. In at least some embodiments, the fuel processing system  100  may be configured and operated to convert other fuels, such as natural gas, into the liquid product  138 . 
     One embodiment of the present disclosure will now be described with reference to  FIG. 2 , which schematically illustrates a fuel processing system  100 . As shown in  FIG. 2 , the fuel injection system  102  may include a fuel pump  14 , an air compressor  22 , a mass flow controller  26 , an air heater  30 , and a fuel injector  18 . The fuel pump  14  receives a logistical fuel stream  12  from a storage vessel  10  and raises the pressure of the logistical fuel. The logistical fuel stream  12  may be in a liquid form. A pressurized liquid logistical fuel stream  16  is then directed out of the fuel pump  14  and into the fuel injector  18 . In at least some embodiments, a fuel pressure regulator (not shown) may be provided downstream of the fuel pump  14  to further control the pressure of the pressurized liquid logistical fuel stream  16 . The air compressor  22  may receive ambient air  20  and may raise the pressure of the ambient air  20  to be within an operative pressure range of the mass flow controller  26 . Pressurized air  24  may then be directed out of the air compressor  22  and into the mass flow controller  26 . The mass flow controller  26  may control the flow rate of the pressurized air  24  in a manner that accords with a desired mixture ratio of logistical fuel to air to be achieved via the fuel injector  18 . The pressurized air  24  may then be directed into the heat exchanger  104 . In the heat exchanger  104  the pressurized air  24  may be heated. Heated and pressurized air  28  may then be directed out of the heat exchanger  104  and into the air heater  30 . The air heater  30  may increase the temperature of the heated and pressurized air  28  to a pre-determined set-point. In one or more embodiments, at least one of the heat exchanger  104  and the air heater  30  may be omitted. Therefore, the heat exchanger  104  and the air heater  30  may each be optional. In at least some embodiments, the temperature of the heated and pressurized air  28  may be greater than or equal to about 160° C., such as greater than or equal to about 300° C., or greater than or equal to about 350° C. The heated and pressurized air  28  may then be directed out of the air heater  30  and into the fuel injector  18 . 
     The fuel injector  18  may facilitate the mixing of the pressurized liquid logistical fuel stream  16  and the heated and pressurized air  28 . After receiving the pressurized logistical fuel stream  16  and the heated and pressurized air  28 , the fuel injector  18  may be “opened,” to force the logistical fuel and air through an atomizing nozzle. This process may create a logistical fuel/air mixture  32  that includes small droplets of liquid logistical fuel dispersed in air. The logistical fuel/air mixture  32  may have an oxygen to carbon ratio of between about 0.4 and about 1.25. In at least some embodiments, the temperature of the logistical fuel/air mixture  32  may be greater than or equal to about 160° C., such as greater than or equal to about 300° C., or greater than or equal to about 350° C. The flow rate and flow regularity of the logistical fuel/air mixture  32  may be modified as desired by adjusting the pressure of the pressurized liquid logistical fuel stream  16 , the amount of time that the fuel injector  18  remains open, and the frequency with which the fuel injector  18  is opened. The logistical fuel/air mixture  32  may be directed to the synthesis gas production system  106 . 
     The synthesis gas production system  106  may include desulfurization units  34  and  44 , a catalytic partial oxidation (CPDX) reactor  38 , and, optionally, a water gas shift (WGS) reactor  48 . The logistical fuel/air mixture  32  may be received by the desulfurization unit  34 . The desulfurization unit  34  may be any suitable apparatus or device known in the art for reducing the sulfur content of a hydrocarbon, such as the logistical fuel. The desulfurization unit  34  may reduce the sulfur content of the logistical fuel/air mixture  32  to a level that substantially reduces or eliminates catalyst poisoning within the CPDX reactor  38 . In at least some embodiments, the desulfurization unit  34  may facilitate a reaction with the logistical fuel/air mixture  32  to produce a desulfurized logistical fuel/air mixture  36  including less than about 50 ppm sulfur. The desulfurized logistical fuel/air mixture  36  may then be directed into the CPDX reactor  38 . In at least some embodiments, the temperature of the desulfurized logistical fuel/air mixture  36  may be within a range of from about 175° C. to about 450° C., such as from about 300° C. to about 425° C., or from about 350° C. to about 400° C. In at least some embodiments, the sulfur content of the logistical fuel and/or the configuration of the CPDX reactor  38  may enable the desulfurization unit  34  to be omitted from the synthesis gas production system  106 , and the logistical fuel/air mixture  32  may be directed into the CPDX reactor  38 . Therefore, the desulfurization unit  34  may be optional. 
     Optionally, to increase the percentage of O 2  in the desulfurized logistical fuel/air mixture  36 , a suitable oxygen concentrator, such as at least one of a pressure swing adsorption (PSA) system (not shown) and a molecular sieve (not shown), may be provided upstream of the CPDX reactor  38 . 
     The CPDX reactor  38  may be any suitable apparatus or device known in the art for the catalytic partial oxidation of a hydrocarbon. The CPDX reactor  38  may be configured and operated to reform the desulfurized logistical fuel/air mixture  36  into a synthesis gas according to the following general equation, where, for a given hydrocarbon, “n” corresponds to an integer within the range of from 1 to 50 and “m” corresponds to an integer within the range of from 1 to 100: 
     
       
         
           
             
               
                 
                   
                     
                       
                         C 
                         n 
                       
                       ⁢ 
                       
                         H 
                         m 
                       
                     
                     + 
                     
                       
                         n 
                         2 
                       
                       ⁢ 
                       
                         O 
                         2 
                       
                     
                   
                   -&gt; 
                   
                     
                       n 
                       ⁢ 
                       
                           
                       
                       ⁢ 
                       CO 
                     
                     + 
                     
                       
                         m 
                         2 
                       
                       ⁢ 
                       
                         H 
                         2 
                       
                     
                   
                 
               
               
                 
                   ( 
                   1 
                   ) 
                 
               
             
           
         
       
     
     The catalytic partial oxidation may be conducted over a catalyst including at least one of Fe, Ru, Os, Co, Rh, Ir, Ni, Pd, Pt, Cu, Ag, and Au. In one embodiment, the catalyst includes at least one of Rh and Pt. The CPDX reactor  38  may have an operating temperature within a range of from about 600° C. to about 1600° C., such from about 800° C. to about 1250° C., or from about 900° C. to about 1100° C. The synthesis gas may include additional components, such as N 2 , CO 2 , H 2 O and trace amounts of small hydrocarbons. A synthesis gas  40  may exit the CPDX reactor  38  and may then be directed into the heat exchanger  104 . 
     The heat exchanger  104  may be any suitable apparatus or device known in the art for exchanging heat from one fluid or gas to another fluid or gas. By way of non-limiting example, the heat exchanger  104  may be a recuperative heat exchanger, which functions to cool the synthesis gas  40  while heating the pressurized air  24 . In one or more embodiments, the heat exchanger  104  may cool the synthesis gas  40  from a temperature within a range of from about 600° C. to about 1600° C. to a temperature within a range of from about 200° C. to about 350° C., such as from about 250° C. to about 340° C. In at least some embodiments, one or more flow control devices (not shown) may be positioned proximate at least one of an inlet and an outlet of the heat exchanger  104  to control the flow rate of at least one of the synthesis gas  40  and the pressurized air  24  and regulate the heat exchange rates thereof. Upon exiting the heat exchanger  104 , a cooled synthesis gas  42  may be directed into the desulfurization unit  44 . In at least some embodiments, the heat exchanger  104  may be omitted, and the synthesis gas  40  may be cooled by some other known device or apparatus, or not at all. Therefore, the heat exchanger  104  may be optional. 
     The desulfurization unit  44  may be any suitable apparatus or device known in the art for reducing the sulfur content of a gas. The desulfurization unit  44  may be similar to or different than the desulfurization unit  34 . The desulfurization unit  44  may substantially reduce the sulfur content of the cooled synthesis gas  42 . A desulfurized synthesis gas  46  may exit the desulfurization unit  44  and may then be directed into the WGS reactor  48 , if present. The temperature of the desulfurized synthesis gas  46  may be within the range of from about 200° C. to about 350° C., such as from about 300° C. to about 350° C. 
     The WGS reactor  48  may be any suitable apparatus or device known in the art for reacting CO 2  and H 2  to produce CO and H 2 O. The WGS reactor  48  may be configured and operated to process the desulfurized synthesis gas  46  according to the following equation:
 
H 2 +CO 2   CO+H 2 O  (2)
 
     The operating temperature of the WGS reactor  48  may be within a range of from about 200° C. to about 400° C., such as from about 300° C. to about 375° C. or from about 325° C. to about 350° C. A treated synthesis gas  50  that may exit the WGS reactor  48  may have a molar ratio of H 2  to CO in the range of from about 1.0 to about 3.0, such as from about 1.5 to about 2.5, or about 2.0. In one or more embodiments, the WGS reactor  48  may be omitted, in which case desulfurized synthesis gas  46  is directed into the methanol synthesis system  108 . The treated synthesis gas  50  may exit the WGS reactor  48  and may then be directed into the methanol synthesis system  108 . 
     Optionally, steam  190  may be added to the synthesis gas production system  106  at a location upstream of the WGS reactor  48 . Adding the steam  190  functions to increase the molar ratio of H 2  to CO in the treated synthesis gas  50 . As shown in  FIG. 2 , a water stream  122  from a second storage vessel  120  may be delivered to a pump  124 , which may pressurize the water stream  122 . A pressurized water stream  126  may exit the pump  124  and may be at least partially directed, as a second pressurized water stream  184 , to a water heater  186 . The water heater  186  may increase the temperature of the second pressurized water stream  184  to generate the steam  190 . The steam  190  may have a temperature that is compatible with a desired molar ratio of H 2  to CO in the treated synthesis gas  50 . The steam  190  may exit the water heater  186  and may then be combined with the desulfurized synthesis gas  46 . 
     To decrease the concentration of at least one of H 2 O and CO 2  in the treated synthesis gas  50 , various conventional means, such as at least one of a PSA system (not shown) and a molecular sieve (not shown) may, optionally, be provided upstream of the methanol synthesis system  108 . 
     In additional embodiments, the synthesis gas production system  106  may be configured and operated as depicted in  FIG. 3 , in which the desulfurization unit  44  may be omitted from the synthesis gas production system  106 ′. The desulfurization unit  34 ′ may reduce the sulfur content within the logistical fuel/air mixture  32  to a sufficient extent that the desulfurization unit  44  may be omitted. After passing through the CPDX reactor  38 ′ and the heat exchanger  104 , the cooled synthesis gas  42 ′ may be directed into the WGS reactor  48 ′. 
     In further embodiments, the synthesis gas production system  106  may be configured and operated as depicted in  FIG. 4 . As shown in  FIG. 4 , the synthesis gas production system  106 ″ may include a thermal partial oxidation (TPDX) reactor  35  in place of the CPDX reactor  38 , and desulfurization unit  34  may not be included. The TPDX reactor  35  may be any suitable apparatus or device known in the art for the production of a synthesis gas from the catalyst-free partial oxidation of a hydrocarbon. The logistical fuel and air mixture  32  may be delivered into the TPDX reactor  35  without prior desulfurization at least because the TPDX reactor  35  does not include a catalyst, which can be poisoned by any sulfur content of the logistical fuel/air mixture  32 . However, in at least some embodiments, a desulfurization unit (not shown, refer to the desulfurization unit  34  depicted in  FIG. 2 ) may be provided upstream of TPDX reactor  35 . The TPDX reactor  35  may have an operating temperature within a range of from about 800° C. to about 1600° C., such as from about 1000° C. to about 1600° C. or from about 1200° C. to about 1600° C. Residence time within the TPDX reactor  35  may be within the range of from about 1×10 −4  s to about 1×10 4  s, more particularly from about 1×10 −3  s to about 1000 s, and even more particularly from about 0.01 s to about 500 s. In at least some embodiments, the synthesis gas  40 ″ may be passed through a particulate separation unit (not shown) such as a high temperature (e.g., ceramic) filter or cyclone separator to substantially reduce any soot levels in the synthesis gas  40 ″ prior to further processing. 
     In yet further embodiments, the synthesis gas production system  106  may be configured and operated as depicted in  FIG. 5 . As shown in  FIG. 5 , the synthesis gas production system  106 ′″ may include an autothermal reactor (ATR)  37  in place of the CPDX reactor  38 . Steam  190  may be added to the desulfurized logistical fuel/air mixture  36 ′″, which may then be directed into the ATR  37 . In at least some embodiments, the ATR  37  may receive the desulfurized logistical fuel/air mixture  36 ′″ and the steam  190  separately. The ATR  37  may be any suitable apparatus or device known in the art for the production of a synthesis gas via the catalytic partial oxidation and steam reformation of a hydrocarbon. The ATR  37  may be configured and operated to reform the desulfurized logistical fuel/air mixture  36 ′″ into a synthesis gas according to general equation (1) and the following general equations, where, for a given hydrocarbon, “n” corresponds to an integer within the range of from 1 to 50 and “m” corresponds to an integer within the range of from 1 to 100: 
     
       
         
           
             
               
                 
                   
                     
                       
                         C 
                         n 
                       
                       ⁢ 
                       
                         H 
                         m 
                       
                     
                     + 
                     
                       n 
                       ⁢ 
                       
                           
                       
                       ⁢ 
                       
                         H 
                         2 
                       
                       ⁢ 
                       O 
                     
                   
                   -&gt; 
                   
                     
                       n 
                       ⁢ 
                       
                           
                       
                       ⁢ 
                       CO 
                     
                     + 
                     
                       
                         ( 
                         
                           n 
                           + 
                           
                             m 
                             2 
                           
                         
                         ) 
                       
                       ⁢ 
                       
                         H 
                         2 
                       
                     
                   
                 
               
               
                 
                   ( 
                   3 
                   ) 
                 
               
             
             
               
                 
                   
                     
                       CH 
                       4 
                     
                     + 
                     
                       
                         H 
                         2 
                       
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                   ↔ 
                   
                     CO 
                     + 
                     
                       3 
                       ⁢ 
                       
                         H 
                         2 
                       
                     
                   
                 
               
               
                 
                   ( 
                   4 
                   ) 
                 
               
             
           
         
       
     
     In at least some embodiments, the ATR  37  may be an apparatus such as that disclosed in U.S. Patent Application Publication No. 2011/0038762, which describes an ATR including a housing, a first plate having a first plurality of fin structures, and a second plate having a second plurality of fin structures assembled such that the first plurality of fin structures is interleaved with the second plurality of fin structures. The fin structures may be coated with a suitable catalyst material, which may include Pt, Pd, and alloys thereof. The synthesis gas  40 ′″ exiting the ATR  37  may have a temperature of less than or equal to 400° C., such as less than or equal to 350° C., or less than or equal to 310° C. The disclosure of U.S. Patent Application Publication No. 2011/0038762 is incorporated by reference herein in its entirety. 
     Returning to  FIG. 2 , the methanol synthesis system  108  may include a heat exchanger  52 , a methanol synthesis reactor  58 , a condensing unit  62 , and a liquid collection unit  66 . The treated synthesis gas  50  may be received by the heat exchanger  52 . The heat exchanger  52  may be any suitable apparatus or device known in the art for cooling a gas flow, such as an air blast heat exchanger. The heat exchanger  52  may decrease the temperature of the treated synthesis gas  50  to a temperature suitable for the synthesis of crude methanol in the methanol synthesis reactor  58 . A cooled and treated synthesis gas  56  may exit the heat exchanger  52  and may then be directed into the methanol synthesis reactor  58 . 
     The methanol synthesis reactor  58  may be any suitable apparatus or device known in the art for producing methanol from the catalyst-assisted reaction of synthesis gas components according to the following equations:
 
2H 2 +CO CH 3 OH  (5)
 
3H 2 +CO 2   CH 3 OH+H 2 O  (6)
 
     The methanol synthesis may be typically be conducted using a catalyst including at least one oxide of Cu, Zn, Mg, Al, Cr, Ag, Mo, W, Ti, Zr, Hf, B, Mn, V, Ga, Pd, Os, or combinations thereof, such as at least one of at least one of CuO, ZnO, Al 2 O 3 , and Cr 2 O 3 . In at least some embodiments, the methanol synthesis reactor  58  may include at least one catalyst such as disclosed in U.S. Pat. No. 6,921,733, which discloses a liquid phase catalyst prepared from the reaction of a transition metal having coordinating ligands and an alkoxide dissolved in either methanol or methanol and a co-solvent. The transition metal is a metal from Group 6, Group 8, Group 9, Group 10, Group 11, Group 12, or mixtures thereof, such as Mo, W, Fe, Ru, Os, Co, Rh, Ir, Ni, Pd, Pt, Cu, Au, Zn, Cd, or mixtures thereof. The coordinating ligands may include N-donor ligands, P-donor ligands, O-donor ligands, C-donor ligands, halogens, or mixtures thereof, such as chloride, acetylacetonate, 2,2′-dipyridyl (Bipy), bis(cyclooctadiene), 1,10-phenanthroline, 1,2-bis(diphenylphosphinethane), or mixtures thereof. Co-solvents may include saturated hydrocarbons, amine based solvents, ethers, esters, alkyl polyethers, hydroxyalkylpolyethers, and alcohols. Use of such a catalyst may enable conversion rates of from about 80% to about 90% with non-ideal stoichiometry ratios. 
     The operating temperature of the methanol synthesis reactor  58  may be within a range of from about 20° C. to about 350° C., such as from about 100° C. to about 280° C. In at least some embodiments, the operating temperature of the methanol synthesis reactor  58  may be within the range of from about 100° C. to about 150° C. The operating pressure of the methanol synthesis reactor  58  may be within a range of from about 3 atm to about 250 atm, such as from about 7 atm to about 150 atm, or from about 7 atm to about 80 atm. In one or more embodiments, the operating pressure of the methanol synthesis reactor  58  may be within the range of from about 4 atm to about 11 atm. The gas hourly space velocity (GHSV) through the catalyst may be adjusted to achieve a desired conversion efficiency. The methanol synthesis reactor  58  may have a single pass conversion efficiency of greater than about 10%, such as greater than about 40%, or greater than about 75%. In at least some embodiments, the methanol synthesis reactor  58  may have a single pass conversion efficiency within the range of from about 90% to about 99%. 
     A crude methanol stream  60 , which may include at least one of liquid methanol and gaseous methanol, along with one or more reaction byproducts, unreacted components, and catalyst, may exit the methanol synthesis reactor  58  and may then be directed to the condensing unit  62 . The condensing unit  62  may include any device or apparatus known in the art (e.g., an electric precipitator) that may be configured and operated to cool the crude methanol gas  60  and liquefy the methanol therein. In at least some embodiments, the condensing unit  62  may be configured and operated to liquefy any gaseous methanol and any gaseous components with a boiling point higher than methanol (e.g., H 2 O, ethanol, if present) while components with lower boiling points (e.g., methyl formate, dimethyl ether, if present) may remain in a gaseous state. A cooled crude methanol stream  64  may exit the condensing unit  62  and may then be directed to a liquid collection unit  66 . The liquid collection unit  66  may collect any liquid components of the cooled crude methanol stream  64  and may vent any gaseous components as offgas  68 . The liquid components may exit the liquid collection unit  66  as a crude methanol liquid  70  and may then be directed into the methanol refining system  110 . In at least some embodiments, the crude methanol liquid  70  may be substantially pure methanol, such as greater than or equal to about 95% methanol. 
     In additional embodiments, the methanol synthesis system  108  may be configured and operated as depicted in  FIG. 6 . As shown in  FIG. 6 , the methanol synthesis system  108 ′ may include a gas compressor  146  and a valve, such as a three-way valve  150 , which may recycle the offgas  68 ′ back to an inlet of the methanol synthesis reactor  58 ′ for additional methanol synthesis processing. The offgas  68 ′ may be received by the gas compressor  146 , which may compress and pressurize the gas. A pressurized offgas  148  may exit the gas compressor  146  and may then be directed to the three-way valve  150  where the gas may be combined with the cooled and treated synthesis gas  56 ′. A combined synthesis gas  152  may exit the three-way valve  150  and may then be directed into the methanol synthesis reactor  58 ′. 
     In yet further embodiments, the methanol synthesis system  108  may be configured and operated in a manner as depicted in  FIG. 7 . As shown in  FIG. 7 , the methanol synthesis system  108 ″ may include a second methanol synthesis reactor  158 , a second condensing unit  162 , and a second liquid collection unit  166  to provide additional methanol synthesis processing of the offgas  68 ″. The offgas  68 ″ may be received by the second methanol synthesis reactor  158 . In at least some embodiments, a heat exchanger (not shown) may be provided upstream of the second methanol synthesis reactor  158  to bring the offgas  68 ″ to an appropriate temperature. The second methanol synthesis reactor  158  may be any suitable apparatus or device known in the art for producing methanol from the catalyst-assisted reaction of synthesis gas according to equations (5) and (6). The second methanol synthesis reactor  158  may be configured and operated in a manner that is either similar to or different than that of the methanol synthesis reactor  58 ″. The second methanol synthesis reactor  158  may react at least a portion of the unreacted synthesis gas components of the offgas  68 ″ to produce a second crude methanol stream  160 . The second crude methanol stream  160  may exit the second methanol synthesis reactor  158  and may then be directed to the second condenser unit  162 , which may cool the second crude methanol stream  160  and liquefy any gaseous methanol therein. A second cooled crude methanol stream  164  may then be directed to the second liquid collection unit  166 . The second liquid collection unit  166  may collect any liquid components of the second cooled crude methanol stream  164  and may vent any gaseous components as second offgas  168 . The liquid components may exit the second liquid collection unit  166  and may be combined with the crude methanol liquid  70 ″. In at least some embodiments, one or more methanol synthesis reactors, condensing units, and liquid separators may be provided downstream of the second collection unit  166  to permit methanol synthesis of any unreacted synthesis gas components remaining in the second offgas  168 . 
     Returning to  FIG. 2 , the methanol refining system  110  may include a pressure throttle valve  72 , a distillation column  76 , a condenser  80 , a reflux unit  84 , and a partial reboiler  94 . The crude methanol stream  70  from the methanol synthesis system  108  may be received by the pressure throttle valve  72 , which may control the flow of the crude methanol stream  70  to accord with the operational parameters of the distillation column  76 . A regulated crude methanol stream  74  may exit the pressure throttle valve  72  and may then be directed into the distillation column  76 . 
     The distillation column  76  may be configured and operated to produce a gaseous tops distillate  78  and a liquid bottoms distillate  92 . The gaseous tops distillate  78 , which includes methanol, may be directed to a condenser  80  that cools the gaseous top distillate  78  to substantially liquefy any methanol therein. A liquefied methanol stream  82  may exit the condenser  80  and may then be directed into the reflux unit  84 . A predetermined portion of the liquefied methanol within reflux drum  84  may be directed back to the distillation column  76  as reflux recycle  88  to assist with the cooling and condensation of upflowing gases in the distillation column  76 . Any liquefied methanol within the reflux drum  84  that is not directed back to the distillation column  76  may be directed into the methanol storage and delivery system  112  as a purified methanol liquid  90 . The purified methanol liquid  90  may be substantially pure methanol, such as greater than or equal to about 95% methanol. The liquid bottoms distillate  92  may include components having higher boiling points than methanol (e.g., H 2 O, higher alcohols, carboxylic acids) and may be directed to a partial reboiler  94 , which may operate at a temperature that enables some of the lighter (i.e., lower boiling point) components to boil. These components may be directed back into the distillation column  76  as gaseous reboiler recycle  96 . The heavier (i.e., higher boiling point) components of the liquid bottoms distillate  92  may be removed as a refined bottoms liquid  98  and may be utilized or disposed of as desired. 
     In additional embodiments, the methanol refining system  110  may be configured and operated as depicted in  FIG. 8 . As shown in  FIG. 8 , the methanol refining system  110 ′ may include a topping distillation column  170 . The topping distillation column  170  may produce a gaseous distillate  172  and a liquid distillate  174 . The gaseous distillate  172  may include at least some components of the regulated crude methanol stream  74 ′ having a lower boiling point than that of methanol (e.g., ketones, aldehydes, ethers, unreacted synthesis gas). The gaseous distillate  172  may be utilized or disposed of as desired. The liquid distillate  174  may include methanol and at least some components of the regulated crude methanol stream  74 ′ having a higher boiling point than methanol (e.g., higher alcohols, H 2 O). The liquid distillate  174  may be directed into the distillation column  76 ′ for processing similar to that previously presented in relation to  FIG. 2 . 
     In at least some embodiments, such as where the crude methanol liquid  70  exiting the methanol synthesis system  108  is substantially pure methanol (i.e., greater than or equal to about 95% methanol), the methanol refining system  110  may be optional (i.e., the methanol refining system  110  may be omitted), in which case the crude methanol liquid  70  may be directed into the methanol storage and delivery system  112 . 
     Returning to  FIG. 2 , the methanol storage and delivery system  112  may include a first storage vessel  114 , a first flow control valve  116 , a second storage vessel  120 , a pump  124 , a purification unit  128 , a third storage vessel  132 , a second flow control valve  134 , and a dispensing valve  140 . The first storage vessel  114  may receive and hold the purified methanol liquid  90  from the methanol refining system  110 . 
     A water supply held within the second storage vessel  120  may be directed to the pump  124  as a water stream  122 . The pump  124  may raise the pressure of the water and a pressurized water stream  126  may be directed out of the pump  124  and into the purification unit  128 . The purification unit  128  may be any device, apparatus, combination of devices, or combination of apparatuses known in the art for reducing or removing undesired materials (e.g., chemical and biological contaminants) from a water source. By means of non-limiting example, the purification unit  128  may include at least one of a rapid sand filtering system, a granular activated carbon filtering system, a reverse osmosis system, a distillation system, and an ion exchange system. A first purified water stream  130  may exit the purification unit  128  and may then be directed into the third vessel  132 , which may hold the purified water. In at least some embodiments, one or more of the second storage vessel  120 , the pump  124 , the purification unit  128 , the third storage vessel  132 , and the second control valve  134  may be optional. 
     A methanol liquid  118  may be directed from the first storage vessel  114  by opening the first flow control valve  116 . A second purified water stream  136  may be directed from the purified water storage vessel  132  by opening the second flow control valve  134 . The second purified water stream  136  and the methanol liquid  118  may be mixed to form a liquid product  138  including methanol and water that may be dispensed as desired via the dispensing valve  140 . However, in at least some embodiments, the liquid product  138  may be substantially free of water. The concentration of methanol in the liquid product  138  may be modified as desired by adjusting the flow of the second purified water stream  136  relative to the flow of the methanol liquid  118  via the first flow control valve  116  and the second flow control valve  134 . In at least some embodiments, the liquid product  138  may have a methanol concentration within a range of from about 0.1 M to about 7.0 M, such as from about 0.5 M to about 5.0 M, or from about 1.0 M to about 5.0 M. In additional embodiments, the liquid product  138  may be substantially pure methanol. The liquid product  138  may, for example, be dispensed into one or more empty DMFC cartridges  142  to produce one or more full DMFC cartridges  144  (i.e., cartridges that are ready for use in a DMFC). 
     In at least some embodiments, the methanol storage and delivery system  112  may be optional (i.e., the methanol storage and delivery system  112  is omitted), in which case the purified methanol liquid  90  exiting the methanol refining system  110  may be utilized as desired. In one or more embodiments, both the methanol refining system  110  and the methanol storage and delivery system  112  may be omitted, in which case the crude methanol liquid exiting the methanol synthesis system  108  may be utilized as desired. 
     Optionally, a second synthesis gas  192 , produced via a biomass gasification system (not shown), may be conventionally delivered into the fuel processing system  100  at a location upstream of the methanol synthesis reactor  58 . By means of non-limiting example, as shown in  FIG. 2 , the second synthesis gas  192  may be combined with the cooled and treated synthesis gas  56  in the methanol synthesis system  108 . The biomass gasification system may be any suitable system known in the art for converting a biomass feedstock into a synthesis gas. Suitable systems may be commercially available, such as from Community Power Corporation, Littleton, Colo. and W2E USA Inc., Chicago, Ill. The biomass gasification system may use at least one of logistical fuel and biomass/waste (e.g., wood, paper, food waste, municipal solid waste) as the biomass feedstock. Delivering the second synthesis gas  192  into the fuel processing system  100  may advantageously offset the amount of logistical fuel required to produce the liquid product  138 . 
       FIGS. 9 and 10  are simplified perspective views of a fuel processing system  100 ′ that is substantially similar to the fuel processing system  100  of  FIG. 2 , absent some devices or apparatuses, such as the methanol storage and delivery system  112 .  FIGS. 9 and 10  generally depict how the fuel processing system  100 ′ may be configured for portability.  FIG. 9  shows how at least some of the devices or apparatuses of the fuel processing system  100 ′ may be physically positioned therein.  FIG. 10  shows at least some of the general physical dimensions of the fuel processing system  100 ′, including a width  176 , a length  178 , a first height  180 , and a second height  182 . The width  176  may be within the range of from about 3.5 feet to about 7.5 feet, such as from about 4.5 feet to about 6.5 feet, or from about 5.0 feet to about 6.0 feet. The length  178  may be within the range of from about 6.0 feet to about 10.0 feet, such as from about 7.0 feet to about 9.0 feet, or from 7.5 feet to about 8.5 feet. The first height  180  may be within the range of from about 5.5 feet to about 9.5 feet, such as from about 6.5 feet to about 8.5 feet, or from about 7.0 feet to about 8.0 feet. The second height  182  may be within the range of from about 12.5 feet to about 16.5 feet, such as from about 13.5 feet to about 15.5 feet, or from about 14.0 feet to about 15.0 feet. In one or more embodiments, at least a portion of the fuel processing system  100 ,  100 ′ may be provided upon a suitable platform (not shown). As used herein, the term “suitable platform” means and includes any material base that is mechanically compatible with the fuel processing system  100 ,  100 ′ and that enables at least a portion of the fuel processing system  100 ,  100 ′ to be readily transported, including but not limited to, a structural steel I-beam matrix. 
     The invention of the present disclosure advantageously permits the efficient, onsite production of methanol. Unlike conventional methanol production systems, the fuel processing system  100 ,  100 ′ does not rely on traditional fuel sources (e.g., natural gas, coal), and may be smaller in size and scale of methanol production (e.g., about 0.1 metric tons per day, as opposed to a typical commercial scale production of about 1000 metric tons per day, or even a typical pilot scale production of about 175 metric tons per day). As a result, the fuel processing system  100 ,  100 ′ may be more portable than conventional methanol production systems and, thus, is more adaptable to the logistical limitations (e.g., location and/or policy based restrictions on the transport or delivery of methanol) and technological interests of various specialized operations. By means of non-limiting example, under the “single fuel forward” initiative, the U.S. Military uses JP-8 in its operations and, therefore, currently lacks an infrastructure conducive to the use of methanol-related technologies, such as DMFCs. However, DMFCs are of interest to the U.S. Military as a means of eliminating or reducing the problems associated with conventional batteries. Conventional batteries are unable to support 72 hour missions without recharge/resupply, have relatively long recharge times, suffer from an overabundance of variety, require special electrochemical storage and disposal considerations, and subject the U.S. Military to the additional costs and vulnerabilities of an additional logistics trail. Conversely, DMFCs offer increased energy density, support 72 hour missions without resupply, have relatively short refill times, support a standard power system for multiple devices, do not rely on hazardous electrochemicals (i.e., methanol is a biodegradable chemical with a 17 day half-life), may reduce power system weight, and, when enabled by the present disclosure, do not require an additional logistics trail. The present disclosure will advantageously enable the U.S. Military to benefit from DMFC technology while adhering to a JP-8 logistic framework. 
     While the present invention may be susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and have been described in detail herein. However, it should be understood that the invention is not intended to be limited to the particular forms disclosed. Rather, the invention includes all modifications, equivalents, and alternatives falling within the scope of the invention as defined by the following appended claims and their legal equivalents. For example, elements and features disclosed in relation to one embodiment may be combined with elements and features disclosed in relation to other embodiments of the present invention.