Patent Publication Number: US-2010122627-A1

Title: Membrane-based systems and methods for hydrogen separation

Description:
TECHNICAL FIELD 
     The present disclosure generally relates to hydrogen separation, as may be implemented by a hydrogen separator. 
     BACKGROUND 
     Synthesis gas (“syngas”) is a gas mixture that contains varying amounts of carbon monoxide and hydrogen. Syngas may be generated from solid and liquid carbonaceous fuels, such as coal, coke, and liquid hydrocarbon feeds. For example, syngas may be generated by heating carbon-containing (i.e., carbonaceous) fuels in a gasification reactor with reactive gases, such as air or oxygen, often in the presence of steam and or water. 
     Syngas may include a pure gas component and a mixed gas component. To recover the pure gas component, a separation process first separates the pure gas component from the mixed gas component. In conventional membrane systems, the pure gas component is recovered at a low pressure while the mixed gas component is recovered at a high pressure. 
     For example, syngas may include hydrogen (i.e., a pure gas component) and carbon dioxide (i.e., a mixed gas component). Conventional membrane systems may be used to separate the hydrogen from the carbon dioxide, by allowing small molecules (i.e., hydrogen) to pass while preventing larger molecules (i.e., carbon dioxide) from passing. Using conventional membrane systems, the separated hydrogen typically exhibits a disadvantageously low pressure. In this regard, hydrogen, like some other pure gas components, cannot be easily used, stored or transported at low pressures. Accordingly, any hydrogen separated by conventional membrane systems must be compressed prior to being used, stored or transported. 
     SUMMARY 
     A method and a system may be provided to receive hydrogen at a first pressure at a first side of a membrane, receive hydrogen at a second pressure from a second side of the membrane, combine the hydrogen received from the second side of the membrane with a purge stream to produce a permeate stream at the second pressure, and separate hydrogen from the permeate stream at a third pressure. The purge stream is associated with a phase transition temperature range. 
     The claims are not limited to the disclosed embodiments, however, as those in the art can readily adapt the description herein to create other embodiments and applications. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The construction and usage of embodiments will become readily apparent from consideration of the following specification as illustrated in the accompanying drawings, in which like reference numerals designate like parts. 
         FIG. 1  is a flow diagram of a process according to some embodiments. 
         FIG. 2  is a block diagram of a system according to some embodiments. 
         FIG. 3  is a flow diagram of a process according to some embodiments. 
         FIG. 4  is a block diagram of a system according to some embodiments. 
         FIG. 5  is a block diagram of a system according to some embodiments. 
         FIG. 6  is a block diagram of a system according to some embodiments. 
         FIG. 7  is a block diagram of a system according to some embodiments. 
         FIG. 8  is a block diagram of a system according to some embodiments. 
         FIG. 9  is a block diagram of a system according to some embodiments. 
         FIG. 10  is a block diagram of a system according to some embodiments. 
         FIG. 11  is a block diagram of a system according to some embodiments. 
     
    
    
     DETAILED DESCRIPTION 
     The following description is provided to enable any person in the art to make and use the described embodiments and sets forth the best mode contemplated by for carrying out the described embodiments. Various modifications, however, will remain readily apparent to those in the art. 
     Now referring to  FIG. 1 , an embodiment of a process  100  is illustrated. Process  100  may be performed by any suitable system that is or becomes known. At  110 , hydrogen is received at a first pressure at a first side of a membrane. The hydrogen (i.e., symbol H on the periodic table) may be contained within a hydrocarbon-based material or any material that includes hydrogen. In some embodiments, the first side of the membrane may allow the hydrogen at the first pressure (e.g., in a gaseous state) to permeate through the membrane. 
       FIG. 2  is a block diagram of system  200  for performing process  100  according to some embodiments. As mentioned above, embodiments are not limited to system  200  or, for that matter, to process  100 . System  200  includes membrane  201 , having first side  202  and second side  203 . Membrane  201  may comprise a high-temperature hydrogen transport membrane as is understood in the art. At  110 , first side  202  may receive hydrogen  204  at a first pressure. The first pressure is denoted P 1  in  FIG. 2 . 
     Referring back to  FIG. 1 , hydrogen is received at a second pressure from a second side of the membrane at  120 . According to the  FIG. 2  example, hydrogen  205  is received at a second pressure from second side  203  at  120 . As shown, the second pressure is denoted P 2 . In some embodiments, a conduit (i.e., dashed line) into which hydrogen  205  is received exhibits a higher pressure than partial pressure P 1  of hydrogen  204 . Therefore, the second pressure P 2  may be greater than the first pressure P 1 . The conduit may comprise any suitable tube, channel, or enclosure. 
     Next, at  130 , the hydrogen received from the second side of the membrane is combined with a purge stream to produce a permeate stream at the second pressure.  FIG. 2  illustrates hydrogen  205  combining with purge stream  206  to produce permeate stream  207 . In keeping with the above-described notation,  FIG. 2  also indicates that a pressure of permeate stream  207  is equal to P 2 . It should be noted that the  FIG. 2  diagram is schematic and is not intended to specify or require any particular physical configuration. For example, purge stream  206  may impact side  203  of membrane  201  in some embodiments. 
     In some embodiments, a temperature of the permeate stream may be at least one hundred degrees Celsius. The purge stream may comprise one or more materials that are heated and pressurized to a gaseous state. The materials of the purge stream may depend on a type of membrane used, a membrane operating temperature and pressure, and/or a chemical composition of the permeate stream. For example, purge stream materials that may be used during hydrogen recovery in conjunction with palladium-alloy membranes include hydrocarbons between about C 6 H 14  and C 10 H 22 . In some embodiments in which a hydrocarbon and a palladium membrane are used, the hydrocarbon may comprise a saturated hydrocarbon because the palladium membrane may act as a hydrogenation catalyst if exposed to the hydrocarbon at elevated temperature and for long exposure times. In some embodiments, other materials with critical temperatures between approximately 100° C. and 400° C. and critical pressures below approximately 40 bar can also be used as purge stream materials provided that they do not react with hydrogen, have a low vapor pressure at a separator (see below) temperature of approximately 100-200° F., and are stable in a hydrogen environment. Purge material selection may be based on a tradeoff between lower volatilities of heavier materials and lower critical temperatures and decomposition rates of lighter materials. In some embodiments, lighter hydrocarbons may require less energy input while yielding lower hydrogen purity, and may exhibit lower decomposition rates. 
     In some embodiments, the purge stream may comprise a supercritical fluid or a condensable multi-component mixture. For example, the purge stream may comprise octane, a mixture of octane and steam, and/or one or more of the following fluids: 1,2,3-trichoropropane, 2,4-dimethylpentane, 2-methyl-3-ethylpentanetrimethyl borate, 3,3-dimethylpentane, 3-methyl-3-ethylpentane, 1-chlorobutane, 3-ethylpentane, 2,2,3,3-tetramethylbutane, 2-chlorobutane, 2,2,3-trimethylbutane, 1-octanoltert-butyl chloride, 1-heptanol, 2-octanol, 1-pentanol, 1,1-dimethylcyclohexane, 2-methyl-3-heptanol, 2-methyl-1-butanol, 1,2-dimethylcyclohexane, 4-methyl-3-heptanol, 3-methyl-1-butanol, 1,3-dimethylcyclohexane, 5-methyl-3-heptanol, 2-methyl-2-butanol, 1,4-dimethylcyclohexane, 2-ethyl-1-hexanol, 2,2-dimethy, 1-1-propanolethylcyclohexanen-propylcyclohexaneperfluorocyclohexane, 1,1,2trimethylcyclopentane, isopropylcyclohexane, perfluoro-n-hexane, 1,1,3-trimethylcyclopentane, n-nonaneperfluoro-2-methylpentane, 1,2,4-trimethylcyclopentane, 2-methyloctane, perfluoro-3-methylpentane, 1-methylethylcyclopentane, 2,2-dimethylheptane, perfluoro-2,3-dimethylbutanenpropylcyclopentane, 2,2,3-trimethylhexane, methylcyclopentane, isopropylcyclopentane, 2,2,4-trimethylhexane, n-hexanecyclooctane, 2,2,5-trimethylhexane, 2-methyl pentane, n-octane, 3,3-diethylpentane, 3-methyl pentane, 2-methylheptane, 2,2,3,3-tetramethylpentane, 2,2-dimethyl butane, 3-methylheptane, 2,2,3,4-tetramethylpentane, 2,3-dimethyl butane4-methylheptane, 2,2,4,4-tetramethylpentane, perfluoromethylcyclohexane, 2,2-dimethylhexane2,3,3,4-tetramethylpentane, perfluoro-n-heptane, 2,3-dimethylhexanel-nonanolcycloheptane, 2,4-dimethylhexane, Butylcyclohexane, 1,1-dimethylcyclopentane, 2,5-dimethylhexane, isobutylcyclohexane, 1,2-dimethylcyclopentane, 3,3-dimethylhexanesec-butylcyclohexane, methylcyclohexane, 3,4-dimethylhexane, tert-butylcyclohexane, n-heptane, 3-ethylhexanen-decane, 2-methylhexane, 2,2,3-trimethylpentane, 3,3,5-trimethylheptane, 3-methylhexane, 2,24-trimethylpentane, 2,2,3,3-tetramethylhexane, 2,2-dimethylpentane, 2,3,3-trimethylpentane, 2,2,5,5-tetramethylhexane, 2,3-dimethylpentane, or 2,3,4-trimethylpentane. 
     At  140  of process  100 , hydrogen is separated from the permeate stream at a third pressure. Separating the hydrogen from the permeate stream may comprise condensing substantially all of the purge stream from the permeate stream by cooling the permeate stream to a liquid state. For example, separator  208  of system  200  may receive permeate stream  207  and separate hydrogen  209  (at pressure P 3 ) therefrom. According to some embodiments, separator  208  may cool permeate stream  207  by using a chiller, by using one or more heat exchangers to exchange the heat of permeate stream  207  with cooler streams, or by combinations thereof. 
     The purge stream, such as purge stream  206  of  FIG. 2 , may comprise one or more components such that when the purge stream  206  is heated, or cooled, purge stream  206  may transition from a liquid state to a gaseous state (or vice versa) over a temperature range (i.e., a phase transition temperature range) instead of at a discrete phase transition temperature. Therefore, in order to separate the hydrogen from the permeate stream at  140 , the permeate stream may be cooled below a critical temperature of at least one of the one or more components of the purge stream. 
     In some embodiments, the second pressure may be substantially equal to the third pressure. However, in some embodiments, the third pressure may be slightly less than the second pressure. In particular, while the purge stream may exhibit a temperature above the critical temperature/pressure of at least one of its constituent purge stream materials, the separator may operate below the critical temperature/pressure of the purge stream. 
     If the separator operates below the critical temperature as described above, the purge stream may be condensed and removed from the permeate stream at  140 . The resulting hydrogen may therefore be recovered at the higher pressure associated with the purge stream even though the hydrogen&#39;s partial pressure on the first side of the membrane is comparatively low. Recovery of hydrogen at the higher pressure may reduce a cost of hydrogen compression compared to conventional low pressure recovery systems. 
     A multi-component purge stream may enhance heat exchange efficiency because the purge stream does not exhibit a discrete phase transition temperature, but rather a phase transition temperature range (i.e., the latent heat is spread out over a range of temperatures). This temperature range is based on the individual components contained in the purge stream. 
     Moreover, by maintaining the purge stream above the critical temperature and pressure, much less (ideally, no) discrete latent heat remains to be recovered by heat exchangers. Therefore, the energy required for the phase change is spread out over a temperature range, and heat may be continuously transferred from a higher-temperature permeate stream to the lower-temperature purge stream. 
     Over time, some of the purge stream may leave a system, either through leaks or through remaining as a vapor and being carried off with a hydrogen product. If a multi-component purge stream is used, different components may exhibit different volatilities, and lighter components may leave the system at a higher rate than heavier components. Therefore, a composition of a multi-component purge stream may change over time and careful analysis may be required to determine which components must be added to maintain a desired purge stream composition. 
     In a case of a supercritical or single-component purge stream, the composition of the purge stream does not change. Accordingly, only a pressure of the purge stream may need to be monitored to detect decomposition of the purge material. When decomposition occurs, molecules of the purge stream may become lighter than the original purge material, so there is a probability that the decomposition products will leave with the hydrogen product. Decomposition may also occur when mixtures are used because mixtures are likely to include at least one hydrocarbon larger than the single-component supercritical stream, and because decomposition rates may increase as a hydrocarbon size increases. In some embodiments, an adsorbent or cooler may be added to a separator outlet to remove any trace hydrocarbons in the separated hydrogen that result from decomposition or volatility. 
     When an expensive membrane is used, such as one made from palladium, it may be desirable to minimize a membrane area to reduce costs. In one embodiment, a need for membrane area may be reduced by increasing a flow rate of the purge stream. The flow rate of the purge stream may depend on a cost of providing and circulating additional purge material and heat, and a capital cost of using the additional membrane area. However, increasing the flow rate of the purge stream may also increase an amount of fuel consumed and thus a purge flow rate may be based on membrane size costs, fuel costs, and desired hydrogen recovery. 
     Now referring to  FIG. 3 , an embodiment of a process  300  is shown. Process  300  may be performed by a system such as, but not limited to, system  400  of  FIG. 4 , the system of  FIG. 5  or the system of  FIG. 6 . 
     An input stream that includes hydrogen is initially received at a first side of a membrane at  310 . The input stream exhibits a first pressure, as illustrated, for example, by input stream (P1)    401  of  FIG. 4 . Steps  320  through  350  of process  300  may proceed as described above with respect to steps  120  through  140  of process  100 .  FIG. 4  depicts hydrogen  205 , purge stream  206 , permeate stream  207  and separator  208 , each of which may operate and be composed as described above. 
     However, at  340 , the input stream is heated with the permeate stream and/or with a retentate. Turning to the first alternative, separator  208  may separate an output permeate stream  403  of  FIG. 4  at  350 . Permeate stream  403  may be virtually identical to purge stream  206 , albeit at a different temperature and/or pressure. 
       FIG. 4  shows heat exchanger  404  receiving permeate stream  207 . As shown, heat exchanger  404  may use the heat of permeate stream  207  to heat input stream  405 . Retentate  406  represents a remainder of input stream  401  after removal of hydrogen  205 . Heat exchanger  404  may also or alternatively use the heat of retentate  406  to heat input stream  405 . After being cooled, the retentate  406  results in cooled retentate  407 . 
       FIG. 5  is a diagram of system  500 , which may implement an embodiment of process  300 .  FIG. 5  shows input feed  1  at a first temperature and heated via heat exchanger  51 , resulting in first heated input feed  2  exhibiting a second temperature greater than the first temperature. First heated input feed  2  may then be heated a second and a third time by a series of heat exchangers such as heat exchanger  52  and heat exchanger  53 , which produce, in turn, second heated input feed  3  and third heated input feed  4 . In some embodiments, third heated input feed  4  exhibits an at least partially-gaseous state. 
     Membrane housing  61 , including membrane  62 , may receive third heated input feed  4  comprising a material that includes hydrogen. The hydrogen permeates through membrane  62  while the remainder of third heated input feed  4 , now depleted of hydrogen (i.e., retentate  5 ), does not pass through membrane  62 . The hydrogen received from the second side of membrane  62  may be combined with purge stream  35  to produce permeate stream  36  at a second pressure. 
     Retentate  5  is fed into heat exchanger  52 , thereby heating first heated input feed  2  to an at least partially-gaseous state (i.e., second heated input feed  3 ) and cooling retentate  5  to produce cooled retentate  6 . As illustrated, cooled retentate  6  may be split such that first portion  7  of cooled retentate  6  is returned to a process from where it originated (not shown in  FIG. 5 ) and second portion  8  of cooled retenate  6  may be burned along with oxygen-containing gas  11  in a reactor or burner  57  to produce hot gas  23 . Burner  57  may comprise an oxidation reactor, or a catalytic partial oxidation (“CPOX”) reactor for syngas production. However, in some embodiments, burner  57  may comprise a steam reformer, an autothermal reformer, an oxygen-based partial oxidation reactor, or an oxygen transport membrane reactor. 
     Hot gas  23  may be fed into heat exchanger  53  to exchange heat with second heated input feed  3 , thereby producing third heated input feed  4  and first cooled gas  24 . In some embodiments, heat from a permeate stream, such as permeate stream  36  of  FIG. 5 , may be exchanged with a purge stream, such as purge stream  33 , to heat the purge stream and to cool the permeate stream so that the permeate stream may be separated into a purge stream and hydrogen. For example, permeate stream  36  may be fed into heat exchanger  55 , where heat from permeate stream  36  is exchanged with cooler purge stream  33  (which is below its critical temperature), thereby producing hotter purge stream  34  and cooler permeate  37 . Heat exchanger  51  may use permeate  37  to heat input feed  1 . Heated purge stream  34  may then be heated above its critical temperature via first cooled gas  24  at heat exchanger  54 . 
     Permeate stream  38 , having been cooled by heat exchanger  51 , is further cooled by heat exchanger  56  below its dew point to create permeate stream  39 . Heat exchanger  56  may be cooled by cooling water that is input via cooling water input  21  and is output from heat exchanger  56  via cooling water output  22 . Permeate stream  39 , now cooled to a gas-liquid stream, may be received at separator  59  to separate the permeate stream  39  into hydrogen product  42  and liquid purge stream  40 . In some embodiments, a portion  41  of liquid purge stream  40  may be removed. 
     Liquid purge stream  40  may be combined with fresh purge material  31  to provide purge stream  32  to pump  58 . Pump  58  may overcome a pressure drop in order to maintain the flow of purge stream  32 . In some embodiments, a temperature of now-pressurized purge stream  33  may be below a critical temperature of the purge material. 
     In some embodiments, one or more of the heat exchangers may be located in proximity to membrane  62  to heat a stream received by heat exchanger  53  beyond its typical temperature. This additional heat may be transferred across membrane  62  to purge stream  35  to heat the purge stream  35  to a higher temperature, such as a membrane operating temperature. Heating purge stream  35  to a higher temperature may eliminate a need for heat exchanger  54 , which may reduce a cost of the system without sacrificing performance or efficiency. 
     Depending on a particular process and a size of the process, a heat exchanger may not be capable of transferring enough heat to justify a capital cost of the heat exchanger. In this situation, extra heat may be provided by burning additional retentate or fuel and accepting a small loss in efficiency to reduce a capital cost. 
     In some embodiments of  FIG. 5 , some of purge stream  35  may exit system  500  with the hydrogen product stream. This may occur in a case that purge stream  35  comprises a light hydrocarbon purge stream. 
     To prevent the loss of purge steam  35 , second separator  60  and compressor or pump  63  are included in system  600  of  FIG. 6 . The elements of system  600  may be implemented as described above with respect to similarly-numbered elements of system  500 . In some embodiments, second separator  60  may comprise an adsorption unit, a cooler or a chiller such as a glycol chiller. 
     Second separator  60  may receive hydrogen product stream  42  from first separator  59  and further chill hydrogen product stream  42  to output higher-purity hydrogen product  43  and sweep gas  44 . Sweep gas  44  may be compressed by compressor or pump  63  and then added to liquid purge stream  40 . In some embodiments, if the second separator  60  comprises an adsorption unit, then the compressor or pump  63  comprises a compressor. 
     Now referring to  FIG. 7 , system  700  may comprise an embodiment of one or more processes described herein. The elements of system  700  may be implemented as described above with respect to similarly-numbered elements of system  500 . System  700  may further comprise third separator  64  and second pump  67 . As stated previously, hydrogen may be separated from permeate stream  37  by cooling permeate stream  37  to a temperature that results in condensation of a desired portion of the liquid purge material. The liquid purge material may be recycled at the cooler temperature, while a vapor component may be further cooled at heat exchanger  56  to remove the remaining purge material. This process may reduce the cooling energy required by removing a significant portion of purge material at a higher temperature prior to the final separation step. 
     As illustrated in  FIG. 7 , separator  64  receives permeate stream  38 . Separator  64  separates permeate stream  38  into vapor component  65  and liquid component  66 / 68 . Vapor component  65  may be further cooled by heat exchanger  56 . Liquid component  68  may be pumped via second pump  67  to a pressure equal to the purge steam  34  and is combined with purge stream  34 . In some embodiments, liquid component  68  may be combined with purge stream  33  depending on a temperature of the liquid component  68 . 
       FIG. 8  illustrates system  800  according to some embodiments of process  100 . As illustrated in  FIG. 8 , first gas  801 , such as, but not limited to, natural gas, may be compressed by first compressor  881 . A first portion  803  of the compressed gas may be heated via heat exchanger  882  to produce heated first gas  804  and may then be fed into reactor  886 . A second portion  802  of the compressed gas may be combined with output  817  of membrane reactor  887  (i.e., a combination of a membrane and a reactor) to form combination output  818 . 
     For example, in some embodiments, compressor  881  may compress 86,700 lb/hr (about 2 million scfh) of natural gas to 470 psig. About 75%, or 66,100 lb/hr, of the compressed natural gas may go directly to a gas turbine (not shown). The remaining 20,600 lb/hr of the compressed natural gas may be heated by heat exchanger  882  to produce hot natural gas at about 1000° F., which may be fed into reactor  886 . 
     A second gas  805 , such as, but not limited to, air, may be compressed by second compressor  883 . The compressed air may be heated at heat exchanger  884  and then combined with heated first gas  804 . Heat exchanger  884  may also receive steam  808  (a portion of steam  807 ) to heat second gas  805 , the steam having been created by water  806  from a water inlet (not shown) that was brought to a boil at heat exchanger  885 . The cooled steam becomes a condensate stream  809  which may be recycled back to the water inlet. Any remaining steam  810 / 811  may be injected into a syngas or may be exported to an external system  812 . 
     For example, and in some embodiments, 1.14 million scfh of air may be compressed to 470 psig using a compressor and heated to 590° F. in a heat exchanger. 35,800 lb/hr of water is boiled in heat exchanger to produce steam. 5600 lb/hr of steam may be used to preheat the air in a heat exchanger, resulting in condensate stream. In this example, 16,900 lb/hr of steam may be exported to a steam turbine or to any other application. 
     First gas  803  and second gas  805  may be heated in separate heat exchangers (i.e., heat exchanger  882  and heat exchanger  884 , respectively) such that mixture  813  of the heated gasses enters reactor  886  at a temperature exceeding 700° F. In some embodiments, the temperature may be substantially 775° F. A higher preheat temperature may reduce an amount of air necessary for reactor  886  to function and thus may reduce an amount of combustion required to heat reactor  886 . Reactor  886  may operate at a temperature of substantially 1700° F. and may convert first gas  803  and second gas  805  into a third gas. For example, natural gas and air may be converted into syngas. 
     Reactor  886  may output a material that comprises hydrogen  814 . For example, the product of reactor  886  may comprise 2.11 million scfh of syngas that contains 31% H 2 , 16% CO, and 6% CH 4 , with a balance composed mainly of CO 2 , N 2 , and H 2 O. The material comprising hydrogen  814  may be cooled in heat exchanger  882  and mixed with steam  810  to cool syngas  815  prior to entering heat exchanger  885 . The cooled syngas  816  may be mixed with steam  811  after exiting heat exchanger  885 . The mixture of steam and cooled syngas may be input into an integrated membrane/shift reactor  887 . For example, syngas  816  may exit the heat exchanger at approximately 440° F. and may be mixed with about 10,500 lb/hr of steam before entering integrated membrane/shift reactor  887 . In some embodiments, a shift reactor may convert CO and steam into CO 2  and hydrogen. The integrated membrane/shift reactor may operate in a range of about 600-650° F. 
     The integrated membrane/shift reactor may receive purge stream  825  that receives permeated (i.e., recovered) hydrogen to form permeate stream  819 . In some embodiments, the membrane of integrated membrane/shift reactor  887  may remove 761,000 scfh of hydrogen using a supercritical octane purge of 2 million scfh, representing 85% hydrogen recovery. 
     Permeate stream  819  may be cooled in heat exchanger  888  by heating cooled liquid  824 , such as, but not limited to, octane. In some embodiments, the purge stream may gain additional heat in the integrated membrane shift reactor  887  due to an exothermic water gas shift reaction. Permeate stream  820  may be further cooled at heat exchanger  889  to produce permeate stream  821 . Heat exchanger  889 , in turn, may be cooled by cooling water  826 , thereby creating steam  827 . If permeate stream  819  comprises octane, then the octane may be condensed by being cooled in the heat exchanger  889  against cooling water  826 . The cooled permeate stream  820  becomes permeate stream  821 , which may be separated in separator  880  to remove hydrogen product  822  from liquid product  823 . Liquid product  823  may be recycled to pump  899 , and recycled liquid  824  may cool heat exchanger  888 . 
       FIG. 9  illustrates a system  900  according to some embodiments of process  100 . The elements of system  900  may be similar to similarly-numbered elements of system  800 , and may further comprise shift reactor  897 , membrane  896  and third compressor  898 . 
     As illustrated in  FIG. 8 , the shift reactor and hydrogen membrane may be integrated in a same unit. When separated as shown in system  900 , membrane  896  may be downstream of shift reactor  897 . In some embodiments, an integrated membrane and shift reactor will produce more hydrogen than a standalone shift reactor and standalone membrane. However, if these elements are separated, it may be possible to run the separate elements in different conditions. For example, a single membrane module could be changed without shutting down the entire process. In this case, power generation may continue by feeding a fuel, such as natural gas  802 , around the process. 
     Compressor  898 , as illustrated, may receive hydrogen product output  819 . The compressor  898  may provide an alternative to the purge process as described with respect to  FIG. 8 . In some embodiments, separating the two processes allows membrane  896  to operate at a cooler temperature. In this regard, a non-palladium membrane, such as, but not limited to, a molecular sieving membrane, may be used at such lower temperatures. Molecular sieve membranes may separate hydrogen based on molecular size and may be more robust than palladium membranes, particularly in harsh environments. For example, sulfur may contaminate palladium membranes, while molecular sieve membranes may be more resistant to sulfur contamination. 
     In some embodiments, a high pressure retentate stream may be used as a fuel source for a gas turbine. Pressure energy stored in the pressurized retentate stream may be used to produce power by blending a fuel, such as natural gas, with the pressurized retentate stream. In some embodiments, a hydrogen content of fuel for a turbine is 10% or less. Since some hydrogen membrane processes may produce a retentate stream including more than 10% hydrogen, blending the retentate with natural gas may not only increase a heating value of the fuel but may also reduce the hydrogen content. In some embodiments, a methanation reactor may be used to convert hydrogen in the retentate and carbon oxides to methane.  FIG. 10  illustrates system  1000  according to some of such embodiments. System  1000  may be similar to system  800  and system  900 , and may further comprise methanator  895 . 
     Methanator  895  may convert output  817  of shift reactor  887  to methane, which may reduce a requirement for natural gas to dilute the hydrogen concentration of fuel going to a gas turbine (not shown). Methanator  895  may also enable the use of more natural gas in reactor  886 , which may increase hydrogen production  819 . In some embodiments, a portion of the output of shift reactor  887  may be methanated while a second portion of the output may bypass methanator  895 . Bypassing a portion of the output may reduce a size and cost of methanator  895 . 
       FIG. 11  illustrates system  1100  according to some embodiments of process  100 . System  1100  comprises system  800  with the addition of booster compressor  891 . Booster compressor  891  may compress gas  804 , such as, but not limited to, natural gas. Compressed gas  804  may be fed to reactor  886  so that a resulting stream  817  may exhibit a same pressure as supplemental natural gas that may be fed to an output of the system. Booster compressor  891  may add equivalent pressure to overcome a pressure drop associated with gas  805  traversing through system  1100 . 
     In some embodiments, gas  801  comprises light hydrocarbons, liquids, or mixtures of light hydrocarbons and liquids. Gas  805  may comprise oxygen or air. In some embodiments, oxygen may be obtained through a ceramic oxygen transport membrane (“OTM”) operating at high temperature. The heat for the OTM may be produced by combustion for the turbine or oxidation reactions occurring in reactor  886 . In some embodiments, the OTM may be integrated into the reactor  886 , which may significantly increase a heating value of reactor product  814 , so less natural gas would be required for blending. Reactor product  814  may contain a higher fraction of hydrogen, so it would be possible to recover more hydrogen using the membrane. 
     In some embodiments, water may be directly fed into the syngas  815 / 816 . This process may quench syngas  815 / 816  and vaporize the water before entering shift reactor  887 . Steam may also be added either upstream (steam  810 ) or downstream (steam  811 ) of heat exchanger  885 . Adding steam upstream may reduce an inlet temperature to heat exchanger  885 , which may simplify the material requirements and reduce capital cost. By adding steam downstream, more steam may be produced in heat exchanger  885  due to a higher inlet temperature. Steam may also be fed into a reactor to produce additional reforming in the reactor and increase a hydrogen/CO ratio, which may increase a hydrogen concentration and partial pressure at a membrane inlet (where flux is the highest). Adding steam to the reactor may also reduce a required conversion where the reactor is a shift reactor. Placement of steam  810 / 811  may be based on a determination of an actual pressure and temperature of export steam, an amount of exported steam desired, the capital cost of the heat exchangers, and relative values or power, natural gas, and hydrogen. 
     Those in the art will appreciate that various adaptations and modifications of the above-described embodiments can be configured without departing from the scope and spirit of the claims. Therefore, it is to be understood that the claims may be practiced other than as specifically described herein.