Patent ID: 12240758

DETAILED DESCRIPTION

The present subject matter will now be described more fully hereinafter with reference to exemplary embodiments thereof. These exemplary embodiments are described so that this disclosure will be thorough and complete, and will fully convey the scope of the subject matter to those skilled in the art. Indeed, the subject matter can be embodied in many different forms and should not be construed as limited to the embodiments set forth herein; rather, these embodiments are provided so that this disclosure will satisfy applicable legal requirements. As used in the specification, and in the appended claims, the singular forms “a”, “an”, “the”, include plural referents unless the context clearly dictates otherwise.

The present disclosure provides systems and methods for production of various materials that are typically gaseous at standard temperature and pressure (e.g., about 20° C. and about 1 bar). The systems and methods are particularly suitable for production of hydrogen and/or carbon dioxide. In one or more embodiments, the systems and methods can relate to the production of hydrogen alone or in combination with carbon dioxide. Likewise, the systems and methods can relate to the production of carbon dioxide that is separated from a process stream, and such separation can also relate to production of hydrogen. In some embodiments, the present systems and methods relate to processes useful in separating carbon dioxide from a process stream that may or may not include hydrogen. In specific embodiments, the systems and methods relate to the production of hydrogen and production of carbon dioxide and can include producing a stream comprising both of hydrogen and carbon dioxide and separating the carbon dioxide from the hydrogen to provide a substantially pure stream of hydrogen and a substantially pure stream of carbon dioxide.

In one or more embodiments, the present disclosure relates to systems and methods suitable for separation of carbon dioxide from a process stream. The process stream may be any industrial process stream comprising carbon dioxide. In some embodiments, the process stream may be a stream from a hydrogen production process. In other embodiments, the process stream may be any further industrial process stream comprising carbon dioxide wherein it can be beneficial to separate at least a portion of the carbon dioxide therefrom. For example, referring toFIG.2, the process stream may be any of streams308,331, and309. As such, the carbon dioxide separation process may be combined with a hydrogen production process as described herein, or the carbon dioxide separation process may be utilized with a different process stream.

A simplified block flow diagram of a carbon dioxide separation process according to the present disclosure is shown inFIG.1. A seen therein, a process stream101containing CO2is provided. As noted above, the process stream101may be received from any source, such as a hydrogen production process. The process stream101can be compressed to a pressure of at least 30 bar, at least 35 bar, or at least 40 bar (e.g., to a maximum of 100 bar) within a compressor200. In example embodiments, the compressor200may be an intercooled multi-stage compressor. The compression step preferably will raise the partial pressure of the CO2within the waste stream to at least about 15 bar (e.g., up to a maximum, in some embodiments, of about 55 bar). The CO2partial pressure can be raised to be in the range of about 15 bar to about 55 bar, about 15 bar to about 45 bar, or about 15 bar to about 40 bar. The compressed process stream102is then directed to a drier205to reduce the moisture content of the compressed process stream and form a first impure CO2stream103. The extent of moisture removal can be adjusted as desired such that the dew point of the process stream will be reduced to a temperature as low as about −60° C. In various embodiments, the dew point can be reduced to a temperature of about −10° C. or less, about −20° C. or less, or about −40° C. or less, such as to a low temperature of about −60° C. For example, the dew point can be reduced to a temperature in the range of about −60° C. to about −10° C., about −60° C. to about-20° C., or about −60° C. to about −30° C. The drier205, in some example embodiments, can be a drying bed packed with appropriate desiccant material, such as molecular sieves or zeolites.

The first impure CO2stream103is cooled to significantly reduce the temperature thereof and ultimately form a two phase stream that is then subject to rapid cooling utilizing auto-refrigeration. In some embodiments, auto-refrigeration can generally indicate that the refrigeration is carried out in the express absence of any external refrigerant. In other words, the streams are not cooled against a typical refrigerant stream, such as Freon, liquid nitrogen, liquid propane, ammonia, or the like. Rather, the stream is only cooled against further streams produced in the CO2separation process and using expansion techniques. In particular, auto-refrigeration can indicate that at least one stream comprising a liquid component is expanded to provide for rapid cooling of the stream.

Returning toFIG.1, the first impure CO2stream103is directed to a first heat exchanger210to partially cool down and form the second impure CO2stream104. Thereafter, the second impure CO2stream104is directed to a reboiler heat exchanger215to further cool down and form the third impure CO2stream105. The third impure CO2stream105is further cooled down in a second heat exchanger211to form a fourth impure CO2stream106. The foregoing cooling steps can be effective to provide the impure CO2stream(s) in the form of a two phase stream including a gaseous component and a liquid component. In some embodiments, the two phase stream is at least partially formed during passage through the reboiler heat exchanger215and/or is formed during passage through the second heat exchanger211.

To further facilitate cooling of the impure CO2stream, the fourth impure CO2stream106is expanded within a first valve220to an appropriate pressure that would drop the temperature of the expanded impure CO2stream107to near the CO2triple point temperature (−56.4° C.). For example, expansion of the stream106can be effective to reduce the temperature of the stream to within about 15° C., within about 10° C., or within about 5° C. of the freezing point of the CO2in the stream. A cold, two phase CO2stream107thus exits the first valve220.

The cold two phase CO2stream107becomes a feed stream to the mass transfer column225. The mass transfer column225has a stripping section226below the feed point of stream107producing a high purity liquid CO2stream108as a bottom product and a rectifying section227above the feed point of stream107producing a purified top vapor phase product109. The mass transfer column225is packed with appropriate packing material to enhance the mass transfer within the column and collection of the liquid CO2at high purity. The design of the stripping column will be done such that it can effectively handle the two-phase feed stream which could be done in variety of ways such as but not limited to flashing the feed in a flash vessel prior to the entrance to the stripping column, the use of a gallery tray or chimney tray within the column or any combination of thereof. The bottom liquid CO2product108typically contains about 80 mol % and preferably at least 85 mol % of the total CO2within the impure CO2stream107while the rest of the CO2content and other volatile impurities within the feed waste stream would end up in the overhead vapor phase stream109. In various embodiments, the bottom liquid CO2product108can contain at least 50 mol %, at least 60 mol %, at least 70 mol %, or at least 80 mol % (e.g., about 50 mol % to about 99 mol %, about 60 mol % to about 98 mol %, about 70 mol % to about 95 mol %, or about 75 mol % to about 90 mol %) of the total CO2within the cold two phase CO2stream107. The bottom liquid CO2product108passes through the reboiler heat exchanger for further cooling and exits as purified a CO2product stream that splits into a first portion110and a second portion150, which is recycled back into the bottom section of the mass transfer column225.

The cool overhead vapor phase stream109can be used as a source of refrigeration to cool down the impure CO2streams in heat exchangers210and211. These two heat exchangers are preferably plate and fin type made from aluminum and although they are shown as discrete blocks inFIG.1, they may be designed and fabricated as a single unit with two (or more) sub-unit or sections. The system is suitably insulated. The liquid CO2product108preferably is at least 80% molar pure CO2, at least 85% molar pure CO2, at least 90% molar pure CO2, at least 95% molar pure CO2, at least 98% molar pure CO2, at least 99% molar pure CO2, at least 99.5% molar pure CO2, or at least 99% molar pure CO2.

To generate additional refrigeration duty, the purified CO2product stream portion110exiting the reboiler heat exchanger215can be divided into 3 separate streams111,114, and117. Purified CO2product streams111and114can be reduced in pressure by expansion in valves230and235, respectively, to achieve appropriate temperature profiles in heat exchangers210and211. Specifically, purified CO2product stream111exits valve230as stream112and passes through heat exchanger211to provide purified CO2stream113. Similarly, purified CO2product stream114exits valve235as stream115and passes through heat exchanger210to provide purified CO2stream116. Although each of streams112and115are illustrated as passing through only one of heat exchangers210and211, it is understood that one or both of streams112and115may be passed through both of heat exchangers210and211prior to passing to the compression step described next. The purified CO2streams (113,116and117) will be partially pressurized and mixed within a compressor240to form a high density CO2stream118before being raised in pressure to the required end-use pressure in a liquid pump245to leave as final CO2product stream119. The final warm overhead vapor phase stream109can be optionally compressed based on the downstream application requirement.

An important feature of this arrangement is the capability of recycling the vapor phase stream109from the separation column225after warming in heat exchanger211to form stream120and heating in heat exchanger210to form stream121at near ambient temperature. The stream121can be compressed in compressor250to form stream122. The stream122can be at least partially combined with original feed stream101, and this recycle allows for a favorable increase in the overall CO2recovery from the process feed stream101. Furthermore, the stream122can be partially or completely recycled back as the feedstock to a chemical production process (such as a hydrogen production process further described below) and achieve up to 100% CO2capture from the chemical production process.

In example embodiments, the presently disclosed systems and methods for carbon dioxide separation particularly can be useful with hydrogen generation processes or revamping of existing hydrogen generation processes that utilize only one H2separation train such as PSA beds or membrane separators to achieve 100% CO2capture. Current methods of thermochemical hydrogen generation typically rely on recovery of hydrogen using PSA beds. Specifically, natural gas and steam (and optionally oxygen) can be input to an H2+CO syngas generation area along with a PSA waste gas. The product therefrom is subjected to syngas cooling and shifting of the CO to H2. Thereafter, PSA separation is carried out to provide an H2product and the PSA waste gas. The PSAs recover 75% to 90% of the total hydrogen in the feed gas. The PSA waste gas containing typically 10% to 15% of the hydrogen production together with all the CO2produced from H2generation is generally burned with CO2vented to the atmosphere.

The systems and methods of the present disclosure can be utilized to capture substantially 100% of the CO2from hydrogen generating processes by recovering CO2from a pressure swing absorber (PSA) waste stream. This can encompass, for example, utilizing a CO2separation process as described above in combination with a hydrogen production process as will be described below. Separation of CO2from PSA off-gas increases the hydrogen concentration in CO2separation train waste gas to at least about 60 mol % which would make it suitable and economic for additional H2recovery within a second PSA. In addition, based on the concentration of CO within CO2separation train waste gas, it can be optionally shifted, prior to the second H2recovery step, using a small low temperature shift reactor to further increase its hydrogen content. The off-gas from the second PSA unit will be recycled back to the syngas generation reactors. It can also be optionally mixed with the off-gas from the first PSA to increase CO2recovery in the CO2cryogenic separation system.

Previous efforts have been undertaken to provide for production of hydrogen through combination with additional systems, and one or more elements from such previous endeavors may be integrated into the presently disclosed systems and methods. For example, U.S. Pat. No. 6,534,551, the disclosure of which is incorporated herein by reference, describes the combination of: 1) a hydrocarbon fuel gas reaction with steam and or oxygen; and 2) a power system utilizing a compressed oxidant gas in which a fuel gas is burned with combustor products producing power by work expansion and in which the expanded combustion product gas is used to superheat the steam used in hydrogen synthesis reactions and in which the oxygen production unit is driven by at least a portion of the power produced by the expansion of the combustion product gas.

In one or more embodiments, the present systems and methods can beneficially provide for hydrogen production with capture of substantially all of the carbon produced, particularly substantially all of the CO2produced. In this manner, the present disclosure may refer to a hydrogen plant, and it is understood that such hydrogen plant refers to the combination of elements necessary to form the hydrogen production system utilized herein. A hydrogen plant as described herein thus can be configured for producing substantially pure hydrogen and likewise producing substantially pure carbon dioxide that is separated from a crude hydrogen stream.

A hydrogen production plant for use according to the present disclosure can incorporate any variety of elements known to be suitable in prior hydrogen production plants. In particular, the hydrogen production plant can comprise a reactor unit configured for forming a stream comprising CO+H2gas. The reactor unit can encompass a single element or a plurality of elements. For example, a reactor unit in a hydrogen production plant can comprise a two stage reactor unit including a first stage reactor which converts a hydrocarbon feed to a CO+H2gas. Such so-called H2+CO synthesis gas generation reactor can be any one or more of a steam methane reforming (SMR) reactor, a partial oxidation (POX) reactor, an autothermal reforming (ATR) reactor, a POX+GHR (gas heated reactor), or an ATR+GHR. In some embodiments, partial oxidation of a natural gas feed with pure oxygen can be carried out at an outlet temperature of about 1300° C. to about 1500° C. at typical pressures of about 30 bar to about 150 bar. An auto-thermal reformer can add steam and excess hydrocarbon, generally natural gas, after the partial oxidation burner so that the high temperature gases can then pass through a bed of catalyst where subsequent steam-hydrocarbon reforming reactions take place yielding further H2+CO and cooling the gas mixture to an outlet temperature of about 1000° C. to about 1100° C. at pressures of about 30 bar to about 150 bar. The second stage reactor can comprise a steam/hydrocarbon catalytic reformer in which the total H2+CO gas product from both reactors (e.g., at a temperature of about 1000° C. or greater) is used to provide the endothermic heat of the reforming reactions in a convectively heated shell side flow with catalyst in the tubes. Optionally the two reactors can operate in a series or parallel mode. A favorable configuration uses a vertical gas heated reformer (GHR) with catalyst filled open ended tubes hanging from a single tube sheet at the top of the vessel, with the product H2+CO leaving the reformer tubes and mixing with the product gas from a POX reactor or an ATR in the base of the GHR, and the total product H2+CO stream passing through the shell side and cooling typically from about 1050° C. to 550° C. to 800° C.

An advantage of the two reactor configuration is that the yield of H2+CO from hydrocarbon feed is maximized, and all CO2formed in the reactions is contained within the high-pressure system. The product CO+H2gas is further cooled in a steam generating waste heat boiler (WHB), and a further advantage is that this steam quantity is only sufficient to provide the required steam flow to the two H2+CO reactors with only a small excess flow. The system has no large by-product steam production.

To generate hydrogen, the H2+CO product leaving the WHB at a typical temperature of about 240° C. to about 290° C. and containing typically about 20 mol % to about 40 mol % steam is passed through either one or two (or more) catalytic shift converters where CO reacts with steam to produce CO2and more H2. The reactions for the whole H2production process sequence are shown below (using CH4as the hydrocarbon).

CH4+ ½O2→CO + 2H2Partial oxidationCH4+ 2O2→CO2+ 2H2OCombustionCH4+ H2O→CO + 3H2Steam reformingCH4+ CO2→2CO + 2H2Dry reformingCO + H2O→CO2+ H2CO shift

The total CO+H2product passing through the CO shift reactors is cooled, and a significant amount of heat is released generally at a temperature level of up to 400° C. or lower as the gas cools and steam condenses. This heat is released not at a single temperature level but over a temperature range down to near ambient temperature. Part of this heat release can be used to preheat boiler feed water, to produce the steam required for syngas production in the reactors but there is a large excess quantity that is at a low temperature level and only available over a temperature range.

The efficiency of the H2+CO generation in the two reactors can be significantly increased by preheating the hydrocarbon and steam feeds to typically about 400° C. to about 600° C. and preferably to about 500° C. to about 550° C. This preferably is done using an external heat source since no excess heat at these temperature levels is available within the H2+CO generation reactors plus WHB.

In one or more embodiments, systems and methods of producing the H2+CO syngas which can be used to produce the pure hydrogen product stream according to the present disclosure may exhibit desired characteristics that can be beneficial for integration of the hydrogen production with other systems, such as power generation systems. The excess heat available over a temperature range from near ambient up to about 400° C. is ideal for boiler feed water heating in a steam based power cycle or for heating a high pressure CO2stream. In each case the result is a reduction in parasitic power demand and an increase in power cycle efficiency. The required external heat need to preheat the syngas reactor feed streams up to about 550° C. can easily be provided using high temperature boiler flue gas leaving the super-heater in a pulverized coal fired power boiler or using the hot turbine exhaust from an industrial gas turbine in a combined cycle power generation system or using a further high temperature exhaust stream from a power production system. The heat integration leads to an overall increase in the efficiency of a combined system.

The cooled H2rich gas stream is now passed through an ambient cooler where condensed water is removed. The gas stream is then passed through a conventional multi-bed pressure swing adsorber (PSA) which separates typically about 85% to about 90% of the hydrogen as a pure stream having typically about 10 ppm to about 50 ppm total impurities. All the impurities in the crude H2feed stream are separated as a waste fuel gas stream, which waste stream can comprise any combination of components, such as H2, CO, CO2, CH4, N2, Ar, and a small quantity of vapor phase H2O. The pressure is typically about 1.1 bar to about 1.6 bar. This waste gas typically has about 20% of the total hydrocarbon reactor hydrocarbon feed lower heating value (LHV) so its efficient use is critical to the overall economics of H2production. The waste gas contains all the carbon from the total hydrocarbon feed as CO2+CO and the recovery of this carbon as pure CO2at pipeline high pressure is vital to meet climate change emission objectives. In order to recover the carbon present in the hydrocarbon feed to the hydrogen plant as CO2product the ideal objective is to convert residual CO by catalytic shift reaction with added steam to produce CO2+H2then separate the CO2as a pure product stream. Three options are available which address this problem of CO2removal and the maximization of CO2recovery.

In some embodiments, CO2removal and the maximization of CO2recovery can comprise adding a chemical or physical solvent scrubbing unit to remove all the CO2from the ambient temperature PSA feed stream. For example, this can be achieved by treating the ambient temperature crude H2stream in an amine CO2scrubbing system upstream of the PSA. The waste gas from the PSA can then be used as a minor portion of the fuel stream consumed in the power system. The PSA waste gas stream contains a significant quantity of H2+CO. Alternatively, the waste gas stream can be compressed to a pressure of 1 to 2 bar higher than the H2delivery pressure from the PSA and then passing this gas stream with added steam through a catalytic CO shift conversion unit which would convert over 90% of the CO by reaction with steam to CO2+H2. The cooled product gas stream will now have a hydrogen concentration of 60% to 70% (molar). This gas stream can then be passed through a second multi-bed pressure swing adsorption unit to recover an additional H2product stream at the same pressure and purity as the hydrogen from the first PSA. The waste gas from the second PSA unit which contains all the inert argon and nitrogen derived from the hydrocarbon and oxygen reactor feed streams can beneficially be sent to the power plant for combustion. The disadvantage of the amine CO2removal system is its high capital cost and the large quantity of low pressure steam required for amine regeneration to produce the pure CO2product stream. This combination of amine scrubbing plus first stage PSA plus CO shift plus second stage PSA results in an overall ratio of H2product divided by (H2+CO) present in the syngas reactor product stream of greater than 95% and preferably greater than 97%.

In other embodiments, CO2removal and the maximization of CO2recovery can comprise eliminating the MEA unit or the physical solvent CO2removal unit upstream of the first PSA leaving all the CO2in the PSA waste gas stream. The stream then can be treated utilizing cryogenic cooling for separation of the CO2as otherwise described herein.

In further embodiments, CO2removal and the maximization of CO2recovery can comprise recycling one or more streams back to the feed streams for the POX or ATR or GHR or SMR reactors. By closing the recycle loop completely, inert components can be vented from the system. The vented purge gas stream can be taken at ambient temperature upstream of the first PSA and sent, for example, to a power plant for combustion. The level of argon present in the oxygen stream and nitrogen present in both the hydrocarbon feed and the oxygen streams are preferably kept at a low total concentration of from about 3 mol % to about 12 mol % in the feed gas to the first PSA. This arrangement does not require a second CO shift and PSA system. All the hydrogen will be produced from the main PSA while all the CO2will be produced from the low temperature CO2removal system. As further described herein, CO2separation can be applied independent of the hydrogen production processes described herein. Suitable CO2separations systems and methods are thus described herein that may be applied to any process stream comprising CO2.

Example embodiments of a hydrogen production plant (and an associated hydrogen production process) are evident in relation toFIG.2. The hydrogen plant can be fueled with a hydrocarbon fuel source, preferably a gaseous hydrocarbon, and more preferably with substantially pure methane. The example embodiment ofFIG.2is described in relation to the use of methane as the hydrocarbon. InFIG.2, the methane in stream300is compressed in compressor401to a pressure of about 20 bar to about 120 bar, about 40 bar to about 110 bar, or about 60 bar to about 100 bar. The compressed methane stream is passed through a heat exchanger412to heat the methane stream to a temperature of about 300° C. to about 700° C., about 350° C. to about 650° C., or about 400° C. to about 600° C. The methane exiting the heat exchanger412is split into two streams302and303. The methane is thus directed to a reactor unit that, as exemplified inFIG.2, is formed of a POX reactor402and a GHR403. In other embodiments, it is understood that the reactor unit may be formed of a single device or multiple devices as otherwise already discussed herein. The methane in stream302combined in the POX reactor with an oxygen stream301that is pre-heated in heater418prior to passage into the POX reactor. Preferably, the oxygen stream301can be about 99.5% pure O2and can be taken, for example, from a cryogenic air separation plant (not illustrated). The oxygen entering the POX reactor302may be at a pressure in the range of about 20 bar to about 120 bar, about 40 bar to about 110 bar, or about 60 bar to about 100 bar.

The methane is partially oxidized in the POX reactor302with the oxygen to produce a product H2+CO stream330at a temperature of about 700° C. to about 1800° C., about 900° C. to about 1700° C., or about 1100° C. to about 1600° C. The product H2+CO stream330optionally be quenched and cooled by the addition of a quenching stream, such as to a temperature that is about 50° C. or more, about 75° C. or more, or about 100° C. or more below the temperature of the product H2+CO stream330directly exiting the POX reactor402. The optionally quenched product H2+CO stream330enters the base of the GHR reactor403, undergoes endothermic reforming reactions, and leaves the GHR as stream304. The total product CO+H2stream can exit the GHR304at a temperature of about 300° C. to about 900° C., about 400° C. to about 800° C., or about 500° C. to about 700° C. The total product CO+H2stream304passes through the waste heat boiler404and exits in stream305at a temperature in a range of about 150° C. to about 450° C., about 200° C. to about 425° C., or about 250° C. to about 400° C. The waste heat boiler can be a steam generating boiler and thus can be effective to add steam to the total product CO+H2stream.

The product stream comprising H2+CO is then reacted in at least one reactor to form a stream comprising H2+CO2. As illustrated inFIG.2, the total product CO+H2stream305passes through a first catalyst filled CO shift reactor405and a second catalyst filled CO shift reactor406in series with respective outlet streams306and308. The outlet stream308passes through heat recovery heat exchanger420, and the outlet stream308passes through heat recovery heat exchanger414and, in each of the heat exchangers, heat is used to heat boiler feed-water preheating streams to provide boiler feed-water for waste heat boiler404.

The stream308comprises H2+CO2, but it is understood that any stream described herein as comprising H2+CO2only defines the minimal composition of the stream, and further materials may be present in said stream, such as carbon monoxide and one or more carbon-containing materials. After stream308passes through the heat exchanger414, the stream308is cooled in water cooler416to near ambient temperature and exits as cooled, crude H2+CO2stream331. The crude H2+CO2stream331preferably can contain substantially all of the CO2derived from combustion of carbon in the hydrocarbon feed together with water vapor and minor amounts of CO, CH4, N2and Ar. Condensed water is separated from cooled, crude H2+CO2stream331in separator407. Water stream332from the separator407and cooled boiler feed-water stream334enter a water treatment unit411which produces purified water55and an excess water stream61. The purified water stream335(which is recycled for use as the boiler feed-water) is pumped to about 87 bar pressure in pump415, and boiler feed water stream316enters the heat exchanger414before passing through heat exchanger420to the waste heat boiler404. The boiler feed-water exiting pump13can be at a pressure in the range of about 50 bar to about 120 bar, about 60 bar to about 110 bar, or about 70 bar to about 100 bar.

The saturated steam stream317leaving the waste heat boiler404first passes through heat exchanger412to exit as stream318, which is compressed in compressor413. Stream329exiting the compressor413branches, and steam stream319passes through the heat exchanger412before combining with methane stream303for entry into the GHR403. Steam in stream333passes back through heat exchanger414to exit as stream334for passage into the water tank/water treatment unit411.

The steam stream319fed to the GHR reactor403provides a steam to carbon ratio (carbon combined with hydrogen in the GHR reactor feed) of 6:1 in this case. This high ratio allows 80 bar H2+CO production pressure with a low quantity of unconverted methane in the total product H2+CO stream304. In some embodiments, the steam to carbon ratio can be about 2:1 to about 10:1, about 3:1 to about 9:1, or about 4:1 to about 8:1. Preferably, the steam to carbon ratio is at least 3:1, at least 4:1, or at least 5:1.

The purified H2+CO2product in stream309exits the separator401and is next processed in a pressure swing adsorber408to provide a product stream formed of substantially pure hydrogen in stream310and also provide waste gas comprising CO2in stream311. For example, the substantially pure H2product stream310can be at a pressure of about 50 bar to about 120 bar, about 60 bar to about 110 bar, or about 65 bar to about 100 bar and can have an impurity level of about 10 ppm to about 200 ppm impurity, about 20 ppm to about 175 ppm impurity, or about 25 ppm to about 150 ppm impurity. In some embodiments, the substantially pure H2product stream310can comprise about 60% to about 98%, about 70% to about 95%, or about 75% to about 92% of the hydrogen from stream309.

The waste gas in stream311preferably contains all the CO2plus CO, H2, CH4, Argon, N2and traces of water vapor previously in stream309. The waste gas stream311is then processed in a low temperature separation unit409(e.g., a cryogenic separation unit) as otherwise described herein to form a liquid CO2product stream. As discussed above, this is preferably carried out such that at least 50 mol % of the CO2in the waste gas stream311is separated into the liquid CO2product stream. Separated CO2is removed in CO2stream312. The remaining vapor phase materials exit the low temperature separation unit409in vapor phase stream313.

The vapor phase stream313from the low temperature separation unit409can be recycled for a variety of uses. InFIG.2, the vapor phase stream313branches, and a first portion of the vapor phase passes in vapor phase portion one stream314through the heat exchanger412to combine with the hydrocarbon feed stream303. In this manner, the remaining impurities are recycled back through the system, particularly being fed back into the GHR reactor403.

In one or more embodiments, the hydrogen production system can include a combined heat source that is separate from the H2+CO synthesis gas generation reactor but that is configured to provide heat that can be provided to one or more streams of the hydrogen production system to increase efficiency thereof. Power production systems can be particularly beneficial for providing a combined heat source. In particular, one or more exhaust streams formed in a power production system can be a combined heat source in that heat can be taken therefrom for transfer to one or more streams in the hydrogen production system.

A particularly beneficial integration of power production and hydrogen production is the gas turbine combined cycle power system. These units are used worldwide usually with natural gas as the fuel. The industrial gas turbine exhaust which is generally at a temperature in the range 550° C. to 650° C. is passed through a large finned tube economizer heat exchanger where it is used to generate high pressure intermediate pressure and low pressure steam for additional power generation using steam turbines. The turbine exhaust at high temperature is suited for use as a combined heat source for addition of heat to the hydrogen production system. Said combined heat source can be used, for example, for preheating the feed streams to the H2plant syngas reactors. Such heating can be in the range of about 400° C. to about 1000° C., about 425° C. to about 800° C., about 450° C. to about 600° C., or about 500° C. to about 550° C. Additionally, the excess heat available from the H2plant is ideal for boiler feed-water preheating over a temperature range up to 400° C., which releases extra steam for power production in the steam turbines. The main benefit lies in the use of the hydrogen as a fuel in the gas turbine.

In systems and methods as described herein, the use of substantially pure oxygen in the hydrogen plant syngas reactors can have the side benefit of providing a large quantity of substantially pure nitrogen as a by-product from the cryogenic air separation plant. The nitrogen can be provided at relatively high pressure directly from the air separation unit as stream93. At least a portion of this nitrogen can be blended with the hydrogen that can be produced as described herein. The end result is an H2+N2fuel gas that is suitable for use in a conventional gas turbine combined cycle power generation system. The blended inert nitrogen is generally required to reduce the adiabatic flame temperature in the gas turbine combustor and has the added benefit of increasing the mass flow of gas in the power turbine. It can also be beneficial to preheat the H2+N2fuel gas and add steam generated from the heat present in the excess boiler feed water stream59at a temperature level below 400° C.

The H2+N2fuel gas can be utilized in any gas turbine combined cycle power generation system. Known systems can be modified as necessary to remove, decommission, or otherwise forego the use of elements that would otherwise be required for removal of CO2. Known gas turbine combined cycle power generation systems that can be utilized according to the present disclosure are described in U.S. Pat. Nos. 8,726,628, 8,671,688, 8,375,723, 7,950,239, 7,908,842, 7,611,676, 7,574,855, 7,089,727, 6,966,171, and 6,474,069, the disclosures of which are incorporated herein by reference.

The combination of H2production with 100% potential CO2capture with a gas turbine combined cycle power generation system using at least a portion of the produced H2as fuel provided by the present disclosure results in substantially no atmospheric discharge of CO2from the combined system. This provides a distinct advantage over the conventional operation of a gas turbine combined cycle system. In particular, the present combination of systems can eliminate the natural gas fuel typically required in a gas turbine and substitute a fuel with no CO2production when combusted. As such, in some embodiments, the present disclosure provides a combination of: 1) an oxygen based hydrogen production unit with near 100% CO2capture; 2) a conventional gas turbine combined cycle power generation unit using H2+N2fuel gas that provides power generation with zero CO2emission. The combined system as described herein can provide a surprisingly high efficiency, low cost power generation, and approximately 100% CO2capture.

The combination of systems can be implemented in a variety of manners. In some embodiments, an existing combined cycle power station can be converted to eliminate all CO2emissions and simultaneously increase the power generation capacity. Such conversion can include addition of the further system components described herein for production of power using a CO2circulating fluid and production of H2+N2fuel gas.

As illustrated inFIG.2, a gas turbine410is provided, and hydrocarbon fuel stream321is input thereto for combustion to produce power in generator417. The gas turbine exhaust stream322is passed through the heat exchanger412to provide heating to hydrocarbon fuel stream321, stream401, stream317, and stream319. The temperature of the exhaust stream322from the gas turbine410can be optionally raised by means of duct-burning using, for example, fresh pre-heated natural gas taken from stream321and input to stream322, or using a waste fuel stream, such as a vapor phase portion two stream336taken from stream313exiting the low temperature CO2separation unit and input to stream322. This is beneficial to accommodate for required heating duty in the process heater412, and the duct-burning thus can take place in the piping for stream322. In some embodiments, streams336and314may be separate streams exiting the low temperature CO2separation unit instead of being branches of a single exit stream, as illustrated.

In some embodiments, a hydrogen production facility as described herein can be particularly suited to provide excess low temperature level heat that can be used in a variety of further systems for a variety of further reasons.

The waste gas from the PSA of the hydrogen production system can be compressed to typically about 200 bar to about 400 bar and mixed with the feed hydrocarbon fuel used in a combustor of a power production system. The waste gas contains not only flammable components CH4+CO+H2but also all the CO2produced in the H2production system. Alternatively the waste gas from the PSA can be compressed to the inlet pressure of the first PSA, the CO2can be removed in one of a number of processes described above, and the CO2depleted gas stream can be sent to a second PSA to separate more H2to add to the total H2product stream. Optionally the waste gas can be preheated in an economizer heat exchanger, steam can be added and more H2can be produced in an additional catalytic CO shift reactor, the gas can then be cooled in the economizer heat exchanger before being processed to separate more H2in the second PSA. The hydrogen production system is thus suited for production of a significant quantity of low grade heat from the cooling H2+CO stream at a temperature level of typically below 400° C. and preferably in the range 240° C. to about 290° C.

Many modifications and other embodiments of the presently disclosed subject matter will come to mind to one skilled in the art to which this subject matter pertains having the benefit of the teachings presented in the foregoing descriptions and the associated drawings. Therefore, it is to be understood that the present disclosure is not to be limited to the specific embodiments described herein and that modifications and other embodiments are intended to be included within the scope of the appended claims. Although specific terms are employed herein, they are used in a generic and descriptive sense only and not for purposes of limitation.