System and method for capturing CO2 using an H2 separator that employs heat desulfurization technology.

Abstract

Method for capturing and isolating carbon dioxide and hydrogen gases from a high-temperature synthesis gas stream containing CO and sulfur compounds, comprising the following steps: Reducing the temperature of the high-temperature synthesis gas stream; substantially all sulfur compounds present in the synthesis gas stream are removed by means of a high-temperature desulfurization unit (13); Converting an initial quantity of CO present in the synthesis gas stream into carbon dioxide by means of a first high-temperature water-gas shift reaction (15); and Converting a second quantum of CO present in the synthesis gas stream into carbon dioxide by means of a second low-temperature water-gas shift reaction (17); characterized by the following steps: Converting a third quantum of CO present in the synthesis gas stream into carbon dioxide by means of a third low-temperature water-gas shift reaction (19); Separation of essentially all hydrogen present in the synthesis gas stream after completion of the first, second and third water-gas shift reactions (15, 17, 19); Condensation of substantially all the water present in the synthesis gas stream after the first, second and third water-gas shift reactions (15, 17, 19); and Recycling of the condensed water from the condensation after the first, second and third water-gas shift reactions (15, 17, 19) for use in the first and second water-gas shift reactions (15, 17).

Description

[0001] The invention relates to a method and system for removing unwanted chemical components from a synthesis gas stream in order to achieve more efficient fuel injection into a gas turbine of a combined cycle power plant, as well as for other industrial applications requiring clean hydrocarbon fuels for combustion. Specifically, the invention relates to a novel method for the efficient conversion of carbon monoxide and the removal of carbon dioxide from a synthesis gas stream, and for the production of carbon dioxide and free hydrogen by means of a high-temperature desulfurization step in combination with several water-gas shift reactions and a hydrogen separation step.

[0002] The new process and system eliminate the need for conventional acid gas removal methods to eliminate sulfur compounds and other legally restricted emissions from a synthesis gas fuel or other gas source stream. As used here, the term "acid gas removal" (or "EGR") generally refers to the removal of COS, CO2, H2S, and other acidic gases produced by hydrocarbon fuels containing sulfur compounds (also referred to as "acid gases"). A typical EGR process removes acid gases (usually by solvent absorption) to produce a more efficient "clean" fuel that can be fed into one or more combustion chamber assemblies, such as a gas turbine in a combined cycle power plant. BACKGROUND TO THE INVENTION

[0003] In recent years, a certain type of synthesis gas ("syngas") has been selected as a primary fuel component in many combined-cycle power plants to promote the use of clean fuel gas derived from the gasification of a low-cost solid fuel, such as coal, in a gas turbine or combined-cycle power plant. Synthetic gas, or "syngas," is the generic term for a gas mixture that typically contains carbon monoxide and hydrogen, as well as hydrocarbons with relatively low molecular weight, such as CH4, and a significant proportion of non-hydrocarbon components, such as nitrogen, carbon dioxide, H2O, and oxygen. Synthetic gas also usually contains a considerable amount of sulfur byproducts or other pollutants generated in upstream gasification steps, particularly gas compounds produced by coal gasification power plants.Several more environmentally friendly processes are available for producing synthetic gas, such as steam reforming of natural gas or liquid hydrocarbons. However, the end product in all of these systems has less than half the energy density of natural gas and contains hydrogen, large amounts of carbon monoxide, and at least some carbon dioxide. Nevertheless, synthetic gas is a valuable potential supplementary fuel source, particularly in combined cycle power plants that use a gas turbine.

[0004] As mentioned, a major problem with most gasification systems that produce synthetic gas, especially those requiring coal as a primary fuel, concerns the high volume percentage of carbon monoxide and carbon dioxide, as well as the presence of sulfur compounds (such as H₂S and COS) and even nitrogen compounds. All of these reduce the calorific value of the synthesis gas, create difficult emissions control problems, and decrease the efficiency of combined cycle power plants. In recent years, several approaches have been attempted, with limited success, to reduce the proportion of sulfur and other non-fuel components in the synthesis gas feed-in without compromising the thermodynamic efficiency of a power plant or increasing the capital investment required to meet stringent legal emissions monitoring standards.

[0005] A well-known process for removing sulfur and other sour gas impurities from a synthesis gas fuel stream is the Selexol process, first developed by Universal Oil Products in the 1990s. In a Selexol system, a solvent absorbs sour gases, such as H₂S, which are present in the feed fuel at relatively high pressure (in the range of 300 to 1500 psia) and low temperature (usually less than 40 °F). The pressure of the enriched solvent containing the absorbed sour gases is then reduced, and the sour gas is separated from the solvent using steam as a heat source. To date, the Selexol process has been successfully used to isolate and capture hydrogen sulfide and carbon dioxide as separate streams, with the hydrogen sulfide being converted to elemental sulfur or used to form sulfuric acid.Despite these successes, Selexol is considered a costly and complicated process for removing sulfur and CO2 from a synthesis gas feed, as it requires cooling the hot gases from the gasification unit to lower process temperatures.

[0006] Although some progress has been made in the conversion and purification of synthetic gas produced via coal gasification, for example as part of an integrated combined cycle (IGCC) power plant, the industrial deployment of most coal-to-hydrogen technologies has been hampered by the high capital expenditure associated with the removal of inorganic impurities, particularly the sulfur present in domestic coal, which ultimately forms oxides and / or H₂S, linked to significant environmental problems. Furthermore, most known liquid absorption systems for H₂S use low-temperature processes that require cooling of the entire gas stream, resulting in further energy and efficiency losses.

[0007] Apart from sulfur, the conversion of carbon monoxide and the removal of carbon dioxide from combustion exhaust streams have gained significant economic importance in recent years, partly due to the economic advantages of converting, isolating, and compressing the carbon dioxide for use in other industries, or to achieve "cleaner" emissions into the atmosphere. Some current CO2 capture methods rely on a fuel decarbonization process that converts carbon monoxide into carbon dioxide and removes the CO2 from the system before the fuel is burned in the power plant. However, typical decarbonization plants are complex, as they require the use of one or more catalytic reactors and reformers as essential components. Furthermore, decarbonization systems may also be thermodynamically inefficient and can be expensive to construct and operate.Due to the energy consumed and dissipated during the reforming process, a decarbonization process can negatively reduce the overall efficiency of a power plant, for example by 8-12%. Separating CO2 from a synthesis gas feed using gas separation devices, e.g., permeable membranes, is possible; however, the separation must always be carried out at high temperature and high pressure to avoid, if possible, the need to compress the CO2 before final separation.

[0008] Regarding the hydrogen present in synthetic gas, some conventional systems are capable of separating fuel-grade H2 from a synthesis gas feedstock. However, these systems require a large number of process steps, such as multiple absorption and desorption columns, as well as a considerable footprint in an existing power plant. In recent years, hydrogen-selective membranes have also been used with some success to isolate the hydrogen. However, the mere use of membranes does not produce a "clean" syngas product free of residual sulfur, carbon monoxide, and carbon dioxide components. Furthermore, the known hydrogen-selective membranes are impermeable to carbon monoxide and therefore unable to convert the separated gas into a rich permeate stream. (The final residual H2 and CO in the membrane retentate stream are often referred to as hydrogen "slip").Most power plant designs that use hydrogen-selective membranes also require additional process steps to ensure that the overall thermal efficiency of the plant is not affected by the H2 and CO slip that follows membrane separation.

[0009] US 2011 / 0030384A1 discloses a method for capturing and isolating carbon dioxide and hydrogen gases from a high-temperature synthesis gas stream containing CO and sulfur compounds, and a system for generating electricity by means of a modified synthesis gas feed, which has the features of the preambles of independent claims 1 and 8.

[0010] From US patent 4 021 366 A, it is known to carry out catalytic water-gas shift reactions in up to three successive stages to effectively remove CO from a synthesis gas stream, wherein a second water-gas shift reaction stage is followed by a third low-temperature water-gas shift reaction stage.

[0011] Therefore, there is still a significant need in the power generation industry for a more efficient system to effectively purify raw syngas feed-in by removing unwanted sulfur byproducts, converting CO to CO2 and separating the CO2, without increasing the energy and investment costs that are normally required to achieve those process objectives. BRIEF DESCRIPTION OF THE INVENTION

[0012] The present invention comprises a method and system for capturing and isolating carbon dioxide and hydrogen gas from a high-temperature synthesis gas stream containing a substantial proportion of CO and sulfur compounds for use as a “clean” supplementary hydrocarbon fuel source.An exemplary process includes the following steps: reducing the temperature of the high-temperature synthesis gas stream from a gasification unit, removing substantially all of the sulfur compounds present in the synthesis feedstock, converting a first quantity of carbon monoxide (CO) to carbon dioxide in a first high-temperature water-gas shift reaction, converting a second quantity of CO to carbon dioxide by means of a second low-temperature water-gas shift reaction, converting a third quantity of CO to carbon dioxide by means of a third low-temperature water-gas shift reaction, and finally separating substantially all of the hydrogen present in the treated synthesis gas stream for use as an additive fuel component.The process also includes the steps of essentially condensing all the water present in the synthesis gas stream after the first, second and third water-gas shift reactions and returning the condensed water from the condensation after the first, second and third water-gas shift reactions for use in the first and second water-gas shift reactions.

[0013] Each of the above-mentioned methods can further include the step of feeding the hydrogen into one or more combustion chamber arrangements of a combined cycle power plant.

[0014] In each of the above-mentioned processes, the high-temperature synthesis gas stream can contain H2S, CO, nitrogen, steam, and hydrogen.

[0015] The hydrogen in each of the above-mentioned processes may include hydrogen initially present in the high-temperature synthesis gas stream and hydrogen generated during the first, second, and third water-gas shift reactions.

[0016] In each of the above-mentioned processes, the sulfur compounds can include hydrogen sulfide (H2S) and sulfur dioxide (SO2).

[0017] In each of the above-mentioned processes, the step of reducing the temperature of the high-temperature synthesis gas stream can involve a reduction in the temperature of the synthesis gas from about 2,400 °F to approximately 1,200 °F.

[0018] In each of the above-mentioned processes, the step of removing essentially all sulfur compounds can take place at approximately 900 °F.

[0019] In each of the processes mentioned above, the first high-temperature water-gas shift reaction can take place at about 680 °F.

[0020] In each of the above-mentioned processes, the second low-temperature water-gas shift reaction can take place at approximately 400 °F.

[0021] Each of the above-mentioned processes can also include the step of separating essentially all of the CO2 present in the synthesis gas stream after the first, second, and third water-gas shift reactions.

[0022] In each of the above-mentioned processes, the third low-temperature water-gas shift reaction can take place at approximately 380 °F.

[0023] In each of the processes mentioned above, the step of condensing essentially all the water present in the synthesis gas stream can take place at about 90 °F.

[0024] In each of the above-mentioned processes, the step of separating essentially all the hydrogen from the synthesis gas stream can also include the step of separating the hydrogen from carbon dioxide using a hydrogen separation device containing a permeable membrane.

[0025] The invention also considers using the new method of CO conversion and hydrogen separation to provide a hydrogen-based supplementary fuel source for use in a combined cycle power plant, which includes: a gasification unit for generating the synthesis gas feed, a high-temperature desulfurization unit for removing the unwanted sulfur pollutants, first, second and third water-gas shift reactors, a hydrogen separation device, for example a hydrogen-permeable membrane, a gas turbine and an electric generator for generating electricity.

[0026] According to the invention, a system for generating electrical current by means of a modified synthesis gas injection can include: a gasification plant to produce a synthesis gas feed containing free hydrogen, steam, CO, CH4, CO2, nitrogen and sulfur compounds; a high-temperature desulfurization unit designed to remove sulfur compounds from the synthesis gas feed-in; a first high-temperature water-gas shift reactor designed to convert carbon monoxide in the synthesis gas feed into carbon dioxide and to form a first converted synthesis gas stream; a second low-temperature water-gas shift reactor, which is set up to further convert carbon monoxide into carbon dioxide to form a second converted synthesis gas stream; a third low-temperature water-gas shift reactor designed to further convert carbon monoxide into carbon dioxide to form a third converted synthesis gas stream; one or more hydrogen separators containing membranes designed to separate free hydrogen from the third converted synthesis gas stream; a gas turbine designed to take in and burn the free hydrogen; an electric generator connected to the gas turbine; a low-temperature gas cooler for condensing essentially all of the water present in the synthesis gas stream after the first, second, and third water-gas shift reactor; and a return line for returning the condensed water from the low-temperature gas cooler for use in the first and second water-gas shift reactors.

[0027] The system may also include a carbon dioxide removal unit designed to remove carbon dioxide from the converted synthesis gas stream.

[0028] Each of the systems mentioned above can also include a low-temperature gas cooler designed to reduce the temperature of the third converted synthesis gas stream and produce a water condensate stream.

[0029] Each of the systems mentioned above can also include an air separation unit for returning oxygen to the gasification device.

[0030] Each of the systems mentioned above can also include means to feed nitrogen and free hydrogen into the gas turbine. BRIEF DESCRIPTION OF THE DRAWINGS

[0031] The figure attached to the application illustrates in a process flow diagram the exemplary process steps and main equipment components required for the implementation of the present invention, namely to remove the unwanted sulfur content, to efficiently convert CO to CO2, to separate the hydrogen fuel content and to create an improved supplementary fuel source containing additional hydrogen for use in a combined cycle power plant. DETAILED DESCRIPTION OF THE INVENTION

[0032] As mentioned, the invention provides a new and more cost-effective method for removing sulfur compounds and CO from a synthesis gas feed, completely eliminating the need for a conventional solvent-based sour gas removal (EGR) subsystem. To achieve this, the invention is the first to combine a high-temperature desulfurization step with several water-gas shift reactions and the associated heat generation steps. The end result is the removal of all residual sulfur and a complete (nearly 100%) conversion (shift) of the CO present in the synthetic gas to CO2, thus completely eliminating the need for solvent-based processes such as Selexol.Furthermore, the process achieves the almost complete removal of CO from the synthesis gas feed without the need for any catalyst to deal with residual CO remaining in the exhaust gas – again, unlike Selexol or other known conventional processes. In addition, the new system effectively isolates and separates all hydrogen present in the feed gas to create a valuable supplementary fuel source for use in a combined cycle process.

[0033] The well-known water-gas shift reaction, which is referred to here, proceeds as follows: CO + H2O → CO2 + H2

[0034] Essentially, the water-gas shift process reacts carbon monoxide (CO) gas with steam at a relatively high temperature to produce a mixture of hydrogen and carbon dioxide. The reaction is exothermic and requires a catalyst, such as iron, iron compounds (e.g., oxides), chromium, chromium compounds, or other catalysts known from the prior art. The rate of conversion to hydrogen can be accelerated by increasing the temperature, while the degree of conversion increases at lower, controlled reaction temperatures. The carbon dioxide can be separated from the reaction product gas mixture using carbonate-forming systems, such as ethanolamine absorption columns or other known methods.

[0035] Historically, most water-gas shift reactions were carried out without prior desulfurization, either using a single-stage shift reactor or a two-stage reactor, to achieve a practical conversion rate of carbon monoxide and steam to hydrogen. The single-stage reaction is exothermic and favors inlet temperatures in the range of 450 °F to 900 °F, with the gaseous outflow from the shift reactor consisting mainly of carbon dioxide and hydrogen gas. In a two-stage water-gas shift conversion, two catalytic shift reactors operating at high and low temperatures, respectively, can achieve a higher conversion rate to free hydrogen. See, for example, U.S. Patent 4,476,683, owned by the inventor.

[0036] As described above, gasification in the case of syngas production typically results in exhaust gas containing sulfur byproducts, e.g., H₂S, as well as a significant proportion of CO and smaller amounts of CO₂, O₂, H₂, and water (steam). The process according to the invention converts virtually all of the CO (which usually constitutes about 50% by volume of the synthesis gas input) into CO₂ by "shifting" the CO in a series of successive water-gas shift reactions. That is, the H₂O and CO produce CO₂ and hydrogen, while heat is generated due to the exothermic nature of the water-gas shift reactions. The result is a substantially modified synthetic gas that consists primarily of hydrogen and CO₂, as well as a very small (negligible) amount of unreacted residual CO.

[0037] In the process according to the invention, the sulfur compounds present in the synthesis gas feed are removed by means of a high-temperature gas desulfurization process prior to the water-gas shift reactions. The result is an initially "sulfur-free" synthesis gas product stream, which is then successively subjected to three separate water-gas shift reactions. The final product is a gas containing hydrogen and CO2 as well as unreacted nitrogen. The fully "shifted" synthesis gas stream is then subjected to a separate series of steps to separate and collect the free hydrogen, usually by means of one or more hydrogen separation devices, for example, membrane units.

[0038] In contrast to known conventional systems, this process first removes all sulfur present in the synthetic gas, then converts almost all of the CO to CO2, and finally separates the CO2 and the free hydrogen (including all the H2 generated during the water-gas shift reactions). These steps highlight a crucial difference between the invention and a conventional Selexol process, which relies on removing H2S and CO2 via a series of absorption and separation columns, as well as cooling and recovery steps. A clear advantage, therefore, lies in the cost of the equipment and the ongoing operating expenses of the invention, which effectively eliminates the need for solvent-based desulfurization equipment.Thanks to the additional (third) water-gas shift reaction, which serves to convert any remaining residual CO into CO2 and H2, very little CO remains in the system (usually only in the ppm range).

[0039] With reference to the figure attached to the application, the exemplary process steps and main equipment components required for implementation are generally designated by 10, wherein, as shown, an initial syngas product originating from a conventional coal gasification plant is used as the primary feed into the system. As mentioned, the syngas product in a gasification / RSC step 11 contains a significant proportion of carbon monoxide and sulfur byproducts originating from the initial combustion.

[0040] In step 11, integrated gasification takes place, i.e., the conversion of a solid or liquid hydrocarbon fuel into a gaseous exhaust stream with a significant calorific value, for example, syngas, which typically contains about 50 percent carbon monoxide by weight and smaller amounts of hydrogen, nitrogen, sulfur compounds (e.g., H₂S), and unreacted oxygen. The exhaust stream exiting the gasification unit (usually at an outlet temperature of about 2,200–2,400 °F) is subjected to an immediate cooling step by means of one or more synthesis gas radiation coolers (labeled "RSC" in the figure), which cools the synthesis gas to a temperature of less than about 1,250 °F.

[0041] After initial cooling, the exhaust gas stream containing several components enters a high-temperature desulfurization unit (“HTDS”) 13, operating at approximately 900 °F, via an HTDS feed line 12, and then a direct sulfur recovery process (“DSRP”) 37, where substantially all of the sulfur 40 is removed, as described above. Desulfurization processes for synthesis gas streams are known and are usually carried out in a reactor by direct contact with a zinc-containing material (possibly with an aluminum oxide additive). In the invention, a certain quantity of the exhaust gas generated during the DSRP process is returned to the HTDS unit 13 as a return 39. The feed into the HTDS 13 also includes a quantity of a first condensate return 36, which is generated downstream in a low-temperature gas cooling process (hereinafter referred to as the “LTGC” step 21).A “slipstream” 42, which mainly contains free hydrogen, CO and CO2, is fed to the DSRP section unit 37, as shown for the production of elemental sulfur.

[0042] After completion of the desulfurization step, the exhaust gases from the HTDS unit are subjected to a series of water-gas shift reactions, beginning with a high-temperature (“HT”) shift reaction, which takes place in step 15 at approximately 680 °F. The high-temperature shift feed 14 contains a second quantity of condensate return 35, which is generated by the low-temperature gas cooler. The exhaust gas from the first high-temperature water-gas shift reaction is immediately subjected in step 17 (at approximately 400 °F) to a second low-temperature water-gas shift reaction, which utilizes a high-temperature shift exhaust gas feed 16 combined with a third quantity 34 of condensate generated by the same low-temperature gas cooler.

[0043] The output 18 from the first low-temperature water-gas shift reaction 17, whose CO concentration is now significantly reduced, is immediately fed into a second low-temperature water-gas shift reaction 19, which takes place at approximately 380 °F. The gas resulting from step 19 enters the low-temperature gas cooler (“LTGC”) 21, which cools the gas to a temperature of 90 °F, causing water vapor in the gas to condense and produce a condensate 33. The condensate is then recycled, as mentioned above in connection with the HTDS step 13, to the HT shift step 15 and the low-temperature shift step 17.

[0044] The embodiment shown in the figure thus illustrates the use of an initial high-temperature water-gas shift reaction, followed by a first low-temperature shift reaction and a second low-temperature shift reaction, which together eliminate almost all of the CO present in the initial synthesis gas feed. The first shift reaction typically achieves about 70–80% of the conversion of CO to CO2; the second shift reaction results in a conversion of about 95%; and the third shift reaction achieves the conversion of almost all of the remaining CO (leaving only amounts in the ppm range). The inventors assume that the last shift reaction is responsible for no more than about 5% of the total CO conversion.

[0045] The low-temperature gas stream resulting from the LTGC 21 (and now almost completely depleted of CO, but containing free hydrogen, carbon dioxide, and nitrogen) is fed directly into and flows through a hydrogen separator device, for example, a membrane separation station 23, which separates and isolates the hydrogen and traces of nitrogen present in the feed as H2 output 30. Simultaneously, the carbon dioxide output 24 from the hydrogen membrane separation station (which may contain a small residual amount of free hydrogen and an even smaller amount of CO) is treated, as shown, in the CO2 separation step 25, resulting in a very clean CO2 product stream 43 that is separated or used for other applications. The remaining H2 and CO stream 26 is combined with nitrogen and hydrogen separated by a hydrogen separator device, e.g., a membrane separation station 23.generated by the membrane separation station 23, which has one or more hydrogen membranes 50.

[0046] The final combined stream, containing separated hydrogen, nitrogen, and (possibly) residual amounts of CO, is then fed into the combined cycle power plant 31 as a hydrogen-based auxiliary fuel stream 41. In most combined cycle power plants, such as the one shown in step 31, a steam turbine and a gas turbine are operationally connected via a common shaft to drive a single electric generator, with the primary energy input being the fuel burned in the gas turbine combustion chambers. The waste heat from the gas turbine typically generates high-pressure steam by means of a heat recovery steam generator (HRSG). In this way, the steam forms a secondary power input source for the rotating shaft train.

[0047] As mentioned above, thanks primarily to the additional (third) water-gas shift reaction, which serves to convert almost all of the remaining residual CO into CO2 and H2, a very small amount of CO (probably on the order of ppm) remains in the system shown in the figure at step 25. The combined CO2 separation feed 24, which contains CO, CO2, and H2, also contains only a small amount of free hydrogen ("hydrogen slip"), i.e., the portion of residual hydrogen that could not be removed through the hydrogen membrane in step 23 and thus forms part of a predominantly carbon dioxide-based stream.

[0048] Finally, air extracted from the combined cycle 31 is recirculated via an air separation unit (“ASU”) 27 to supply additional oxygen to the gasification unit / RSC 11 via an ASU oxygen feed line 28. Similarly, some of the nitrogen generated by the ASU 27 is fed back into the hydrogen membrane separation station 23.

[0049] While the invention has been described using a preferred embodiment which is currently believed to be the most feasible, the invention is of course not limited to the described embodiment, but rather is intended to cover a wide range of modifications and equivalent arrangements which fall within the scope of protection of the attached patent claims.

[0050] Method and system for capturing and isolating carbon dioxide and hydrogen gases from a high-temperature synthesis gas stream containing a substantial amount of CO and sulfur compounds for use as a "clean" additive fuel, comprising the steps of: reducing the temperature of the high-temperature synthesis gas stream, removing substantially all of the sulfur compounds present in the synthesis gas, converting a first quantity of CO to carbon dioxide in a first high-temperature water-gas shift reaction, converting a second quantity of CO to carbon dioxide by means of a second low-temperature water-gas shift reaction, converting a third quantity of CO to carbon dioxide by means of a third low-temperature water-gas shift reaction, and subsequently separating substantially all of the hydrogen present in the treated synthesis gas stream. Reference symbol list: 12 HTDS feed line 13 High-temperature desulfurization unit (“HTDS”) 37 Direct sulfur recovery process (“DSRP”) 40 Sulfur 39 H2 return 36 first condensate return 21 Low-temperature gas cooling process 19 Second low-temperature water-gas shift reaction 14 High-temperature shift feed 35 second quantum condensate return 17 first low-temperature water-gas shift reaction 16 High-temperature shift exhaust gas injection 34 third condensate quantum 18 Output 33 Condensate 15 High-temperature shift 23 Hydrogen separator 30 H2 output 24 CO2 emission injection 25 CO2 separation step 26 CO electricity 50 one or more hydrogen membranes 41 Fuel flow 31 Combined Cycle Power Plant 27 Air separation unit (“ASU”) 11 Gasification unit / RSC 28 ASU oxygen feed line 42 Slip current 43 CO2 product flow

Claims

[1] Method for capturing and isolating carbon dioxide and hydrogen gases from a high-temperature synthesis gas stream containing CO and sulfur compounds, comprising the following steps: Reducing the temperature of the high-temperature synthesis gas stream; substantially all sulfur compounds present in the synthesis gas stream are removed by means of a high-temperature desulfurization unit (13); Converting an initial quantity of CO present in the synthesis gas stream into carbon dioxide by means of a first high-temperature water-gas shift reaction (15); and Converting a second quantum of CO present in the synthesis gas stream into carbon dioxide by means of a second low-temperature water-gas shift reaction (17); characterized by the next steps: Converting a third quantum of CO present in the synthesis gas stream into carbon dioxide by means of a third low-temperature water-gas shift reaction (19); Separation of essentially all hydrogen present in the synthesis gas stream after completion of the first, second and third water-gas shift reactions (15, 17, 19); Condensation of substantially all the water present in the synthesis gas stream after the first, second and third water-gas shift reactions (15, 17, 19); and Recycling of the condensed water from the condensation after the first, second and third water-gas shift reactions (15, 17, 19) for use in the first and second water-gas shift reactions (15, 17). [2] Method according to claim 1, further comprising the step of feeding the hydrogen into one or more combustion chamber arrangements in a combined cycle power plant. [3] The method of claim 1, wherein the high-temperature synthesis gas stream contains H2S, CO, nitrogen, steam and hydrogen. [4] Method according to claim 1, wherein the hydrogen comprises: hydrogen initially present in the high-temperature synthesis gas stream and hydrogen formed during the first, second and third water-gas shift reactions (15, 17, 19). [5] The method of claim 1, wherein the sulfur compounds comprise hydrogen sulfide (H2S) and sulfur dioxide (SO2). [6] The method of claim 1, further comprising the step of separating substantially all of the CO2 present in the synthesis gas stream after the first, second and third water-gas shift reactions (15, 17, 19). [7] Method according to claim 1, wherein the step of separating substantially all of the hydrogen in the synthesis gas stream also includes the step of separating the hydrogen from the carbon dioxide by means of a hydrogen separation device (23) having a permeable membrane. [8] System for generating electricity by means of a modified synthesis gas injection, comprising: a gasification device (11) for producing a synthesis gas feed containing free hydrogen, steam, CO, CH4, CO2, nitrogen and sulfur compounds; a high-temperature desulfurization unit (13) designed to remove sulfur compounds from the synthesis gas feed; a first high-temperature water-gas shift reactor (15) designed to convert carbon monoxide present in the synthesis gas feed into carbon dioxide and to form a first converted synthesis gas stream; a second low-temperature water-gas shift reactor (17) configured to further convert carbon monoxide into carbon dioxide to form a second converted synthesis gas stream; one or more hydrogen separators (23) comprising membranes designed to separate free hydrogen from converted synthesis gas stream; a gas turbine designed to take in and burn the free hydrogen; and an electric generator connected to the gas turbine; characterized by , that a third low-temperature water-gas shift reactor (19) is arranged downstream of the second low-temperature water-gas shift reactor (19) in the process direction and is configured to further convert carbon monoxide into carbon dioxide to form a third converted synthesis gas stream; one or more hydrogen separators (23) are designed to separate free hydrogen from the third converted synthesis gas stream; a low-temperature gas cooler (21) is installed for condensing substantially all of the water present in the synthesis gas stream downstream of the first, second, and third water-gas shift reactor (15, 17, 19); and a return line (33, 36, 35) is arranged to return the condensed water from the low temperature gas cooler (21) for use in the first and second water gas shift reactors (15, 17).

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