Introduction The present invention relates to a system and process to capture industrial emissions and recycle sulfur and carbon compounds, including hydrogen sulfide (H ₂ S) and sulfur dioxide (S0 ₂ ) as well as carbon dioxide (C0 ₂ ) to produce higher value chemicals such as sulfuric acid and methanol. H ₂ S, S0 ₂ and C0 ₂ can be considered harmful gases present in large volumes in several types of industrial emissions. Sulfur emissions present problems especially in the vicinity of heavy industry and much emphasis has been put on developing technological solutions to clean industrial emissions in a suitable manner. Likewise, increased emission of C0 ₂ into the atmosphere is believed to be the leading cause for anthropogenic climate change.

The Industrial emissions of interest for the present invention are largely comprised of carbon dioxide (C0 ₂ ), hydrogen sulfide (H ₂ S), sulfur dioxide (S0 ₂ ) and hydrogen (H ₂ ) along with lesser quantities of other combustible and inert gases. For example, unprocessed emissions from geothermal power plants, natural gas processing and coal gasification can contain high concentrations of H ₂ S and C0 ₂ that can cause environmental, health and property damage. The present invention presents an integrated system where industrial emissions are cleaned and some or all of the present C0 ₂ , H ₂ S and S0 ₂ are efficiently utilized to produce higher value liquid fuels and chemicals, reducing greenhouse gas emissions and producing minimal amounts of waste.

Background

Several technologies are known to remove sulfur compounds from industrial emissions, as are several methods known to sequester, store or utilize carbon dioxide. The most common and oldest process for sulfur removal is the Claus process (Fisher et al., US 4097585), (Singleton et al., US 4085199) a process comprising the total oxidation of hydrogen sulfide to yield elemental sulfur with heat recovery in terms of steam generation. The Claus process however does not include utilization of the remaining emission gases and thus does not support global warming mitigation. Furthermore the main product of the Claus process is elemental sulfur that is of less commercial value than sulfuric acid which is one of the products of the present invention. A number of separate sulfur removal technologies are based on the production of elemental sulfur, these include the chemical reaction processes using iron oxide (FeO) and zinc oxide (ZnO). Other sulfur removal processes include; wet sulfuric acid (WSA) process from Haldor Topsoe A/S that produces sulfuric acid; (Tatarchuk et al., US 2008/062054); The THIOPAQ biochemical process (Jansen et al., EP 0845288A1); The LO-CAT ^® process of Merichem Company; The Fe-CI hybrid process produces elemental sulfur and hydrogen (Mizuta et al.,) and as does high temperature thermal treatment of H ₂ S. One of the main drawbacks of conventional sulfur removal processes that employ combustion is that they introduce oxygen in the form of atmospheric air and thereby dilute the resulting C0 ₂ emission stream with nitrogen making it more energy intensive and costly to capture it for utilization or sequestration. Known industrial processes that sequester or utilize C0 ₂ include; cleaning and utilization in the food industry, i.e. carbonated beverages and as a cooling medium; sequestration in soil or rocks; enhanced oil recovery; use as a raw material for the production of urea, carbonates, salicylic acid, formic acid and several polymers. However none of these methods are currently close to sequestering carbon dioxide at the scale of which it is currently being emitted by industry and most chemical conversion processes are net emitters of C0 ₂ .

The wet sulfuric acid (WSA) sulfur removal process patented by Haldor Topsoe A/S catalytically produces sulfuric acid from H ₂ S emissions along with heat recovery for generation of steam. However the WSA process does not include a method for utilizing the remaining emission gases and does not support global warming mitigation. Kita et al., present a process that monitors the concentration of sulfur dioxide (S0 ₂ ) and catalytically oxidizes it to sulfur trioxide (S0 ₃ ) which is subsequently hydrolyzed to yield sulfuric acid (US 8052949 B2). Dorr et al., present a process that produces sulfuric acid from wet sulfur dioxide containing gases. The process includes cooling and purification of sulfur dioxide, catalytic conversion to sulfur trioxide which is absorbed in sulfuric acid. (US 4333917). Honna et al., present a process where a hydrogen sulfide containing gas is brought into contact with an aqueous iron salt (Fe ³⁺ ) solution to carry out oxidation reaction and produce a solution of Fe ²⁺ , sulfur and secondarily produced sulfuric acid (US 5391278).

One approach to support climate change mitigation is direct reduction of C02 emissions through Carbon Capture and Sequestration (CCS), a process comprising of the separation of C02 from industrial and energy-related sources, transport to a storage location and long-term isolation from the atmosphere. In most scenarios for stabilization of atmospheric greenhouse gas concentrations between 450 and 750 ppmv C02. The economic potential of CCS would amount to 220-2,200 Gt C02 (60-600 GtC) cumulatively, which would mean that CCS contributes 15-55% to the cumulative mitigation effort worldwide until 2100, averaged over a range of baseline scenarios. Uncertainties in these economic potential estimates are significant. For CCS to achieve such an economic potential, several hundreds to thousands of C02 capture systems would need to be installed over the coming century, each capturing some 1-5 MtC02 per year. The actual implementation of CCS, as for other mitigation options, is likely to be lower than the economic potential due to factors such as environmental impacts, risks of leakage and the lack of a clear legal framework or public acceptance. CCS is a costly process, leading to reduced plant efficiencies and is not economically favorable unless incentives are provided.

Another approach for direct C02 emission reduction is through carbon capture and re-use. Commercial applications of C02 reuse are currently limited to refrigeration for food (PCT/US1999/5974826 Novak et al), carbonated beverages, enhanced oil recovery and chemicals. In 1980, the total US market consumption of 2.3 million tons carbon represents only 0.18% of the US total emission. Halmann et al. concludes that as a sink for C02 the market demand would have to grow by at least two factors of 10 to become a major factor in reducing man made C02. Another C02 reduction scheme is disclosed in PCT/US2001/6237284 by Stewart E. Erickson where C02 storage and distribution underground to plant soil for enhancing plant growth is proposed. Iceland patent IS 2300, Shulenberger et al., presents a process which combines industrially captured C02 with H2 from electrolysis using renewable energy for the production of methanol by means of a low pressure and temperature process. PCT/IT2008/000559, submitted by A.S.T. Engineering s.r.l., presents a system closely modeled on the Carnol Process in which the C02 from industrial flue gas is separated from other emission components and mixed with H2 from natural gas for methanol production. US 2008/0319093 Al, submitted by George Olah, aims to use industrial C02, not necessarily from industrial exit stacks, along with methane or natural gas for the production of methanol and methanol byproducts using "bi-reformation", a combination of steam reformation and dry reformation. WO 03/066779, submitted by Felicien Absil, discusses a method for the recovery of C02 from industries like cement plants or coal fired power stations for the production of syngas for heat energy and carbon nanotube production. US2008/0072496 Al submitted by A. Yogev et al. relates to the thermochemical capture of C02 from gas by reaction with K2C03 and producing methane or methanol fuel by releasing the captured C02 and reacting it with hydrogen. Commercial application of these processes is yet to be seen. It is to be noted that in most CCS or C02 reuse systems, the cost of C02 capture could be the largest cost component. A number of systems for the removal and recovery of C02 are described by Halmann et al. including, amine absorption, oxy-combustion, potassium carbonate absorption, molecular sieves, refrigeration, seawater absorption, pressurized, fluidized bed combustor, and membrane separation. On this topic, it is noted that both thermal and electrical energy are needed to remove and recover C02. WO 2009/087210, WO 2009/087060, WO 2009/076042, and WO 2009/073422, submitted by Alstom Technology, describe methods for the capture of C02 either through compressive means, solid materials or specialty systems. WO 2009/091437, submitted by Powerspan Corporation, describes a system in which a synergistic system removes C02 from a flue gas. WO 2008/137815 Al submitted by Clark describes a process where biomass feedstock is converted to synthesis gas streams where one is converted to C02 and steam for producing electricity and another is converted to fuel in a Fischer-Tropsch reactor.

Biomass utilization is a natural cycle of C02 capture and reuse. Biomass provides a potentially C02- neutral source of energy as the C02 released during processing and combustion is taken up by the next crop. Biomass is majorly used for transport fuel production through biochemical (fermentation, transesterification, and anaerobic digestion) or thermochemical (gasification, pyrolysis and conversion) methods. At present, the main transportation fuel available from biomass is ethanol. Haroon et al. studies that current ethanol production techniques from fermentation consume fossil carbon for energy and chemical inputs and it is these fossil carbon inputs that result in positive full- fuel-cycle emissions. Each liter of ethanol saves 1.85 kg of C02 by replacing gasoline, but at the same time releases 1.39 kg of C02 as produced in the US and 0.24 kg of C02 in Brazil. Thus the fu((-fue(- cycle analysis shows that current ethanol fuel systems are only partially successful at recycling C02 and being C02-neutral sources of energy. Full-fuel-cycle C02 emissions from corn ethanol in the USA nearly wipe out all of the C02 advantage of replacing gasoline. Another disadvantage of this process is that only a fraction of the biomass is converted to the final desired liquid fuels. This problem is also associated with proposed biofuel production from algae, which is currently un-economical and has serious sustainability challenges relating to high requirements of water and nutrients. Thermochemical production pathways of biofuels from biomass could use biomass with higher efficiency. This process happens through an intermediate called synthesis gas, also known as syngas, which consists of a variable ratio mixture of H2, CO, and C02. Depending on the type of biomass and the conditions of syngas production, C02 concentration of the raw syngas output may vary from 6 to 40 mol% on dry basis. To obtain the required ratio of CO/H2, water gas shift reaction is employed in which CO is reacted with H20 to generate more hydrogen, thus releasing further C02. For example, methanol production processes from biomass produce around 600 to 1200 pounds of C02 per ton of methanol. The Hynol Process is employed for the conversion of carbonaceous materials into methanol via a syngas intermediate. Steam reformation and hydrogasification are performed in parallel in this system, and high conversion efficiency to the production of methanol is achieved. The Hynol Process causes a reduction of C02 emissions on the order of 30% relative to conventional processes for methanol production, but still causes the emission of approximately 103 pounds of C02 for each MMBTu of methanol produced (Halmann 249). US 6,736, 955B2 by Shaw, US2008/0115415A1 by Agrawal et al., US1995/5416245 by MacGroger et al. further overcome the problem of excess C02 generation by offsetting the stoichiometric imbalance of syngas with H2 produced from off peak electricity. While Shaw and Agrawal et al. uses Reverse Water Gas Shift (RWGS) to reduce C02, MacGroger et al. plans to dissociate C02 to CO with energy generated from a Partial Oxidation (POX) reactor to reduce C02. All the three methods use partial oxidation reactor or gasification system for syngas production either to produce methanol or any other liquid synthetic fuels. The success of the above processes to solve the problem of internal C02 generation and release is dependent on the availability, adaptability and effective utilization of carbon free energy sources for H2 production, which has its own limitations as discussed previously.

Purpose

The purpose of the present invention relates to a system and process to desulphurize and decarbonize industrial emission streams by utilizing the emitted gases and recover waste energy for the efficient production of fuels and chemicals such as methanol and sulfuric acid with minimal associated waste or emissions.

Summary of invention

In the present invention a system is disclosed whereby industrial gas emission streams comprising hydrogen sulfide H ₂ S and/or S0 ₂ and carbon dioxide, and which may contain as well other combustible gases such as hydrogen and methane are sent to a combustion unit (CU). Oxygen that is produced in an oxygen production unit (OPU) is sent to the CU where it is used for oxidation and combustion of the emission stream compounds. Flow of oxygen from said OPU and recycled C0 ₂ rich flue gas is in some embodiments controlled to produce a synthetic air stream that can best maintain optimal process conditions and minimize the presence of inert gases such as N ₂ in the final concentrated flue gas stream. In the CU H ₂ S is oxidized to yield sulfur dioxide (S0 ₂ ) according to equation i). This reaction is highly exothermic and the heat is recovered from the process as superheated steam at high pressure in a heat recovery unit (HRU) for use in downstream processes and/or the generation of electricity. i) H ₂ S + ~ 0 ₂ →S0 ₂ + H ₂ 0

The oxidized gas stream is led to a catalyzed acid production unit (CAPU) where S0 ₂ is further oxidized using vanadium oxide catalysts to yield sulfur trioxide (S0 ₃ ). The S0 ₃ is then hydrated in the CAPU to produce sulfuric acid (H ₂ S0 ₄ ). Equations ii) and iii) describe the chemical reactions taking place in the CAPU.

S0 ₃ + H ₂ 0 → H ₂ SO These reactions are exothermic and the heat is recovered as superheated steam at high pressure in the HRU for use in downstream processes or for the generation of electricity in a steam turbine. The combusted emission gases are then led to an acid condensation unit (ACU) where the sulfuric acid is condensed from the gas stream and collected in a collection vessel for storage, distribution and sales. Using this process up to 99% of sulfur compounds may be removed from the original emission gas stream.

The remaining emission gas stream containing mainly carbon dioxide with low levels of oxygen and nitrogen is sent to a gas conversion unit (GCU) for further processing and recycling. The first step in the GCU is the purification of the flue gas stream to the specifications required for downstream processes, including further decreasing H ₂ S concentrations to within 100 ppb in a catalytic guard bed (CGB) where trace compounds are removed by reactions with a scavenger catalyst. The processed flue gas stream is free from sulfur compounds and other trace impurities and mostly consists of C0 ₂ along with lesser amounts of N ₂ and Ar. The second step in the GCU is mixing the said processed flue gas stream with a hydrogen gas stream from a hydrogen production unit (HPU) to produce a synthesis gas stream with a suitable H ₂ /C0 ₂ ratio that is considered ideal for catalytic conversion to methanol. In preferred embodiments the HPU utilizes recovered heat from said HRU and/or electricity generated from recovered heat to disassociate water into hydrogen and oxygen. The third step in the GCU is to produce a pressurized synthesis gas stream by compressing the said synthesis gas stream to a suitable pressure of 50-100 bars. The said pressurized synthesis gas stream is sent to a methanol production unit (M PU) where methanol is produced selectively in a fixed bed reactor using a copper based catalyst according to the reaction described by equation iv):

iv) C0 ₂ + 3H ₂ → CH ₃ OH + H ₂ 0

Due to an equilibrium limited reaction, approximately 25% of the said pressurized gas stream is converted per pass through the reactor. The unreacted gases are looped back to the reactor to ensure high overall conversion efficiency. The products from the MPU are condensed and sent to a product separation unit (PSU) where a high purity product methanol stream and water bottoms are produced through distillation using recovered heat in the form of steam from said HRU.

In a further aspect, the invention provides a process as described herein for capturing industrial emissions comprising carbon dioxide and sulfur compounds and producing therefrom sulfuric acid and methanol, wherein the process comprises transferring an industrial emission stream comprising carbon dioxide and combustible sulfur compounds to a combustion unit as described herein, generating an oxygen stream and transferring said stream to the combustion unit to react with said industrial emission stream, to produce an oxidized emission stream, transferring said oxidized emission stream to a catalytic acid production unit to catal tically produce sulfuric acid, a concentrated C02 stream, and steam, transferring said concentrated C02 stream to a gas conversion unit, providing a hydrogen stream and transferring said hydrogen stream to said gas conversion unit to react with C02 to form methanol, and recovering said steam from step c to utilize heat from said steam to provide at least a part of energy required in any of the above steps. As will understood, the process advantageously makes use of the system as described herein and any of the variations and embodiments encompassed therein. Brief description of the drawings

The current invention addresses sulfur removal, C0 ₂ capture, reuse and disposal. These and other advantages of the present disclosure may be more completely fully understood by means of the following description of the accompanying drawings of the preferred embodiment of the invention in which:

FIG. 1 is a schematic showing a system for the capture and recycling of combustible industrial emissions for the production of chemicals.

FIG. 2. Is a schematic showing a system to capture and recycle combustible emissions through water electrolysis and production of chemicals.

FIG. 3 is a preferred embodiment of a system to capture and recycle combustible industrial emissions through water electrolysis and production of chemicals.

FIG. 4 is a preferred embodiment of a system to capture and recycle combustible geothermal emissions through water electrolysis and production of sulfuric acid and methanol.

FIG. 5 is a preferred embodiment of a system to capture and recycle combustible geothermal emissions through water electrolysis, gas separation and production of sulfuric acid and methanol.

Detailed description of invention

FIG. 1 shows a schematic diagram in relation to the system of the present invention for sulfur and carbon dioxide removal from emission gases and efficient energy utilization and storage through heat recovery and conversion to fuels and chemicals. A combustible emission stream 010 comprises primarily C0 ₂ , and H ₂ S and typically along with other combustible and inert gases such as H ₂ , S0 ₂ , COS, CS ₂ , N ₂ , CH ₄ and other hydrocarbons The release of C0 ₂ , and H ₂ S into the atmosphere can be regarded as harmful emission or in the case of the present invention as feedstock for the production of fuels and chemicals. Said combustible emission stream 010 is firstly introduced to a combustion unit 100 where it takes part in a combustion reaction along with at least part of an oxygen stream 210 that is produced in an Oxygen Production Unit (OPU) 200, producing an oxidized gas stream 150 and steam 380. In some embodiments a recycled concentrated C0 ₂ stream 610 is recirculated to the said combustion unit 100 for maintaining process conditions analogous to that of combustion using air. The main chemical reactions that takes place is shown in equation i). Other relevant reactions include: v) H ₂ + ^ 0 ₂ →+H ₂ 0

vi) Ctf ₄ + 20 ₂ → C0 ₂ + 2H ₂ 0

vii) C _x H _y + (x + )0 ₂ → xC0 ₂ + ζ)Η ₂ O The combusted emission gases exit the combustion unit as an oxidized gas stream 150. Said oxidized gas stream 150 is subsequently introduced to a Catalytic Acid Production unit (CAPU) 300 along with at least part of the said oxygen stream 210 produced in the said oxygen production unit (OPU) 200. The combusted gases undergo an oxidation reaction in said Catalytic Acid Production unit 300 followed by a hydration reaction that yields a Sulfuric Acid Product stream 310. The relevant reactions are described by equations ii) and iii) respectively.

In some embodiments at least a part of the said concentrated C0 ₂ stream produced in the said Catalytic Acid Production Unit 300 is recycled to the Combustion Unit 100 in a Recycled Concentrated C0 ₂ stream 610. The reactions that take place in said catalytic acid production unit 300 are exothermic reactions generating a significant amount of energy in the form of heat, the heat is utilized to produce Steam 380 which is subsequently utilized in an Energy recovery unit (ERU) 400. The recovered energy can be used as electrical and/or thermal energy 410 where at least a part of the said recovered energy is utilized in the said oxygen production unit 200. At least a part of the unreacted gases exiting the catalytic acid production unit form a concentrated C0 ₂ emission stream 350 which is subsequently introduced to a gas conversion unit (GCU) 600. A hydrogen production unit will utilize at least a part of the electrical and/or thermal energy 410 from said energy recovery unit 400 for the production of a hydrogen stream 510. Said hydrogen stream is introduced to the said gas conversion unit where it reacts with the said concentrated C0 ₂ emission stream 350 to form a methanol product stream 650 and a water stream 810. In some embodiments said gas conversion unit 600 will utilize at least a part of the said electrical and/or thermal energy 410 from said energy recovery unit 400.

In some embodiments of the invention, the OPU 200 is one or a combination of water electrolysis and Air Separating Unit (ASU). Preferably in some embodiments, ASU can comprise any of commercially available oxygen production system from air, such as Cryogenic Air Separation (CAS) or Vacuum Pressure Swing Adsorption (VPSA).

In some embodiments of the invention, at least a part of the recycled energy from the ERU 400 is used to produce a hydrogen stream 510 in a HPU 500 and an oxygen stream 210 in an OPU 200. In some embodiments of the invention, the production of the hydrogen stream 510 by a HPU 500 comprises at least one or a combination of: electrolysis of water, dehydrogenation of hydrocarbons, biological hydrogen production, chemical hydrogen production, photochemical hydrogen production, thermo-chemical hydrogen production and any other means of producing hydrogen.

In some embodiments of the invention, the oxygen and hydrogen are stored temporarily in the OPU 200 and the HPU 500 respectively before forming the oxygen stream 210 and the hydrogen stream 510 respectively.

In some embodiments of the invention, at least a part of hydrogen from the hydrogen stream 510 and oxygen from the oxygen stream 210 are temporarily stored in either gaseous or liquid or chemical form separately before use. Preferably, the hydrogen stream 510, the oxygen stream 210 and the concentrated C0 ₂ emission stream 350 have a purity of at least 90% by volume on a dry basis of hydrogen and oxygen respectively. More preferably, the said hydrogen stream should have a purity of at least 95% by volume of hydrogen on a dry basis. More preferably, the concentrated C0 ₂ emission stream 350 has a purity of at least 95% by volume of carbon dioxide on a dry basis. More preferably, oxygen stream should have a purity of at least 95% by volume of oxygen on a dry basis. In some embodiments, some or all of the said hydrogen, oxygen and carbon dioxide streams can be considered commercial value products. In some embodiments of the invention, a HPU 500 can also simultaneously function as an OPU 200 and vice versa. For example, a hydro splitting system producing the hydrogen stream 510 through the dissociation of water also produces an oxygen stream 210, thus acting simultaneously as both HPU 500 and OPU 200. In some embodiments of the invention, at least a part of the oxygen from the oxygen stream 210 is considered a valuable by-product of the process, because the process produces more oxygen than the requirement for internal process combustion. For example, in one embodiment where both the oxygen stream 210 and the hydrogen stream 510 are produced by water electrolysis unit 250 there is a possibility that all the hydrogen from the hydrogen stream 510 is consumed in the internal process while only part of the oxygen from the oxygen stream 210 is utilized. This excess oxygen is thus a valuable by-product for example through its utilization in oxy-fuel combustion or gasification with an added economical benefit by replacing separate production of oxygen.

In some embodiments of the invention, the process utilizes less hydrogen than is produced and thus at least a part of the hydrogen from the hydrogen stream 510 is considered a valuable by-product of the process.

In some embodiments of the invention as described in FIG. 3, the CAPU 300 is comprised of a catalytic acid production Unit (CAPU) 300 and a Acid Condensation Unit (ACU) 330. The concentrated C0 ₂ emission stream 350 exiting the CAPU will contain a gaseous sulfuric acid product which is introduced to the ACU 330 where the gaseous chemical product will be condensed from the concentrated C0 ₂ emission stream to a liquid sulfuric acid product 310. In some embodiments at least a part of the concentrated C0 ₂ will be recycled to the CU 100 in a concentrated C0 ₂ recycle stream 610. At least a part of the energy generated by the exothermic reactions in the CAPU 300 and the ACU 330 will be extracted as steam 380 by a heat recovery unit 450 and utilized in internal production processes. In some embodiments of the invention as described in FIG. 3, the GCU 600 is comprised of a Catalytic Guard Bed (CGB) 630, a Gas Pressurization Unit (GPU) 670, a Methanol Production Unit (MPU) 700 and a Product separation Unit (PSU) 800. At least part of the concentrated C0 ₂ recycle stream 610 will be introduced to the CGB 630 which will remove all remaining sulfur species in the process stream. In said CGB 630 the concentrated C0 ₂ recycle stream 610 is mixed with the hydrogen stream 510 from an Electrolysis Unit (EU) 250 to achieve a molar ratio of H ₂ :C0 ₂ of 2. The mixed gas stream exits the CGB as a synthesis gas stream 650 which is subsequently introduced to the GPU 670 where it is compressed to a pressure of 50-100 bars. The compressed gas stream exits the GCU as a Pressurized Synthesis Gas Stream 690 which is subsequently introduced to the MPU 700. The pressurized synthesis gas undergoes an exothermal catalytic conversion reaction in the MPU 700 which yields a crude methanol stream 720. At least part of the energy released in the exothermic reactions in the MPU 700 is recovered as steam 380 in the HRU 450. Said crude methanol stream is introduced to the PSU 800 where water is separated from methanol using at least part of the processed steam 420 from the HRU 450 yielding a final methanol product 810.

In some embodiments of the invention, the ERU 400 is comprised of a heat recovery unit (HRU) 450 and an Electricity Generation Unit (EGU) 470. At least part of the energy released in the exothermic reactions in the GU 100, CAPU 300, ACU 330, MPU 700 and the EU 250 will be recovered as steam 380 and waste heat 410. Heat Recovery Unit 450 may comprise any one or combination of recuperative and regenerative heat exchangers that recover said steam 380 and said waste heat 410 for the production of processed steam suitable for use in internal production processes. At least a part of the energy recovered by the HRU 450 will be utilized as processed steam 420 in internal production processes. In some embodiments of the invention, at least part of the energy recovered by the HRU will be utilized as processed steam 420 in an electricity generation unit (EGU) 470 to produce electricity 490 in a steam turbine. In some embodiments at least a part of said electricity will subsequently be utilized by the electrolysis unit (EU) 250 to convert a water stream 020 to a hydrogen stream 510 and an oxygen stream 210. Lower grade waste heat 410 from the EU will be utilized by the HRU 450. In some embodiments said electrolysis unit 250 comprises a high temperature electrolyzer operating above 500°C receiving at least a part of the required thermal energy from said processed steam 420 for minimizing electricity requirements for generation of said oxygen 210 and said hydrogen 510 streams.

FIG. 4 shows a schematic diagram describing a preferred embodiment of the invention. In this preferred embodiment at least part of the industrial emissions is derived from the non-condensable portion of geothermal steam 440 from a Geothermal Reservoir (GR) 120. The Geothermal Steam 440 is introduced to a steam turbine (ST) 480 where it is utilized to generate electricity 490. At least part of said electricity 490 is utilized by the GPU 670 and the EU 250 in internal production processes. The geothermal steam is condensed after generating electricity and the non condensable combustible emission stream 010 is introduced to the CU 100. In some embodiments of the invention as described in FIG. 5, the combustible emission stream 010 contains a significant amount of H ₂ , in this embodiment the combustible emission stream 010 is introduced to a Gas Separation Unit (GSU) 480 where H ₂ is separated from the stream. Said H ₂ is extracted from the GSU as a Recovered hydrogen stream 050 that is subsequently mixed with the hydrogen stream 510 produced in a EU 250, the mixed hydrogen streams are then introduced to the CGB 630 where it is mixed with the Concentrated C0 ₂ recycle stream 610. The remaining gases from the combustible emission stream 010 are then introduced to CU 100.

Example 1

One example of the invention is the removal and utilization of carbon dioxide and hydrogen sulfide emissions from a geothermal power plant as described in FIG. 5. A Geothermal reservoir is tapped and the geothermal gases including high pressure steam are led to steam turbines for the generation of electricity. The condensable portion of the geothermal gases is condensed and removed as effluent, the remaining non-condensable gases are normally emitted to the atmosphere but in the embodiment of the present invention they are utilized as feedstock for the production of renewable fuels and chemicals. The non-condensable geothermal gas stream is comprised as follows:

Gas component Flow [kg/hr]

Carbon dioxide (C0 ₂ ) 5003

Hydrogen sulfide (H ₂ S) 2088

Hydrogen (H ₂ ) 55

Nitrogen (N ₂ ) 94

Methane (CH ₄ ) 8 The non condensable gases are extracted from the geothermal power plant and introduced to a hydrogen separation unit where hydrogen is extracted from the gas mixture to produce a H ₂ recycle stream. The remaining gases are subsequently introduced to a combustion unit where the combustible components of the gas stream are combusted in the presence of oxygen produced in an electrolysis unit. Depending on the thermodynamics of the combustion system a recycled C0 ₂ stream may be introduced to the combustion unit to achieve optimal control of concentration of inert gases in the system. The combusted gas flow exiting the combustion unit are introduced to a catalytic acid production unit where the combusted sulfur species are further oxidized using vanadium oxide based catalysts and hydrolyzed at temperatures in the range from 250-400 °C to yield a sulfuric acid product. The remaining gases and the produced gaseous sulfuric acid are introduced to an acid condensation unit where the acid is condensed to yield a concentrated liquid sulfuric acid product at a production rate of 6008 kg/hr. The remaining gases comprised mainly of C0 ₂ are mixed with a hydrogen stream that is produced in a water electrolysis unit to achieve a H ₂ /C0 ₂ ratio of 3.15. The mixed gases are subsequently introduced to a guard bed of ZnO and/or FeO where any remaining sulfur species are removed. The cleaned and mixed gases exit the guard bed as a synthesis gas stream which is subsequently pressurized in a gas compression unit to a pressure of 50-100 bar. The pressurized syngas stream is introduced to a methanol production unit where it reacts at a temperature in the range 200-250T over a Cu/ZnO catalyst to yield a crude methanol stream with an equimolar composition of methanol and water. The crude methanol stream is introduced to a product separation unit where methanol is distilled from water using steam to yield a product methanol stream with a production rate of 3594 kg/hr and a purge water stream.

Since most of the reactions taking place in the system described in the present invention are exothermic a significant amount of heat is released that may be recovered. A heat recovery unit will utilize at least part of the released heat from the steam turbines, the combustion unit, the catalytic acid production, the acid condensation, the methanol production and the electrolysis unit. The recovered heat in form of processed steam will be sufficient to meet the steam requirements of the product separation unit and any other internal steam requirements. The remaining reaction heat will be utilized to raise steam suitable for use in steam turbines to generate electricity. At least a part of said electricity will be further utilized by the electrolysis unit and the gas compression unit. Example 2

One preferred embodiment of the present invention as described in FIG. 4 is a modification on the embodiment in Example 1. In this embodiment the combustible emission stream exiting the steam turbines is directly introduced to the combustion unit forgoing the gas separation unit mentioned in the previous example. In this embodiment the capital cost of a plant operating on the technology described in the present invention would be reduced. Furthermore there will be an increase in the recovered energy from the combustion unit as in this case hydrogen is being combusted along with the other emission components. However an increased amount of hydrogen will have to be produced in the hydrogen production unit as a further 49,28 kg/hr of hydrogen must be produced to compensate for the loss of hydrogen from the absence of the gas separation unit. Example 3

One preferred embodiment of the present invention is a modification of the embodiment described in Example 2. In this embodiment an electrolyzer is utilized as both the hydrogen production unit and the oxygen production unit. In this embodiment Oxygen will be considered the limiting reagent for the electrolysis reaction, thereby eliminating any venting of excess oxygen. Only enough oxygen will be produced to sustain the combustion of the combustible emission stream in the combustion unit and the oxidation of the oxidized gas stream in the catalytic acid production unit. In this embodiment all the hydrogen produced in the electrolysis unit will be utilized in the methanol production unit leaving an excess 1100 kg/hr of carbon dioxide. In this embodiment of the present invention the power demand by the electrolysis unit will decrease as all gases from the electrolysis unit will be fully utilized in the internal processes. The excess carbon dioxide available in this embodiment is highly concentrated and has been cleaned from any impurities and is considered a commercial value product that can for example be utilized in the agricultural greenhouse industry. In this embodiment of the invention carbon conversion will be reduced and methanol production will decrease as compared to previous examples to 2869 kg/hr

Example 4

One embodiment of the present invention relates to the utilization of an emission stream from a coal gasification plant or a natural gas sweetening plant operating an amine scrubbing system to remove sulfur and carbon dioxide. The present embodiment is a modification of the embodiment described in Example 1. The acid gases containing up to 50% H ₂ S and 50% C0 ₂ are introduced to an amine scrubber where H ₂ S and C0 ₂ are removed from the emission stream with high selectivity. The emission stream exiting the amine scrubber is comprised of concentrated C0 ₂ and H ₂ S, which are subsequently introduced to the combustion unit to take place in the overall process as it is described in the present invention. Common amounts of emission gases from amine scrubbing units in coal gasification plants or natural gas power plants are in the vicinity of 60.000 Nm ³ /hr, given an equimolar composition of H ₂ S and C0 ₂ the outputs of the integrated system as disclosed in the present invention are 98.000 kg/hr sulfuric acid and 47.000 kg/hr methanol.