Simultaneous production of hydrogen, carbon, electricity, and steel with carbon dioxide recovery

Abstract

The hydrocarbon feed stream is exposed to heat in the absence of oxygen, and the hydrocarbon feed stream is converted into a solid stream and a gas stream. The gas stream is separated into an exhaust gas stream and a first hydrogen stream. Carbon is separated from the solid stream to produce a carbon stream. Electrolysis is performed on the water stream to produce an oxygen stream and a second hydrogen stream. Iron ore is reduced by flowing hydrogen over the iron ore to produce iron. Iron is combined with a first portion of the carbon in the carbon stream to produce steel. At least a portion of the oxygen in the oxygen stream is combined with a second portion of the carbon in the carbon stream to produce power and a carbon dioxide stream.

Description

Technical Field

[0001] Claim of Priority This application claims the priority of U.S. Patent Application No. 17 / 731,062, filed on April 27, 2022, the entire content of which is incorporated herein by reference.

[0002] The present disclosure relates to the simultaneous production of hydrogen, carbon, and electricity for steel manufacturing.

Background Art

[0003] Carbon is an element that is abundantly present in the Earth's crust. Carbon functions as an element common to all known life due to its abundance, diversity in the formation of organic compounds, and ability to form polymers at temperatures commonly experienced on Earth. Carbon atoms bond in many ways to form various allotropes of carbon. Examples of carbon allotropes include graphite, diamond, amorphous carbon, carbon nanotubes, carbon fibers, and fullerenes. The physical properties of carbon vary greatly depending on the allotropic form. Therefore, carbon is widely used across various markets on a commercial or near-commercial scale.

[0004] Hydrogen is the lightest element. Under standard conditions, hydrogen is a gas of diatomic molecules, which is colorless, odorless, tasteless, non-toxic, and flammable. Hydrogen is the most abundant chemical substance in the universe. Most of the hydrogen on Earth exists in molecular form in water and organic compounds (such as hydrocarbons). Examples of the use of hydrogen include the treatment of fossil fuels (e.g., hydrocracking) and the production of ammonia.

[0005] As a global effort to reduce carbon dioxide emissions, there is an increasing interest in the energy conversion from fossil fuels to renewable energy or sustainable energy. Examples of decarbonization pathways in energy conversion to renewable energy include improving energy efficiency, manufacturing and / or using low-carbon fuels, and carbon dioxide capture and storage (CCS).

Summary of the Invention

[0006] This disclosure describes a technique related to the simultaneous production of hydrogen, carbon, electricity, and steel with isolated and prepared carbon dioxide. Specific aspects of the described subject matter can be implemented as a method. A hydrocarbon feed stream is exposed to heat in the absence of oxygen, and the hydrocarbon feed stream is converted into a solid stream and a gas stream. The hydrocarbon feed stream contains hydrocarbons. The solid stream contains carbon. The gas stream contains hydrogen. The gas stream is separated into an exhaust gas stream and a first hydrogen stream. The first hydrogen stream contains at least a portion of the hydrogen from the gas stream. Carbon is separated from the solid stream to produce a carbon stream. Electrolysis is performed on a water stream to produce an oxygen stream and a second hydrogen stream. The water stream contains water. The oxygen stream contains oxygen. The second hydrogen stream contains hydrogen. Iron ore is reduced to produce iron by flowing at least one of A) at least a portion of the first hydrogen stream or B) at least a portion of the second hydrogen stream over the iron ore. Iron is combined with a first portion of the carbon in the carbon stream to produce steel. At least a portion of the oxygen in the oxygen stream is combined with a second portion of the carbon in the carbon stream to generate electricity and a carbon dioxide stream. The carbon dioxide stream contains carbon dioxide. A first portion of the generated electricity is used to perform electrolysis on the water stream. A second portion of the generated electricity is used to reduce the iron ore. A third portion of the generated electricity is used to produce steel.

[0007] This aspect and other aspects can include one or more of the following features. The hydrocarbon feed stream can include a plurality of hydrocarbons selected from C1-C22 alkanes. The hydrocarbon feed stream can include hydrogen. Oxygen and carbon can be combined by a direct carbon fuel cell (DCFC) that includes a solid oxide. Oxygen and carbon can be combined by a direct carbon fuel cell at an operating temperature in the range of about 800°C to about 1000°C. Heat can be transferred from the gas stream to a buffer fluid by a first waste heat recovery heat exchanger. Before exposing the hydrocarbon feed stream to heat in the absence of oxygen, heat can be transferred from the buffer fluid to the hydrocarbon feed stream by a second waste heat recovery heat exchanger. Electric power can be generated by a Rankine cycle using heat transferred from the gas stream to the buffer stream. Power generation by the Rankine cycle can include transferring heat from the buffer fluid to a working fluid in a boiler to vaporize the working fluid into a vaporized working fluid. Power generation by the Rankine cycle can include flowing the vaporized working fluid through a turbine to expand and generate power. Power generation by the Rankine cycle can include condensing the vaporized working fluid into a condensed working fluid. Power generation by the Rankine cycle can include circulating the condensed working fluid back to the boiler. Heat can be transferred from the carbon dioxide stream to the buffer fluid by a first waste heat recovery heat exchanger. Before exposing the hydrocarbon feed stream to heat in the absence of oxygen, heat can be transferred from the buffer fluid to the hydrocarbon feed stream by a second waste heat recovery heat exchanger. The carbon dioxide stream generated by the direct carbon fuel cell can be sequestered within an underground formation and the carbon dioxide stream is not released into the atmosphere.

[0008] Certain aspects of the subject matter described can be implemented as a system. The system includes a hydrocarbon feed stream, a pyrolysis chamber, a gas separation unit, a carbon separation unit, a water stream, an electrolysis unit, an iron ore reduction unit, a steel manufacturing unit, and a power generation unit. The hydrocarbon feed stream contains hydrocarbons. The pyrolysis chamber is configured to receive the hydrocarbon feed stream and expose the hydrocarbon feed stream to heat in the absence of oxygen to convert the hydrocarbon feed stream into a solid stream and a gas stream. The solid stream contains carbon. The gas stream contains hydrogen. The gas separation unit is configured to receive the gas stream from the pyrolysis chamber and separate hydrogen from the gas stream to produce an exhaust gas stream and a first hydrogen stream. The first hydrogen stream contains at least a portion of the hydrogen from the gas stream. The carbon separation unit is configured to receive the solid stream from the pyrolysis chamber and separate carbon from the solid stream to produce a carbon stream. The water stream contains water. The electrolysis unit is configured to receive the water stream and power. The electrolysis unit is configured to perform electrolysis of the water stream using the power to produce an oxygen stream and a second hydrogen stream. The oxygen stream contains oxygen. The second hydrogen stream contains hydrogen. The iron ore reduction unit is configured to receive at least a portion of the first hydrogen stream from the gas separation unit, at least a portion of the second hydrogen stream from the electrolysis unit, and iron ore. The iron ore reduction unit is configured to flow a portion of the first hydrogen stream and a portion of the second hydrogen stream over the iron ore to reduce the iron ore and produce iron. The steel manufacturing unit is configured to receive the iron from the iron ore reduction unit and a first portion of the carbon stream from the carbon separation unit. The steel manufacturing unit is configured to combine the iron and the first portion of the carbon stream to produce steel. The power generation unit is configured to receive at least a portion of the oxygen stream from the electrolysis unit and a second portion of the carbon stream from the carbon separation unit. The power generation unit includes a direct carbon fuel cell.A direct carbon fuel cell is configured to combine oxygen from a portion of an oxygen stream with carbon from a portion of a carbon stream to produce power and a carbon dioxide stream. The carbon dioxide stream contains carbon dioxide. A first portion of the power generated by the power generation unit is supplied to an electrolysis unit where electrolysis of a water stream is performed. A second portion of the power generated by the power generation unit is supplied to an iron ore reduction unit to reduce iron ore. A third portion of the power generated by the power generation unit is supplied to a steel manufacturing unit to manufacture steel.

[0009] This and other embodiments can include one or more of the following features: The hydrocarbon feed stream can include a plurality of hydrocarbons selected from C1-C22 alkanes. The hydrocarbon feed stream can include hydrogen. The direct carbon fuel cell can include a solid oxide electrolyte configured to operate at a temperature in a range of about 800° C. to about 1000° C. The system can include a first waste heat recovery heat exchanger. The first waste heat recovery heat exchanger can be in fluid communication with a gas stream exiting the pyrolysis chamber. The first waste heat recovery heat exchanger can be in fluid communication with a buffer fluid. The first waste heat recovery heat exchanger can be configured to transfer heat from the gas stream to the buffer fluid. The system can include a second waste heat recovery heat exchanger. The second waste heat recovery heat exchanger can be in fluid communication with the hydrocarbon feed stream entering the pyrolysis chamber. The second waste heat recovery heat exchanger can be in fluid communication with the buffer fluid. The second waste heat recovery heat exchanger can be configured to transfer heat from the buffer fluid to the hydrocarbon feed stream before the hydrocarbon feed stream enters the pyrolysis chamber. The system can include a Rankine cycle configured to generate electrical power using heat transferred from the gas stream to a buffer fluid. The Rankine cycle can include a boiler configured to receive a working fluid and a buffer fluid. The boiler can be configured to transfer heat from the buffer fluid to the working fluid to vaporize the working fluid into a vaporized working fluid. The Rankine cycle can include a turbine configured to receive the vaporized working fluid and generate electrical power when the vaporized working fluid flows through the turbine and expands. The Rankine cycle can include a condenser configured to receive and condense the vaporized working fluid into a condensed working fluid. The Rankine cycle can include a pump configured to circulate the condensed working fluid to the boiler. The system can include a first waste heat recovery heat exchanger. The first waste heat recovery heat exchanger can be in fluid communication with a carbon dioxide stream exiting the power generation unit. The first waste heat recovery heat exchanger can be in fluid communication with the buffer fluid. The first waste heat recovery heat exchanger can be configured to transfer heat from the carbon dioxide stream to the buffer fluid.The system can include a second waste heat recovery heat exchanger. The second waste heat recovery heat exchanger can be in fluid communication with the hydrocarbon feed stream entering the pyrolysis chamber. The second waste heat recovery heat exchanger can be in fluid communication with a buffer fluid. The second waste heat recovery heat exchanger can be configured to transfer heat from the buffer fluid to the hydrocarbon feed stream before the hydrocarbon feed stream enters the pyrolysis chamber. The pyrolysis chamber can include a catalyst. The catalyst can include at least one of activated carbon, carbon black, cobalt, iron, copper, and nickel.

[0010] The details of one or more implementations of the subject matter of this disclosure are set forth in the accompanying drawings and the specification. Other features, aspects, and advantages of the subject matter will become apparent from the specification, drawings, and claims. [Brief description of the drawings]

[0011]

Figure 1A

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Figure 1B

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Figure 1C

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Figure 1D

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Figure 1E

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Figure 2

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Figure 3

[0022] This disclosure describes a system for the simultaneous production of hydrogen, oxygen, carbon, carbon dioxide, electricity, and steel. The two main feeds to the system include a hydrocarbon stream and a water stream. In some implementations, renewable electricity and / or electricity from the grid is used as needed. The hydrocarbon stream is pyrolyzed to produce carbon and hydrogen. The water stream is split by electrolysis to produce oxygen and hydrogen. Electricity can be produced by (i) burning carbon in the presence of oxygen (obtained from electrolysis of the water stream) to generate heat and using the heat to generate steam for a steam turbine, (ii) using a direct carbon fuel cell (DCFC) to combine carbon (obtained from pyrolysis of the hydrocarbon stream) and oxygen (obtained from electrolysis of the water stream), or both (i) and (ii). At least a portion of the produced hydrogen is used to reduce iron ore. At least a portion of the carbon is added to the reduced iron to produce steel. In some implementations, waste heat recovery is implemented for process integration and efficiency optimization. The carbon dioxide produced by the system is sequestration-ready in that it is ready to be transported (e.g., by pipeline) for sequestration in a subsurface region of the Earth, as opposed to being released into the atmosphere and contributing to carbon dioxide emissions.

[0023] The subject matter described in this disclosure can be implemented in certain implementations that achieve one or more of the following advantages: Carbon dioxide, which may be produced as a by-product, can be sequestered and / or used in another industrial process, rather than being released into the atmosphere. The system is flexible in that it can accept a variety of feedstocks, such as traditional hydrocarbons (e.g., natural gas, crude oil, and / or their derivatives), biogas, bioliquid fuels, or oil waste. The system described herein can be implemented to utilize excess solid carbon products resulting from pyrolysis that are typically difficult to put into the carbon market, while also addressing the intermittency of renewable energy sources. For example, a portion of the carbon produced by the system can be used as an energy storage medium, and another portion of the carbon produced by the system can be sold in the market as a feedstock for another industrial process. For example, the carbon produced by the system can be used to form carbon black, synthetic graphite, carbon filaments / fibers, and / or carbon nanostructures (such as carbon nanotubes and carbon nanofibers). For example, at least a portion of the carbon produced by the system can be used to produce steel.

[0024] FIG. 1A is a schematic diagram of an example hydrogen, carbon, and electricity co-production system 100 for steel production. System 100 includes a hydrocarbon feed stream 101. Hydrocarbon feed stream 101 includes hydrocarbons (e.g., alkanes, alkenes, alkynes, cyclic hydrocarbons, aromatic hydrocarbons, and / or non-aromatic hydrocarbons). In some implementations, hydrocarbon feed stream 101 includes a plurality of hydrocarbons selected from C1-C22 alkanes (i.e., alkanes having a number of carbon atoms ranging from 1 to 22). In some implementations, hydrocarbon feed stream 101 includes components other than hydrocarbons, such as hydrogen. However, hydrocarbon feed stream 101 does not include oxygen-containing components. System 100 includes a feed stream that ... 2 O).

[0025] The system 100 includes a pyrolysis chamber 110, a gas separation unit 120, a carbon separation unit 130, an electrolysis unit 140, a power generation unit 150, an iron ore reduction unit 170A, and a steel production unit 170B. The pyrolysis chamber 110 is configured to receive a hydrocarbon feed stream 101. The pyrolysis chamber 110 is configured to expose the hydrocarbon feed stream 101 to heat in the absence of oxygen to convert the hydrocarbon feed stream 101 into a solid stream 105 and a gas stream 107. In some implementations, depending on the composition of the hydrocarbon feed stream 101, the pyrolysis chamber 110 may produce liquids (e.g., bio-oil) exiting the pyrolysis chamber 110 along with the solid stream 105. The solid stream 105 includes carbon. The gas stream 107 includes hydrogen. In some implementations, the gas stream 107 includes carbon (e.g., small particles entrained in the gas stream 107), unconverted hydrocarbons from the hydrocarbon feed stream 101, or both.

[0026] The gas separation unit 120 is configured to receive the gas stream 107 from the pyrolysis chamber 110. The gas separation unit 120 is configured to separate hydrogen from the gas stream 107 to produce an exhaust gas stream 109 and a first hydrogen stream 111. The first hydrogen stream 111 includes at least a portion of the hydrogen from the gas stream 107. In some implementations, the first hydrogen stream 111 includes substantially all of the hydrogen from the gas stream 107. In some implementations, the exhaust gas stream 109 is the remainder of the gas stream 107 excluding the first hydrogen stream 111. For example, the exhaust gas stream 109 may include a relatively small amount of hydrogen from the gas stream 107 compared to the first hydrogen stream 111. In some implementations, at least a portion of the exhaust gas stream 109 is recycled to the pyrolysis chamber 110 because the exhaust gas stream 109 may include unconverted hydrocarbons from the hydrocarbon feed stream 101. In some implementations, at least a portion of the first hydrogen stream 111 is stored and / or transported for use in other industrial processes, such as ammonia production, power generation, feedstock for hydrogen fuel cells, hydrocarbon sweetening processes, oil refining, metal processing (e.g., steel production), fertilizer production, and food processing.

[0027] The carbon separation unit 130 is configured to receive the solids stream 105 from the pyrolysis chamber 110. The carbon separation unit 130 is configured to separate carbon from the solids stream 105 to produce a carbon stream 113. For example, if the solids stream 105 includes a liquid, the carbon separation unit 130 separates the carbon from the liquid to produce a carbon stream 113. The carbon stream 113 may include carbon black, carbide, synthetic graphite, carbon filaments / fibers, carbon nanostructures (such as carbon nanotubes and carbon nanofibers), or any combination thereof. In some implementations, at least a portion of the carbon stream 113 is stored and / or transported for use in another industrial process, such as power generation, carbon black production, carbide production, synthetic graphite production, carbon filament / fiber production, and carbon nanostructure (e.g., carbon nanotubes and carbon nanofiber) production. In some implementations, at least a portion of the carbon stream 113 is sold to an external market.

[0028] The electrolysis unit 140 is configured to receive the water stream 103 and electrical power. The electrolysis unit 140 is configured to use the received electrical power to perform electrolysis of the water stream 103 to produce an oxygen stream 115 and a second hydrogen stream 117. The oxygen stream 115 comprises oxygen. At least a portion of the oxygen stream 115 (e.g., all of the oxygen stream 115) is passed to the power generation unit 150 to produce electrical power. In some implementations, at least a portion of the oxygen stream 115 is stored and / or transported for use in another industrial process, such as fuel combustion or power generation. The second hydrogen stream 117 comprises hydrogen. In some implementations, at least a portion of the second hydrogen stream 117 is stored and / or transported for use in other industrial processes, such as ammonia production, power generation, feedstock for hydrogen fuel cells, hydrocarbon sweetening processes, petroleum refining, metal processing (e.g., steel production), fertilizer production, and food processing. In some implementations, at least a portion of the first hydrogen stream 111 and at least a portion of the second hydrogen stream 117 are combined, stored, and / or transported for use in another industrial process, such as ammonia production, power generation, feedstock for hydrogen fuel cells, hydrocarbon sweetening processes, oil refining, metal processing (e.g., steel production), fertilizer production, and food processing. The electrolysis unit 140 can be configured to receive power from a variety of power sources. For example, the electrolysis unit 140 can be configured to receive power from a renewable energy source. For example, the electrolysis unit 140 can be configured to receive power from a power grid. For example, the electrolysis unit 140 can be configured to receive power from the power generation unit 150. For example, the electrolysis unit 140 can be configured to receive power from a Rankine cycle (an example is shown in FIG. 2 and described in more detail below). The electrolysis unit 140 can be configured to switch between power sources based on the available power from the various power sources and the power demand.

[0029] The power generation unit 150 is configured to receive at least a portion of the oxygen stream 115 from the electrolysis unit 140 (e.g., most or all of the oxygen stream 115) and at least a portion of the carbon stream 113 from the carbon separation unit 130. The power generation unit 150 includes a direct carbon fuel cell 151. The direct carbon fuel cell 151 is configured to combine oxygen from a portion (or all) of the oxygen stream 115 and carbon from a portion (or all) of the carbon stream 113 to generate electrical power and a carbon dioxide stream 119. The carbon dioxide stream 119 includes carbon dioxide. The carbon dioxide stream 119 generated by the direct carbon fuel cell 151 is a high purity carbon dioxide stream. For example, the carbon dioxide stream 119 includes at least 99 percent by volume (Vol.%) or at least 99.9 Vol.% carbon dioxide. For example, the carbon dioxide stream 119 is pure carbon dioxide. At least a portion of the electrical power generated by the power generation unit 150 is supplied to the electrolysis unit 140 to perform electrolysis of the water stream 103. In some implementations, at least a portion of the carbon dioxide stream 119 (e.g., most or all of the carbon dioxide stream 119) is transported (e.g., via a pipeline) and sequestered, for example, in a subsurface region of the earth. The subsurface region may be a geological formation within the earth that defines a reservoir, while in other cases the subsurface region may be a geological formation or a portion of a formation. The subsurface region may include, for example, a formation, a portion of a formation, or multiple formations within a reservoir. In some implementations, the subsurface region includes a subsurface formation of naturally fractured or porous rock. In some implementations, the subsurface region may intersect with other types of formations, including reservoirs that are not naturally fractured. In some implementations, at least a portion of the carbon dioxide stream 119 is stored and / or transported for use in another industrial process, such as cement production. In some implementations, at least a portion of the carbon dioxide stream 119 is injected into a subsurface formation, for example, to facilitate the recovery of hydrocarbons from the subsurface formation. The carbon dioxide stream 119 is not released into the atmosphere and therefore does not contribute to greenhouse gas emissions.

[0030] The power generation unit 150 may include additional and / or alternative components aside from the direct carbon fuel cell 151 for generating electrical power. In some implementations, the power generation unit 150 includes a combustion chamber (not shown) in which carbon (fuel) from some (or all) of the carbon stream 113 is combusted in the presence of oxygen (oxidant) from some (or all) of the oxygen stream 115. In such implementations, heat is provided to the combustion chamber to combust the carbon. The heat from the combustion may be used in a Rankine cycle (e.g., including a turbine) to generate electrical power (an example is shown in FIG. 2 and described in more detail below).

[0031] The iron ore reduction unit 170A is configured to receive A) at least a portion of the first hydrogen stream 111 from the gas separation unit 120, B) at least a portion of the second hydrogen stream 117 from the electrolysis unit 140, or both A) and B). The iron ore reduction unit 170A is configured to flow A), B), or both A) and B) over the iron ore. Iron ore contains oxygen and iron bonded in molecular form. Examples of rocks and minerals that make up iron ore include magnetite (Fe 3 O 4 ), hematite (Fe 2 O 3 ), goethite (FeO(OH)), limonite (FeO(OH)n(H 2 O), siderite (FeCO 3 ) In some cases, iron ore contains other additional trace minerals besides iron. The iron oxides present in the iron ore can be reduced to produce metallic iron (Fe). Hydrogen in A), B), or both A) and B) undergoes a redox reaction with the iron oxide. The reduction of the iron oxide can produce iron 171b and water in the form of steam. In contrast to conventional methods that use carbon from coke as a reducing agent, the iron ore reduction unit 170A does not require the iron ore to be melted because it uses hydrogen as a reducing agent.

[0032] The steel production unit 170B is configured to receive the iron 171b from the iron ore reduction unit 170A and at least a portion of the carbon stream 113 from the carbon separation unit 130. The steel production unit 170B is configured to combine the iron 171b with carbon from a portion of the carbon stream 113 to produce steel 173. Steel is an alloy of iron with carbon. Carbon, and possibly other elements (such as chromium depending on the desired properties of the formed steel), can be introduced into the iron to enhance the properties of the formed steel. Steel can be produced, for example, by a blast furnace or an electric arc furnace. In a conventional process, metallurgical coke is used to alloy the steel with carbon to give the steel the strength required for its intended use. The carbon content in steel typically does not exceed 1.5% by weight, but in some cases can reach 4% by weight. Increasing the carbon content in steel can increase the strength of the steel, but typically makes the steel more brittle and less ductile. To produce steel, iron and coke (carbon) are heated to high temperatures to melt the iron and alloy it with carbon. In some cases, oxygen is introduced to combine with impurities to form oxides that can be removed as a gas, liquid, or solid. The operating conditions of the steel production unit 170B can be adjusted to optimize the production of steel 173. For example, the steel production unit 170B can include a heater. The heater can be configured to generate heat within the steel production unit 170B such that an operating temperature at which the iron 171b and carbon combine within the steel production unit 170B ranges from about 1000° C. to about 1600° C. The operating temperature of the steel production unit 170B is sufficient to melt the iron 171b such that the iron 171b can combine with the carbon. The heater can be, for example, a gas burner, or an electric heater including an electric resistor. If the heater includes an electric resistor (electric heater), the heater can be powered to generate heat within the steel production unit 170B. In some implementations, at least a portion of the electricity generated by power generation unit 150 is provided to steel production unit 170B to generate heat for combining iron 171b with carbon to produce steel 173.

[0033] In some implementations, at least a portion of the power generated by the power generation unit 150 is used by another component of the system 100. For example, at least a portion of the power generated by the power generation unit 150 can be provided to the electrolysis unit 140 to perform electrolysis of the water stream 103. For example, at least a portion of the power generated by the power generation unit 150 can be used to provide heat to the pyrolysis chamber 110 to perform pyrolysis of the hydrocarbon feed stream 101. In some implementations, at least a portion of the power generated by the power generation unit 150 is provided to another user. For example, at least a portion of the power generated by the power generation unit 150 can be used in another industrial process. For example, at least a portion of the power generated by the power generation unit 150 can be exported to a power grid where it can be stored and / or distributed to various users.

[0034] In some implementations, the system 100 includes a power distribution unit 160. The power distribution unit 160 can receive power from various power sources. For example, the power distribution unit 160 can connect to a power grid and receive power therefrom. For example, the power distribution unit 160 can connect to a renewable energy source (such as wind energy or solar energy) and receive power therefrom. For example, the power distribution unit 160 can connect to a power generation unit 150 and receive power therefrom. For example, the power distribution unit 160 can connect to a Rankine cycle and receive power therefrom (e.g., from a turbine in the Rankine cycle). The power distribution unit 160 can distribute power to various users. For example, the power distribution unit 160 can connect to the electrolysis unit 140 and provide power to the electrolysis unit 140. For example, the power distribution unit 160 can connect to the pyrolysis chamber 110 and provide power to the pyrolysis chamber 110. For example, the power distribution unit 160 can connect to a power grid and provide power to the power grid. For example, the power distribution unit 160 may be coupled to a Rankine cycle and provide power to the Rankine cycle (eg, to a pump within the Rankine cycle).

[0035] FIG. 1B is a schematic diagram of an example of a pyrolysis chamber 110. In some implementations, as shown in FIG. 1B, the pyrolysis chamber 110 includes a catalyst 110a. The catalyst 110a can include at least one of activated carbon, carbon black, cobalt, iron, copper, and nickel. The operating pressure in the pyrolysis chamber 110 can be substantially atmospheric pressure (about 1 atm). The pyrolysis chamber 110 includes a heater 110b. When the pyrolysis chamber 110 is a plasma pyrolysis reactor, the heater 110b includes electrodes and the pyrolysis chamber 110 is supplied with an inert gas along with the hydrocarbon feed stream 101. The electrodes of the heater 110b can be powered, and the inert gas serves as a working gas to produce a plasma to pyrolyze the hydrocarbon feed stream 101. When the pyrolysis chamber 110 is a catalytic or non-catalytic reactor, the heater 110b provides heat indirectly by a mechanism that generates radiant heat. For example, the heater 110b can be a gas burner or an electric heater including an electric resistor. When heater 110b includes electrodes (plasma reactor) or electrical resistors (electrical heater), electrical power is supplied to heater 110b to generate heat within pyrolysis chamber 110.

[0036] FIG. 1C is a schematic diagram of examples of components that may be included in the gas separation unit 120. The gas separation unit 120 may include gravity settling chambers, cyclones, baghouse filters, microfilters, pressure swing adsorption beds, temperature swing adsorption beds, dense membranes, or any combination thereof. As previously described, the gas separation unit 120 separates the gas stream 107 into an exhaust gas stream 109 and a first hydrogen stream 111. The first hydrogen stream 111 includes at least a majority of the hydrogen from the gas stream 107, and the exhaust gas stream 109 includes the remainder of the gas stream 107. As such, the gas separation unit 120 is primarily used to extract hydrogen from the gas stream 107. The hydrogen may be extracted from the gas stream 107 using a pressure swing adsorption bed, a temperature swing adsorption bed, a dense membrane, or any combination thereof. In some cases, the gas stream 107 may include some solid particles (e.g., solid carbon particles entrained in the gas stream 107). In such cases, gravity settling chambers, cyclones, baghouse filters, microfilters, or any combination thereof may be used to remove solids from gas stream 107. The components included in gas separation unit 120 are configured to operate within the expected operating range (operating pressure and temperature range) of gas stream 107 plus a design margin (e.g., ±5%, ±10%, ±15%, ±20%, ±25%, or ±30%). In some implementations, gas stream 107 is cooled prior to entering gas separation unit 120.

[0037] Figure 1C shows examples of a gravity settling chamber, a cyclone, a baghouse filter, a pair of pressure swing adsorption beds, and a high density membrane. In the gravity settling chamber and / or the cyclone, the outlet velocity of the gas stream 107 may be less than 300 centimeters per second (cm / s). For example, the outlet velocity of the gas stream 107 exiting the gravity settling chamber may be about 275 cm / s, about 250 cm / s, about 225 cm / s, about 200 cm / s, about 175 cm / s, about 150 cm / s, about 125 cm / s, about 100 cm / s, about 90 cm / s, about 80 cm / s, about 70 cm / s, about 60 cm / s, about 50 cm / s, about 40 cm / s, about 30 cm / s, about 20 cm / s, about 10 cm / s, or about 5 cm / s. In some implementations, it is preferred that the outlet velocity of the gas stream 107 exiting the gravity settling chamber is less than 30 cm / s. In some implementations, the gravity settling chamber and / or the cyclone are configured to remove solid particles having an average or maximum particle size in the range of about 10 microns to about 50 microns from the gas stream 107. The density of the solid particles may also be a factor in separating the solid particles from the gas stream 107. In the pressure swing adsorption bed, the extraction of hydrogen from the gas stream 107 depends on various factors such as the pressure difference between the bed and the absorbent material. As shown in Figure 1C, in the case of the pressure swing adsorption bed, there are at least two containers that swing over a range of pressures. During the adsorption process, a fluid (e.g., the gas stream 107) passes through the bed in a first direction and hydrogen is adsorbed onto the bed to produce an exhaust gas stream 109. During the desorption process, the fluid passes through the bed in a second direction and hydrogen is desorbed from the bed to produce a first hydrogen stream 111.

[0038] 1D is a schematic diagram of examples of components that may be included in the carbon separation unit 130. The carbon separation unit 130 may include a gravity settling chamber, a cyclone, a baghouse filter, a microfilter, a centrifuge, a wet collector, electrostatic separation, an acid flux process, or any combination thereof. As previously described, the carbon separation unit 130 separates carbon from the solids stream 105 to produce the carbon stream 113. As such, the carbon separation unit 130 is primarily used to extract carbon from the solids stream 105. The components included in the carbon separation unit 130 are configured to operate within the expected operating range (operating pressure and temperature range) of the solids stream 105 plus a design margin (e.g., ±5%, ±10%, ±15%, ±20%, ±25%, or ±30%).

[0039] FIG. 1D shows examples of a gravity settling chamber, a cyclone, a baghouse filter, and a centrifuge. In the gravity settling chamber and / or the cyclone, the exit velocity of the solid stream 105 may be less than 300 centimeters per second (cm / s). For example, the exit velocity of the solid stream 105 exiting the gravity settling chamber may be about 275 cm / s, about 250 cm / s, about 225 cm / s, about 200 cm / s, about 175 cm / s, about 150 cm / s, about 125 cm / s, about 100 cm / s, about 90 cm / s, about 80 cm / s, about 70 cm / s, about 60 cm / s, about 50 cm / s, about 40 cm / s, about 30 cm / s, about 20 cm / s, about 10 cm / s, or about 5 cm / s. In some implementations, it is preferable that the exit velocity of the solid stream 105 exiting the gravity settling chamber is less than 30 cm / s. In some implementations, the gravity settling chamber and / or the cyclone are configured to remove solid particles having an average or maximum particle size in the range of about 10 microns to about 50 microns from the solid stream 105. Carbon particles with smaller particle sizes may be more commercially valuable than carbon particles with larger particle sizes, so smaller particle sizes may be desired for sale in the external market. In such cases, the larger-sized carbon particles may be used, for example, for power generation. The density of the solid particles may also be a factor when separating the solid particles from the solid stream 105. In a centrifuge, the rotational speed depends on the desired size of the carbon particles removed from the solid stream 105. For example, the rotational speed of the centrifuge can range from about 1,500 revolutions per minute (rpm) to about 50,000 rpm. In some cases, the rotational speed of the centrifuge may exceed 50,000 rpm.

[0040] Figure 1E is a schematic diagram of an example of the electrolysis unit 140. The example of the electrolysis unit 140 shown in Figure 1E is a polymer electrolyte membrane (PEM) electrolysis unit, but different types of electrolysis units such as an alkaline water electrolysis unit, a solid oxide electrolysis unit, or an anion exchange membrane (AEM) electrolysis unit may be alternatively or additionally used. The PEM electrolysis unit 140 includes an anode 140a, a cathode 140b, and a proton exchange membrane 140c. The proton exchange membrane 140c is a solid polymer electrolyte membrane that conducts protons from the anode 140a to the cathode 140b while electrically insulating the electrodes (140a, 140b). The half-reaction occurring on the anode 140a side is also called an oxygen evolution reaction (Equation 1). 2H 2 O→O 2 +4H + +4e - (1) The half-reaction occurring on the cathode 140b side is also called a hydrogen evolution reaction (Equation 2). 4H + +4e - →2H 2 (2)

[0041] The water stream 103 enters the PEM electrolysis unit 140. The PEM electrolysis unit 140 decomposes water into hydrogen and oxygen. The generated hydrogen and oxygen are separated. For example, the membrane is permeable to hydrogen, and hydrogen can pass through the membrane and be separated from oxygen, and oxygen remains on the opposite side of the membrane. The oxygen stream 115 exits the PEM electrolysis unit 140 from the anode 140a side, and the second hydrogen stream 117 exits the PEM electrolysis unit 140 from the cathode 140b side.

[0042] The open-circuit voltage of the electrolysis unit 140 during operation can be in the range of about 1.2 volts (V) to about 2.5 V. Depending on the implementation, the operating temperature of the PEM electrolysis unit 140 is in the range of about 50°C to about 80°C. Depending on the implementation, the operating pressure of the PEM electrolysis unit 140 is less than about 70 bar. Depending on the implementation, the current density of the power supplied to the PEM electrolysis unit 140 is from about 1 ampere per square centimeter (A / cm 2 ) to about 6 A / cm 2 .

[0043] When the electrolysis unit 140 is an alkaline water electrolysis unit, the open-circuit voltage of the electrolysis unit 140 during operation can be in the range of about 1.2 V to about 3 V. Depending on the implementation, the operating temperature of the alkaline water electrolysis unit 140 is in the range of about 70°C to about 90°C. Depending on the implementation, the operating pressure of the alkaline water electrolysis unit 140 is less than about 70 bar. Depending on the implementation, the current density of the power supplied to the alkaline water electrolysis unit 140 is from about 0.2 A / cm 2 to about 6 A / cm 2 .

[0044] When the electrolysis unit 140 is a solid oxide electrolysis unit, the open-circuit voltage of the electrolysis unit 140 during operation can be in the range of about 1 V to about 1.5 V. Depending on the implementation, the operating temperature of the solid oxide electrolysis unit 140 is in the range of about 700°C to about 850°C. Depending on the implementation, the operating pressure of the solid oxide electrolysis unit 140 is less than about 30 bar. Depending on the implementation, the current density of the power supplied to the solid oxide electrolysis unit 140 is from about 0.3 A / cm 2 to about 6 A / cm 2 .

[0045] When the electrolysis unit 140 is an AEM electrolysis unit, the open circuit voltage of the operating electrolysis unit 140 can be in the range of about 1.2 V to about 2 V. Depending on the implementation, the operating temperature of the AEM electrolysis unit 140 is in the range of about 40°C to about 80°C. Depending on the implementation, the operating pressure of the AEM electrolysis unit 140 is less than about 70 bar. Depending on the implementation, the current density of the power supplied to the AEM electrolysis unit 140 is from about 0.2 A / cm 2 to about 6 A / cm 2 range.

[0046] Figure 1F is a schematic diagram of an example of a direct carbon fuel cell 151. The example of the direct carbon fuel cell 151 shown in Figure 1F includes a solid oxide electrolyte 152, but different types of electrolytes such as molten salts (e.g., hydroxide salts), molten carbonates, and molten tin anodes may be used alternatively or additionally. Oxygen from the oxygen stream 115 flows into the direct carbon fuel cell 151, and carbon from the carbon stream 113 flows into the direct carbon fuel cell 151. The direct carbon fuel cell 151 combines oxygen and carbon to generate carbon dioxide and electricity. The carbon dioxide stream 119 flows out of the direct carbon fuel cell 151. Depending on the implementation, the solid oxide electrolyte 152 is zirconium oxide (ZrO 2 ). Depending on the implementation, oxides such as yttrium oxide (Y 2 O 3 ) or scandium(III) oxide (Sc 2 O 3 ) are added to the solid oxide electrolyte 152. The solid oxide electrolyte 152 can be configured to combine carbon and oxygen at an operating temperature in the range of about 550°C to about 1000°C, about 600°C to about 1000°C, about 650°C to about 1000°C, about 700°C to about 1000°C, about 750°C to about 1000°C, about 800°C to about 1000°C, about 850°C to about 1000°C, about 900°C to about 1000°C, or about 950°C to about 1000°C to generate electricity and carbon dioxide.

[0047] When the direct carbon fuel cell 151 includes a molten salt electrolyte (e.g., potassium hydroxide or sodium hydroxide), the direct carbon fuel cell 151 can be configured to combine carbon and oxygen at an operating temperature in the range of about 500°C to about 600°C to produce electricity and carbon dioxide. When the direct carbon fuel cell 151 includes a molten carbonate electrolyte (e.g., including lithium, sodium, or potassium), the direct carbon fuel cell 151 can be configured to combine carbon and oxygen at an operating temperature in the range of about 750°C to about 800°C to produce electricity and carbon dioxide. When the direct carbon fuel cell 151 includes a molten tin anode, the direct carbon fuel cell 151 can be configured to combine carbon and oxygen at an operating temperature of about 900°C to produce electricity and carbon dioxide.

[0048] FIG. 1G is a schematic diagram of an example of a reactor 172 that can be included in the iron ore reduction unit 170A. Iron ore 171a is placed within the reactor 172. The iron ore 171a may be in the form of, for example, pellets and / or granules. The reactor 172 receives A) at least a portion of the first hydrogen stream 111 from the gas separation unit 120, B) at least a portion of the second hydrogen stream 117 from the electrolysis unit 140, or both A) and B). When hydrogen from A), B), or both A) and B) flows over the iron ore 171a, the iron ore 171a is reduced to iron 171b. Water vapor is produced as a byproduct and may exit the reactor 172 along with unreacted hydrogen. Depending on the implementation, the water vapor produced by the iron ore reduction unit 170A may be condensed and recycled, for example, as an additional feed along with the water stream 103 to the electrolysis unit 140 to produce additional hydrogen and oxygen. Depending on the implementation, at least a portion of the unreacted hydrogen from the reactor 172 is recycled to the reactor 172. Depending on the implementation, at least a portion of the unreacted hydrogen from the reactor 172 is stored and / or transported for use in other industrial processes such as ammonia production, power generation, feedstock for hydrogen fuel cells, hydrocarbon sweetening processes, petroleum refining, metal processing (e.g., steel manufacturing), fertilizer manufacturing, and food processing. Depending on the implementation, at least a portion of the unreacted hydrogen from the reactor 172 is combined with at least a portion of the first hydrogen stream 111, at least a portion of the second hydrogen stream 117, or both, and combined, stored, and / or transported for use in another industrial process such as ammonia production, power generation, feedstock for hydrogen fuel cells, hydrocarbon sweetening processes, petroleum refining, metal processing (e.g., steel manufacturing), fertilizer manufacturing, and food processing.

[0049] The operating conditions within the reaction apparatus 172 can be adjusted to optimize the reduction of the iron ore 171a and produce iron 171b. For example, the reaction apparatus 172 can include a heater 172a. The heater 172a can be configured to generate heat within the reaction apparatus 172, such that the operating temperature of the reaction apparatus 172 ranges from about 200°C to about 1000°C, from about 300°C to about 900°C, or from about 400°C to about 800°C. The heater 172a can be, for example, a gas-based burner or an electric heater including an electrical resistor. When the heater 172a includes an electrical resistor (electric heater), power can be supplied to the heater 172a to generate heat within the reaction apparatus 172. In some implementations, at least a portion of the power generated by the power generation unit 150 is supplied to the heater 172a, and heat is generated within the reaction apparatus 172. In some implementations, the operating pressure within the reaction apparatus 172 ranges from atmospheric pressure to about 10 atmospheres.

[0050] FIG. 1H is a schematic diagram of an example of a simultaneous production system 100H for hydrogen, carbon, and electricity that realizes waste heat recovery. System 100H is substantially similar to system 100 shown in FIG. 1A and can include substantially the same components. System 100H includes a first waste heat recovery heat exchanger 190H and a second waste heat recovery heat exchanger 190H'. The first waste heat recovery heat exchanger 190H is in fluid communication with at least a portion of the gas stream 107 exiting the pyrolysis chamber 110 on a first side. The first waste heat recovery heat exchanger 190H is in fluid communication with a buffer fluid on a second side. The first waste heat recovery heat exchanger 190H is configured to transfer heat from a portion (or all) of the gas stream 107 to the buffer fluid. Thus, the gas stream 107 is cooled by the first waste heat recovery heat exchanger 190H before being processed by the gas separation unit 120. The second waste heat recovery heat exchanger 190H' can be in fluid communication with at least a portion of the hydrocarbon supply stream 101 entering the pyrolysis chamber 110 on a first side. The second waste heat recovery heat exchanger 190H' can be in fluid communication with a buffer fluid on a second side. The second waste heat recovery heat exchanger 190H' can be configured to transfer heat from the buffer fluid to a portion (or all) of the hydrocarbon supply stream 101 before the hydrocarbon supply stream 101 enters the pyrolysis chamber 110. Thus, the first and second waste heat recovery heat exchangers 190H, 190H' cooperate to recover heat from the gas stream 107 and use the recovered heat to preheat a portion (or all) of the hydrocarbon supply stream 101 before the hydrocarbon supply stream 101 is pyrolyzed in the pyrolysis chamber 110. The buffer fluid is an intermediate fluid that transfers heat from the gas stream 107 to the hydrocarbon supply stream 101. The buffer fluid can be any suitable fluid capable of transferring heat from the gas stream 107 to the hydrocarbon supply stream 101. For example, the buffer fluid can be an aqueous fluid or an oily fluid (such as a hydrocarbon fluid). For example, the buffer fluid can include supercritical carbon dioxide.

[0051] FIG. 1J is a schematic diagram of an example of a system 100J for simultaneous production of hydrogen, carbon, and electricity to achieve waste heat recovery. System 100J is substantially similar to system 100 shown in FIG. 1A and can include substantially the same components. System 100J includes a first waste heat recovery heat exchanger 190J and a second waste heat recovery heat exchanger 190J'. The first waste heat recovery heat exchanger 190J is in fluid communication, on a first side, with at least a portion of a carbon dioxide stream 119 exiting the power generation unit 150. The first waste heat recovery heat exchanger 190J is in fluid communication with a buffer fluid on a second side. The first waste heat recovery heat exchanger 190J is configured to transfer heat from a portion (or all) of the carbon dioxide stream 119 to the buffer fluid. The second waste heat recovery heat exchanger 190J' can be in fluid communication, on a first side, with at least a portion of a hydrocarbon supply stream 101 entering the pyrolysis chamber 110. The second waste heat recovery heat exchanger 190J' can be in fluid communication with the buffer fluid on a second side. The second waste heat recovery heat exchanger 190J' can be configured to transfer heat from the buffer fluid to a portion (or all) of the hydrocarbon supply stream 101 before the hydrocarbon supply stream 101 enters the pyrolysis chamber 110. Thus, the first and second waste heat recovery heat exchangers 190J, 190J' cooperate to recover heat from the gas stream 107 and use the recovered heat to preheat a portion (or all) of the hydrocarbon supply stream 101 before the hydrocarbon supply stream 101 is pyrolyzed in the pyrolysis chamber 110. The buffer fluid is an intermediate fluid that transfers heat from the gas stream 107 to the hydrocarbon supply stream 101. The buffer fluid can be any suitable fluid that can transfer heat from the gas stream 107 to the hydrocarbon supply stream 101. For example, the buffer fluid can be an aqueous fluid or an oily fluid (such as a hydrocarbon fluid). FIGS. 1H and 1J show specific examples of where waste heat can be recovered from specific regions within their respective systems, but waste heat recovery can be implemented anywhere where waste heat is generated.

[0052] FIG. 2 is a schematic diagram of an example of a Rankine cycle 200 that generates electric power using heat. Cycle 200 includes a boiler 210, a turbine 220, a condenser 230, and a pump 240. Pump 240 circulates a working fluid 202 through cycle 200. The working fluid 202 changes in temperature and pressure as it flows through cycle 200. As the working fluid 202 flows through cycle 200, a phase change of the working fluid 202 occurs due to the change in temperature and pressure. For clarity, the various states of the working fluid 202 (having various phase compositions) are shown in a form where a letter follows 202 (e.g., 202a and 202b). As the working fluid 202 flows through cycle 200, the overall composition of the working fluid 202 does not change. However, the individual phases (e.g., the gas phase and the liquid phase) can have various compositions based on the operating conditions, heat, and work (thermodynamics).

[0053] The liquid working fluid 202 (202a) enters the boiler 210. The boiler 210 is configured to receive the liquid working fluid 202. The boiler 210 is configured to transfer heat to the working fluid 202 to produce a vaporized working fluid 202b. The vaporized working fluid 202b flows from the boiler 210 to the turbine 220. The turbine 220 is configured to receive the vaporized working fluid 202b. The turbine 220 is configured to generate electric power as the vaporized working fluid 202b expands as it flows through the turbine 220. The vaporized working fluid 202b exiting the turbine 220 has a reduced operating pressure compared to the vaporized working fluid 202b entering the turbine 220. The vaporized working fluid 202b flows from the turbine 220 to the condenser 230. The condenser 230 is configured to receive and condense the vaporized working fluid 202b into a condensed working fluid 202a. The condensed working fluid 202a flows from the condenser 230 to the pump 240. The pump 240 is configured to circulate the condensed working fluid 202a to the boiler 210 to restart cycle 200.

[0054] The heat used by the boiler 210 to vaporize the working fluid 202 can be supplied from various heat sources. In some embodiments, the boiler 210 receives heat from a buffer fluid (e.g., from the first waste heat recovery heat exchanger 190H or 190J). For example, the boiler 210 can be configured to be in fluid communication with the buffer fluid from the first waste heat recovery heat exchanger 190H on a first side and in fluid communication with the working fluid 202 on a second side. For example, the boiler 210 can be configured to be in fluid communication with the buffer fluid from the first waste heat recovery heat exchanger 190J on a first side and in fluid communication with the working fluid 202 on a second side. In some embodiments, the boiler 210 receives heat from the combustion of fuel (e.g., from the combustion of at least a portion of the carbon stream 113 in the presence of oxygen from at least a portion of the oxygen stream 115 in the power generation unit 150).

[0055] In some embodiments, at least a portion of the power generated by the turbine 220 is used by components of the system 100, 100H, or 100J. For example, at least a portion of the power generated by the turbine 220 can be supplied to the electrolysis unit 140 to perform electrolysis of the water stream 103. For example, using at least a portion of the power generated by the turbine 220, heat can be supplied to the pyrolysis chamber 110 to perform pyrolysis of the hydrocarbon feed stream 101. In some embodiments, at least a portion of the power generated by the turbine 220 is supplied to another user. For example, at least a portion of the power generated by the turbine 220 can be used in another industrial process. For example, at least a portion of the power generated by the turbine 220 can be sent to the power grid, where it can be stored and / or distributed to various users. For example, at least a portion of the power generated by the turbine 220 can be supplied to another process within the same facility as one of the systems 100, 100H, or 100J.

[0056] Figure 3 is a flowchart showing an example of a simultaneous production method 300 of hydrogen, carbon, electricity, and separated carbon dioxide for steel manufacturing. Method 300 can be implemented using any of systems 100, 100H, or 100J. A hydrocarbon feed stream (such as hydrocarbon feed stream 101) flows into a pyrolysis chamber (such as pyrolysis chamber 110). In block 302, the hydrocarbon feed stream 101 is exposed to heat in the absence of oxygen (e.g., within pyrolysis chamber 110), converting the hydrocarbon feed stream 101 into a solid stream (such as solid stream 105) and a gas stream (such as gas stream 107). As described above, the solid stream 105 contains carbon and the gas stream 107 contains hydrogen. The gas stream 107 flows from the pyrolysis chamber 110 to a gas separation unit (such as gas separation unit 120). In block 304, the gas stream 107 is separated (e.g., within gas separation unit 120) into an exhaust gas stream (such as exhaust gas stream 109) and a first hydrogen stream (such as first hydrogen stream 111) containing at least a portion of the hydrogen from the gas stream 107. The solid stream 105 flows from the pyrolysis chamber 110 to a carbon separation unit (such as carbon separation unit 130). In block 306, carbon is separated from the solid stream 105 (e.g., within carbon separation unit 130) to produce a carbon stream (such as carbon stream 113). A water stream (such as water stream 103) flows into an electrolysis unit (such as electrolysis unit 140). The electrolysis unit 140 is supplied with power. In block 308, electrolysis is performed on the water stream 103 (e.g., by electrolysis unit 140 in response to receiving power) to produce an oxygen stream (such as oxygen stream 115) and a second hydrogen stream (such as second hydrogen stream 117). At least a portion of the oxygen stream 115 flows from the electrolysis unit 140 to a power generation unit (such as power generation unit 150). At least a portion of the carbon stream 113 flows from the carbon separation unit 130 to the power generation unit 150. As described above, the power generation unit 150 includes a direct carbon type fuel cell 151.In block 310, iron ore (such as iron ore 171a) is reduced by flowing hydrogen over the iron ore 171a to produce iron (such as iron 171b). Block 310 can be implemented, for example, in an iron ore reduction unit 170A. The hydrogen flowing over the iron ore 171a in block 310 can be supplied from at least a part of the first hydrogen stream 111, at least a part of the second hydrogen stream 117, or both. In block 312, iron 171b and carbon are combined to produce steel (such as steel 173). Block 312 can be implemented, for example, in a steel manufacturing unit 170B. The carbon combined with iron 171b in block 312 can be supplied from at least a part of the carbon stream 113. In block 314, oxygen from a part (or all) of the oxygen stream 115 and carbon from a part (or all) of the carbon stream 113 are combined (for example, by a direct carbon type fuel cell 151) to generate electric power and a carbon dioxide stream (such as carbon dioxide stream 119). At least a part of the electric power generated in block 314 is used to perform electrolysis of the water stream 103 (block 308). Therefore, at least a part of the electric power used to perform electrolysis in block 308 (for example, by an electrolysis unit 140) is supplied from at least a part of the electric power generated in block 314. Depending on the implementation, at least a part of the electric power generated in block 314 is used to perform thermal decomposition of the hydrocarbon supply stream 101 (block 302). Depending on the implementation, at least a part of the electric power generated in block 314 is used to reduce the iron ore 171a (block 310). Depending on the implementation, at least a part of the electric power generated in block 314 is used to produce the steel 173 (block 312).

[0057] Although this specification contains many details of specific implementations, these should not be construed as limitations on the scope of the claims, but rather as descriptions of features specific to particular implementations. The specific features described in this specification in the context of individual implementations can be implemented singly or in combination. Conversely, the various features described in the context of a single implementation can be implemented individually or in any partial combination in multiple implementations. Furthermore, the above features have been described as functioning in a particular combination and have even been initially claimed as such, but one or more features from the claimed combination may, in some cases, be removed from the combination, and the claimed combination may be directed to a partial combination or a variation of a partial combination.

[0058] As used in this disclosure, the terms "a", "an", or "the" are used to include one or more, unless the context clearly indicates otherwise. The term "or" is used to refer to non-exclusive "or" unless otherwise specified. The description "at least one of A and B" has the same meaning as "A, B, or A and B". Further, it should be understood that the expressions or terms used in this disclosure and not otherwise defined are for illustrative purposes only and not for limiting purposes. The use of section headings is for the purpose of document readability and not for limiting. Information related to a section heading may appear within or outside that particular section.

[0059] The terms "about" or "approximately" as used in this disclosure allow for a degree of variation in a value or range. For example, within 10%, 5%, or 1% of the stated value or the limits of the stated range.

[0060] The term "substantially" as used in this disclosure refers to a majority or a large portion, such as at least about 50%, 60%, 70%, 80%, 90%, 95%, 96%, 97%, 98%, 99%, 99.5%, 99.9%, 99.99%, or at least about 99.999% or more.

[0061] Values expressed in a range format should be interpreted flexibly to include not only the numerical values explicitly stated as the limits of the range, but also all individual numerical values or sub-ranges included within that range as if each numerical value and sub-range were explicitly stated. For example, a range of "0.1% to about 5%" or "0.1% to 5%" should be interpreted to include not only about 0.1% to about 5%, but also the individual values (e.g., 1%, 2%, 3%, and 4%) and sub-ranges (e.g., 0.1% to 0.5%, 1.1% to 2.2%, 3.3% to 4.4%) within the indicated range. The description "from X to Y" has the same meaning as "from about X to about Y" unless otherwise specified. Similarly, the description "X, Y, or Z" has the same meaning as "about X, about Y, or about Z" unless otherwise specified.

[0062] Particular implementations of the subject matter have been described. Other implementations, modifications, and substitutions of the described implementations are within the scope of the following claims, as will be apparent to those skilled in the art. Although operations are represented in the drawings or claims in a particular order, this should not be understood as requiring that such operations be performed in the particular order or sequential order shown, or that all of the illustrated operations be performed (some operations may be considered optional in some cases). In certain situations, multitasking or parallel processing (or a combination of multitasking and parallel processing) may be advantageous and may be performed when appropriately determined.

[0063] Furthermore, the separation or integration of the various system modules and components in the foregoing implementations should not be understood as being required in all implementations, and it should be understood that the components and systems described can generally be integrated together or packaged in multiple products.

[0064] Accordingly, the foregoing examples of implementations are not intended to define or limit the present disclosure. Other changes, substitutions, and modifications are possible without departing from the spirit and scope of the present disclosure.

Claims

Claim 1 Exposing a hydrocarbon feed stream containing hydrocarbons to heat in the absence of oxygen to convert the hydrocarbon feed stream into a solid stream and a gas stream, wherein the solid stream contains carbon and the gas stream contains hydrogen; Separating the gas stream into an exhaust gas stream and a first hydrogen stream containing at least a portion of the hydrogen from the gas stream; Separating the carbon from the solid stream to produce a carbon stream; Performing electrolysis of a water stream containing water to produce an oxygen stream and a second hydrogen stream, wherein the oxygen stream contains oxygen and the second hydrogen stream contains hydrogen; Reducing the iron ore to produce iron by flowing at least one of A) at least a portion of the first hydrogen stream or B) at least a portion of the second hydrogen stream over the iron ore; Combining the iron with a first portion of the carbon of the carbon stream to produce steel; Combining at least a portion of the oxygen of the oxygen stream with a second portion of the carbon of the carbon stream to produce a carbon dioxide stream containing power and carbon dioxide, using a first portion of the generated power to perform electrolysis of the water stream, using a second portion of the generated power to reduce the iron ore, and using a third portion of the generated power to produce the steel; A method. Claim 2 The hydrocarbon feed stream contains a plurality of hydrocarbons selected from C1-C22 alkanes, The method according to claim 1. Claim 3 The hydrocarbon feed stream contains hydrogen, The method according to claim 2. Claim 4 The oxygen and the carbon are combined by a direct carbon type fuel cell containing a solid oxide, and the oxygen and the carbon are combined by the direct carbon type fuel cell at an operating temperature in the range of about 800°C to about 1000°C, The method according to claim 3. Claim 5 Comprising transferring heat from the gas stream to a buffer fluid by a first waste heat recovery heat exchanger, The method according to claim 4. Claim 6 Before exposing the hydrocarbon feed stream to heat in the absence of oxygen, a step of transferring heat from the buffer fluid to the hydrocarbon feed stream by a second waste heat recovery heat exchanger is provided. The method according to claim 5.

7. A step of generating electric power by a Rankine cycle using the heat transferred from the gas stream to the buffer stream is provided, and the step of generating electric power by the Rankine cycle includes: A step of transferring heat from the buffer fluid to a working fluid in a boiler to vaporize the working fluid into a vaporized working fluid; A step of flowing the vaporized working fluid through a turbine to expand and generate electric power; A step of condensing the vaporized working fluid into a condensed working fluid; A step of circulating the condensed working fluid to the boiler; and is provided. The method according to claim 5.

8. A step of transferring heat from the carbon dioxide stream to a buffer fluid by a first waste heat recovery heat exchanger is provided. The method according to claim 4.

9. Before exposing the hydrocarbon feed stream to heat in the absence of oxygen, a step of transferring heat from the buffer fluid to the hydrocarbon feed stream by a second waste heat recovery heat exchanger is provided. The method according to claim 8.

10. A step of isolating the carbon dioxide stream generated by the direct carbon fuel cell within an underground layer so that the carbon dioxide stream is not released into the atmosphere is provided. The method according to claim 4.

11. A hydrocarbon feed stream containing hydrocarbons; A pyrolysis chamber configured to receive the hydrocarbon feed stream and expose the hydrocarbon feed stream to heat in the absence of oxygen to convert the hydrocarbon feed stream into a solid stream containing carbon and a gas stream containing hydrogen; A gas separation unit configured to receive the gas stream from the pyrolysis chamber, separate the hydrogen from the gas stream, and produce an exhaust gas stream and a first hydrogen stream containing at least a portion of the hydrogen from the gas stream; A carbon separation unit configured to receive the solid stream from the pyrolysis chamber and separate the carbon from the solid stream to produce a carbon stream; A water stream containing water; An electrolysis unit configured to receive the water stream and electric power, wherein the electrolysis unit is configured to perform electrolysis on the water stream using the electric power to produce an oxygen stream containing oxygen and a second hydrogen stream containing hydrogen; An iron ore reduction unit configured to receive at least a portion of the first hydrogen stream from the gas separation unit, at least a portion of the second hydrogen stream from the electrolysis unit, and iron ore, wherein the iron ore reduction unit is configured to reduce the iron ore to produce iron by flowing the portion of the first hydrogen stream and the portion of the second hydrogen stream over the iron ore; A steel manufacturing unit configured to receive the iron from the iron ore reduction unit and a first portion of the carbon stream from the carbon separation unit, wherein the steel manufacturing unit is configured to combine the iron and the first portion of the carbon stream to produce steel; A power generation unit configured to receive at least a portion of the oxygen stream from the electrolysis unit and a second portion of the carbon stream from the carbon separation unit, wherein the power generation unit includes a direct carbon fuel cell configured to combine the oxygen from the portion of the oxygen stream and the carbon from the portion of the carbon stream to generate electric power and a carbon dioxide stream containing carbon dioxide, and a first portion of the electric power generated by the power generation unit is supplied to the electrolysis unit to perform electrolysis on the water stream, a second portion of the electric power generated by the power generation unit is supplied to the iron ore reduction unit to reduce the iron ore, and a third portion of the electric power generated by the power generation unit is supplied to the steel manufacturing unit to produce the steel; A system.

12. The hydrocarbon supply stream contains a plurality of hydrocarbons selected from C1-C22 alkanes. The system according to claim 11.

13. The hydrocarbon supply stream contains hydrogen. The system according to claim 12.

14. The direct carbon type fuel cell includes a solid oxide electrolyte configured to operate at a temperature in the range of about 800°C to about 1000°C. The system according to claim 13.

15. A first waste heat recovery heat exchanger in fluid communication with the gas stream exiting the pyrolysis chamber and a buffer fluid, the first waste heat recovery heat exchanger being configured to transfer heat from the gas stream to the buffer fluid. The system according to claim 14.

16. A second waste heat recovery heat exchanger in fluid communication with the hydrocarbon supply stream entering the pyrolysis chamber and the buffer fluid, the second waste heat recovery heat exchanger being configured to transfer the heat from the buffer fluid to the hydrocarbon supply stream before the hydrocarbon supply stream enters the pyrolysis chamber. The system according to claim 15.

17. A Rankine cycle configured to generate power using the heat transferred from the gas stream to the buffer fluid, the Rankine cycle comprising: A boiler configured to receive a working fluid and the buffer fluid, the boiler being configured to transfer heat from the buffer fluid to the working fluid to vaporize the working fluid into a vaporized working fluid; The turbine configured to receive the vaporized working fluid and generate power when the vaporized working fluid flows through the turbine and expands; A condenser configured to receive the vaporized working fluid and condense it into a condensed working fluid; A pump configured to circulate the condensed working fluid to the boiler; The system according to claim 15.

18. A first waste heat recovery heat exchanger in fluid communication with the carbon dioxide stream exiting the power generation unit and a buffer fluid, the first waste heat recovery heat exchanger being configured to transfer heat from the carbon dioxide stream to the buffer fluid. The system according to claim 14.

19. A second waste heat recovery heat exchanger in fluid communication with the hydrocarbon supply stream entering the pyrolysis chamber and the buffer fluid, the second waste heat recovery heat exchanger being configured to transfer the heat from the buffer fluid to the hydrocarbon supply stream before the hydrocarbon supply stream enters the pyrolysis chamber. The system according to claim 18. **Claim 20** The pyrolysis chamber comprises a catalyst containing at least one of activated carbon, carbon black, cobalt, iron, copper, or nickel. The system according to claim 14.

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