WO2024254646A1 - Combustor and pyrolysis component, assembly and related systems and methods, and calcination system and method - Google Patents

Abstract

A combustor component is disclosed comprising a combustion chamber, which comprises an oxidant inlet configured to receive a gas flow of an oxidant, a fuel inlet configured to receive a gas flow of a fuel into the combustion chamber, and a gases outlet configured to allow passage of a flow of exhaust gases from the combustion chamber. The combustor component is configured to facilitate separation of the gas flows of the oxidant and the fuel entering the combustion chamber prior to combustion of the fuel with the oxidant. A combustor assembly comprising a plurality of combustor components for staged combustion of a fuel with an oxidant, and related systems and methods for control and use of the combustor assembly, including in calcination processes, are also disclosed. A pyrolysis component, a pyrolysis assembly comprising a plurality of pyrolysis components, and related systems and methods using the pyrolysis component are also disclosed.

Description

COMBUSTOR AND PYROLYSIS COMPONENT, ASSEMBLY AND RELATED SYSTEMS AND METHODS, AND CALCINATION SYSTEM AND METHOD

[0001] This application claims priority from Australian Provisional Patent Application No. 2023901914 filed on 16 June 2023, Australian Provisional Patent Application No. 2023903231 filed on 9 October 2023, and Australian Provisional Patent Application No. 2023904228 filed on 22 December 2023, the contents of each of which are to be taken as incorporated herein by this reference.

Field

[0002] The present disclosure relates to a combustor component, a combustor assembly and related systems and methods using the combustor assembly. It relates particularly but not exclusively to combustion of hydrogen in oxygen to produce steam for providing high temperature thermal energy for use e.g., in large-scale industrial processes.

[0003] The present disclosure also relates to a pyrolysis component, a pyrolysis assembly and related systems and methods using the pyrolysis component and/or assembly. It relates particularly but not exclusively to steam pyrolysis of hydrocarbons to produce unsaturated hydrocarbons.

Background

[0004] Oxygen combustion of hydrocarbons is often achieved using premix or partially premixed designs of combustors, where the fuel (mostly hydrocarbons or hydrogen mixed with diluent) and the oxidant (air or oxygen) are premixed upstream of the combustion zone and introduced largely on one end of the combustor, forming a combustion zone downstream. This process relies on the premixing of the fuel and oxidant to mitigate generation of pollutants (mostly nitrogen oxides, carbon monoxide and unburned hydrocarbons). Adapting these solutions to combust pure hydrogen with pure oxygen has been a challenge due to the very rapid and explosive nature of this hydrogen-oxygen combustion reaction requiring the need to avoid any premix of hydrogen and oxygen.

[0005] Hydrogen’s high combustion reaction speed, which is nearly eight times that of natural gas, is a fundamental cause of concern while developing a burner design. Burner designs that utilize lean premix, premix, or rapid premix designs are not suited for a fuel stream that varies in hydrogen composition. As the composition of hydrogen increases in the fuel stream, these types of burners become more susceptible to flashback. Flashback occurs when the gas velocity exiting the burner nozzle is slower than the combustion reaction speed in a premixed application. Damage to the burner components can result when flashback occurs.

[0006] Non-premix diffusion combustors can combust hydrogen-rich fuels with air, and mostly in combination with a diluent (e.g., nitrogen or carbon dioxide) with potential high nitrogen oxide emissions. However, such burner designs have not been designed to burn pure hydrogen with pure oxygen. Non-premix burners are suited for a higher percentage of hydrogen fuel combustion with air.

[0007] It would be desirable to provide a combustor and associated method for enabling controlled, safe and stable combustion of pure hydrogen (H2) as a fuel with pure oxygen (O2) as an oxidant, thus generating steam (H2O) to provide high temperature thermal energy, e.g., for use in large-scale industrial processes such as alumina refining, cement manufacture, steel making, fertilizer production, mineral processing, food processing and similar applications, and/or which ameliorates one or more disadvantages of present arrangements or at least provides a useful alternative.

[0008] In another aspect, steam pyrolysis or the steam cracking process is an important step in the hydrocarbon processing industry. When the feedstock is methane (CH4), this produces hydrogen, as required for ammonia synthesis (called steam methane reforming). When the feedstocks are other saturated hydrocarbons (comprising of ethane, propane, butane, etc. as contained in LPG, naptha, gas condensates and gas oil produced in a refinery), the main products of steam cracking are lower olefins (ethylene, propylene, butylenes, etc.) and hydrogen.

[0009] Ethylene is the feedstock of most products used by humans. Steam cracking process produces the world’s largest volume of organic petrochemical, ethylene, with a worldwide production of 224 million tonnes per annum (Mtpa) as of 2022. The olefin production sector is poised to see considerable growth over the next few years to 310 Mtpa by 2027 (39% growth), providing the world with rubbers, detergents, plastics, insulation materials, glues, solvents, to name a few. The steam cracking process is the most energy-consuming process in the global chemical industry, using 8% of the entire sector’s total primary energy use.

[0010] The olefin yield is determined by the steam cracking process, which are furnaces in current technology. The steam crackers presently used are common heating furnaces designed and built to withstand large energy flux at high temperature levels to drive the endothermic hydrocarbon cracking reactions in the presence of steam. The maximum temperature achieved with current steam crackers is constrained by the metallurgy of the heat transfer surfaces, as any higher temperatures will result in softening, deformation and premature failure of the heat transfer tubes, causing a catastrophic release of hydrocarbons into the furnace itself.

[0011] It would also be desirable to provide a pyrolysis component and associated system and method which enables higher temperature cracking of hydrocarbons to increase product yield and/or ameliorates one or more disadvantages of present arrangements in steam cracking technology or at least provides a useful alternative.

[0012] A reference herein to a patent document or any other matter identified as prior art, is not to be taken as an admission that the document or other matter was known or that the information it contains was part of the common general knowledge as at the priority date of any of the claims.

Summary of Disclosure

[0013] Some embodiments of the present disclosure are designed for combusting gaseous fuel, and specifically gaseous hydrogen (H2) with gaseous oxygen (O2). Fuel combustion is typically achieved by adding lean-fuel to excess oxidant, sustaining combustion until the fuel is consumed by the oxidant. The present disclosure teaches the opposite, namely where partial oxidant is added to fuel in a staged combustion process. The oxidant effectively is entirely consumed in the excess-fuel environment at each stage, and combustion is achieved by sequentially increasing the percentage of oxidant in air / fuel.

[0014] Some embodiments of the present disclosure are directed to systematic sequentially staged combustion of hydrogen with oxygen to deliberately distribute and exploit the wide flammability range of hydrogen over multiple stages, self-generating increasing amounts of steam as diluent for subsequent combustion stages, thereby aiming to achieve safe and stable hydrogen combustion with oxygen.

[0015] Some embodiments of the present disclosure do not premix the gaseous hydrogen and gaseous oxygen prior to admission into the combustion chamber, thereby seeking to address the key risk of flashback and premature explosion and/or combustion with premixing gaseous hydrogen and oxygen. [0016] Some embodiments of the present disclosure rely on a tangential entry flow pattern, or more specifically a cyclonic flow pattern, imparted to the fuel stream unlike other known oxyfuel combustors. Many combustor devices employ swirl devices to impart swirling motion to the combustion fuel, oxidant and/or mixture. However, this method is not feasible for hydrogen combustion since it is a very light gas and cannot achieve high angular momentum using swirling vanes, which is important for developing a strong cyclonic flow pattern. Some embodiments of the present disclosure employ cyclone combustors to further stage the combustion of hydrogen in oxygen.

[0017] Cyclone combustors have been deployed primarily to combust solid fuels entrained in a gas stream, and achieve this by separating the solid ash or slag produced for extraction at the bottom opening of a vertically oriented cyclone structure. Cyclone combustors often have two outlets: one bottom oriented outlet for solids extraction and a top oriented outlet for solids free flue gas extraction. Cyclone combustors premix gaseous fuel and oxidant before admitting into a combustion chamber and then impart a cyclonic motion to the premixed fuel and oxidant mixture (primarily for control of pollutant production and/or mitigation).

[0018] The operating principle of some embodiments of the present disclosure require the flow patterns to adapt upon leaving a cyclonic combustion chamber through only one outlet; thus being very distinct to a traditional cyclone combustor designed for entrained solids separation. The traditional bottom outlet of a cyclone separator does not exist, and is instead a conical end cover portion, which projects the oxidant jet deep into the combustion chamber of the novel combustion component.

[0019] In a first aspect, the present disclosure provides a combustor component comprising: a combustion chamber comprising: an oxidant inlet configured to receive a gas flow of an oxidant; a fuel inlet configured to receive a gas flow of a fuel into the combustion chamber; and a gases outlet configured to allow passage of a flow of exhaust gases from the combustion chamber, wherein the combustor component is configured to facilitate separation of the gas flows of the oxidant and the fuel entering the combustion chamber prior to combustion of the fuel with the oxidant.

[0020] In some embodiments, the gas flows of the oxidant and the fuel entering the combustion chamber are in opposite directions upon entering the combustion chamber. The combustor component may be further configured to direct the gas flow of the fuel towards the oxidant inlet upon entering the combustion chamber through the fuel inlet. The combustion chamber may be shaped and/or dimensionally profiled to direct the gas flow of the fuel towards the oxidant inlet. The combustion chamber may comprise a tapered portion located between the gases outlet and the oxidant inlet to direct the gas flow of the fuel towards the oxidant inlet. The tapered portion may be substantially conically-shaped.

[0021] In some embodiments, the combustor component is further configured to impart a tangential flow pattern to the gas flow of the fuel upon entering the combustion chamber through the fuel inlet. The tangential flow pattern may be a cyclonic flow pattern of the gas flow of the fuel around an internal wall of the combustion chamber as it moves towards the oxidant inlet.

[0022] In some embodiments, the combustor component further comprises at least one nozzle angled relative to the combustion chamber and in fluid communication with the fuel inlet to direct the gas flow of the fuel at or along an internal wall of the combustion chamber. The combustor component may comprise a plurality of nozzles configured to direct the gas flow of the fuel through a corresponding plurality of fuel inlets into the combustion chamber. The plurality of nozzles and the corresponding plurality of fuel inlets may be circumferentially spaced on an external surface of the combustion chamber.

[0023] In some embodiments, the combustor component further comprises a shield portion extending into an interior of the combustion chamber and in fluid communication with the gases outlet to provide separation between the gas flow of the fuel entering through the fuel inlet and the flow of exhaust gases exiting through the gases outlet. The shield portion may be shaped and/or dimensionally profiled to direct flow of the fuel at or along an internal wall of the combustion chamber and/or towards the oxidant inlet.

[0024] In some embodiments, the fuel inlet is arranged adjacent to the gases outlet to facilitate separation of the gas flows of the oxidant and the fuel prior to combustion. The combustor component may be further configured to direct the gas flow of the oxidant towards a combustion zone of the combustion chamber. The oxidant inlet may be dimensioned to limit an amount of oxidant delivered to the combustion zone of the combustion chamber so that the oxidant is substantially or entirely consumed during combustion with the fuel. The oxidant inlet may have an internal diameter sufficient to produce a jet flow of the oxidant into the combustion chamber. [0025] In some embodiments, the combustor component further comprises a guide portion extending into an interior of the combustion chamber and in fluid communication with the oxidant inlet to position the gas flow of the oxidant in the combustion zone of the combustion chamber. The guide portion may extend axially into the interior of the combustion chamber and is substantially co-axial with the gases outlet. The combustion chamber may further comprise a cover portion at least partly surrounding the guide portion, wherein the cover portion is configured to reverse the direction of the gas flow of the fuel towards the gases outlet. The cover portion may be configured to support the guide portion. The cover portion may protrude axially into the combustion chamber along a length of the guide portion. The cover portion may entirely surround the guide portion. The cover portion may be tapered from the oxidant inlet towards an opening of the guide portion. The cover portion may be conically-shaped.

[0026] In some embodiments, the combustor component further comprises at least one membrane wall located on an internal surface of the combustor component configured to absorb at least a portion of the thermal energy released during combustion of the fuel with the oxidant. The at least one membrane wall may comprise a spiraled tube configured to receive a heat transfer fluid and a plurality of membrane fins that together form a contiguous heat transfer surface.

[0027] In some embodiments, the combustor component further comprises a plurality of injection nozzles in fluid communication with an interior of the combustion chamber to distribute diluent into the combustion chamber. The combustor component may further comprise a sheet with a plurality of openings positionable within the combustion chamber to distribute the diluent along an internal surface of the combustion chamber.

[0028] In some embodiments, an interior of the combustor component, one or more inlets of the combustor component and/or the gases outlet of the combustor component comprise an insulating liner. The insulating liner may comprise a refractory and/or ceramic material. The insulating liner may comprise calcium silicates, alumina, magnesia, zirconia or combinations thereof. An outer casing of the combustor component may be made of metal.

[0029] In some embodiments, the fuel comprises hydrogen (H2) gas and the oxidant comprises oxygen (O2) gas. The fuel may comprise a mixture of hydrogen (H2) gas and a diluent gas. The diluent gas may be an inert gas such as nitrogen (N2) or carbon dioxide (CO2). [0030] In a second aspect, the present disclosure provides a combustor assembly for staged combustion of a fuel with an oxidant, the combustor assembly comprising: a plurality of combustor components arranged sequentially for staged combustion of the fuel with the oxidant, wherein each combustor component comprises a combustion chamber, and wherein at least one subsequent combustor component is configured to receive a flow of exhaust gases from a preceding combustor component as the fuel for combustion with a gas flow of the oxidant in the at least one subsequent combustor component, wherein the flow of exhaust gases produced from each combustor component comprises a proportion of the fuel provided to a first combustor component, which reduces in proportion to substantially none of the fuel provided to the first combustor component being present in the flow of the exhaust gases from a final combustor component.

[0031] In some embodiments, an amount of oxidant provided to each of the plurality of combustor components is limited so that the oxidant is substantially or entirely consumed during combustion with the fuel in each combustion chamber.

[0032] In some embodiments, the fuel provided to the first combustor component comprises a pure gas. The fuel provided to the first combustor component may further comprise a diluent. The combustor assembly may further comprise a mixing device configured to combine the diluent with the pure gas to form a homogenous mixture of the fuel to be provided at the first combustor component.

[0033] In some embodiments, the combustor assembly is configured to adjust a temperature of the flow of the exhaust gases from at least one combustor component to a target temperature before use as the fuel in a subsequent combustor component. The combustion assembly may further comprise a temperature controller configured to operate a control valve for delivering a flow of a fluid for evaporation into the flow of exhaust gases to maintain the target temperature. The combustor assembly may further comprise a spray device operable by the temperature controller to discharge the flow of the fluid passing through the control valve into the flow of exhaust gases.

[0034] In some embodiments, the at least one subsequent combustor component is configured to receive a flow of exhaust gases from two or more preceding combustor components. The final combustor component may also be configured to receive a flow of exhaust gases from two or more preceding combustor components. In some embodiments, the combustor assembly comprises two or more combustor components for at least one stage of combustion. The combustor assembly may comprise two or more combustor components at each stage of combustion. The combustor assembly may comprise two or more subsequent combustor components and/or two or more final combustor components which are each configured to receive a flow of exhaust gases from a respective preceding combustor component.

[0035] In some embodiments, the plurality of combustor components each comprise a combustor component according to the first aspect of the present disclosure or any of the embodiments as disclosed herein.

[0036] In a third aspect, the present disclosure provides a method for staged combustion of a fuel with an oxidant, the method comprising: providing a plurality of combustor components arranged sequentially for staged combustion of the fuel with the oxidant, wherein each combustor component comprises a combustion chamber; and receiving, at at least one subsequent combustor component, a flow of exhaust gases from a preceding combustor component as the fuel for combustion with a gas flow of the oxidant in the at least one subsequent combustor component, wherein the flow of exhaust gases produced from each combustor component comprises a proportion of the fuel provided to a first combustor component, which reduces in proportion to substantially none of the fuel provided to the first combustor component being present in the flow of exhaust gases from a final combustor component.

[0037] In some embodiments, the method further comprises providing a limited amount of oxidant to each of the plurality of combustor components so that the oxidant is substantially or entirely consumed during combustion with the fuel in each combustion chamber.

[0038] In some embodiments, the method further comprises providing the fuel comprising a pure gas to the first combustor component. The fuel provided to the first combustor component may further comprise a diluent. In some embodiments, the method further comprises combining, using a mixing device, the diluent with the pure gas to form a homogenous mixture of the fuel to be provided at the first combustor component.

[0039] In some embodiments, the method further comprises adjusting a temperature of the flow of the exhaust gases from at least one combustor component to a target temperature before use as the fuel in a subsequent combustor component. The step of adjusting the temperature may comprise operating, using a temperature controller, a control valve for delivering a flow of a fluid for evaporation into the flow of exhaust gases to maintain the target temperature. The method may further comprise operating, using the temperature controller, a spray device to discharge the flow of the fluid passing through the control valve into the flow of exhaust gases.

[0040] In some embodiments, the plurality of combustor components each comprise a combustor component according to the first aspect of the present disclosure or any of the embodiments as disclosed herein. In some embodiments, the method further comprises providing a combustor assembly comprising the plurality of combustor components according to the second aspect of the present disclosure or any of the embodiments as disclosed herein.

[0041] In a fourth aspect, the present disclosure provides a combustor assembly for staged combustion of a fuel with an oxidant, the combustor assembly comprising: a plurality of combustor components arranged sequentially for staged combustion of the fuel with the oxidant, wherein each combustor component comprises a combustion chamber, and wherein at least one subsequent combustor component is configured to receive a flow of exhaust gases from a preceding combustor component as the fuel for combustion with a gas flow of the oxidant in the at least one subsequent combustor component, wherein the flow of exhaust gases produced from each combustor component comprises a proportion of the fuel provided to a first combustor component, which reduces in proportion to a predetermined amount of the fuel being present in the flow of the exhaust gases from a final combustor component.

[0042] In some embodiments, an amount of oxidant provided to each of the plurality of combustor components is limited so that the oxidant is substantially or entirely consumed during combustion with the fuel in each combustion chamber.

[0043] In some embodiments, the fuel provided to the first combustor component comprises a pure gas. The fuel provided to the first combustor component may further comprise a diluent. The combustor assembly may further comprise a mixing device configured to combine the diluent with the pure gas to form a homogenous mixture of the fuel to be provided at the first combustor component.

[0044] In some embodiments, the combustor assembly is configured to adjust a temperature of the flow of the exhaust gases from at least one combustor component to a target temperature before use as the fuel in a subsequent combustor component. The combustion assembly may further comprise a temperature controller configured to operate a control valve for delivering a flow of a fluid for evaporation into the flow of exhaust gases to maintain the target temperature. The combustor assembly may further comprise a spray device operable by the temperature controller to discharge the flow of the fluid passing through the control valve into the flow of exhaust gases.

[0045] In some embodiments, the at least one subsequent combustor component is configured to receive a flow of exhaust gases from two or more preceding combustor components. The final combustor component may also be configured to receive a flow of exhaust gases from two or more preceding combustor components. In some embodiments, the combustor assembly comprises two or more combustor components for at least one stage of combustion. The combustor assembly may comprise two or more combustor components at each stage of combustion. The combustor assembly may comprise two or more subsequent combustor components and/or two or more final combustor components which are each configured to receive a flow of exhaust gases from a respective preceding combustor component.

[0046] In some embodiments, the plurality of combustor components each comprise a combustor component according to the first aspect of the present disclosure or any of the embodiments as disclosed herein.

[0047] In a fifth aspect, the present disclosure provides a method for staged combustion of a fuel with an oxidant, the method comprising: providing a plurality of combustor components arranged sequentially for staged combustion of the fuel with the oxidant, wherein each combustor component comprises a combustion chamber; and receiving, at at least one subsequent combustor component, a flow of exhaust gases from a preceding combustor component as the fuel for combustion with a gas flow of the oxidant in the at least one subsequent combustor component, wherein the flow of exhaust gases produced from each combustor component comprises a proportion of the fuel provided to a first combustor component, which reduces in proportion to a predetermined amount of the fuel being present in the flow of the exhaust gases from a final combustor component.

[0048] In some embodiments, the method further comprises providing a limited amount of oxidant to each of the plurality of combustor components so that the oxidant is substantially or entirely consumed during combustion with the fuel in each combustion chamber. [0049] In some embodiments, the method further comprises providing the fuel comprising a pure gas to the first combustor component. The fuel provided to the first combustor component may further comprise a diluent. In some embodiments, the method further comprises combining, using a mixing device, the diluent with the pure gas to form a homogenous mixture of the fuel to be provided at the first combustor component.

[0050] In some embodiments, the method further comprises adjusting a temperature of the flow of the exhaust gases from at least one combustor component to a target temperature before use as the fuel in a subsequent combustor component. The step of adjusting the temperature may comprise operating, using a temperature controller, a control valve for delivering a flow of a fluid for evaporation into the flow of exhaust gases to maintain the target temperature. The method may further comprise operating, using the temperature controller, a spray device to discharge the flow of the fluid passing through the control valve into the flow of exhaust gases.

[0051] In some embodiments, the plurality of combustor components each comprise a combustor component according to the first aspect of the present disclosure or any of the embodiments as disclosed herein. In some embodiments, the method further comprises providing a combustor assembly comprising the plurality of combustor components according to the fourth aspect of the present disclosure or any of the embodiments as disclosed herein.

[0052] In a sixth aspect, the present disclosure provides a system configured to operate a combustor assembly to produce a flow of exhaust gases with one or more desired characteristics, the system comprising: the combustor assembly according to the second or fourth aspects of the present disclosure or any of the embodiments as disclosed herein; at least one sensor configured to measure one or more parameters of the flow of exhaust gases from a final combustor component in the combustor assembly; and a system controller configured to: receive a predetermined target flow of exhaust gases comprising the one or more desired characteristics; process the one or more parameters measured by the at least one sensor to determine a deviation from the predetermined target flow of exhaust gases; and modify one or more fluid flows in the system to meet the one or more desired characteristics of the predetermined target flow of exhaust gases.

[0053] The one or more fluid flows modified may comprise gas flows and/or liquid flows in the system. In some embodiments, the one or more fluid flows modified by the system controller may comprise the gas flow of fuel provided to a first combustor component of the combustor assembly, the gas flow of oxidant provided to each combustor component of the combustor assembly, and/or the gas flow of fuel provided to subsequent combustor components of the combustor assembly after the first combustor component. In some embodiments, the system controller is configured to modify the gas flow of fuel provided to subsequent combustor components through temperature control. The system controller may be configured to modify delivery of a flow of liquid being evaporated into the gas flow of fuel provided to subsequent combustor components to maintain the gas flow of fuel at a desired temperature.

[0054] In some embodiments, the one or more desired characteristics may comprise a desired composition, pressure and/or temperature of the flow of exhaust gases. In some embodiments, the desired composition is the predetermined amount of the fuel being present in the flow of the exhaust gases from the final combustor component of the combustor assembly of the fourth aspect. The flow of exhaust gases may further comprise steam in the form of water vapour (H2O), and the desired composition may be a ratio of the predetermined amount of fuel to steam in the flow of exhaust gases from the final combustor component of the combustor assembly of the fourth aspect.

[0055] In some embodiments, the at least one sensor is configured to measure a concentration of one or more substances in the flow of exhaust gases from the final combustor component. The one or more substances may comprise oxygen (O2), hydrogen (H2) and/or hydroxyl ion (OH") concentration. In some embodiments, the at least one sensor is configured to measure temperature, pressure and/or volume of the flow of exhaust gases from the final combustor component.

[0056] In some embodiments, the system controller is further configured to determine a mass flow of the exhaust gases from the final combustor component based on at least one of the concentration of the one or more substances, the temperature, the pressure and/or the volume of the flow of exhaust gases.

[0057] In some embodiments, the system controller is configured to modify one or more fluid flows in the system by operating a fuel flow controller to modify the gas flow of the fuel provided to the first combustor component. In some embodiments, the system controller is configured to modify one or more fluid flows in the system by operating an oxidant flow controller to modify the gas flow of the oxidant provided to the combustor assembly. [0058] In some embodiments, the system controller is configured to operate the oxidant flow controller to modify the gas flow of the oxidant provided to each of the combustor components of the combustor assembly to limit an amount of oxidant so that the oxidant is substantially or entirely consumed during combustion with the fuel in each combustion chamber.

[0059] In some embodiments, the system controller is further configured to receive a temperature signal of the flow of exhaust gases from at least one temperature controller associated with a combustor component of the combustor assembly, and wherein the system controller is further configured to operate the oxidant flow controller to modify the gas flow of the oxidant provided to each of the combustor components of the combustor assembly based on the temperature signal.

[0060] In some embodiments, the system further comprises at least one sensor configured to measure pressure and/or volume of the gas flow of fuel and/or oxidant provided to at least one of the combustor components of the combustor assembly, wherein the system controller is further configured to modify one or more fluid flows in the system also based on the measured pressure and/or volume of the gas flow of fuel and/or oxidant.

[0061] In some embodiments, the system further comprises at least one safety feature to limit the gas flow of fuel and/or oxidant to at least one of the combustor components of the combustor assembly. The at least one safety feature may comprise a valve to stop the gas flow of fuel and/or oxidant to at least one of the combustor components and/or a flow limiter to limit the gas flow of fuel and/or oxidant to at least one of the combustor components.

[0062] In a seventh aspect, the present disclosure provides a system configured to produce high temperature thermal energy for an external process using electrolysis and a combustor assembly, the system comprising: an electrolyser configured to receive pure water (H2O) and separate it into hydrogen gas (H2) and oxygen gas (O2); the combustor assembly according to the second aspect of the present disclosure or any of the embodiments as disclosed herein, wherein the fuel comprises the hydrogen gas from the electrolyser and the oxidant comprises the oxygen gas from the electrolyser, and wherein the flow of exhaust gases comprises steam in the form of water vapour (H2O) which is provided as the high temperature thermal energy to the external process; and a condenser for receiving the steam after use by the external process to condense the steam into pure water, wherein the system is configured to return the pure water to the electrolyser for re-use. [0063] In some embodiments, the system further comprises a pressure controller configured to modify the pressure of the hydrogen gas and/or oxygen gas produced by the electrolyser, or optionally from hydrogen gas storage and/or oxygen gas storage, to ensure that a desired pressure of the flow of exhaust gases at a final combustor component of the combustor assembly will be satisfied for the external process.

[0064] In some embodiments, the system further comprises a compressor configured to receive the hydrogen gas from the electrolyser and increase its pressure for storage in a hydrogen storage vessel. In some embodiments, the system further comprises a compressor configured to receive the oxygen gas from the electrolyser and increase its pressure for storage in an oxygen storage vessel.

[0065] In some embodiments, the system is further configured to provide additional pure water to the condenser based on loss of steam to the external process. In some embodiments, the system further comprises a condensate pump for returning the pure water from the condenser to the electrolyser.

[0066] In some embodiments, the system further comprises a mixing device for receiving a source of a diluent which is combined with the hydrogen gas produced by the electrolyser to form a homogenous mixture of the fuel to be provided at the first combustor component. The system may further comprise a pressure controller configured to modify the pressure of the diluent to ensure that it is sufficient to combine with the hydrogen gas produced by the electrolyser at the first combustor component. The system may further comprise a diluent pump (e.g., a diluent extraction pump) for removing diluent from the condenser, and a compressor configured to receive the diluent from the condenser and increase its pressure for storage in a diluent storage vessel ready for re-use in the combustor assembly.

[0067] In some embodiments, the system further comprises a pump for extracting pure water from the condenser and increasing its pressure for use as a fluid for evaporation into the flow of exhaust gases from at least one combustor component to maintain a desired temperature for use as a fuel in a subsequent combustor component in the combustor assembly. In some embodiments, the system further comprises a bleed line for varying the composition of the pure water extracted from the condenser to be returned to the electrolyser. [0068] In an eight aspect, the present disclosure provides a system configured to produce high temperature thermal energy for an external process using electrolysis and a combustor assembly, the system comprising: an electrolyser configured to receive pure water (H2O) and separate it into hydrogen gas (H2) and oxygen gas (O2); and the combustor assembly according to the second aspect of the present disclosure or any of the embodiments as disclosed herein, wherein the fuel comprises the hydrogen gas from the electrolyser and the oxidant comprises the oxygen gas from the electrolyser, and wherein the flow of exhaust gases comprises steam in the form of water vapour (H2O) which is provided as the high temperature thermal energy to the external process.

[0069] In some embodiments, the system further comprises a condenser for receiving the steam after use by the external process to condense the steam into pure water. The system may be further configured to return the pure water to the electrolyser for re-use.

[0070] In some embodiments, the system further comprises a pressure controller configured to modify the pressure of the hydrogen gas and/or oxygen gas produced by the electrolyser, or optionally from hydrogen gas storage and/or oxygen gas storage, to ensure that a desired pressure of the flow of exhaust gases at a final combustor component of the combustor assembly will be satisfied for the external process.

[0071] In some embodiments, the system further comprises a compressor configured to receive the hydrogen gas from the electrolyser and increase its pressure for storage in a hydrogen storage vessel. In some embodiments, the system further comprises a compressor configured to receive the oxygen gas from the electrolyser and increase its pressure for storage in an oxygen storage vessel. In some embodiments, the system is further configured to provide additional pure water to the condenser based on loss of steam to the external process. In some embodiments, the system further comprises a condensate pump for returning the pure water from the condenser to the electrolyser.

[0072] In some embodiments, the system further comprises a mixing device for receiving a source of a diluent which is combined with the hydrogen gas produced by the electrolyser to form a homogenous mixture of the fuel to be provided at the first combustor component. The system may further comprise a pressure controller configured to modify the pressure of the diluent to ensure that it is sufficient to combine with the hydrogen gas produced by the electrolyser at the first combustor component. The system may further comprise a diluent pump (e.g., a diluent extraction pump) for removing diluent from the condenser, and a compressor configured to receive the diluent from the condenser and increase its pressure for storage in a diluent storage vessel ready for re-use in the combustor assembly.

[0073] In some embodiments, the system further comprises a pump for extracting pure water from the condenser and increasing its pressure for use as a fluid for evaporation into the flow of exhaust gases from at least one combustor component to maintain a desired temperature for use as a fuel in a subsequent combustor component in the combustor assembly. In some embodiments, the system further comprises a bleed line for varying the composition of the pure water extracted from the condenser to be returned to the electrolyser.

[0074] In a ninth aspect, the present disclosure provides a method for producing high temperature thermal energy for an external process using electrolysis and a combustor assembly, the method comprising: receiving, at an electrolyser, pure water (H2O) and separating it into hydrogen gas (H2) and oxygen gas (O2); providing the combustor assembly according to the second aspect of the present disclosure or any of the embodiments as disclosed herein, wherein the fuel comprises the hydrogen gas from the electrolyser and the oxidant comprises the oxygen gas from the electrolyser; providing the flow of exhaust gases comprising steam in the form of water vapour (H2O) from the final combustor component of the combustor assembly as the high temperature thermal energy for use in the external process; receiving, at a condenser, the steam after use by the external process and condensing the steam into pure water; and returning the pure water to the electrolyser for re-use.

[0075] In some embodiments, the method further comprises modifying, using a pressure controller, the pressure of the hydrogen gas and/or oxygen gas produced by the electrolyser to ensure that a desired pressure of the flow of exhaust gases at a final combustor component of the combustor assembly will be satisfied for the external process.

[0076] In some embodiments, the method further comprises receiving, at a compressor, the hydrogen gas from the electrolyser and increasing its pressure for storage in a hydrogen storage vessel. In some embodiments, the method further comprises receiving, at a compressor, the oxygen gas from the electrolyser and increasing its pressure for storage in an oxygen storage vessel. The method may further comprise providing additional pure water to the condenser based on loss of steam to the external process. In some embodiments, the method further comprises returning, using a condensate pump, pure water from the condenser to the electrolyser. [0077] In some embodiments, the method further comprises receiving a source of a diluent and combining, using a mixing device, the diluent with the hydrogen gas produced by the electrolyser to form a homogenous mixture of the fuel to be provided at the first combustor component. The method may further comprise modifying, using a pressure controller, the pressure of the diluent to ensure that it is sufficient to combine with the hydrogen gas produced by the electrolyser at the first combustor component.

[0078] In some embodiments, the method further comprises removing, using a diluent pump (e.g., a diluent extraction pump), diluent from the condenser, and receiving, at a compressor, the diluent from the condenser and increasing its pressure for storage in a diluent storage vessel ready for re-use in the combustor assembly.

[0079] In some embodiments, the method further comprises extracting, using a pump, pure water from the condenser and increasing its pressure for use in heating the flow of exhaust gases from at least one combustor component to a desired temperature for use as a fuel in a subsequent combustor component in the combustor assembly. In some embodiments, the method further comprises varying, using a bleed line, the composition of the pure water extracted from the condenser to be returned to the electrolyser.

[0080] In a tenth aspect, the present disclosure provides a method for producing high temperature thermal energy for an external process using electrolysis and a combustor assembly, the method comprising: receiving, at an electrolyser, pure water (H2O) and separating it into hydrogen gas (H2) and oxygen gas (O2); providing the combustor assembly according to the second aspect of the present disclosure or any of the embodiments as disclosed herein, wherein the fuel comprises the hydrogen gas from the electrolyser and the oxidant comprises the oxygen gas from the electrolyser; and providing the flow of exhaust gases comprising steam in the form of water vapour (H2O) from the final combustor component of the combustor assembly as the high temperature thermal energy for use in the external process.

[0081] In some embodiments, the method further comprises receiving, at a condenser, the steam after use by the external process and condensing the steam into pure water. The method may further comprise returning the pure water to the electrolyser for re-use.

[0082] In some embodiments, the method further comprises modifying, using a pressure controller, the pressure of the hydrogen gas and/or oxygen gas produced by the electrolyser to ensure that a desired pressure of the flow of exhaust gases at a final combustor component of the combustor assembly will be satisfied for the external process.

[0083] In some embodiments, the method further comprises receiving, at a compressor, the hydrogen gas from the electrolyser and increasing its pressure for storage in a hydrogen storage vessel. In some embodiments, the method further comprises receiving, at a compressor, the oxygen gas from the electrolyser and increasing its pressure for storage in an oxygen storage vessel. The method may further comprise providing additional pure water to the condenser based on loss of steam to the external process. In some embodiments, the method further comprises returning, using a condensate pump, pure water from the condenser to the electrolyser.

[0084] In some embodiments, the method further comprises receiving a source of a diluent and combining, using a mixing device, the diluent with the hydrogen gas produced by the electrolyser to form a homogenous mixture of the fuel to be provided at the first combustor component. The method may further comprise modifying, using a pressure controller, the pressure of the diluent to ensure that it is sufficient to combine with the hydrogen gas produced by the electrolyser at the first combustor component.

[0085] In some embodiments, the method further comprises removing, using a diluent pump (e.g., a diluent extraction pump), diluent from the condenser, and receiving, at a compressor, the diluent from the condenser and increasing its pressure for storage in a diluent storage vessel ready for re-use in the combustor assembly.

[0086] In some embodiments, the method further comprises extracting, using a pump, pure water from the condenser and increasing its pressure for use in heating the flow of exhaust gases from at least one combustor component to a desired temperature for use as a fuel in a subsequent combustor component in the combustor assembly.

[0087] In some embodiments, the method further comprises varying, using a bleed line, the composition of the pure water extracted from the condenser to be returned to the electrolyser.

[0088] In a eleventh aspect, the present disclosure provides a system configured to heat hydrogen gas (H2) for use in an external process, the system comprising: the combustor assembly according to the second aspect of the present disclosure or any of the embodiments as disclosed herein; and a heat exchanger configured to receive the flow of exhaust gases from the final combustor component and impart thermal energy to heat a flow of hydrogen gas for use in the external process.

[0089] In some embodiments, the system further comprises an electrolyser configured to receive pure water (H2O) and separate it into hydrogen gas (H2) and oxygen gas (O2). The fuel of the combustor assembly may comprise hydrogen gas from the electrolyser and the oxidant of the combustor assembly may comprise the oxygen gas from the electrolyser. The flow of exhaust gases from the final combustor component may comprise steam in the form of water vapour (H₂O).

[0090] In some embodiments, the flow of hydrogen gas to be heated is provided from the electrolyser. The system may further comprise a valve for regulating the pressure of the flow of hydrogen gas from the electrolyser prior to heating in the heat exchanger. In some embodiments, the system further comprises a condenser for receiving the steam after use by the heat exchanger to condense the steam into pure water, wherein the system is configured to return the pure water to the electrolyser for re-use.

[0091] In a twelfth aspect, the present disclosure provides a method configured to heat hydrogen gas (H2) for use in an external process, the method comprising: providing the combustor assembly according to the second aspect of the present disclosure or any of the embodiments as disclosed herein; receiving, at a heat exchanger, the flow of exhaust gases from the final combustor component; and heating, using the heat exchanger, a flow of hydrogen gas for use in the external process by imparting thermal energy to the flow of hydrogen gas from the flow of exhaust gases.

[0092] In some embodiments, the method further comprises receiving, at an electrolyser, pure water (H2O) and separating it into hydrogen gas (H2) and oxygen gas (O2). In some embodiments, the method further comprises providing the flow of hydrogen gas to be heated from the electrolyser. The method may further comprise regulating, using a valve, the pressure of the flow of hydrogen gas from the electrolyser prior to heating in the heat exchanger.

[0093] In some embodiments, the fuel of the combustor assembly comprises hydrogen gas from the electrolyser and the oxidant of the combustor assembly comprises the oxygen gas from the electrolyser. The flow of exhaust gases received at the heat exchanger may comprise steam in the form of water vapour (H2O). The method may further comprise: receiving, at a condenser, the steam after use by the heat exchanger to condense the steam into pure water; and returning the pure water to the electrolyser for re-use.

[0094] In an thirteenth aspect, the present disclosure provides a calcination system comprising: at least one combustor assembly, wherein the at least one combustor assembly is the combustor assembly according to the second aspect of the present disclosure or any of the embodiments as disclosed herein; and at least one calcination component configured to calcinate a feed material, wherein the at least one calcination component is configured to receive the flow of exhaust gases from a final combustor component of the at least one combustor assembly to impart thermal energy to the feed material.

[0095] In some embodiments, the at least one combustor assembly comprises a calciner combustor assembly, and wherein the system further comprises: a calciner, wherein the calciner is configured to receive the feed material and the flow of exhaust gases from a final combustor component of the calciner combustor assembly to impart thermal energy to the feed material being processed by the calciner.

[0096] Additionally/alternatively, the at least one combustor assembly may comprise a kiln combustor assembly, and wherein the system further comprises: a kiln, wherein the kiln is configured to receive the feed material and the flow of exhaust gases from a final combustor component of the kiln combustor assembly to impart thermal energy to the feed material being processed by the kiln. In some embodiments, the kiln is configured to receive processed feed material from the calciner and heat the processed feed material using the flow of exhaust gases from the kiln combustor assembly.

[0097] In some embodiments, the calcination system further comprises a cooler configured to receive and cool the processed feed material from the at least one calcination component. The cooler may comprise a plurality of cooling zones in which heat is recovered from the processed feed material and deployed within the calcination system. The calcination system may comprise one or more of: a first cooling zone adjacent to the kiln, wherein heat recovered from the first cooling zone is provided to the kiln combustor assembly; a second cooling zone adjacent to the first cooling zone, wherein heat recovered from the second cooling zone is provided to the calciner combustor assembly; and a third cooling zone adjacent to an outlet of the cooler, wherein heat recovered from the third cooling zone is provided to a heat exchanger for cooling off-gas from the calciner and kiln. [0098] In some embodiments, the calcination system further comprises a preheater for heating the feed material to a desired temperature prior to delivery to the at least one calcination component. The heat exchanger may impart thermal energy to a flow of gases (e.g., CO2 with H2O) from the cooler which is provided to the preheater to heat the feed material.

[0099] In some embodiments, the calcination system further comprises an electrolyser configured to receive pure water (H2O) and separate it into hydrogen gas (H2) and oxygen gas (O2), wherein the at least one combustor assembly utilises the hydrogen gas from the electrolyser as the fuel and the oxygen gas from the electrolyser as the oxidant, and wherein the flow of exhaust gases from the final combustor component of the at least one combustor assembly comprises steam in the form of water vapour (H2O).

[0100] In some embodiments, the calcination system further comprises a condenser for receiving a mixture of carbon dioxide (CO2) and steam from the heat exchanger and/or preheater and condensing the gas mixture to produce a substantially pure gas flow of CO2 and substantially pure water. The system may be configured to return the substantially pure water from the condenser to the electrolyser for re-use.

[0101] In some embodiments, the calcination system further comprises an e-methanol synthesis unit for receiving the substantially pure gas flow of CO2 from the condenser and a flow of hydrogen gas from the electrolyser to produce liquid methanol. In some embodiments, the calcination system further comprises one or more blowers to circulate fluid flows within the system to maximise thermal energy recovery.

[0102] In a fourteenth aspect, the present disclosure provides a calcination method, comprising: providing at least one combustor assembly, wherein the at least one combustor assembly is the combustor assembly according to the second aspect of the present disclosure or any of the embodiments as disclosed herein; receiving, at at least one calcination component, the flow of exhaust gases from a final combustor component of the at least one combustor assembly; and calcinating a feed material, using the at least one calcination component, by imparting thermal energy from the flow of exhaust gases to the feed material.

[0103] In some embodiments, the at least one combustor assembly comprises a calciner combustor assembly, and wherein the method comprises receiving, at a calciner, the feed material and the flow of exhaust gases from a final combustor component of the calciner combustor assembly to impart thermal energy to the feed material being processed by the calciner.

[0104] In some embodiments, the at least one combustor assembly comprises a kiln combustor assembly, and wherein the method comprises receiving, at a kiln, the feed material and the flow of exhaust gases from a final combustor component of the kiln combustor assembly to impart thermal energy to the feed material being processed by the kiln. The method may further comprise receiving, at the kiln, processed feed material from the calciner and heating the processed feed material using the flow of exhaust gases from the kiln combustor assembly.

[0105] In some embodiments, the method further comprises receiving, at a cooler, the processed feed material from the at least one calcination component; and cooling the processed feed material using the cooler. The method may further comprise recovering heat from the processed feed material in a plurality of cooling zones of the cooler, and deploying the recovered heat within a calcination system. In some embodiments, the method comprises one or more of: recovering heat from a first cooling zone adjacent to the kiln, and providing the recovered heat to the kiln combustor assembly; recovering heat from a second cooling zone adjacent to the first cooling zone, and providing the recovered heat to the calciner combustor assembly; and recovering heat from a third cooling zone adjacent to an outlet of the cooler, and providing the recovered heat to a heat exchanger for cooling off-gas from the calciner and kiln.

[0106] In some embodiments, the method further comprises heating, using a preheater, the feed material to a desired temperature prior to delivery to the at least one calcination component. The method may further comprise providing, to the preheater, a flow of gases (e.g., CO2 with H2O) from the cooler to which thermal energy is imparted by the heat exchanger to heat the feed material.

[0107] In some embodiments, the method further comprises receiving, at an electrolyser, pure water (H2O) and separating it into hydrogen gas (H2) and oxygen gas (O2), wherein the at least one combustor assembly utilises the hydrogen gas from the electrolyser as the fuel and the oxygen gas from the electrolyser as the oxidant, and wherein the flow of exhaust gases from the final combustor component of the at least one combustor assembly comprises steam in the form of water vapour (H2O). [0108] In some embodiments, the method further comprises receiving, at a condenser, a mixture of carbon dioxide (CO2) and steam from the heat exchanger and/or preheater and condensing the gas mixture to produce a substantially pure gas flow of CO2 and substantially pure water. The method may further comprise returning the substantially pure water from the condenser to the electrolyser for re-use.

[0109] In some embodiments, the method further comprises: receiving, at an e-methanol synthesis unit, the substantially pure gas flow of CO2 from the condenser and a flow of hydrogen gas from the electrolyser; and producing liquid methanol from the gas flows of CO2 and hydrogen gas. In some embodiments, the method further comprises circulating, using one or more blowers, fluid flows within a calcination system to maximise thermal energy recovery.

[0110] In a fifteenth aspect, the present disclosure provides liquid methanol produced according to the method of the fourteenth aspect or any of the embodiments as disclosed herein.

[0111] In a sixteenth aspect, the present disclosure provides a pyrolysis component comprising: a main body comprising: a feed inlet configured to receive a feed material comprising at least one hydrocarbon; a preheat gas inlet configured to receive a preheat gas flow for preheating and mixing with the feed material in a preheating zone of the main body; and a main gas inlet configured to receive a main gas flow for heating a mixture of the preheated feed material and preheat gas flow in a cracking zone of the main body to produce a gas flow comprising one or more products.

[0112] In some embodiments, the pyrolysis component is configured to direct the mixture of the preheated feed material and preheat gas flow towards the cracking zone. The main body may further comprise an eductor zone between the preheating zone and the cracking zone to draw and/or accelerate the mixture of the preheated feed material and preheat gas flow towards the cracking zone. The main body may further comprise a sloped and/or profiled wall forming the eductor zone to draw and/or accelerate gases flow towards the cracking zone.

[0113] In some embodiments, the main body is shaped and/or dimensionally profiled to direct gases flow towards the cracking zone. The main body may be tapered from the preheating zone to a narrowed portion of the main body to accelerate gases flow towards the cracking zone. [0114] In some embodiments, the main gas inlet is axially oriented relative to the main body to direct the main gas flow towards the cracking zone. The main body may further comprise at least one nozzle in fluid communication with the main gas inlet to direct the gas flow towards the cracking zone.

[0115] The feed inlet and the preheat gas inlet may be positioned on the main body to provide interfacing flow streams of the feed material and the preheat gas flow. The feed inlet may be positioned on the sloped and/or profiled wall forming the eductor zone. The feed inlet and the preheat gas inlet may be angled towards the main gas inlet. The angling of the feed inlet and the preheat gas inlet may promote intimate mixing of the two fluids while effectively preheating the feed inlet prior to flowing towards the main gas inlet through the eductor zone.

[0116] In some embodiments, the main body further comprises an outlet to allow passage of a gas flow comprising the one or more products from the main body. The main body may further comprise a diverging portion that expands in dimension from the cracking zone to the outlet of the main body.

[0117] At least a portion of the cracking zone may be at a lower pressure than the preheating zone and/or the diverging portion of the main body. The cracking zone may comprise a throat section at the narrowest portion of the pyrolysis component. The throat section may be at a lower pressure than the preheating zone and/or the diverging portion of the main body. The cracking zone may be at a higher temperature than the preheating zone.

[0118] In some embodiments, the main body further comprises a fluid inlet to receive a fluid flow to reduce the temperature of the gas flow comprising the one or more products in a quenching zone of the main body adjacent the cracking zone. The main body may further comprise a plurality of nozzles configured to direct the fluid flow through a corresponding plurality of fluid inlets towards the quenching zone.

[0119] The main body may further comprise a plurality of nozzles configured to direct the feed material and/or the gas flow through a corresponding plurality of feed inlets and/or preheat gas inlets towards the preheating zone. The plurality of nozzles of the preheat gas inlets may circumferentially surround the main gas inlet at an end portion of the main body adjacent the preheating zone. [0120] In some embodiments, the main body further comprises a recycle feed inlet configured to receive recycled feed material comprising the at least one hydrocarbon, wherein the preheat gas flow preheats and mixes with the recycled feed material in the preheating zone of the main body.

[0121] In some embodiments, an interior of the main body, one or more inlets and/or an outlet of the main body comprise an insulating liner. The insulating liner may comprise a refractory and/or ceramic material. The insulating liner may comprise calcium silicates, alumina, magnesia, zirconia, or combinations thereof. An outer casing of the main body may be made of metal.

[0122] In some embodiments, the preheat gas flow and/or the main gas flow comprise steam in the form of water vapour (H2O). The one or more products may comprise at least one unsaturated hydrocarbon and/or hydrogen gas (H2). The at least one unsaturated hydrocarbon may comprise an olefin. The at least one unsaturated hydrocarbon may comprise ethylene.

[0123] In a seventeenth aspect, the present disclosure provides a pyrolysis system comprising: a pyrolysis component comprising: a main body comprising: a feed inlet configured to receive a feed material comprising at least one hydrocarbon; a preheat gas inlet configured to receive a preheat gas flow for preheating and mixing with the feed material in a preheating zone of the main body; and a main gas inlet configured to receive a main gas flow for heating a mixture of the preheated feed material and preheat gas flow in a cracking zone of the main body to produce a gas flow comprising one or more products; and a gas source for supplying the preheat gas flow and/or the main gas flow received at the main body of the pyrolysis component.

[0124] In some embodiments, the gas source comprises: at least one combustor assembly, wherein the at least one combustor assembly is the combustor assembly of the second aspect of the present disclosure or any of the embodiments as disclosed herein, wherein the flow of exhaust gases from the at least one combustor assembly supplies the preheat gas flow and/or the main gas flow received at the main body of the pyrolysis component.

[0125] In some embodiments, the gas source comprises: two combustor assemblies, wherein the two combustor assemblies each comprise the combustor assembly of the second aspect of the present disclosure or any of the embodiments as disclosed herein, wherein a first combustor assembly supplies the preheat gas flow received at the preheat gas inlet of the pyrolysis component, and a second combustor assembly supplies the main gas flow received at the main gas inlet of the pyrolysis component. [0126] In some embodiments, the supplied preheat gas flow and/or the main gas flow comprise steam in the form of water vapour (H2O). The gas source may further comprise an electrolyser configured to receive pure water (H2O) and separate it into hydrogen gas (H2) and oxygen gas (O2), wherein the at least one combustor assembly utilises the hydrogen gas from the electrolyser as the fuel and the oxygen gas from the electrolyser as the oxidant, and wherein the flow of exhaust gases from the final combustor component of the at least one combustor assembly comprises steam in the form of water vapour (H2O).

[0127] In some embodiments, the supplied preheat gas flow and/or the main gas flow comprise steam in the form of water vapour (H2O). The gas source further comprises an air separation unit (ASU) configured to produce oxygen gas (O2), wherein the at least one combustor assembly utilises hydrogen gas (H2) as the fuel and the oxygen gas produced from the air separation unit as the oxidant, and wherein the flow of exhaust gases from the final combustor component of the at least one combustor assembly comprises steam in the form of water vapour (H2O). The one or more products may comprise hydrogen gas (H2), and wherein at least some of the hydrogen gas is directed for use as the fuel of the at least one combustor assembly.

[0128] In some embodiments, the one or more products comprise at least one unsaturated hydrocarbon and/or hydrogen gas (H2). The at least one unsaturated hydrocarbon may comprise an olefin. The at least one unsaturated hydrocarbon may comprise ethylene. In some embodiments, the pyrolysis component comprises the pyrolysis component according to the sixteenth aspect of the present disclosure or any of the embodiments as disclosed herein.

[0129] In an eighteenth aspect, the present disclosure provides a pyrolysis method comprising: supplying a feed material comprising at least one hydrocarbon to a main body of a pyrolysis component; preheating and mixing the feed material with a preheat gas flow in a preheating zone of the main body; and heating a mixture of the preheated feed material and preheat gas flow in a cracking zone of the main body to produce a gas flow comprising one or more products.

[0130] In some embodiments, the pyrolysis method further comprises one or both of: supplying the preheat gas flow to a preheat gas inlet of the main body; and supplying the main gas flow to a main gas inlet of the main body. In some embodiments, supplying the preheat gas flow and/or the main gas flow comprises: receiving a flow of exhaust gases from at least one combustor assembly to supply the preheat gas flow and/or the main gas flow, wherein the at least one combustor assembly comprises the combustor assembly of the second aspect of the present disclosure or any of the embodiments as disclosed herein.

[0131] In some embodiments, the pyrolysis method further comprises providing the at least one combustor assembly; and receiving the flow of exhaust gases from the at least one combustor assembly to supply the preheat gas flow and/or the main gas flow. The pyrolysis method may further comprise providing two combustor assemblies, wherein the two combustor assemblies each comprise the combustor assembly of the second aspect of the present disclosure or any of the embodiments as disclosed herein; supplying the preheat gas flow from the flow of exhaust gases from a first combustor assembly; and supplying the main gas flow from the flow of exhaust gases from a second combustor assembly.

[0132] In some embodiments, gas source further comprises an electrolyser configured to receive pure water (H2O) and separate it into hydrogen gas (H2) and oxygen gas (O2), wherein the pyrolysis method further comprises providing to the at least one combustor assembly the hydrogen gas from the electrolyser as the fuel and the oxygen gas from the electrolyser as the oxidant, and wherein the flow of exhaust gases from the final combustor component of the at least one combustor assembly comprises steam in the form of water vapour (H2O).

[0133] In some embodiments, the gas source further comprises an air separation unit (ASU) configured to produce oxygen gas (02), wherein the pyrolysis method further comprises providing to the at least one combustor assembly the oxygen gas from the air separation unit as the oxidant and hydrogen gas (H2) as the fuel, and wherein the flow of exhaust gases from the final combustor component of the at least one combustor assembly comprises steam in the form of water vapour (H2O). The one or more products may comprise hydrogen gas (H2) and the pyrolysis method further comprises directing at least some of the hydrogen gas (H2) to the at least one combustor assembly for use as the fuel.

[0134] The pyrolysis method may further comprise reducing the temperature of the gas flow comprising the one or more products in a quenching zone of the main body adjacent the cracking zone. The step of reducing the temperature of the gas flow may comprise supplying a fluid flow to a fluid inlet of the main body to reduce the temperature of the gas flow in the quenching zone.

[0135] In some embodiments, the pyrolysis method further comprises recycling feed material in the one or more by-products to a recycle feed inlet of the pyrolysis component. The preheat gas flow and/or the main gas flow may comprise steam in the form of water vapour (H2O). The recycled feed material may comprise residual uncracked feed material in the one or more byproducts.

[0136] In some embodiments, the one or more products comprise at least one unsaturated hydrocarbon and/or hydrogen gas (H2). The at least one unsaturated hydrocarbon may comprise an olefin. The at least one unsaturated hydrocarbon may comprise ethylene. In some embodiments, the pyrolysis component comprises the pyrolysis component according to the sixteenth aspect of the present disclosure or any of the embodiments as disclosed herein.

[0137] In a nineteenth aspect, the present disclosure provides an unsaturated hydrocarbon produced according to the method of the eighteenth aspect of the present disclosure or any of the embodiments as disclosed herein.

[0138] In a twentieth aspect, the present disclosure provides an olefin produced according to the method of the eighteenth aspect of the present disclosure or any of the embodiments as disclosed herein.

[0139] In a twenty-first aspect, the present disclosure provides a pyrolysis assembly comprising a plurality of pyrolysis components arranged in parallel, wherein the plurality of pyrolysis components each comprise a pyrolysis component according to the sixteenth aspect of the present disclosure or any of the embodiments as disclosed herein.

[0140] In some embodiments, the pyrolysis assembly is configured to be retrofit to an existing pyrolysis system. The plurality of pyrolysis components may be configured for individual collection of the gas flow comprising the one or more products. Alternatively, the plurality of pyrolysis components may be configured for common collection of the gas flow comprising the one or more products. An outlet of each pyrolysis component may be coupled with a pressurised plenum for common collection of the gas flows comprising the one or more products.

Brief Description of Drawings

[0141] The present disclosure will now be described in greater detail with reference to the accompanying drawings in which like features are represented by like numerals. It is to be understood that the embodiments shown are examples only and are not to be taken as limiting the scope of the present disclosure as defined in the claims appended hereto. [0142] Figure 1 is a perspective cross-sectional view of a combustor component comprising a combustion chamber illustrating a cyclonic flow pattern of the gas flow of the fuel, according to some embodiments of the disclosure.

[0143] Figure 2 is a perspective cross-sectional view of another combustor component comprising a combustion chamber illustrating a cyclonic flow pattern of the gas flow of the fuel and having an insulating liner, according to some embodiments of the disclosure.

[0144] Figure 3 is a schematic diagram showing a combustor assembly including a plurality of combustor components arranged sequentially for staged combustion in a linear arrangement, where different lines shown in the key represent distinct fluid flows interacting with the combustor assembly, according to some embodiments of the disclosure.

[0145] Figure 4 is a perspective view showing another combustor assembly including four combustor components with two combustor components in the first stage (100-1) and one combustor component in each of the second and third stages (100-2 and 100-3), and demonstrating non-linear arrangement of the combustor assembly, according to some embodiments of the disclosure.

[0146] Figure 5 is a schematic diagram showing another combustor assembly including a plurality of combustor components arranged sequentially for staged combustion in a linear arrangement and having diluent added to the fuel provided to a first combustor component, where different lines shown in the key represent distinct fluid flows interacting with the combustor assembly, according to some embodiments of the disclosure.

[0147] Figure 6 is a schematic diagram showing another combustor assembly including a plurality of combustor components arranged sequentially for staged combustion in a linear arrangement and with temperature control (attemperating) of the flow of the exhaust gases exiting each combustor component to maintain a constant target temperature into a downstream combustor component, where different lines shown in the key represent distinct fluid flows interacting with the combustor assembly, according to some embodiments of the disclosure.

[0148] Figure 7 is a schematic diagram illustrating a process cycle configuration utilising the combustor assembly according to Figure 6 to achieve electrification of high temperature thermal energy supply to an industrial process, where different lines shown in the key represent distinct fluid flows in the process cycle, according to some embodiments of the disclosure.

[0149] Figure 8 is a schematic diagram illustrating a process cycle configuration utilising the combustor assembly having the features illustrated in Figures 5 and 6 using a diluent in the gas flow of the fuel to achieve electrification of high temperature thermal energy supply to an industrial process, where different lines shown in the key represent distinct fluid flows in the process cycle, according to some embodiments of the disclosure.

[0150] Figure 9 is a schematic diagram illustrating alternative process cycle configurations for: a) heating of hydrogen gas for use in an external process using the combustor assembly of Figure 6, and b) production of a mixture of hydrogen and steam through incomplete combustion of hydrogen in another combustor assembly, where different lines shown in the key represent distinct fluid flows in the process cycle, according to some embodiments of the disclosure.

[0151] Figure 10 is a cross-sectional view of a combustor component illustrating dimensional parameters for design of the desired product steam pressure and temperature, in view of the combustor assembly, according to some embodiments of the disclosure.

[0152] Figure 11 is a schematic diagram illustrating a control system for controlling the combustor assembly to deliver the process steam at the desired composition, pressure and/or temperature while meeting the flow demands of the downstream industrial process, where solid lines represent electrical connections/communications between the controller(s) and various components, and the dashed/broken lines correspond to distinct fluid flows in the key of Figure 5, according to some embodiments of the disclosure.

[0153] Figure 12 is a perspective view of another combustor component comprising three inlet nozzles which are circumferentially arranged and at a substantially tangential angle relative to a cylindrical portion of the combustor component, according to some embodiments of the disclosure.

[0154] Figure 13 is a cross-sectional view of the combustor component of Figure 12 comprising a combustion chamber which includes heat transfer membrane walls, according to some embodiments of the disclosure. [0155] Figure 14 is a cross-sectional view of the combustor component of Figure 12 comprising a combustion chamber including a plurality of injection nozzles for distributing diluent within the combustion chamber to assist with the combustion process, according to some embodiments of the disclosure.

[0156] Figure 15 is a chart illustrating the flammability range corresponding to the hydrogen concentration in the presence of minimal oxygen in the first stage of the combustor assembly according to some embodiments of the disclosure.

[0157] Figure 16 is a chart illustrating the flammability range of hydrogen-oxygen-steam mixtures for establishing stable combustion in subsequent stages of the combustor assembly according to some embodiments of the disclosure.

[0158] Figure 17 is a flow chart illustrating steps in a method for staged combustion of a fuel with an oxidant, according to some embodiments of the disclosure.

[0159] Figure 18 is a flow chart illustrating steps in a method for producing high temperature thermal energy for an external process using electrolysis and a combustor assembly, according to some embodiments of the disclosure.

[0160] Figure 19 is a flow chart illustrating steps in another method for producing high temperature thermal energy for an external process using electrolysis and a combustor assembly, with optional recycling of steam after use by the external process, according to some embodiments of the disclosure.

[0161] Figure 20 is a flow chart illustrating steps in a method for producing high temperature hydrogen gas for use in an external process, according to some embodiments of the disclosure.

[0162] Figure 21 is a schematic diagram illustrating a process cycle configuration utilising the combustor assembly according to embodiments of the disclosure to achieve electrification of high temperature thermal energy supply for calcination and optional e-methanol production, where different lines shown in the key represent distinct fluid flows/materials in the process cycle, according to some embodiments of the disclosure. [0163] Figure 22 is a flow chart illustrating steps in a method for producing high temperature thermal energy for calcination and optional e-methanol production, according to some embodiments of the disclosure.

[0164] Figure 23 is a schematic diagram illustrating a steam cracker with dual furnace arrangement of the current technology.

[0165] Figure 24 is a flow diagram illustrating the cracking process using the steam cracker of Figure 23.

[0166] Figure 25 is schematic diagram of a pyrolysis component, in cross-sectional view taken along the axis X-X’ shown in Figure 26, according to some embodiments of the disclosure.

[0167] Figure 26 is an end view of the pyrolysis component of Figure 25 illustrating the circumferential positioning of the preheat gas and feed/recycle feed nozzles relative to a central main gas nozzle, according to some embodiments of the disclosure.

[0168] Figure 27 illustrates dimensional parameters of the pyrolysis component of Figure 25, according to some embodiments of the disclosure.

[0169] Figure 28 is another schematic diagram of the pyrolysis component of Figure 25 illustrating the functional zones and flow arrangements in the main body of the pyrolysis component, according to some embodiments of the disclosure.

[0170] Figure 29 is another schematic diagram of the pyrolysis component of Figure 25 illustrating the temperature ranges in the functional zones of the main body of the pyrolysis component, according to some embodiments of the disclosure.

[0171] Figure 30 is another schematic diagram of the pyrolysis component of Figure 25 illustrating the pressure ranges in the functional zones of the main body of the pyrolysis component, according to some embodiments of the disclosure.

[0172] Figure 31 is another schematic diagram of the pyrolysis component of Figure 25 illustrating dimensional parameters of the pyrolysis component, according to some embodiments of the disclosure. [0173] Figure 32 is a flow diagram of a pyrolysis system comprising the pyrolysis component and a gas source, which may optionally comprise one or more combustor assemblies and an electrolysis sub-unit, according to some embodiments of the disclosure, where the features shown in broken lines are optional/preferable features of the system and the different lines shown in the key represent distinct fluid flows in the system.

[0174] Figure 33 is a flow diagram of another pyrolysis system comprising the pyrolysis component and a gas source, which may optionally comprise one or more combustor assemblies and an air separation unit sub-system, according to some embodiments of the disclosure, where the features shown in broken lines are optional/preferable features of the system and the different lines shown in the key represent distinct fluid flows in the system.

[0175] Figure 34 is a chart illustrating theoretical equilibrium conversion for the dehydrogenation of ethane (C2H6), propane (C3F ) and isobutane (C4H10) at 1 bar, and a comparison of the conversion ratio and reaction temperature for the pyrolysis component according to some embodiments of the disclosure.

[0176] Figure 35 is a flow chart illustrating steps in a pyrolysis method according to some embodiments of the disclosure, where the steps shown in broken lines are optional/features steps of the method.

[0177] Figure 36 is a schematic diagram showing a pyrolysis assembly which is retrofit to an existing pyrolysis system or steam cracker, with a common collection plenum for the gas flow with the one or more products, according to some embodiments of the disclosure.

[0178] Figure 37 is a schematic diagram of another pyrolysis assembly which is retrofit to an existing pyrolysis system or steam cracker, with individual collectors for the gas flow with the one or more products, according to some embodiments of the disclosure.

Description of Embodiments

[0179] Embodiments of the present disclosure are discussed herein by reference to the drawings which are not to scale and are intended merely to assist with explanation of the present disclosure. [0180] Reference herein to a “flame” or flame-related characteristics is to be interpreted as meaning a combustion reaction zone and its characteristics, respectively. While stating this, it is recognised that, in fact, the combustion of pure hydrogen with pure oxygen using the methodology described in this disclosure could as well result in an invisible flame, unlike a visible flame as in the case of hydrocarbon combustion.

[0181] Reference herein to a “stream” of a gas or gases, such as a fuel stream, oxidant stream and exhaust stream, is to be interpreted as meaning a flow of the gas or gases. The wording of a “stream” is not to be limited necessarily to a continuous flow of the gas or gases and embodiments of the disclosure may include variable flow of the gas or gases. Furthermore, the wording of a “stream” is not to be limited necessarily to flow of the gas in a specified direction and embodiments of the disclosure may include the flow of the gas or gases changing direction in various arrangements of the disclosure.

[0182] Reference herein to “high temperature” is to be interpreted as meaning a flow of exhaust gases (e.g., steam) generated at a minimum temperature to achieve combustion of a fuel in an oxidant, and specifically in the context of hydrogen-oxygen combustion in the possible presence of a diluent fluid or its absence, the high temperature may be at least about 500 degrees Celsius. High temperature may also refer to a temperature in a range of at least about 500 degrees Celsius to about 2000 degrees Celsius, and preferably, in a range of at least about 500 degrees Celsius to about 1500 degrees Celsius, which is specifically in the context of hydrogen-oxygen combustion in the possible presence of a diluent fluid or its absence. The temperature range for combustion of other fuels in oxygen would be appreciated by a person skilled in the art. The exhaust gases (e.g., steam) may also have a final temperature designed to match the desired high temperature of a certain process demand, e.g., of an industrial process.

[0183] Embodiments of the disclosure may be directed to controlled, safe and stable combustion of pure hydrogen (H2) as the fuel with pure oxygen (O2) as the oxidant. The combustion process may be distributed over sequentially arranged novel cyclonic fuel flow non-premix combustor components to form a composite combustor assembly, thus generating steam (H2O) to provide high temperature thermal energy to an external process. The external process may comprise large-scale industrial processes such as alumina refining, cement manufacture, steel making, fertilizer production, mineral processing, food processing and similar applications. [0184] This system of combustion may further uniquely generate most of its own diluent (steam) in its preceding stages, which is required for the safe and stable combustion of hydrogen with oxygen, thus greatly minimising or even eliminating the need for external diluents.

[0185] Combustion of hydrogen is challenged by its unique combustion characteristics (very low ignition energy: one-fifteenth of natural gas in air, very wide flammability range in air: 4% to 94% as compared to 5% to 15% of methane, and extremely high flame speed: 8 times of natural gas), which are particularly aggravated when combusting it with pure oxygen, making the combustion explosive in nature, challenging the ability to hold a stable flame within a combustor. The innovative idea of this novel combustor is to sequentially divide and systematically and intentionally exploit only portions of the wide flammability range of hydrogen combustion in oxygen in each stage, thereby achieving a safe and stable sequential combustion system for burning pure hydrogen in the presence of pure oxygen, thus producing high temperature thermal energy in the form of steam.

[0186] Hydrogen, when burnt in the presence of oxygen, combusts explosively due to hydrogen’s low ignition energy, high flame speed and large energy release. When hydrogen gas is burnt with oxygen gas the molecular bonds between the individual gas molecules are broken to form new bonds between hydrogen and oxygen atoms, forming steam while releasing heat of combustion. In its simplest form, the reaction can be summarised as below:

2H₂(gas) + O₂(gas) —> 2H₂O steam) + 286,000 Joules heat)

[0187] However, this combustion being explosive, is difficult to control on its own. Sustaining the hydrogen with oxygen combustion flame in a combustion chamber is not possible without the addition of inert diluents in the hydrogen fuel. Such diluents can be steam, or mostly inert gases like carbon dioxide or nitrogen.

[0188] The intended function of some embodiments of the present disclosure therefore is to distribute the combustion of supplied fuel (e.g., hydrogen gas) over multiple stages, such that the combustion is mostly starved of the oxidant (e.g., oxygen gas) at every stage until the final stage but is sufficient to produce and sustain combustion at every stage at the desired temperature. Combustion in the first stage exploits the wide flammability range of hydrogen when burning with pure oxygen. Thus, the first stage receives only enough oxygen such that the hydrogen concentration approaches the upper flammability limit of approximately 96%. Combustion in the first stage may be initiated using an electric spark. The combustion product of the first stage, while consuming all the oxygen supplied, thus contains the produced steam and mostly unburnt hydrogen. This produced steam then acts as a diluent for the next stage allowing a greater percentage of hydrogen to be burnt with a separate stream of oxygen introduced in this subsequent stage. The produced steam thus increases in each stage, resulting in increased diluent production, allowing for greater fractions of supplied hydrogen fuel to be burnt with oxygen.

[0189] The molar chemical reactions across the n stages of combustion, with each stage receiving a fraction x_lt x₂, x₃ ••• x_n, of the total oxygen supply such that xi +^x2 +^x3 + — I- x_n = 1.0, can therefore be summarised as follows:

2H₂ + x₁O₂ 2x₁H₂O + 2(1 — X₁)H₂ for the first stage;

2(1 - X_X)H₂ + x₂O₂ -> 2(%i + x₂)H₂O + 2(1 - Xi - x₂')H₂ for the second stage, in the presence of 2x₁H₂O (steam) from the preceding stage as diluent, and so on

2(1 - Xi - x₂ -^x_n-i)H₂ + x_nO₂ -> 2(Xi + x₂ + ••• + x_n)H₂0 + 2(1 - x₁ - x₂ -^xn)H₂ for the n^th stage, in the presence of increasing steam diluent, where all the oxidant is consumed with the fuel hydrogen being completely burnt into high temperature steam.

[0190] Referring to Figures 15 and 16 before detailing the novel combustor component and combustor assembly, charts are shown illustrating flammability characteristics relating to combustion of hydrogen in oxygen. Figure 15 depicts the flammability range corresponding to the hydrogen concentration in the presence of minimal oxygen in the first stage of a novel combustion chamber. The hydrogen concentration is at least about 96% concentration in O₂ at the first combustor Stage with an adiabatic flame temperature range of about 600 degrees Celsius to about 1500 degrees Celsius, and preferably, at least about 1100 degrees Celsius. Figure 16 illustrates the flammability range of hydrogen-oxygen-steam (H2-O2-H2O) mixtures, at pressures near atmospheric, for establishing stable combustion in subsequent stages of a novel combustion chamber of a combustion assembly. The hydrogen concentration reduces from an initial concentration of about 96% in O2 (no steam) across the multiple combustor stages in an approximately linear function as the diluent steam concentration (volume % of the mixture) increases. The steam concentration increases through the subsequent combustion stages to at least about 80% of the volume of the H2-O2-H2O steam mixture, to in a range of about 70% volume to about 85% volume, and preferably, at least about 80% volume in the final stage. The spray-addition of water for temperature control (attemperating), in some embodiments of the disclosure, offers a direct means of adjusting the amount of diluent steam for subsequent combustor stages. The concentrations of hydrogen and steam, in the presence of oxygen may be adjusted for the desired adiabatic flame temperature and operating pressure, while ensuring the overall objective of staying in proximity to the upper flammability limit using the supply of limited oxidant thereby producing pure steam at the final combustor outlet.

[0191] Under special circumstances like startup, and to reduce the capital expenditure of the novel composite combustor assembly, embodiments of the disclosure may utilise an inert diluent gas in the first stage of the combustion assembly. This variation will be described in more detail with reference to Figures 5 and 8.

[0192] When the produced steam through the aforementioned novel combustion process can be mostly recovered as condensed water, after imparting its heat to the industrial process, the hydrogen and oxygen gases are expected to be generated through electrolysis of this recycled water forming a mostly closed process cycle (see Figures 7 and 8). A small stream of fresh treated water could be utilised as make-up for cycle losses due to process requirements or a bleed stream for chemistry control. Thus, such mostly closed cycle, enabled by the aforementioned embodiments of the disclosure, serves to convert electrical energy into high grade (temperature) thermal energy with zero emissions to the environment by displacing the use of fossil fuels currently used for steam generation for these industrial processes. Thus, this innovation provides a pathway for electrification of large-scale high temperature thermal energy generation, paving the way for future decarbonisation of the process industry sector.

[0193] When the electricity is sourced through renewable green electric power generation sources (e.g., solar, wind, hydro, biomass, etc.) or nuclear energy, this solution achieves decarbonisation of the process industry sector by displacing the use of fossil fuels currently used for thermal energy production.

[0194] In another energy storage application, to address the variable nature of renewable energy production, the electrolysis of stored water produces stores of gaseous hydrogen and oxygen during periods when affordable renewable electricity is available. Subsequently, during periods when renewable electricity is unaffordable or unavailable, the stored hydrogen and oxygen gases are combusted in the aforementioned novel combustor to produce steam, which when expanded in a turbine produces electricity through a mechanically coupled electricity generator.

[0195] In another application, the aforementioned novel composite combustor assembly allows holding a green ammonia synthesis converter at operating temperature, in the absence of availability of affordable green hydrogen supply as the feedstock. In this application, the aforementioned novel composite combustor assembly can combust stored green hydrogen with pure oxygen to produce heat for a green ammonia synthesis process, when it is temporarily shutdown due to lack of availability of affordable green hydrogen for ammonia synthesis, when renewable electricity prices are high or renewable electric supply is unavailable due to its variable nature of generation. The amount of hydrogen required to be stored for use in the aforementioned novel composite combustor assembly, to maintain the ammonia synthesis converter at high temperature, when the synthesis process is not operating, is significantly smaller than storing hydrogen required for operating the ammonia synthesis process at its minimum allowable turndown (typically, in excess of 50% throughput). Thus, the aforementioned novel composite combustor assembly may significantly reduce the capital expenditure of a green ammonia synthesis facility by drastically reducing the size of required green hydrogen storage. In addition, by preventing cooling of the green ammonia synthesis converter, the use of the novel composite combustor assembly may reduce the levelized cost of ammonia produced, benefiting the economics of green ammonia synthesis. Otherwise, a shutdown and subsequent startup of an ammonia synthesis plant is unaffordable on a diurnal or routine basis.

[0196] In another application, the aforementioned novel composite combustor assembly may allow for calcination of calcium carbonate which yields a nearly pure stream of carbon dioxide, which can then be converted into e-methanol, a synthetic sustainable fuel produced using green electricity. In this application, the calcination process is decarbonised while producing a sustainable fuel e.g., to further decarbonise the transportation sector. Cement manufacturing processes are responsible for more than 8% of planet-warming carbon dioxide emissions. Calcination emissions remain stubbornly high - the development and deployment of new technologies is essential to get on track in limiting global warming to a maximum of 1.5°C by 2050. Today, heat required for calcination is produced by combustion of fuels. CO2 is formed through calcination of limestone (-65%; CaCO3- CaO+CO2), as example, and fuel combustion (-35%). About 60% of the fuel energy is supplied in the calciner in case of cement production as example, and the remaining 40% in the rotary kiln. High gas temperatures are required in the calciner (~900°C for cement production) and rotary kiln (~1400°C for cement production) to obtain a proper product quality. In the future, when green energy replaces fossil energy, calcination processes may have to be driven by electricity to a greater extent than today.

Combustor Component

[0197] Figure 1 illustrates an individual combustor component 100 comprising a combustion chamber 101. The combustion chamber 101 comprises an oxidant inlet 106 configured to receive a gas flow of an oxidant 105, a fuel inlet 114 configured to receive a gas flow of a fuel 102 into the combustion chamber 101, and a gases outlet 109 configured to allow passage of a flow of exhaust gases 113 from the combustion chamber 101. While Figure 1 illustrates a flanged connection for the gases outlet 109, this could be a welded connection to a downstream pipe or duct connection (see outlet 729 described with reference to Figure 10), as would be appreciated by a person skilled in the art. The combustor component 100 is configured to facilitate separation of the gas flows of the oxidant 105 and the fuel 102 entering the combustion chamber 101 prior to combustion of the fuel with the oxidant.

[0198] The construction of the individual combustor component 100 is especially suited to avoid any premix of oxygen and fuel hydrogen as it is admitted into the combustion chamber 101. Figure 1 illustrates that the gas flows of the oxidant 105 and the fuel 102 are moving in opposite directions upon entering the combustion chamber 101. The gas flow of the oxidant 105, also referred to as the oxidant stream, enters the combustion chamber 101 through the oxidant inlet 106 and is directed towards the gases outlet 109. The gas flow of the fuel 102, also referred to as the fuel stream, enters the combustion chamber 101 through the fuel inlet 114 and is directed towards the oxidant inlet 106 in a cyclonic flow pattern 104 where the fuel molecules acquire a strong angular momentum allowing it to spiral towards the oxidant inlet.

[0199] The novel combustor component 100 proposed herein comprises a combustion chamber lOlthat encloses the combustion reaction which occurs in a combustion zone 111 and is designed to withstand the operating temperatures and pressures. The fuel stream 102 may comprise pure hydrogen (H2), or a mixture of hydrogen and steam generated from a preceding stage, or a mixture of hydrogen (H2) and a diluent gas (external supply of steam, or carbon dioxide gas or nitrogen gas). The combustor component 100 is configured to direct the gas flow of the fuel 102 towards the oxidant inlet 106 upon entering the combustion chamber 101 through the fuel inlet 114. The fuel stream 102 is introduced at high velocity, in a range of about 10 m/s to about 35 m/s, and preferably at about 20 m/s, and tangentially into the combustion chamber

101 through a nozzle 103 in fluid communication with the fuel inlet 114. The nozzle 103 is angled relative to the combustion chamber 101 such that the gas flow of the fuel 102 is directed at or along an internal wall 115 of the combustion chamber 101. The nozzle 103 may be angled tangentially relative to the combustion chamber 101 in order to impart a tangential flow pattern 104 to the gas flow of the fuel 102 upon entering the combustion chamber 101 through the fuel inlet 114.

[0200] The nozzle 103 and the fuel inlet 114 are positioned adjacent to the gases outlet 109 as shown in Figure 1. However, the nozzle 103 could also be placed at any location along the axial length of the combustor component 100 to best enhance and reinforce the high velocity tangential and cyclonic flow pattern 104 in the combustion chamber 101 (not shown). Although a single nozzle 103 is illustrated in Figure 1, a plurality of nozzles may be provided in some embodiments which are configured to direct the gas flow of the fuel 102 through a corresponding plurality of fuel inlets 114 into the combustion chamber 101. Possible configurations with three nozzle inlets 103A, 103B and 103C are shown in Figures 10 to 12. The plurality of nozzles 103 A, 103B and 103C and the corresponding plurality of fuel inlets 114A, 114B and 114C may be circumferentially spaced on an external surface 116 of the combustion chamber 101, and may be equally spaced around the combustion chamber 101, in order to further reinforce the high velocity tangential flow pattern 104 into the combustion chamber 101. The plurality of nozzles may include at least two nozzles, or at least three nozzles, or at least four nozzles, or any number of nozzles and a corresponding number of the plurality of fuel inlets to best enhance and reinforce the tangential flow pattern 104 of the gas flow of fuel 102 in the combustion chamber 101.

[0201] The tangential flow pattern 104 may be a cyclonic flow pattern of the gas flow of the fuel

102 around the internal wall 115 of the combustion chamber 101 as it moves towards the oxidant inlet 106. The introduced fuel stream 102 is directed into a high velocity strong cyclonic swirling flow pattern 104 by the influence of one or more of the shape and/or dimensional profile of the combustion chamber 101, the dimensions of a shield portion 108 and profiles and dimensions of other various internal components, which are described later in Figure 10.

[0202] In particular, the combustion chamber 101 may be shaped and/or dimensionally profiled to direct the gas flow of the fuel 102 towards the oxidant inlet 106. The combustion chamber 101 may comprise a tapered portion 117 located between the gases outlet 109 and the oxidant inlet 106 to direct the gas flow of the fuel 102 towards the oxidant inlet 106. The tapered portion 117 may reduce in dimension towards the oxidant inlet 106. The tapered portion 117 as shown in Figure 1 is substantially conically-shaped, although it would be appreciated that other shapes may be adopted that produce a tapered portion 117 towards the oxidant inlet 106.

[0203] The combustor component 100 further comprises a shield portion 108, also referred to as a vortex shield, and is illustrated in Figure 1 as a tubular portion extending into an interior 118 of the combustion chamber 101 and in fluid communication with the gases outlet 109. The role of the shield portion 108 is to provide separation between the gas flow of the fuel 102 entering through the fuel inlet 114 and the flow of exhaust gases 113 exiting through the gases outlet 109. The shield portion 114 may be tubular in shape with a substantially constant cross-section extending from the interior 118 of the combustion chamber 101 to the gases outlet 109 thereby providing a path for the flow of exhaust gases 113 from the combustion zone 111 and exiting the combustion chamber 101. However, it should be appreciated that the shield portion 108 may adopt various cross-sectional shapes and may not be tubular in some embodiments. The shield portion 108 may be shaped and/or dimensionally profiled to direct flow of the fuel 102 at or along an internal wall 115 of the combustion chamber 101 and/or towards the oxidant inlet 106. The positioning of the fuel inlet 114 being adjacent to the gases outlet 109 further facilitates separation of the gas flows of the oxidant 105 and the fuel 102 prior to combustion.

[0204] Furthermore, the combustor component 100 may comprise a cylindrical portion 121 as shown in Figure 1 with a substantially constant cross-section in which the shield portion 108 extends and the fuel inlet 114 is located. The cylindrical portion 121 may be adjacent to the tapered portion 117 of the combustion chamber 101. In other embodiments, the cylindrical portion 121 may not be provided and the entire combustion chamber 101 from the oxidant inlet 106 to the gases outlet 109 may be tapered and have a substantially conical shape.

[0205] The combustor component 100 is further configured to direct the gas flow of the oxidant 105 towards a combustion zone 111 of the combustion chamber 100. A stream of gaseous oxygen 105 is introduced at high velocity through the oxidant inlet 106. The oxidant inlet 106 may be dimensioned to limit an amount of oxidant, e.g., oxygen gas, delivered to the combustion zone 111 of the combustion chamber 101 so that the oxidant is substantially or entirely consumed during combustion with the fuel. The oxidant inlet 106 may have an internal diameter which is sized to limit the flow of oxygen, and thus control the combustion process within the combustion chamber 101. The oxidant inlet 106 may have an internal diameter sufficient to produce a jet flow of the oxidant (e.g., at high velocity, in a range of about 10 m/s to about 25 m/s, preferably at about 15 m/s, and/or in a specified direction) into the combustion chamber 101.

[0206] Figure 1 illustrates that the combustor component 100 may further comprise a guide portion 119 extending into an interior 118 of the combustion chamber 101 and in fluid communication with the oxidant inlet 106 to position the gas flow of the oxidant 105 in the combustion zone 111 of the combustion chamber 101. The guide portion 119 may extend axially into the interior 118 of the combustion chamber 101 and be substantially co-axial with the gases outlet 109 to direct the gas flow of the oxidant 105 towards the gases outlet 109. The guide portion 119 may be a tubular portion having a substantially constant cross-section from the oxidant inlet 106 to an opening 120 of the guide portion 119 adjacent the combustion zone 111.

[0207] It will be appreciated that the guide portion 119 may have a length that assists in positioning the flame or the combustion zone 111 in the combustion chamber 101, such that this flame does not impinge on the opening 120 for a range of flow rates of the fuel 102 and oxidant 105. This length of the guide portion 119 further allows a small portion of the fuel stream 102 to reverse direction around the conical cover 107 and approach the combustion zone 111 from behind, further assisting in stabilizing the flame hold. Thus, the guide portion 119 may project the gas flow of the oxidant 105 into the combustion zone 111 through the jet flow and also extension into the interior of the combustion chamber 101. The guide portion 119 may project inside the tapered portion 117 in a range from about 10 percent of the axial length of the tapered portion 117 to about 70 percent of the axial length of the tapered portion 117, but preferably about 30 percent of the axial length of the tapered portion 117. The internal diameter of the guide portion 119 is sized to be sufficient to produce a jet flow at a desired velocity of the oxidant exiting the opening 120 of the guide portion 119. Although the guide portion 119 is illustrated as tubular and/or cylindrically-shaped and with a substantially constant cross-section, it will be appreciated that the shape and/or diameter may vary from that shown in Figure 1. [0208] Figure 1 illustrates that the combustion chamber 101 may further comprise a cover portion 107 at least partly surrounding the guide portion 119. The cover portion 107 may be tapered from the oxidant inlet 106 towards the opening 120 of the guide portion 119, thereby reducing in dimension towards the opening 120. The cover portion 107 may be conically-shaped. The conical end cover 107 enwraps and supports the oxidant guide portion 119, and protrudes axially deep into the combustion chamber 101, thereby assisting in positioning the flame, that is the oxidant for combustion in the combustion zone 111. The design dimensions and conical profile of combustion chamber 101, the diameter of the inlet nozzle 103, the number of inlet nozzles (where a plurality of nozzles and corresponding fuel inlets are provided), and the axial protrusion of the conical end cover 107 along with the oxidant guide portion 119 forming the jet flow of the oxidant, are intentionally designed to create this strong cyclonic swirling flow pattern 104 of the fuel stream 102 that swirls adhering to the tapering and narrowing body of the combustion chamber 101, while moving in a cyclonic flow pattern 104 towards and around the protruding conical end cover 107. The strong cyclonic flow pattern 104 may prevent buoyancy effects to affect the produced combustion zone 111.

[0209] Thus, in this novel combustor component design the fuel is admitted and flowed largely opposite to the oxidant entry unlike known combustors where the fuel and oxidant are largely admitted mostly flowing in the same direction, before forming the flame or combustion zone. In addition, unlike the known combustors there is no pre-mixing of hydrogen with its oxidant, eliminating associated risks of spontaneous combustion or flashback into the fuel supply system. Upon arriving at the narrowest conical portion 107 of the combustion chamber 101, the fuel stream 102 is forced to reverse direction and flow out of the combustion chamber 101 largely along the central axis 125 (see Figure 14), in an axial direction towards the combustor gases outlet 109 comprising an exit nozzle which extends beyond a body of the combustion chamber 101. Herein, the fuel mostly cylindrically, and axially mixes with the co-axially flowing oxygen jet 102 and sustains an ignited flame or combustion zone 111.

[0210] Another novel aspect of this combustor component design is to exploit the very high upper flammability range of hydrogen combustion with oxygen. Consistent with this, the internal diameter of the oxidant supply jet 106 substantially constricts and limits the oxygen supply to the combustion chamber 101, thereby providing a substantially fuel-rich environment and ensuring all oxygen supplied through the oxidant supply jet 106 is rapidly consumed, and remaining unburnt fuel leaves the combustor 100 through the exhaust stream 113 for combustion in subsequent stages of such combustors which may be arranged in series. The exhaust stream 113 thus contains a mixture of the produced steam as a product of combustion and unburnt hydrogen.

[0211] Figure 2 illustrates an embodiment of another combustor component 100 which includes a combustion chamber 101 with corresponding features having the same reference numbers as the combustor 100 of Figure 1. The combustor component 100 includes a pressure-containing metallic shell or outer layer 116 which is internally lined with an insulating liner 110. The insulating liner 110 may comprise a refractory and/or ceramic material capable of withstanding heat from the combustion reaction. The refractory and/or ceramic material may comprise, for example, calcium silicates, alumina, magnesia, zirconia, or combinations thereof. The insulating liner 110 may line internal walls 115 of the outer shell 116 and may form and/or line a wall of the gases outlet 108 and/or the conical portion 107 that surrounds the guide portion 119. Thus, the combustion reaction may be insulated and heat-resistively contained by the insulating liner 110 and within the pressure-containing outer shell 116.

[0212] The outer layer 116 of the combustor component 100 may be made of a base metal which is coated internally with the insulating liner 110. The external metallic housing 116 of the combustor component 100 may comprise a metal capable of withstanding temperatures up to around 400°C. The base metal may comprise, for example, carbon steel, stainless steel, cast iron, cast steel, aluminum, titanium, galvanised steel, other similar base metals or alloys thereof. The insulating liner 110 may comprise refractory and/or ceramic materials of suitable thickness to withstand the operating conditions and form a thermal barrier coating, protecting the base metal by drastically slowing down heat transfer to the base metal. The insulating refractory liner 110 ideally protects the outer metallic shell 116 from exposure to any higher temperatures than the base metal’s capability. The outer metallic shell 116 also provides means of welding anchors (not shown) that enable adherence of insulating refractory, and provides internal reinforcement to the refractory material. When provision for thermal expansion is provided for in the form of expansion joints (not shown) within the refractory material, provision can be made for suitable purge to ensure that hot gases from the reaction zone 111 do not migrate towards the outer metallic shell 116.

Combustor Assembly

[0213] Figure 3 illustrates a schematic representation of a combustor assembly 201 for staged combustion of a fuel with an oxidant. The different lines shown in the key represent distinct fluid flows interacting with the combustor assembly 201. The combustor assembly 201 comprises a plurality of combustor components 100 (suffixed by the sequential numbers -1, -2 and so on to - n) which are arranged sequentially for staged combustion of the fuel with the oxidant. In this embodiment, the combustor components 100 are in a linear arrangement. Each combustor component 100 comprises a combustion chamber 101. At least one subsequent combustor component 100 is configured to receive a flow of exhaust gases 207 (suffixed by the sequential numbers -1, -2 and so on to -n) from a preceding combustor component 100-(l-n) as the fuel for combustion with a gas flow of the oxidant 205 in the at least one subsequent combustor component 100-(n-l). The flow of exhaust gases 207 produced from each combustor component 100 comprises a proportion of the fuel 203 provided to a first combustor component 100-1 which reduces in proportion to substantially none of the fuel provided to the first combustor component 100-1 being present in the flow of the exhaust gases 211 from a final combustor component 100- n.

[0214] Although Figure 3 schematically illustrates each combustor component 100 (suffixed by the sequential numbers -1, -2 and so on to -n) to be of identical size, these could be differing in size, employ differing number of combustor components for each stage, employ differing number of inlets for each combustor component, employ differing physical orientations in 3D space, employ differing relative dimensions and differing variations to accommodate the varying molecular weight and temperature of the fuel composition mixture received at each combustor component 100, as would be appreciated by a person skilled in the art and described below with reference to the embodiment of Figure 4. It is to be understood that the combustor components 100 as illustrated throughout the Figures may be identical in size, or alternatively, each individual combustor component 100 may vary in size, number of inlets, dimensions and other variations to those shown and described in this specification.

[0215] The composite combustor assembly 201 arranges the individual novel combustor components 100, each as described above, in a flow series (suffixed by the sequential numbers - 1, -2, and so on to -n) such that the fuel stream of pure hydrogen 203 and oxidant stream of pure oxygen 205 is supplied to the first stage combustor component 100-1. The produced exhaust stream 207-1 is supplied as fuel to the next stage combustor component 100-2. This stream 207- 1 is a mixture of unburnt hydrogen from combustor component 100-1 and produced steam as part of combustion in the combustion chamber 101. This produced steam acts as a diluent for combustion in subsequent stages. Thus, this novel composite combustor assembly 201 combusts incremental amounts of the supplied hydrogen stream 203 across its individual combustion chamber stages 101-1 to 101 -n with increasing steam production. In the final stage combustion chamber 101 -n all the hydrogen fuel 203 is consumed, and steam is the only constituent of the final exhaust stream 211.

[0216] In this embodiment, an amount of oxidant provided to each of the plurality of combustor components 100-1 to 100-n is limited so that the oxidant is substantially or entirely consumed during combustion with the fuel in each combustion chamber 101 of the combustor components 100-1 to 100-n. The fuel provided to the first combustor component 100-1 may comprise a pure gas such as hydrogen gas (H2).

[0217] Figure 4 illustrates a perspective view showing another composite combustor assembly 210 having three stages of combustion (1^st, 2^nd and 3^rd) with two combustor components in the first stage (100-1) and one combustor component in the second and third stages (100-2 and 100- 3), according to some embodiments of the disclosure. The two combustor components 100-1 in the first stage include three fuel inlets each. The gases outlets of these two first stage combustor components 100-1 supply to each of the two fuel inlets of a one double inlet second stage combustor component 100-2. The gases outlet of the second stage combustor component 100-2 supplies a single flow path to one third stage single inlet combustor component 100-3. In other embodiments, the second stage combustor component 100-2 may split the outlet into two flow paths which supply one third stage double inlet combustor (not shown). The combustor components 100 of the combustor assembly 210 have a non-linear arrangement in contrast to the combustor assemblies 201 in the remaining figures.

[0218] Figure 5 is another schematic representation depicting a varying operating mode of the novel composite combustor assembly 201 of Figure 3, in which a diluent stream 301, comprising of steam or carbon dioxide gas or both or an inert gas, is introduced into the pure hydrogen fuel stream 203 entering the first combustor sub-assembly 100-1 with combustion chamber 100. The different lines shown in the key represent distinct fluid flows interacting with the combustor assembly 201. This configuration could be either used during startup or during normal operation. The combustor assembly 201 may comprise a mixing device 303 configured to combine the diluent stream 301 with the pure gas from the fuel stream 203 to form a homogenous mixture before being introduced into the first combustion chamber 100 as fuel. The mixing device 303 may be a downstream static mixer, or a proportional mixing valve, or mechanical mixing valve, or electrical mixing valve, or gas mixer with volumetric or mass flow rate controller. In other embodiments, the mixing device 303 may not be a static mixer, but may include other possible types of fluid mixers as known to a person skilled in the art in achieving the desired homogenous mixture. When operating in this configuration the exhaust streams (307-1, 307-2, to 307-(n-l)) of each combustor stage include the mostly unaffected diluent along with unbumt hydrogen and produced steam. In this varying operating mode then the final exhaust stream 311 includes the inert diluent along with the final steam product. When the diluent is steam the resulting stream 311 comprises only of steam. When the diluent stream 301 comprises of carbon dioxide or an inert gas, the carbon dioxide or inert gas present in stream 311 can be systematically separated through condensing the steam into water after it has imparted its thermal energy to the industrial process 513. The diluent carbon dioxide or similar inert gas is recovered as a gas separated from the condensed water and can be recycled back as a diluent stream 301. This arrangement is further explained in Figure 8, and the related system description.

[0219] Figure 6 is yet another schematic representation depicting a temperature control feature of the novel composite combustor assembly 201 of Figure 3. The different lines shown in the key represent distinct fluid flows interacting with the combustor assembly 201. Thus, the combustor assembly 201 may be configured to adjust a temperature of the flow of the exhaust gases (207-1, 207-2, to 207-(n-l)) from at least one combustor component (100-1, 100-2, to 100-(n-l)) to a target temperature before use as the fuel in a subsequent combustor component 100-n. The combustor assembly 201 may comprise a temperature controller TC as shown in Figure 6 (denoted as 407-1, 407-2, to 407-n) for each or all of the combustor stages. The temperature controller TC may be on-off type, or limit type, or proportional type, or integral type, or derivative type, or proportional-integral-derivative type, or fuzzy type, or microcontroller type or any combination of the above arranged in parallel, series or cascade configurations, or other variants as would be appreciated by a person skilled in the art in view of the combustor assembly 201. The temperature controller TC may be configured to operate a control valve (denoted as 405-1, 405-2, to 405-n) for delivering a flow of a fluid, typically water, for evaporation into the flow of exhaust gases (207-1, 207-2, to 207-n) to maintain the target temperature. The combustor assembly 201 may also comprise a spray device (denoted as 403-1, 403-2, to 403-n) which is operable by the temperature controller TC to discharge the flow of the fluid passing through the control valve (405-1, 405-2, to 405-n) into the flow of exhaust gases (207-1, 207-2, to 207-n). The control valve (405-1, 405-2, to 405-n) may be globe type, or needle type, or butterfly type, or gate type, or pinch type, or diaphragm type, or plug type, or ball type, or other variants as would be appreciated by a person skilled in the art, using features compatible with the fluids and operating conditions (pressures, temperatures, and/or compositions) of embodiments of the present disclosure. [0220] The temperature controller TC may perform various functions to adjust the temperature of the flow of the exhaust gases to the target temperature. The temperature controller TC may be programmed to perform the functions of adjusting the spray fluid control valve (405-1, 405-2 to 405-n) in response to the measured temperature from a temperature sensor, as transmitted by a temperature transmitter. The controller function may reside in a Programmable Logic Controller (PLC) for example, which is widely used in the art of control engineering practice. The spray device (403-1, 403-2, to 403-n) may include single or multiple spray nozzles for delivering the flow of the fluid, e.g., water, and various configurations of geometry of the nozzle design. The various options for the spray device (403-1, 403-2, to 403-n) may be screwed spray nozzle or seal welded spray nozzle into a nozzle holder, or a plurality of water injection openings in the pipe wall equispaced in a geometric pattern, or flanged connection with spray water pipework penetrating downstream of the unit combustor 100 outlet or any other type as would be appreciated by a person skilled in the art in view of the outcomes to be achieved by the combustor assembly 201.

[0221] As illustrated in Figure 6, a stream of water of high purity (401-1, 401-2, to 401 -(n-1)) in liquid state is introduced into the discharge of individual combustor sub-assemblies through a spray device (403-1, 403-2, to 403-(n-l)). The mass flow of water may be adjusted by a temperature control valve (405-1, 405-2, to 405(n-l)) to completely evaporate into the fluid stream exiting the preceding combustor stage 100-(l-n), while maintaining a constant target temperature of vapour into the downstream combustor sub -assembly, using a target setpoint configured in a temperature controller TC (407-1, 407-2, to 407-(n-l)). The target temperature could range from about 400 degrees Celsius to about 800 degrees Celsius, and preferably about 550 degrees Celsius for the intermediate stages, with the final stage target temperature determined by the process application. Depending on the system design requirements the final design may provide this temperature control or attemperating feature only at select stages, instead of every stage.

[0222] It is to be appreciated that the combustor assembly 201 and combustor assembly 210 comprise a plurality of combustor components (100-1 to 100-n) which each may comprise a combustor component 100 with any combination of the features as shown in Figures 1 and 2 and also in Figures 10 and 12 to 14, and described in the present specification. While Figures 3 and 5 to 9 illustrate each combustor component 100 (suffixed by the sequential numbers -1, -2 and so on to -n) to be of identical size, these could be differing in size, employ differing number of combustor components for each stage, differing number of inlets for each combustor component, employ differing physical orientations in 3D space, employ differing relative dimensions and differing features to accommodate the varying molecular weight and temperature of the fuel composition mixture received at each combustor component 100. In other variants, the arrangement of the individual combustor components 100-1, 100-2, 100-3, . . ,,100-n may not be a linear arrangement as depicted by the combustor assembly 201 of the aforementioned figures. For example, the combustor assembly 210 of Figure 4 includes four combustor components which are not in a linear arrangement. Thus, such variants could arrange the sequential stages of the individual combustor sub-assemblies in a manner that might suit the particular plant process requirements, plant installation, or to suit particular piping arrangements, maintainability, access, constructability, aesthetics, visual impact, etc.

[0223] The following description references and exemplifies the combustor assembly 201 in the systems and methods disclosed. It is to be appreciated that the combustor assembly 201 could be substituted with the combustor assembly 210 of Figure 4 or with variations on the combustor components 100 or their arrangement as discussed in the paragraph above.

System for Supplying High Temperature Thermal Energy to External Process using Combustor Assembly

[0224] Figure 7 depicts the entire process cycle configuration of a system 500 utilising the novel composite combustor assembly 201 to achieve electrification of high temperature thermal energy supply to an external process, e.g., an industrial process 513. The industrial process 513 may include a large-scale industrial process such as alumina refining, cement manufacture, steel making, fertilizer production, mineral processing, food processing and similar applications. The different lines shown in the key represent distinct fluid flows in the process cycle.

[0225] The system 500 is configured to produce high temperature thermal energy for an external process 513 using electrolysis and a combustor assembly 201. The system 500 comprises an electrolyser 503 configured to receive pure water (H2O) and separate it into hydrogen gas (H2) and oxygen gas (O2). The electrolyser 503 could be alkaline type or acidic proton exchange membrane (PEM) type or solid oxide type or any other technology type that ensures effective separation of the hydrogen and oxygen streams produced, as would be appreciated by a person skilled in the art. For example, the PEM type electrolyser may provide an advantage of inherently providing gases under pressure, thereby eliminating the need for compression if the supply pressure is higher than the process demand pressure. The system 500 also comprises the combustor assembly 201 according to any one of the embodiments as described with respect to Figures 3, 5 and 6, where the fuel comprises the hydrogen gas from the electrolyser 503 and the oxidant comprises the oxygen gas from the electrolyser 503, and the flow of exhaust gases 211 comprises steam in the form of water vapour (H2O) which is provided as the high temperature thermal energy to the external process 513. The system 500 also comprises a condenser 519 for receiving the steam after use by the external process 513 to condense the steam into pure water. The system 500 is configured to return the pure water to the electrolyser 503 for re-use.

[0226] As shown in Figure 7, alternating current (AC) electric supply from the grid 501, generated mostly from non-fossil fuel sources, is converted into direct current (DC) electric supply and then supplied to the electrolyser 503. The electrolyser 503 electrolytically splits demineralised water supplied to it into its constituent elements of hydrogen and oxygen. Hydrogen gas is released at the negatively charged cathode, while oxygen gas is released at the positively charged anode in the electrolyser 503. The electrolyser system 503 is typically designed with auxiliary systems (not shown here) which purify the incoming water and purification systems (not shown here) for produced hydrogen and oxygen gases.

[0227] The system 500 further comprises a compressor 505 configured to receive hydrogen gas from the electrolyser 503 and increase its pressure for storage in a hydrogen storage vessel 509. The compressor 505 may be a motor-driven compressor, and optionally a reciprocating type, or centrifugal type, or an ionic liquid piston type or dry screw type, or wet oil/water injected screw type, or diaphragm type, and the hydrogen gas may be stored in the storage vessel 509 for use in the downstream process 513. Alternative forms of storage vessel 509 could be underground storage in caverns, rock formations, depleted mines or other cavities suitably modified for gaseous hydrogen storage. Similarly, the system 500 further comprises a compressor 507 configured to receive oxygen gas from the electrolyser 503 and increase its pressure for storage in an oxygen storage vessel 511. The compressor 507 may be a motor-driven compressor, and optionally a reciprocating type or a centrifugal type, or an ionic liquid piston type, or dry screw type, or wet oil/water injected screw type, or diaphragm type, depending on the size, and the oxygen gas may be stored in the storage vessel 511 for use in the downstream process 513. Alternative forms of storage vessel 511 could be underground storage in caverns, rock formations, depleted mines or other cavities suitably modified for gaseous oxygen storage. The storage pressure in the storage vessels 509 and 511, at least, exceeds the required steam pressure of the industrial process 513 to overcome the pressure drops in the downstream piping, control valve stations and the novel composite combustor assembly 201. The storage pressure could be further increased to enable storage of excess hydrogen and oxygen produced during periods of renewable energy generation, and thus make up for periods when renewable energy may not be available due to lack of sunlight or wind.

[0228] When the electrolyser 503 employs a technology that enables its operation at a pressure, this system could eliminate the need for the motor-driven hydrogen and oxygen compressors 505 and 507, respectively, if this electrolyser operating pressure meets the steam pressure requirement of the industrial process 513 after overcoming the pressure drops in the downstream piping, control valve stations and the novel composite combustor assembly 201.

[0229] The system 500 may comprise a pressure controller 510, 512 configured to modify the pressure of the hydrogen gas and/or oxygen gas produced by the electrolyser 503 to ensure that a desired pressure of the flow of exhaust gases 211 at a final combustor component 100-n of the combustor assembly 201 will be satisfied for the external process 513. Pressure control stations 510 and 512 as shown in Figure 7 ensure that hydrogen fuel and oxygen respectively, are supplied to the novel composite combustor assembly 201 at a pressure such that the downstream industrial process 513 receives the final stream of high temperature steam 211 at the desired pressure. While Figure 7 and Figure 8 indicate a downstream pressure regulator, this pressure controller could be controlled through an overall system control that ensures that the hydrogen fuel and oxygen supply are always at a pressure such that the downstream industrial process 513 receives the final stream of high temperature steam 211 at the desired pressure. The pressure controllers 510, 512 may be pressure reducing regulators or back pressure controllers or closed volume pressure controllers, pressure sustaining valve or pressure sustaining regulator, single stage regulators or a multi-stage regulators or of the type that are typical in the art and as would be implemented by a person skilled in the art based on the process demands.

[0230] The novel composite combustor assembly 201 could employ combinations of spray stations 403 to control the temperature of the high temperature steam 211 to a value desired by the downstream industrial process 513. Thus, the system design depicted in Figure 7 ensures that the produced high pressure and high temperature steam 211 meets the pressure and temperature requirements of the industrial process 513. The high pressure and high temperature steam 211 thus produced in the novel composite combustor assembly imparts thermal energy to the industrial process 513 through multiple heat transfer surfaces, energy recovery devices, and/or pressure-reducing devices, represented in a simplified form as coil 515. The temperature and pressure of the steam is expected to drop after flowing through the industrial process heat users. Some industrial processes could even consume some of the produced steam (not shown here). [0231] The low pressure and low temperature steam 517 is then led to the condenser 519, where external circulating cooling water supply received through stream 521 condenses it into pure water. The circulating cooling water thus leaves with increased temperature as stream 523. The circulating cooling water flow is adjusted to limit its temperature rise to that allowed by the external heat sink (not shown), where this residual heat is rejected to the environment. In the condenser 519, the low pressure and low temperature steam 517, thus condenses into water and collects in the bottom of the condenser, which maintains a constant level. The condensation of the steam causes it to collapse in volume resulting in the condenser operating at near vacuum conditions. Any non-condensable gases are extracted out of the condenser through a motor- driven vacuum extraction pump 525 and can be exhausted out as stream 527. Any losses of steam to the industrial process 513 are made up using a makeup stream 529 of pure water added into the condenser 519. Thus, the system 500 may be configured to provide additional pure water to the condenser 519 based on loss of stream to the external process 513. The pure water condensed in the condenser 519 is then extracted out using the motor-driven condensate extraction pump 531 and pumped back to the electrolyser 503 completing the cycle as shown in Figure 7.

[0232] The system 500 may further comprise a pump 531, 533 for extracting pure water from the condenser 519 and increasing its pressure for use as fluid for evaporation into the flow of exhaust gases 211 from at least one combustor component 100-1 to 100-n to maintain a desired temperature for use as a fuel in a subsequent combustor component 100-(l-n) in the combustor assembly 201. Pressurised water stream for temperature control in the novel composite combustor assembly 201 is provided from the discharge of the condensate extraction pump 531, by further increasing its pressure using a motor-driven pump 533. The pumps 531, 533 may be of a centrifugal type, vertical multistage pumps, vertical turbine pump, vertical can pump, horizontal end suction type pump or pump with an integral booster, for example, or other variants as would be appreciated by a person skilled in the art.

[0233] The system may further comprise a bleed line 535 for varying the composition of the pure water extracted from the condenser 519 to be returned to the electrolyser 503. Figure 7 illustrates a bleed stream 535 which offers means for chemistry control if the cycles of concentration affect the cycle water or steam chemistry beyond thresholds acceptable to the materials of construction used in the cycle, and to avoid fouling of heat transfer surfaces within the industrial process 513. Alternative System for Supplying High Temperature Thermal Energy to External Process using Combustor Assembly with Diluent

[0234] In yet another variation, Figure 8 below depicts the entire process cycle configuration of a system 500 utilising the novel composite combustor assembly 201 to achieve electrification of high temperature thermal energy supply to an external process (e.g., an industrial process 513), while utilising a mostly inert diluent. The combustor assembly 201 as shown in Figure 8 includes a combination of features, including the use of diluent as shown in Figure 5 and temperature control as shown in Figure 6. The different lines shown in the key represent distinct fluid flows in the process cycle.

[0235] The cycle depicted in Figure 8 is identical to that in Figure 7, except in the use of the diluent stream and its reuse, which is explained now. As shown in Figure 8, an initial external supply of inert diluent 601 is imported under high pressure, typically utilising high pressure industrial gas cylinders, and emptied into the storage tank 603 while maintaining it at a pressure higher than the operating pressure of the novel composite combustor assembly 201. Once operational, there could be a need to add more of the external diluent supply only to makeup for any leakages in the system 500.

[0236] The system 500 may comprise a pressure controller 605 configured to modify the pressure of the diluent to ensure that it is sufficient to combine with the hydrogen gas produced by the electrolyser 503 at the first combustor component 100-1. Typically, the diluent is preferably supplied at a pressure that is at least about 200 kPa greater than the hydrogen fuel stream pressure, although this differential pressure could be varied and optimized depending on the system design and/or operating requirements. The pressure controller, therefore, could be a differential pressure controller that ensures that the diluent is always supplied at a pressure greater than the hydrogen fuel stream supply pressure. In alternative arrangements (not shown), the pressure controller 605 could be supplemented by a pressure reducing regulator or back pressure controller or closed volume pressure controller, pressure sustaining valve or pressure sustaining regulator, single stage regulator or multi-stage regulators or other variants as would be appreciated by a person skilled in the art. Pressure control station 605 as illustrated in Figure 8 ensures that the diluent gas has enough injection pressure to enter the hydrogen fuel stream leading into the novel composite combustor assembly 201.

[0237] The system 500 may also comprise a mixing device 303 for receiving a source of a diluent which is combined with the hydrogen gas produced by the electrolyser 503 to form a homogenous mixture of the fuel to be provided at the first combustor component 100-1. The static mixer 303 as shown in Figure 8 homogeneously mixes the diluent gas and the hydrogen fuel gas before it enters the novel composite combustor assembly 201. The diluent gas ensures stable combustion of the supplied hydrogen fuel with oxygen, and leaves the composite combustor assembly 201 mostly unreacted, along with the produced steam as stream 211.

[0238] After imparting its thermal energy to the industrial process 513 heat users across the heat transfer surfaces, energy recovery devices and/or pressure-reducing devices 515, the mixture of low pressure, low temperature steam and diluent 517 enters the condenser 519. Here, the circulating cooling water supply 521 absorbs the residual heat by condensing the steam, and leaves the condenser at a warmer temperature as stream 523. The diluent gas is non-condensable under the condenser 519 operating conditions and is extracted out of the condenser through a motor-driven vacuum extraction pump 525.

[0239] The system 500 further comprises a diluent extraction pump 525 for removing diluent from the condenser 519, and a compressor 609 configured to receive the diluent from the condenser 519 and increase its pressure for storage in a diluent storage vessel 603 ready for reuse in the combustor assembly 201. The diluent extracted out of the condenser 519 is discharged into a purification system 607 as shown in Figure 8, where any other non-condensable gases can be separated, if necessary. The provision of the purification system 607 is optional, depending upon the operating conditions of the entire cycle, and its interactions with the industrial process 513. Motor-driven compressor 609 increases the pressure of the purified diluent and charges it into the diluent storage vessel 603, thus completing the diluent supply cycle.

[0240] In another embodiment, the system 500 of Figures 7 and 8 may optionally exclude the condenser and recycling of pure water to the electrolyser for re-use. An exemplary system configured to produce high temperature thermal energy for an external process may comprise an electrolyser 503 configured to receive pure water (H2O) and separate it into hydrogen gas (H2) and oxygen gas (O2), and a combustor assembly 201 or 210 according to any one of the embodiments as disclosed herein. The fuel may comprise the hydrogen gas from the electrolyser 503 and the oxidant may comprise the oxygen gas from the electrolyser 503. The flow of exhaust gases 211 may comprise steam in the form of water vapour (H2O) which is provided as the high temperature thermal energy to the external process 513. As optional features, the system may further comprise a condenser 519 for receiving the steam after use by the external process 513 to condense the steam into pure water. The system may optionally be further configured to return the pure water to the electrolyser 503 for re-use. A corresponding method 3020 is described below with reference to Figure 19.

[0241] Turning now to Figure 9, a schematic diagram illustrates alternative process cycle configurations for: a) heating of hydrogen gas for use in an external process using the combustor assembly of Figure 6 as denoted as assembly 201 A, and b) production of a mixture of hydrogen and steam through incomplete combustion of hydrogen in an alternative combustor assembly denoted as assembly 20 IB, according to some embodiments of the disclosure. The process cycle configuration may achieve electrification of high temperature thermal energy supply to an industrial process. The different lines shown in the key represent distinct fluid flows in the process cycle.

Alternative System for Supplying High Temperature Hydrogen to External Process using Combustor Assembly

[0242] Figure 9 illustrates a process cycle configuration employing system 700A which achieves electrification of high temperature thermal energy supply to an industrial process to enable production of pure hydrogen gas (H2) at high temperature. The system 700A may be configured to heat the hydrogen gas to a temperature in a range of about 700°C to about 1000°C, and preferably in a range of about 750°C to about 1000°C, and preferably to a temperature of about 800°C. The system 700A may be configured to heat the hydrogen gas to a temperature in a range of about 750°C to about 990°C, and preferably, about 800°C, for supply in steelmaking applications e.g., as a reducing agent to a Direct Reduced Iron process.

[0243] System 700A is configured to heat hydrogen gas (H2) for use in an external process 615. The system 700A comprises the combustor assembly 201 A which may include any of the features of the combustor assembly 201 as shown and described in relation to the embodiments of Figures 3, 5 and 6. The system 700A also comprises a heat exchanger 613 configured to receive the flow of exhaust gases 211 from the final combustor component 100-n and impart thermal energy to heat a flow of hydrogen gas for use in the external process 615.

[0244] In some embodiments, the system 700A is configured to heat hydrogen gas produced by electrolysis to high temperatures (e.g., see components in Figures 7 and 8), where the flow of exhaust gases 211 from the composite combustor assembly 201 A comprises steam in the form of water vapour (H2O) at high temperature imparting thermal energy to a stream of pure hydrogen received from the electrolyser 503 or hydrogen storage 509 (see Figures 7 and 8) utilizing a heat exchanger 613.

[0245] The system 700A may comprise an electrolyser 503 configured to receive pure water (H2O) and separate it into hydrogen gas (H2) and oxygen gas (O2) (see Figures 7 and 8). The flow of hydrogen gas to be heated may be supplied from the electrolyser 503. The fuel of the combustor assembly 201A may comprise hydrogen gas from the electrolyser 503 and the oxidant of the combustor assembly 201 may comprise the oxygen gas from the electrolyser 503, and the flow of exhaust gases 211 from the final combustor component 100-n may comprise steam in the form of water vapour (H2O). Additionally or alternatively, the system 700A may comprise a hydrogen storage vessel 509 (see Figures 7 and 8).

[0246] The system 700A is configured to produce high temperature thermal energy as described to impart it to pure hydrogen gas, thereby producing hydrogen gas at high temperatures for a downstream process 615. In this arrangement, the pressure of the hydrogen gas from the electrolyser 503 or hydrogen storage 509 is first adjusted to that desired by the downstream process 615 using a pressure regulating valve 611. The pressure regulating valve 611 may be pressure reducing regulators or back pressure controllers or closed volume pressure controllers, pressure sustaining valve or pressure sustaining regulator, single stage regulators or a multi-stage regulators or of the type that are typical in the art and as would be implemented by a person skilled in the art based on the process demands.

[0247] The hydrogen gas is then passed through a heat exchanger 613, where it receives high temperature heat from the composite combustor assembly 201 A. Figure 9 further illustrates the produced high temperature steam on the tube side of the heat exchanger 613, and the heated hydrogen gas on the shell side of heat exchanger 613. However, this arrangement could be reversed, if considered more economical or suitable to do so. Such heat exchanger 613 can be of shell and tube type, double pipe heat exchangers, plate heat exchangers, printed circuit heat exchangers, tube in tube heat exchanger, finned heat exchanger, phase change heat exchanger, microchannel heat exchanger, or any other type of heat transfer device of the type that are typical in the art and as would be implemented by a person skilled in the art based on the process demands. Hydrogen gas at high temperature is thus supplied to the downstream process 615.

[0248] After the steam has been used by the heat exchanger 613, the system 700A may comprise a condenser 519 (see also Figures 7 and 8) for receiving the steam and condensing it into pure water. Thus, the system 700A may be configured to return the pure water to the electrolyser 503 for re-use. The system 700A may include any of the components such as pumps, compressors and valves as described in relation to Figures 7 and 8 to enable re-use of the condensed water by the electrolyser 503.

[0249] Referring to the system 800 of Figure 11 which will be discussed in more detail below, the combustion lambda controller 801, along with the temperature controller 819 and the oxygen stage flow controller 815 may allow for precise control of the temperature of the heated hydrogen, as desired by the downstream process 615. The control system 800 may be configured to allow precise control of the temperature of the heated hydrogen gas to a temperature in a range of about 700°C to about 1000°C, and preferably in a range of about 750°C to about 1000°C, and preferably to a temperature of about 800°C. The control system 800 may be configured to control the temperature of the heated hydrogen gas to a temperature in a range of about 750°C to about 990°C, and preferably, about 800°C, for supply to the downstream process 615, e.g., in steelmaking applications as a reducing agent to a Direct Reduced Iron process.

Alternative Combustor Assembly and System for Supplying a Mixture of Hydrogen and Steam to External Process

[0250] In another aspect, the present disclosure provides an alternative combustor assembly 20 IB and system 700B configured, in some embodiments, to provide a hot mixture of hydrogen and steam of varying compositions yielding varying hydrogen to steam ratios, as demanded by a downstream process plant or external process 623 as shown in Figure 9. The hydrogen to steam ratio and temperature may be controlled as desired for use in the external process 623.

[0251] Figure 9 illustrates in relation to system 700B an alternative combustor assembly 201B for staged combustion of a fuel with an oxidant according to some embodiments of the disclosure. The combustor assembly 20 IB comprises a plurality of combustor components 100 (two are shown in Figure 9 although additional components 100 can be provided) arranged sequentially for staged combustion of the fuel with the oxidant. Each combustor component 100 comprises a combustion chamber 101. At least one subsequent combustor component 100 is configured to receive a flow of exhaust gases 207 from a preceding combustor component 100- (1-n) as the fuel for combustion with a gas flow of the oxidant 205 in the at least one subsequent combustor component 100-(n-l). The flow of exhaust gases 207 produced from each combustor component 100 comprises a proportion of the fuel 203 provided to a first combustor component 100-1, which reduces in proportion to a predetermined amount of the fuel being present in the flow of the exhaust gases 211 from a final combustor component 100-n.

[0252] The combustor assembly 20 IB is a truncated version of that shown and described in relation to assemblies 201 of Figures 3, 5 and 6 and 201A of Figure 9. The assembly 201B does not achieve complete combustion of the supplied fuel (e.g., hydrogen) stream, leaving a mixture of fuel (e.g., hydrogen) and steam at the outlet, with possible traces of unutilized oxidant (e.g., oxygen gas). Such system 700B can provide a mixture of fuel (e.g., hydrogen) and steam, as produced at the outlet of a final combustor component 100-n, illustrated as stream 621. Alternatively, the stream may be controlled for temperature and steam content at the outlet using a temperature controlled attemperator, illustrated as stream 619. Alternatively, the hydrogen content could be further reduced, but not completely combusted by adding further stages of unit combustor components 100 to produce a more diluted stream of hydrogen in steam, illustrated as stream 617.

[0253] Referring to the system 800 of Figure 11 which will be discussed in more detail below, the combustion lambda controller 801, along with the temperature controller 819 and the oxygen stage flow controller 815 may allow for precise control of the produced hydrogen to steam ratio and its temperature, as desired by the downstream process 623. The desired composition may be controlled such that it is equivalent to the predetermined amount of the fuel being present in the flow of the exhaust gases 211 from the final combustor component 100-n. In embodiments where the flow of exhaust gases 211 further comprises steam in the form of water vapour, the desired composition may be a ratio of the predetermined amount of fuel to steam in the flow of exhaust gases 211 from the final combustor component 100-n.

[0254] The system 800 may be configured to control the produced hydrogen to steam ratio to provide a mixture which comprises about 5% to about 20% of steam and about 80% to about 95% of hydrogen gas. Preferably, the system 800 provides a mixture of about 5% to about 15% of steam and about 85% to about 95% of hydrogen gas. More preferably, the mixture comprises about 7% to about 15% of steam and about 85% to about 93% of hydrogen gas. Some traces of unburnt oxygen and OH radicals may also be present in the mixture. Providing a mixture may be a preferred solution for heating of hydrogen gas in contrast to the system 700A with combustor assembly 201 A as illustrated in Figure 9. The presence of a small proportion of steam can be tolerated in the high temperature hydrogen. Thus, the heat exchanger 613 as required in system 700A may be eliminated, thereby reducing the number of system components. Combustor Component Design

[0255] Figure 10 illustrates the key dimensional variables of the individual combustor component 100 of Figure 1, which decide the performance of the combustor component 100 in terms of combustion efficiency, fraction of fuel combusted, flame stability, flame position, flame holding pattern, combustion dynamics and overall thermal performance. Table 1 further describes these individually. These dimensional variables are selected through systematic design for the desired product steam pressure and temperature, particularly considering the novel composite combustor assembly 201, 210 described earlier. Table 1 also provides example parameters of a combustor component 100 of some embodiments of the disclosure used in a preferred configuration using multiple combustor trains for a 3000 TPD (production capacity tons per day) cement plant. The combustor component 100 in this example is the first stage of a 10 MW thermal final heat output combustor system operating at 1 barg. Where Table 1 includes values or ranges for the parameters, it is to be understood that the values or ranges are approximate only and may be varied, particularly to suit a retrofit situation. It is also to be appreciated that this example is an example only and not limiting on the scope of the invention that may be claimed.

[0256] Table 1 - Individual Combustor Component: Dimensional Parameter Descriptors

Control System for Combustor Assembly

[0257] Figure 11 illustrates a system 800 configured to operate a combustor assembly 201 to produce a flow of exhaust gases 211, demand for which may be set by a flow controller 811 as shown, with one or more desired characteristics. The solid lines represent electrical connections/communications between the controller(s) and various components of the system 800, and the dashed/broken lines correspond to distinct fluid flows illustrated in the key of Figure 5.

[0258] The system 800 comprises the combustor assembly 201 (or the assemblies 201 A, 201B) according to any one of the embodiments as disclosed herein with reference to Figures 3, 5, 6 and 9. While Figure 11 illustrates a single combustor for each stage, the actual composite assembly could comprise of multiple combustors for each stage (see alternative combustor assembly 210 in Figure 4). This section of the description will refer to combustor assembly 201 for simplicity although it is to be appreciated that either assemblies 201 A or 201B of Figure 9 or the combustor assembly 210 of Figure 4 could be readily employed by the system 800. The system 800 also comprises at least one sensor 803, 805, 807, 809 configured to measure one or more parameters of the flow of exhaust gases 211 from a final combustor component 100-n in the combustor assembly 201. The system 800 also comprises a system controller 801 configured to receive a predetermined target flow of exhaust gases comprising the one or more desired characteristics, process the one or more parameters measured by the at least one sensor 803, 805, 807, 809 to determine a deviation from the predetermined target flow of exhaust gases, and modify one or more fluid flows into the system 800 to meet the one or more desired characteristics of the predetermined target flow of exhaust gases.

[0259] The one or more fluid flows which may be modified by the system controller 801 may include gas flows and/or liquid flows in the system 800. The one or more fluid flows modified by the system controller 801 may comprise the gas flow of fuel 203 provided to a first combustor component 100-1 of the combustor assembly 201, the gas flow of oxidant 205 provided to each combustor component 100 of the combustor assembly 201, and/or the gas flow of fuel 203 provided to subsequent combustor components 100-2, 100-3, to 100-n of the combustor assembly 201. In some embodiments, the system controller 801 is configured to modify the gas flow of fuel 203 provided to subsequent combustor components 100-2, 100-3, to 100-n through temperature control. The system controller 801 may be configured to modify delivery of a flow of liquid being evaporated into the gas flow of fuel 203 provided to subsequent combustor components 100-2, 100-3, to 100-n to maintain the gas flow of fuel 203 at a desired temperature. [0260] The system controller 801 may be configured to modify one or more of the gas flow of fuel 203 provided to the first combustor component 100-1 (e.g., using the flow controller 813), the gas flow of oxidant 205 provided to each combustor component stage (e.g., using individual flow controllers 817-1 to 817-n), and the gas flow of fuel 203 entering each subsequent combustor components 100-2, 100-3, to 100-n (e.g., by modifying the individual and total temperature control water evaporation flow using the temperature controller 819 and temperature controllers 407-1 to 407-(n-l)).

[0261] The control system 800 of Figure 11 aims to ensure that the novel composite combustor assembly 201 delivers the process steam (i.e., exhaust gases 211) at the desired pressure and temperature while meeting the flow demands of an external process, e.g., set by the flow controller 811, which may include a downstream industrial process 513. Thus, the one or more desired characteristics may comprise a desired composition, pressure and/or temperature of the flow of exhaust gases 211.

[0262] One of the main objectives of the combustion control system 800 is to provide the desired safe combustion composition at each combustion stage for given operating pressure and temperature, which in turn is determined by correlations using variables illustrated in Figure 16 as an example at the unit combustor operating conditions. Such composition graphical correlations, an example of which is Figure 16, may be programmed using a combination of algorithms, mathematical equations, thermodynamic correlations, experimental data, correlated variables, transfer functions and/or control variables in the combustion lambda controller 801. Another main objective of the combustion control system 800 is to ensure complete combustion of the supplied hydrogen fuel stream 203 with the use of oxygen stream 205 as oxidant while ensuring complete combustion, with minimal residual unburnt hydrogen or un-utilised oxygen. Such combustion requires achieving a lambda of unity when considering the entire novel composite combustor assembly 201 as a single unit. Lambda represents the ratio of the amount of oxygen 205 supplied to the combustor components 100 compared to the amount required to achieve stoichiometric combustion. Hence, the prime function of the combustion control system 800 is to maintain a near unity lambda at the final outlet of the novel composite combustor assembly 201.

[0263] The combustion lambda controller 801 may be programmed using a combination of algorithms, mathematical equations, thermodynamic correlations, experimental data, correlated variables, transfer functions and/or control variables. The system controller 801 receives input from the final outlet stream 211 through the residual chemical sensors 803. Such chemical sensors 803 are configured to measure a concentration of one or more substances in the flow of exhaust gases 211 from the final combustor component 100-n. The chemical sensors and/or analysers 803 may measure residual oxygen (O2), hydrogen (H2) and/or hydroxyl ion (OH") concentration or any other chemical constituent of interest in the produced outlet stream 211, and produce a signal in proportion to the measured deviation from the desired setpoint. The sensors and/or analysers 803 could be electrochemical type, or catalytic bead type, or photo ionisation type, or infrared type or semiconductor type, or zirconia sensor, or titania sensor, or exhaust gas sensor, or other variants as would be appreciated by a person skilled in the art.

[0264] The system 800 may also comprise at least one sensor configured to measure temperature, pressure and/or volume of the flow of exhaust gases 211 from the final combustor component 100-n. Temperature sensor 805 and pressure sensor 807 provide signals representing the produced pressure and temperature of the final outlet stream 211. The temperature sensor 805 could be thermocouples, or resistance temperature detector (RTD) or positive temperature coefficient sensor, or negative temperature coefficient sensor or other variants as would be appreciated by a person skilled in the art. The pressure sensor 807 could be aneroid barometer pressure sensor, or manometer pressure sensor, or bourdon tube pressure sensor, or sealed pressure sensor, or piezoelectric pressure sensor, or strain gauge pressure sensor, or other variants as would be appreciated by a person skilled in the art. These temperature and pressure sensors 805 and 807, respectively, also assist in computing the actual mass flow of the final outlet stream 211, utilising the output signal from the volumetric flow sensor 809. The volumetric flow sensor 809 could be obstruction type, or differential pressure type, or variable area type, or inferential turbine type, or electromagnetic type, or fluid dynamic type, or vortex shedding type, or anemometer type, or ultrasonic type, or mass flow (Coriolis force) type, or other variants as would be appreciated by a person skilled in the art. Each of the sensors 803, 805, 807 and 809 may be associated with transmitters for transmitting the one or more measured parameters from the sensors 803, 805, 807 and 809 to the system controller 801.

[0265] The combustion lambda controller 801 is configured to determine a mass flow of the exhaust gases 211 from the final combustor component 100-n based on at least one of the concentration of the one or more substances, the temperature, the pressure and/or the volume of the flow of exhaust gases 211. Based on the computed mass flow of the final outlet stream 211, the system controller 801 computes its deviation from the desired target flow required by the downstream process 513 as set by an external industrial process controller 811 as shown in Figure 10. The system controller 801 is configured to modify one or more fluid flows in the system 800 by operating a fuel flow controller 813 to modify the gas flow of the fuel provided to the first combustor component 100-1 based on the computed deviation, while adjusting for the mass flow of temperature control water communicated from the temperature controller 819. The system controller 801 is configured to modify one or more fluid flows in the system 800 by operating an oxidant flow controller 815 to modify the gas flow of the oxidant provided to the combustor assembly 201 based on the computed deviation. The signal provided to the oxygen stage flow controller 815 further cascades and distributes the oxygen flow demand signal to individual combustor stages using respective flow controllers 817-1, 817-2, 817-3 and so on to 817-n, utilizing temperature controller outputs from 407-1 to 407-(n-l) using the temperature controller 819 and flow controller outputs from 825-1 to 825-n. Thus, the system controller 801 is configured to operate the oxidant flow controller 815 to modify the gas flow of the oxidant provided to each of the combustor components 100-1 to 100-n of the combustor assembly 201 to limit an amount of oxidant so that the oxidant is substantially or entirely consumed during combustion with the fuel in each combustion chamber 100.

[0266] The system 800 also includes temperature controller 819 as shown in Figure 11. The temperature controller 819 receives a temperature signal at the discharge of individual combustor sub-assembly 100-1, 100-2, 100-3, and so on to 100-n, from the temperature controllers 407-1, 407- 2,. . . 407-(n-l), and further adjusts the oxidant flow demand signal to the individual combustor stages through the oxidant flow controller 815. The various options for the temperature controller 819 may be on-off type, or limit type, or proportional type, or integral type, or derivative type, or proportional-integral-derivative type, or fuzzy type, or microcontroller type or any combination of the above arranged in parallel, or series or cascade configurations or any other type that would be appreciated by a person skilled in the art. Pressure sensors 821 and 823 may also be provided as correction factors for adjusting the computations performed in the combustion lambda controller 801 for actual operating pressures. The pressure sensor 821 may detect pressure of the fuel stream (e.g., hydrogen) and the pressure sensor 823 may detect pressure of the oxidant stream (e.g., oxygen), and the sensors may be associated with respective transmitters to transmit the signals to the temperature controller 819. The pressure sensors 821 and 823 could be aneroid barometer pressure sensor, or manometer pressure sensor, or bourdon tube pressure sensor, or sealed pressure sensor, or piezoelectric pressure sensor, or strain gauge pressure sensor, or other variants as would be appreciated by a person skilled in the art. [0267] The combustion lambda controller 801 may be configured to receive the temperature signal(s) from the temperature controller(s) 819 and 407-1 to 407-(n-l), for at least one of the combustor components 100-1 to 100-(n-l). The system controller 801 may be further configured to operate the oxidant flow controller 815 to modify the gas flow of the oxidant provided to each of the combustor components 100-1 to 100-n of the combustor assembly 201 based on the temperature signal.

[0268] The system 800 may further comprise at least one sensor configured to measure pressure and/or volume of the gas flow of fuel and/or oxidant provided to at least one of the combustor components 100-1 to 100-n of the combustor assembly 201. The combustion lambda controller 801 is further configured to modify the one or more fluid flows in the system 800 also based on the measured pressure and/or volume of the gas flow of fuel and/or oxidant. The at least one sensor may include flow or volume sensors 825-1, 825-2, 825-3. . . 825-n configured to monitor the volumetric flow of fuel (pure hydrogen gas or a hydrogen and diluent mixture) which has to be sufficient enough to create the high velocity tangential flow pattern 104 illustrated in Figure 1, within the individual combustor sub-assembly 100-1, 100-2, 100-3, and so on to 100-n. The flow or volume sensors 825-1, 825-2, 825-3. . .825-n may be associated with respective transmitters to transmit the signals to the system controller 801. The volumetric flow sensor 825-1, 825-2, 825- 3. . . 825-n could be obstruction type, or differential pressure type, or variable area type, or inferential turbine type, or electromagnetic type, or fluid dynamic type, or vortex shedding type, or anemometer type, or ultrasonic type, or mass flow (Coriolis force) type, or other variants as would be appreciated by a person skilled in the art.

[0269] The system 800 may further comprise at least one safety feature to limit the gas flow of fuel and/or oxidant to at least one of the combustor components 100-1 to 100-n of the combustor assembly 201. The at least one safety feature may comprise a valve to stop the gas flow of fuel and/or oxidant to at least one of the combustor components 100-1 to 100-n. The system 800 of Figure 11 comprises over-pressure shut-off (OPSO) valves 827 and 829 to protect the downstream oxygen (i.e., oxidant) and hydrogen (i.e., fuel) systems in the novel composite combustor assembly 201 by shutting off the systems in case of abnormal over-pressure conditions.

[0270] The at least one safety feature may also comprise a flow limiter to limit the gas flow of fuel and/or oxidant to at least one of the combustor components 100-1 to 100-n. The system 800 of Figure 11 comprises flow limiters 831-1, 831-2, 831-3, ..., 831-n to physically limit the flow of oxygen into the respective individual combustor sub-assembly 100-1, 100-2, 100-3, . .., 100-n as an additional safety feature. The flow limiters 831-1, 831-2, 831-3, . . . , 831-n could be a flow restrictor, or an inline flow restrictor, or a capillary insert flow restrictor, or a fitting connector flow restrictor combination, or an integral flow restrictor or a flow stopping valve operated by an excess flow switch, or other variants as would be appreciated by a person skilled in the art.

Variations on Combustor Component

[0271] Figure 12 illustrates a variation of the individual combustor component 100 shown in Figure 1 which includes a plurality of nozzles, namely three (3) nozzles 103 A, 103B and 103C as shown, configured to direct the gas flow of the fuel 102 through a corresponding plurality of fuel inlets 114A, 114B and 114C into the combustion chamber 101. As illustrated, the nozzles 103 A, 103B and 103C may be circumferentially spaced on an external surface 116 of the combustion chamber 101. The nozzles 103 A, 103B and 103C may be circumferentially spaced around an cylindrical portion 121 of the component 100. The spacing may be equally spaced as shown, or unequally spaced around the cylindrical portion 121. In other embodiments, two nozzles or optionally four nozzles or any number of nozzles may be provided with a corresponding plurality of fuel inlets. Furthermore, the nozzles 103A, 103B and 103C may be arranged substantially tangentially relative to the external surface 116/cylindrical portion 121 of the component 100. In other embodiments, the nozzles may not be tangential to the external surface 116/cylindrical portion 121.

[0272] Figure 13 illustrates a variation of the individual combustor component 100 shown in Figure 12 which comprises at least one membrane wall 901, 903 located on an internal surface 122 of the combustor component 100 and being configured to absorb at least a portion of the thermal energy released during combustion of the fuel with the oxidant. Figure 13 shows the component 100 which incorporates the provision of heat transfer membrane walls 901 and 903. The membrane wall 901 is located on an internal surface 122 of the combustion chamber 101. The membrane wall 903 is located on an internal surface 122 of the shield portion 108. Each of these membrane walls 901, 903 comprise a spiraled tube 123 configured to receive a heat transfer fluid and a plurality of membrane fins 124 that together form a contiguous heat transfer surface. The membrane fins 124 are welded together with the spiraled tube 123. Inside the spiraled tube 123 flows a heat transfer fluid, which could be either treated water or a special purpose heat transfer fluid or a process gas required to be heated in the downstream industrial process 513, shown in Figures 7 and 8. [0273] The membrane wall 901 is profiled to match the internal profile of the conical portion 117 of the combustion chamber 101. Similarly, a separate membrane wall 903 can be provided along the internal surface 122 of the vortex shield 108, extending to the combustor outlet nozzle 109 or part thereof. Thus, these membrane walls 901, 903 absorb a portion of the thermal energy released during combustion, which otherwise would have to be absorbed by the structural elements of the combustion chamber 101 and its components such as the vortex shield 108 and outlet nozzle 109. This offers the opportunity to reduce the cost of the individual combustor component 100. Moreover, this feature conducts the absorbed heat away from the combustion zone 111 (Figure 1) to the downstream industrial process 513 thereby improving the overall efficiency of the cycles depicted in Figure 7 and Figure 8.

[0274] When the membrane walls 901 and 903 involve a phase change from a liquid state to a gaseous state due to the heat absorption, the membrane wall tubes 123 can be provided with an internal rifled profile (not shown) to improve the liquid’s departure from nucleate boiling. The internally rifled profile prevents the formation of a vapour blanket which can act as an insulating film reducing heat transfer to the bulk liquid within the tubes 123. When the cooling fluid used within the membrane walls 901 and/or 903 is pure water converted to steam, such produced steam could be utilised as a diluent for use within the individual novel combustor component 100 as part of the novel composite combustor assembly 201 itself.

[0275] Figure 14 depicts another variation of the individual combustor component 100 of Figure 12 which utilises a feature to add substantial quantity of diluent along the combustion zone 111 housed within the combustion chamber 101 in order to assist the combustion process. This feature can thus allow increased portions of hydrogen to be combusted with oxygen, thereby reducing the number of sequential stages required in the composite combustor assembly 201.

[0276] In this embodiment, the combustor component 100 comprises a plurality of injection nozzles 1001 in fluid communication with an interior 118 of the combustion chamber 101 to distribute diluent into the combustion chamber 101. As shown in Figure 14, the combustor component 100 may comprise at least two injection nozzles 1001 which penetrate the combustion chamber 101 and diluent fluid is injected therethrough. Although only two injection nozzles are shown, it is to be appreciated that any number of injection nozzles may be provided and at varying locations along the length and circumferential surface of the combustion chamber 101 (not shown). [0277] In this embodiment, the combustor component 100 comprises a sheet 1003 with a plurality of openings 1004 positionable within the combustion chamber 101 to distribute the diluent along an internal surface 122 of the combustion chamber 101. The sheet 1003 may be cast ceramic or formed of ceramic, or may be formed of metal which is optionally coated with ceramic. The sheet 1003 may be a perforated sheet to provide the plurality of openings 1004. The sheet 1003 could be designed in multiple manners to include expansion joints, folds, corrugations, deliberate profiled cuts to accommodate thermal expansion from startup to operating temperatures (not shown). The sheet 1003 can be supported internally from the combustion chamber 101 utilising multiple hold-down designs or struts, welded structures, locking pins, expansion joints, etc. (not shown) to allow unrestricted thermal expansion in all directions as operating temperature rapidly increases from near-ambient at startup conditions to the rated high temperature at full load operation. The hole pattern 1004 on the sheet 1003 can be varied (not shown), although a possible pattern of circular holes uniformly spaced circumferentially has been shown in Figure 13. The hole pattern 1004 could utilise different hole distribution pattern (triangular pattern, circular patterns, square pattern, etc.) or a non-uniform distribution pattern with varying hole diameters, hole profiles / shapes and/or with varying pitch or gaps between adjacent holes (not shown).

[0278] Further, it shall be noted that various embodiments of the combustor component 100 could include a combination of any one of the features shown and described with reference to Figures 1, 2, 10, and 12 to 14. The following description involving use of a combustor component 100 and a combustor assembly 201, 210, may include a combustor component 100 having a combination of any one of the features shown and described with reference to Figures 1, 2, 10, and 12 to 14.

Method for Staged Combustion

[0279] Figure 17 is a flow chart illustrating steps in a method 2000 for staged combustion of a fuel with an oxidant, according to some embodiments of the disclosure. The method 2000 comprises the step 2001 of providing a plurality of combustor components (100-1 to 100-n) arranged sequentially for staged combustion of the fuel with the oxidant, where each combustor component 100 comprises a combustion chamber 101. The method 2000 also comprises the step 2006 of receiving, at at least one subsequent combustor component 100-(n-l), a flow of exhaust gases from a preceding combustor component 100-(l-n) as the fuel for combustion with a gas flow of the oxidant in the at least one subsequent combustor component 100-(n-l). The flow of exhaust gases produced from each combustor component 100 comprises a proportion of the fuel provided to a first combustor component 100-1, which reduces in proportion to substantially none of the fuel provided to the first combustor component 100-1 being present in the flow of exhaust gases from a final combustor component 100-n.

[0280] The method 2000 may comprise the optional step 2002 after providing the combustor components 100, the step 2002 of providing the fuel comprising a pure gas to the first combustor component (e.g., 100-1 of Figures 3 to 6). The step 2002 may optionally comprise providing a diluent to the first combustor component 100-1. In the case that a diluent is used, the method 2000 may further comprise combining, using a mixing device (e.g., static mixer 303), the diluent with the pure gas to form a homogenous mixture of the fuel to be provided at the first combustor component 100-1. The diluent may include an inert gas such as carbon dioxide or nitrogen, or steam/water vapour from a preceding stage.

[0281] The method 2000 may further comprise the optional step 2004 of providing a limited amount of oxidant to each of the plurality of combustor components (e.g., 100-1 to 100-n of Figures 3 to 6) so that the oxidant is substantially or entirely consumed during combustion with the fuel in each combustion chamber 100.

[0282] In some embodiments, the method 2000 also comprises the optional step 2005 of adjusting a temperature of the flow of the exhaust gases from at least one combustor component to a target temperature before use as the fuel in a subsequent combustor component. The step 2005 of adjusting the temperature may comprises operating, using a temperature controller TC (e.g., 405-1 to 405-n), a control valve (e.g., 405-1 to 405-n) for delivering a flow of a fluid for evaporation into the flow of exhaust gases (e.g., 207-1 to 207-n) to maintain the target temperature. In other embodiments, the step 2005 may comprise, additionally or alternatively, the step of operating, using the temperature controller TC, a spray device (e.g., 403-1 to 403-n) to discharge the flow of the fluid passing through the control valve (e.g., 405-1 to 405-n) into the flow of exhaust gases (e.g., 207-1 to 207-n).

[0283] The plurality of combustor components (e.g., 100-1 to 100-n) may each comprise a combustor component 100 having any combination of features as described above with respect to the embodiments of Figures 1, 2, 10 and 12 to 14.

[0284] The method 2000 may further comprise the optional step of providing a combustor assembly 201, 210 comprising the plurality of combustor components (e.g., 100-1 to 100-n) having any combination of features as described above with respect to the embodiments of Figures 3 to 6.

Method for Staged Combustion - Incomplete

[0285] Although not shown, it is to be appreciated that an alternative method for staged combustion of a fuel with an oxidant may be provided which results in incomplete combustion of the fuel. The method describes the process cycle of the embodiments of the system 700B that employs the alternative combustor assembly 20 IB as described above with reference to Figure 9.

[0286] The method may include any one of the steps shown and described above with reference to the method 2000 of Figure 17. However, the flow of exhaust gases 211 produced from each combustor component 100 comprises a proportion of the fuel provided to a first combustor component 100-1, which reduces in proportion to a predetermined amount of the fuel being present in the flow of the exhaust gases 211 from a final combustor component 100-n. Thus, a mixture of the fuel in the combustion product, e.g., steam may be provided. In some embodiments of the method, a ratio of the fuel (e.g., hydrogen) in the combustion product (e.g., steam) may be controlled to provide a desired composition for a downstream process 623 (see Figure 9). In some embodiments, a mixture of steam and unbumt hydrogen gas may be present in the flow of the exhaust gases 211 from the final combustor component 100-n. The mixture may comprise about 5% to about 20% of steam and about 80% to about 95% of hydrogen gas. Preferably, the mixture comprises about 5% to about 15% of steam and about 85% to about 95% of hydrogen gas. More preferably, the mixture comprises about 7% to about 15% of steam and about 85% to about 93% of hydrogen gas. Some traces of unburnt oxygen and OH radicals may also be present in the mixture.

Method for Supplying High Temperature Thermal Energy to External Process using Combustor Assembly

[0287] Figure 18 is a flow chart illustrating steps in a method 3000 for producing high temperature thermal energy for an external process 513 using electrolysis and a combustor assembly 201, according to some embodiments of the disclosure. The method 3000 describes the process cycle of the embodiments of the system 500 as described above with reference to Figures 7 to 9.

[0288] The method 3000 comprises the step 3001 of receiving, at an electrolyser 503, pure water (H2O) and separating it into hydrogen gas (H2) and oxygen gas (O2). The method 3000 also comprises the step 3002 of providing the combustor assembly 201, 210 according to any one of the embodiments described with reference to Figures 3 to 6, where the fuel comprises the hydrogen gas from the electrolyser 503 and the oxidant comprises the oxygen gas from the electrolyser 503. The method 3000 then comprises the step 3003 of providing the flow of exhaust gases 211 comprising steam in the form of water vapour (H2O) from the final combustor component 100-n of the combustor assembly 201 as the high temperature thermal energy for use in the external process 513. The method 3000 also comprises the step 3004 of receiving, at a condenser 519, the steam after use by the external process 513 and condensing the steam into pure water. Finally, the method 3000 completes the process cycle by returning the pure water to the electrolyser 503 for re-use.

[0289] In some embodiments, the method 3000 may further comprising modifying, using a pressure controller 510, 512, the pressure of the hydrogen gas and/or oxygen gas produced by the electrolyser 503 to ensure that a desired pressure of the flow of exhaust gases 211 at a final combustor component 100-n of the combustor assembly 201 will be satisfied for the external process 513.

[0290] In some embodiments, the method 3000 may further comprise receiving, at a compressor 505, the hydrogen gas from the electrolyser 503 and increasing its pressure for storage in a hydrogen storage vessel 509. The method 3000 may further comprise receiving, at a compressor 507, the oxygen gas from the electrolyser 503 and increasing its pressure for storage in an oxygen storage vessel 511.

[0291] The method 3000 may further comprise providing additional pure water to the condenser 519 based on loss of steam to the external process 513. The method 3000 may also comprise returning, using a condensate pump 531, pure water from the condenser 519 to the electrolyser 503.

[0292] In some alternative embodiments, the method 3000 comprises receiving a source of a diluent and combining, using a mixing device 303, the diluent with the hydrogen gas produced by the electrolyser 503 to form a homogenous mixture of the fuel to be provided at the first combustor component 100-1. The method 3000 may comprise modifying, using a pressure controller 605, the pressure of the diluent to ensure that it is sufficient to combine with the hydrogen gas produced by the electrolyser 503 at the first combustor component 100-1. The method 3000 may also comprise removing, using a diluent pump 525, diluent from the condenser 503, and receiving, at a compressor 609, the diluent from the condenser 519 and increasing its pressure for storage in a diluent storage vessel 603 ready for re-use in the combustor assembly 201.

[0293] The method 3000 may also comprise extracting, using a pump 531, 533, pure water from the condenser 519 and increasing its pressure for use in heating the flow of exhaust gases 211 from at least one combustor component 100-1 to 100-n to a desired temperature for use as a fuel in a subsequent combustor component 100-(l-n) in the combustor assembly 201. Finally, the method 3000 may comprise varying, using a bleed line 535, the composition of the pure water extracted from the condenser 519 to be returned to the electrolyser 503.

[0294] Figure 19 illustrates steps in another method 3020 for producing high temperature thermal energy for an external process using electrolysis and a combustor assembly, according to some embodiments of the disclosure. The method 3020 comprises the step 3001 of receiving, at an electrolyser 503, pure water (H2O) and separating it into hydrogen gas (H2) and oxygen gas (O2). The method 3020 also comprises the step 3002 of providing the combustor assembly 201, 210 according to any one of the embodiments described with reference to Figures 4 to 6, where the fuel comprises the hydrogen gas from the electrolyser 503 and the oxidant comprises the oxygen gas from the electrolyser 503. The method 3020 then comprises the step 3003 of providing the flow of exhaust gases 211 comprising steam in the form of water vapour (H2O) from the final combustor component 100-n of the combustor assembly 201 as the high temperature thermal energy for use in the external process 513.

[0295] The method 3020 is similar to the method 3000 of Figure 18 except that it includes optional recycling of steam after use by the external process as indicated by the broken lines for steps 3004 and 3005. In some embodiments, the method 3020 may optionally include the step 3004 of receiving, at a condenser 519, the steam after use by the external process 513 and condensing the steam into pure water. Finally, the method 3020 may complete the process cycle at step 3005 by returning the pure water to the electrolyser 503 for re-use. The method 3020 may comprise one or more of the additional steps mentioned above with reference to the method 3000 of Figure 18. Method for Supplying High Temperature Hydrogen to External Process using Combustor Assembly

[00100] Figure 20 is a flow chart illustrating steps in a method 3010 for producing high temperature hydrogen gas for use in an external process, according to some embodiments of the disclosure. The method 3010 describes the process cycle of the embodiments of the system 700A as described above with reference to Figure 9.

[0296] The method 3010 of Figure 20 is configured to heat hydrogen gas (H2) for use in an external process 623 (see Figure 9). The method 3010 comprises the step 3012 of providing the combustor assembly 201, 210 (e.g., assembly 201 A of Figure 9) according to any one of the embodiments described with reference to Figures 3 to 6. The method 3010 also comprises the step 3013 of receiving, at a heat exchanger 613, the flow of exhaust gases 211 from the final combustor component 100-n. The method 3010 also comprises the step 3014 of heating, using the heat exchanger 613, a flow of hydrogen gas for use in the external process 615 by imparting thermal energy to the flow of hydrogen gas from the flow of exhaust gases 211.

[0297] In some embodiments, the method 3010 may further comprise receiving, at an electrolyser 503 (see Figures 7 and 8), pure water (H2O) and separating it into hydrogen gas (H2) and oxygen gas (O2). The method 3010 may further comprise providing the flow of hydrogen gas to be heated from the electrolyser 503. Additionally/altematively, the flow of hydrogen gas may be supplied from a hydrogen storage vessel 509 (see also Figures 7 and 8). In this example, the method 3010 may further comprise regulating, using a valve 611, the pressure of the flow of hydrogen gas from the electrolyser 503 prior to heating in the heat exchanger 613.

[0298] Where an electrolyser 503 is employed, the fuel of the combustor assembly 201 may comprise hydrogen gas from the electrolyser 503 and the oxidant of the combustor assembly 201 comprises the oxygen gas from the electrolyser 503. The flow of exhaust gases 211 received at the heat exchanger 613 may comprise steam in the form of water vapour (H2O).

[0299] In other embodiments, the system 700A may also employ a condenser 519. Thus, the method 3010 may further comprise the step of receiving, at a condenser 519, the steam after use by the heat exchanger 613 to condense the steam into pure water. Finally, the method 3010 may comprise the step of returning the pure water to the electrolyser 519 for re-use. Calcination and e-Methanol Production

[0300] Aspects of the present disclosure have already described systems and methods which convert green electricity into high-temperature heat through the combustion of green hydrogen with oxygen produced through electrolysis of water. The application of this technology may desirably eliminate the combustion of fossil fuels in a calciner and associated kiln, if used, in calcination processing of feedstocks.

[0301] While calcination processing typically refers to thermal decomposition of limestone (CaCCh) into lime (CaO) and CO2 gas, the process can be applied to decomposition of hydrated mineral to remove water of crystallization, decompose volatile matter such as carbonaceous matter, selective removal of ions through heat, and other thermal decomposition processes. Thus, the feedstocks and raw meals which may be processed by the systems and methods disclosed herein may include various sources, and cover applications including calcination of battery minerals, including the extraction of lithium from spodumene, for example. Embodiments of the disclosure are mainly related to calcination of limestone as a raw meal, as occurs in cement production. This predominantly produces CO2, which can be purified to produce a substantially pure stream of CO2 and optionally used as a by-product for e-Methanol synthesis, as will be described. However, it is to be appreciated that embodiments of the disclosure are not limited to calcination of limestone, e.g., for cement production, but can be applied to other calcination processes.

[0302] By deploying the novel combustor assembly 201 as disclosed herein in calcination processing two benefits may be obtained: (i) CO2 formation from the calciner and kiln fossil fuel combustion is eliminated, reducing the total CO2 formation from the calcination process; and (ii) the exhaust gas from the calciner is a mixture of CO2 and water vapour, and this gas upon cooling and removal of condensed water, yields a near-pure CO2 stream that eliminates the need for a separate CO2 capture plant.

[0303] In contrast, where hydrogen is used for combustion with air in the calciner or calcinerkiln system, nitrogen is a dominant component of the flue gas, making subsequent capture of CO2, as part of post-combustion capture process, prohibitively expensive given the diluted concentration of CO2 in the flue gas to be treated. In addition, combustion of hydrogen with air produces large amounts of NOx emissions, a major pollutant and toxin. [0304] Figure 21 is a schematic diagram illustrating a process cycle configuration utilising the combustor assembly 201, 210 according to various embodiments of the disclosure and as described in relation to Figures 3 to 6 to achieve electrification of high temperature thermal energy supply for calcination, and optionally e-methanol production. The system 4000 depicted in Figure 21 is simplified and only identifies the main components for carrying out the calcination processing. However, it should be understood that additional components may be provided in the system 4000 for operation as would be appreciated by a person skilled in the art. The different lines shown in the key represent distinct fluid flows/materials in the process cycle.

[0305] The calcination system 4000 comprises at least one combustor assembly 4020, 4030, and at least one calcination component 4040, 4050 configured to calcinate a feed material 4090. The calcination component 4040, 4050 is configured to receive the flow of exhaust gases 211 from a final combustor component 100-n of the at least one combustor assembly 4020, 4030 to impart thermal energy to the feed material 4090.

[0306] The system 4000 may comprise two combustor assemblies, namely a kiln combustor assembly 4020 and a calciner combustor assembly 4030. Furthermore, the system 4000 may comprise two calcination components, namely a calciner 4050 and a kiln 4040, in gaseous communication with the flow of exhaust gases 211 from the respective combustor assemblies 4030, 4020. In some embodiments, the system 4000 may comprise only of the calciner 4050 and calciner combustor assembly 4030, or only of the kiln 4040 and kiln combustor assembly 4020, or a combination of both, as shown in Figure 21.

[0307] The calciner 4050 is configured to receive the feed material or raw meal 4090 and the flow of exhaust gases 211 (e.g., steam) from the calciner combustor assembly 4030 to impart thermal energy to the feed material 4090 being processed by the calciner 4050. The kiln 4040 is configured to receive the feed material 4090 and the flow of exhaust gases 211 from the kiln combustor assembly 4020 to impart thermal energy to the feed material 4090 being processed by the kiln 4040. In this embodiment, the kiln 4040 is configured to receive processed feed material 4090 from the calciner 4050 and heat the processed feed material 4090 using the flow of exhaust gases 211 from the kiln combustor assembly 4020.

[0308] The system 4000 may also include an electrolysis sub-system 4010 which includes an electrolyser and sources of hydrogen and oxygen gas. The electrolyser converts a stream of treated water into gaseous hydrogen and oxygen using renewable electricity. These gases are separated, compressed and stored to optimise the cost of production, considering the variable nature of renewable electricity. The electrolysis sub-system 4010 may also include storage vessels for hydrogen and oxygen gas, and associated compressors to compress the gas for such storage. The electrolyser may include similar features to the electrolyser 503 as described in relation to Figures 7 and 8. The sources of hydrogen and oxygen gas may include similar features to the hydrogen compressor 505 and storage vessel 509 and oxygen compressor 507 and storage vessel 511 as described in relation to Figures 7 and 8.

[0309] The electrolyser may be configured to receive to receive pure water (H2O) and separate it into hydrogen gas (H2) and oxygen gas (O2). The combustor assemblies 4020, 4030 of the system 4000 may be configured to utilise the hydrogen gas from the electrolyser as the fuel and the oxygen gas from the electrolyser as the oxidant, and the flow of exhaust gases 211 from the final combustor component 100-n of the combustor assemblies 4020, 4030 may comprise steam in the form of water vapour (H2O).

[0310] The hydrogen and oxygen gases are systematically combusted in combustor assemblies 4020 and 4030 installed to provide high temperature heat to the kiln 4040 and the calciner 4050, respectively. The heat supplied to the kiln 4040 can range from approximately 900°C to 1600°C, but predominantly approximately 1400°C, and that supplied to the calciner 4050 can range from approximately 500°C to 1100°C, but predominantly is approximately 900°C. Combustion of hydrogen and oxygen gases in the kiln 4040 and the calciner 4050 produces high temperature steam, which imparts its heat to the solids being processed and the kiln 4040 and calciner 4050 itself, maintaining the desired operating temperatures in the respective equipment.

[0311] In the case of cement production, as example, most of the calcination process (exceeding 90%) occurs in the calciner 4050 where predominantly calcium carbonate (CaCCh) is converted into lime or calcium oxide (CaO), while releasing carbon dioxide (CO2) gas. Residual calcination of the supplied solids is achieved in the kiln 4040. Thus, the off-gas or by-product gas from the kiln 4040 and the calciner 4050, by virtue of utilising the novel combustor assemblies 4020 and 4030, respectively, comprises a mixture of carbon dioxide (CO2) and steam (H2O) in this embodiment.

[0312] The off-gas or by-product gas from the kiln 4040 and the calciner 4050 is then cooled through a heat exchanger 4060, which imparts heat to a hot stream of CO2 obtained from a calcined product cooler 4070. This even hotter stream of CO2 is then drawn into a raw meal preheater 4080, where the fresh feed of solids or raw meal 4090 is preheated to approximately 650 °C. This temperature may vary depending on the material being calcined.

[0313] The cooler streams of CO2 obtained from the heat exchanger 4060 and the preheater 4080 (after giving up heat to the preheating of solids 4090) are further cooled in a condenser 4100 to near ambient temperatures. This facilitates condensation of the water vapour into liquid water for effective separation of CO2 and liquid water in the condenser 4100. A near-pure or substantially pure stream of CO2 is thus produced from the condenser 4100 for downstream process use e.g., for an external or industrial process.

[0314] Condensed water from the condenser 4100 can be sent to a water treatment unit 4110 of the system 4000 as shown in Figure 21 to remove any entrained solids and neutralise any acidity or alkalinity. Purified and treated water can then be recycled back to the electrolysis sub-system 4010, to reduce the water footprint.

[0315] Fans or blower 4120 provides energy to circulating CO2 and water vapour streams to effectively recover heat from the hot calcined product solids exiting the kiln 4040 in the calcined product cooler 4070. The calcined product cooler 4070 is configured to receive and cool the processed feed material from the kiln 4040 as shown in Figure 21. Additionally/altematively, in embodiments which omit the kiln 4040, the cooler 4070 is configured to receive and cool the processed feed material from the calciner 4050 (not shown).

[0316] The calcined product cooler 4070 comprises a plurality of cooling zones in which heat is recovered from the processed feed material (e.g., from the kiln 4040 or optionally from the calciner 4050) and deployed within the calcination system 4000. The cooler 4070 can be roughly separated into three cooling zones: the hottest primary or first cooling zone immediately adjacent to the kiln 4040 outlet, the intermediate cooling zone or second cooling zone, and a final or third cooling zone closest to the cooled calcined solids outlet of the calcined product cooler 4070. The hottest heat recovered from the primary or first cooling zone is led to the kiln combustor 4020, to reduce fresh fuel (hydrogen) and oxidant (oxygen) demand. The secondary heat recovered from the intermediate or second cooling zone is led to the calciner combustor 4030, to reduce fresh fuel (hydrogen) and oxidant (oxygen) demand. The tertiary heat recovered from the final or third cooling zone is led to the heat exchanger 4060 for recovering heat from the off-gas leaving the kiln 4040 and the calciner 4050 as described earlier. Fan or blower 4130 provides energy for circulating this tertiary stream of CO2 and steam mixture to heat the fresh raw meal solids 4090 in the preheater 4080. This desirably maximises thermal energy recovery and thus the overall thermal efficiency.

[0317] The electrolysis sub-system 4010 also supplies gaseous hydrogen gas to react with the near or substantially pure stream of CO2 from the condenser 4100 in the e-Methanol synthesis unit 4140. The e-Methanol synthesis unit 4140 pretreats the CO2 and gaseous hydrogen streams and then synthesizes these gases into liquid methanol, which may thus be produced using green electricity by use of the electrolysis sub-system 4010. The e-Methanol synthesis unit 4140 may comprise a methanol synthesis plant, with the features and operations known from commercially available technology. For example, the methanol plant 4140 may use green-electricity-produced hydrogen gas as a feed input, such as the hydrogen gas (H2) supplied by the electrolysis subsystem 4010, which is reacted with CO2 gas produced by the calcination system 4000. Methanol may be produced in the plant 4140 by a two-step process which firstly reduces the CO2 gas to carbon monoxide (CO), and secondly reduces the carbon monoxide (CO) with the hydrogen gas to produce methanol (CH3OH). Alternatively, methanol may be produced in the plant 4140 by a direct hydrogenation of the CO2 gas with hydrogen gas in a one-step process.

[0318] Thus, the novel combustor assemblies 4020, 4030 may enable complete decarbonising of the calcination process, while creating a pure or substantially pure stream of CO2 for effective production of e-Methanol being liquid methanol, use of which may include as a sustainable fuel in the transportation sector (e.g., aviation, shipping, road transport) can further decarbonise this significant CO2 emitting sector.

[0319] The temperatures of the preheater 4080, calciner 4050 and kiln 4040 may vary drastically depending on the product being calcined. The temperatures indicated and the overall flow scheme depicted in Figure 21 is more suited for green cement production along with the optional e-Methanol product.

[0320] The calcination may be direct, where the combustor gases come in direct contact with the solids to be calcined (as in cement production, as example) or indirect, where the combustor gases heat the solids to be calcined contained within a metallic shell (as in battery minerals, as example).

[0321] The orientation of the calciner 4050 and kiln 4040 could vary from being vertical or horizontal or inclined to varying degrees of inclination. The orientation of the combustor assemblies 4020, 4030 could vary from being on either end of the calciner 4050 and/or kiln 4040 or any of the sides, or either top or bottom or any combinations of these orientations.

[0322] The calciner 4050, the preheater 4080 and the combustor assemblies 4020, 4030 of the system 4000 could be modified in construction to suit and adapt to retrofit onto existing plant equipment, machinery forming or serving directly or indirectly the calciner 4050 or kiln 4040 in an existing plant, as would be required in a retrofit application, converting an existing plant from the use of fossil fuels to green electricity as primary source by the use of the novel combustor assemblies 4020, 4030 provided by the present disclosure.

[0323] The calciner 4050 and preheater 4080 of the system 4000 could be of cyclonic construction, in part or in varying combinations. The various components of the system 4000 shown in Figure 21 could be arranged in parallel multiple streams of varying sizes and with cross-connections between equipment, if so desired for maximising flexibility, reliability and availability of the overall system 4000. The various components of the system 4000 shown in Figure 21 could be designed to operate under varying pressures and varying temperatures as best suited for the process conditions.

[0324] The process interfaces to the e-Methanol synthesis unit 4140 can vary depending on the technology offering of the e-Methanol synthesis technology provider. The process disclosed in Figure 21 is agnostic to the e-Methanol synthesis process that will be used.

[0325] Electrolysers within the electrolysis sub-system 4010 can be alkaline, PEM, solid oxide, salt water, but may include other possible types of electrolysers as known to a person skilled in the art in achieving the desired gaseous hydrogen and gaseous oxygen production.

[0326] Calciner 4050 can be cyclonic, fluidized bed, spiral flow, vertical, horizontal, multiplehearth furnaces, rotary, stationary, inclined, direct-fired or indirect-fired, but may include other possible types of calciners as known to a person skilled in the art in achieving the desired high operating temperatures and other process operating conditions required for the calcination process.

[0327] Kiln 4040 can be vertical shaft, horizontal inclined, updraft, downdraft, direct-fired or indirect-fired, but may include other possible types of kilns as known to a person skilled in the art in achieving the desired high operating temperatures and other process operating conditions required for the process.

[0328] Preheater 4080 can be suspension, travelling grate, cyclonic, vertical, horizontal, rotary, stationary, inclined, direct-fired or indirect-fired, heat exchange vessels, but may include other possible types of preheaters as known to a person skilled in the art in achieving the desired heat exchange to the process material / feed.

[0329] Calcined Solids Cooler 4070 can be grate type, single cylinder type, multiple cylinder type, rotary cooler, moving grate plate type, fixed grate plate type, vibrating type, push type, indirect cooling drums, but may include other possible types of calcined solids coolers as known to a person skilled in the art in achieving the desired cooling of solids with effective heat recovery.

[0330] Heat exchanger 4060 can be tubular, shell and tube, regenerative, rotary, stationary, finned, un-finned, with turbulators, without turbulators, but may include other possible types of heat exchangers as known to a person skilled in the art in achieving the desired heat transfer.

[0331] Condenser 4100 can be tubular, shell and tube, direct contact, absorber, trayed column, trayed column with downcomers, trayed column without downcomers, packed column, unpacked column spray absorber, glass-lined, rubber-lined, unlined, but may include other possible types of condensers as known to a person skilled in the art in achieving the condensing duty while effectively separating the moisture from the CO2 gas.

[0332] Fans / Blowers 4120, 4130 can be centrifugal type, turbo type, positive displacement type, dynamic type, multi-lobe roots blower type, vane type, liquid ring type, but may include other possible types of fans / blowers as known to a person skilled in the art in achieving the desired movement of gases throughout the system. The location of the fans / blowers 4120, 4130 and the number provided could vary, depending on the cycle interactions and system design.

[0333] Figure 22 is a flow chart illustrating steps in a method 5000 for producing high temperature thermal energy for calcination and optional e-methanol production, according to some embodiments of the disclosure. The method 5000 may be implemented with one or more components as shown in the flow process chart and system 4000 of Figure 21. [0334] The method 5000 comprises the step 5002 of providing at least one combustor assembly, and preferably may include providing two combustor assemblies being a kiln combustor assembly 4020 and a calciner combustor assembly 4030. The combustor assemblies may include the features shown and described in respect of the embodiments of Figures 3 to 6. The method 5000 also comprises the step 5003 of receiving, at at least one calcination component, and preferably at two calcination components being a kiln 4040 and calciner 4050, the flow of exhaust gases 211 from a final combustor component 100-n of the at least one combustor assembly. The method 5000 also comprises the step 5004 of calcinating a feed material 4090, using the at least one calcination component (e.g., kiln 4040 and/or calciner 4050), by imparting thermal energy from the flow of exhaust gases 211 to the feed material 4090.

[0335] Where the combustor assembly comprises the calciner combustor assembly 4030, the method 5000 may include at the step 5003 receiving at the calciner 4050 the feed material 4090 and the flow of exhaust gases 211 from the calciner combustor assembly 4030 to impart thermal energy to the feed material being processed by the calciner 4050. Where the combustor assembly includes additionally or alternatively the kiln combustor assembly 4020, the method 5000 may include at the step 50003 receiving at the kiln 4040 the feed material 4090 and the flow of exhaust gases 211 from the kiln combustor assembly 4020 to impart thermal energy to the feed material being processed by the kiln 4040. In embodiments including both the kiln 4040 and the calciner 4050, the method 5000 may comprise receiving, at the kiln 4040, processed feed material from the calciner and heating the processed feed material using the flow of exhaust gases 211 from the kiln combustor assembly 4020.

[0336] The method 5000 may further comprise the steps of receiving, at a calcined solids cooler 4070, the processed feed material from the at least one calcination component (for example, from the kiln 4040 as shown in Figure 21), and cooling the processed feed material using the cooler 4070. The method 5000 may further comprise the steps of recovering heat from the processed feed material in a plurality of cooling zones of the cooler 4070, and deploying the recovered heat within a calcination system 4000.

[0337] The method 5000 may further comprise one or more of the following steps: recovering heat from a first cooling zone adjacent to the kiln 4040, and providing the recovered heat to the kiln combustor assembly 4020; recovering heat from a second cooling zone adjacent to the first cooling zone, and providing the recovered heat to the calciner combustor assembly 4030; and recovering heat from a third cooling zone adjacent to an outlet of the cooler 4070, and providing the recovered heat to a heat exchanger 4060 for cooling off-gas from the calciner 4050 and kiln 4040.

[0338] In other embodiments, the method 5000 may further comprise the step of heating, using a preheater 4080, the feed material 4090 to a desired temperature prior to delivery to the at least one calcination component (e.g., the calciner 4050 as shown in Figure 21). The method 5000 may further comprise providing, to the preheater 4080, a flow of gases (e.g., CO2 with H2O) to which thermal energy is imparted by the heat exchanger to heat the feed material 4080.

[0339] Figure 22 illustrates optional steps in the method 5000 as shown by steps 5001, 5005, 5006 and 5007 with broken lines and arrows. The method 5000 may include the optional step 5001 before the step of providing the combustor assembly 5002 of receiving, at an electrolyser (e.g., in the electrolysis sub-system 4010), pure water (H2O) and separating it into hydrogen gas (H2) and oxygen gas (O2). The combustor assemblies 4020, 4030 may utilises the hydrogen gas from the electrolyser as the fuel and the oxygen gas from the electrolyser as the oxidant, and the flow of exhaust gases from the final combustor component of the combustor assemblies may comprise steam in the form of water vapour (H2O).

[0340] At optional step 5005, the method 5000 may further comprise receiving, at a condenser 4100, a mixture of carbon dioxide (CO2) and steam from the heat exchanger 4060 and/or preheater 4080 and condensing the gas mixture to produce a substantially pure gas flow of CO2 and substantially pure water. At optional step 5006, the method 5000 may further comprise receiving, at an e-methanol synthesis unit 4140, the substantially pure gas flow of CO2 from the condenser 4100 and a flow of hydrogen gas from the electrolyser (e.g., via the electrolysis subsystem 4010). A final optional step 5007 may comprise producing liquid methanol from the gas flows of CO2 and hydrogen gas.

[0341] In some embodiments (not shown), the method 5000 may further comprise returning the substantially pure water from the condenser 4100 to the electrolyser (e.g., via the electrolysis sub-system 4010) for re-use. The method 5000 may also comprise circulating, using one or more blowers 4120, 4130, fluid flows within the calcination system 4000 to maximise thermal energy recovery. Steam Pyrolysis

[0342] Another aspect of the present disclosure is directed towards improvements in steam cracking or pyrolysis. By way of background, an initial description of the current technology is provided below. Figure 23 is a schematic of a steam cracker 1100 used in the current technology with a dual furnace arrangement. Multiple furnaces are typically arranged in parallel, and need not be restricted to a two or dual furnace arrangement. Figure 24 illustrates a flow diagram of the cracking process using the steam cracker 1100.

[0343] The highly endothermic cracking reactions are initiated by heating a hydrocarbon feed source to high temperatures in the presence of steam. This “cracks” the feedstock (breaks the feedstock molecules apart) to produce desirable products inside the cracker coils or tubes 1105. The feedstock travels through the furnace through the cracker coils or tubes 1105 and never comes in direct contact with the fuel being burned inside the furnace firebox 1107. The feedstock is delivered to the cracker coils or tubes 1105 in its gas or liquid state (e.g., heavier feedstocks are delivered in liquid form).

[0344] The feedstock first passes through the top portion of the steam cracker 1100 for preheating through the stack 1101. Steam is added to the feedstock, partly through the preheating process as “dilution steam”, to lower the partial pressure of the feedstock, and keep the feedstock molecules from recombining once broken apart. The preheated feedstock and dilution steam mixture then passes through the high-temperature radiant section 1113 with radiant coils or tubes 1105 of the furnace firebox 1107.

[0345] Inside the firebox 1107, side wall burners 1103 and/or bottom burners 1109 combust fossil fuels with combustion air to discharge heat at flame temperatures of approximately 1250°C. Combustion of fossil fuels with air at such high temperatures emit tonnes of toxic thermal-NOx emissions as nitrogen and oxygen gases in the combustion air combine, besides emitting in excess of 260 million tonnes of carbon dioxide per year, making this process unit the largest emitter for the chemical industry.

[0346] Thermal energy radiates from the burners 1103, 1109 directly impinging on metallic heat transfer tubes or coils 1105 suspended vertically in the furnace 1100, achieving a skin tube metal temperature of 1050°C. These tubes 1105 transmit the incident radiant energy on the outside skin of the tubes 1105 to the hydrocarbon feed and steam mixture contained within to a cracking temperature of approximately 850°C. The temperature gradient from the outside skin temperature of 1050°C to the internal 850°C enables this heat transfer while sustaining the maximum temperature the material of construction can withstand without softening and deforming under the hot operating conditions.

[0347] A higher tube internal temperature is desired for maximal ethylene yield, for example; however, this cannot be achieved due to metallurgical constraints imposed by the materials of construction of the heat transfer tubes 1105, which are currently exotic speciality alloys containing chromium, iron and nickel. Heating these heat transfer tubes 1105 any further will result in softening, bending, deforming and eventual catastrophic puncture of the tubes releasing highly flammable hydrocarbons into the furnace 1100. Tube temperatures are therefore continuously monitored, and any inadvertent transient excursions in temperature require expensive premature tube replacements. Also, these tubes have low life expectancy, requiring planned periodic replacements as well over the lifetime of the entire plant.

[0348] Effluent cracked gas from each furnace passes through one or more heat exchangers, and aggregated into a cracked gas header 1115 via a system of transfer line valves prior to downstream operations. The flue gases from the combustion of fuel in the cracking furnace are then led to a convection section 1111 where heat in the flue gases is transferred across feed preheating and steam generating tubes. The convection section 1111 thus serves as an energy recovery system to reduce the overall energy consumption of the steam cracking process.

[0349] The current technology suffers from the following drawbacks:

[0350] 1. Maximal reaction product yields cannot be achieved due to the inability of metal tubes to withstand the required higher external skin temperatures. Equilibrium conversion for the dehydrogenation of ethane to produce ethylene at 1 bar pressure requires the hydrocarbon steam mixture to achieve in excess of 1000°C internal tube temperature. However, this is currently limited to ~875°C (corresponding to approximately 1150°C maximum external tube skin metal temperature for tubes made from Cr-Ni alloys) due to metallurgical constraints. See chart in Figure 34 which illustrates theoretical equilibrium conversion for the dehydrogenation of ethane (C2H5), propane (CsHs) and isobutane (C4H10) at 1 bar with respect to the reaction temperature.

[0351] 2. As the hydrocarbon feedstock passes through the radiant tubes, a layer of carbon (i.e., coke) builds up on the interior of the tubing over time, forming a physical heat transfer hindering barrier inside the tubing. Coke deposits are created on the inner walls of the cracking furnace tubes through undesirable catalysis in the presence of nickel and iron in the furnace tube’s base steel. Because of this build up, the tubing gradually gets hotter during the cracking process due to its inability to transfer the radiant heat on its external surface to the hydrocarbon and steam mixture flowing inside the radiant tubes. The temperature of the tubing increases by 3 to 4 °C per day even with a constant firebox temperature because the coke acts as an insulator on the tubing. When the temperature of the tubing gets to about 1100°C, the furnace 1100 must be taken out of production so the internal coke deposits can be removed (i.e., burned out) of the tubing 1105 (this is known as decoking). These coke deposits are so severe that the cracking furnace 1100 must be taken off-line and decoked about every 20 to 60 days (McKimpson. 2006. High- Performance, Oxide-Dispersi on- Strengthened Tubes for Production of Ethylene and Other Industrial Chemicals. EPA Docket No. EPA-HQ-OAR-2017-0357 ).

[0352] Prior to decoking, the fuel firing rate of the ethylene cracking furnace is reduced, and hydrocarbon feedstock is stopped, leaving steam as the only stream being sent through the radiant tubing to purge any hydrocarbons out of the system. The furnace is then isolated from the process, and the radiant tubing effluent is directed to a decoking header, and either diverted to a decoking pot (cyclone separator) for solids and effluent gas separation or back into the firebox. Air and steam are gradually added to the inside of the radiant tubing until the internal coke lining ignites. The coke burn is then monitored using the radiant tube outlet temperature and the outlet CO2 levels in the decoke header stack. Once the coke burn is completed, as indicated by a drop in emitted CO2 levels, the furnace can be placed back into normal operation. Thus, the decoking operation results in additional CO2 emissions, NO_X emissions and Hazardous Air Pollutant (HAP) emissions.

[0353] 3. High-temperature wall and floor burners have poor reliability due to the severe operating conditions, requiring daily monitoring for flame impingement on the tubes, formation of local hot spots, effects due to localised internal coke buildup that further reduces cracker run times. Often these burners cannot be easily repaired and require frequent replacements. Emissions excursions from design are a common occurrence.

[0354] In summary, owners and operators of steam crackers, in particular ethylene crackers, currently experience high operating and maintenance costs due to the following factors:

• The coke deposits of a few millimeters to centimeters in thickness lead to poor heat transfer. To retain the same process temperature and hence the same cracking conversion, the cracking furnace firebox temperature must be raised continuously (e.g., burning more fuel), which often leads to more rapid coke formation.

• Shortened life of the radiant tubes because of the constant thermal cycling of the tubes.

• Excessively high temperature during decoking cycles is assumed to be the most important cause of radiant tube failure.

[0355] The decoking operations also result in loss of ethylene production due to the following reasons:

• The coke build-up also increases the pressure drop, which results in lower ethylene yield.

• With time, the accumulation of coke forces the operator to shut down the cracking furnace due to temperature or pressure drop. The furnace is, therefore, taken offline for coke removal (decoking).

Pyrolysis Component

[0356] Some embodiments of the disclosure will now be described that seek to at least ameliorate one or more disadvantages of the present technology in steam cracking as mentioned above.

[0357] The current technology of steam cracking typically uses a steam to hydrocarbon ratio of 0.3 to 0.4 on a mass basis, with all the heat required for the endothermic reactions being provided by fossil-fuel fired burners in the radiant furnaces, then transferred across heat transfer coils, as described above in relation to Figures 23 and 24. In contrast, the pyrolysis component or steam cracker of the disclosure adds all the endothermic energy demand directly into the reaction zone using higher temperature steam, without any external conductive heat source. Thus, the steam cracker operates at markedly different steam to hydrocarbon ratios exceeding 4 and up to 7, but preferably operating at a steam to hydrocarbon ratio of approximately 5.7 for a pure ethane feed. This ratio will of course vary with the hydrocarbon feed composition, but will remain significantly higher due to the fact that all of the heat for the cracking reactions is provided using the very steam mixed with the hydrocarbon.

[0358] Figures 25 and 26 illustrate the components of a pyrolysis component 6000 according to some embodiments of the disclosure. The pyrolysis component 6000 comprises a main body 6001. The main body 6001 comprises a feed inlet 6011 configured to receive a feed material 6013 comprising at least one hydrocarbon. The main body 6001 also comprises a preheat gas inlet 6005 configured to receive a preheat gas flow 6003 for preheating and mixing with the feed material 6013 in a preheating zone 6200 of the main body 6001 (see also Figure 28). The main body 6001 also comprises a main gas inlet 6009 configured to receive a main gas flow 6007 for heating a mixture of the preheated feed material and preheat gas flow in a cracking zone 6300 of the main body 6001 to produce a gas flow 6031 comprising one or more products (see also Figure 28).

[0359] The feed material or feedstock 6013 may be in liquid or gaseous state when received at the feed inlet 6011 of the main body 6001. Heavier feedstocks 6013 are typically provided in liquid state. The feed material 6013 comprises at least one hydrocarbon. The feed material 6013 may be a mixture of hydrocarbons and/or other substances. The at least one hydrocarbon may be a saturated hydrocarbon. The saturated hydrocarbon may be an alkane, such as methane (CH4), ethane (C2H5), propane (CsHs) or butane (C4H10), to name a few. In other embodiments, the feed material 6013 may include naphtha, gas oil, or crude oil for example, obtained from the oil refining and/or petrochemical industry.

[0360] The one or more products produced by the cracking or pyrolysis process may comprise at least one hydrocarbon and/or hydrogen gas (H2). The hydrocarbon may be an unsaturated hydrocarbon, such as an alkene, alkyne or aromatic hydrocarbon. The unsaturated hydrocarbon may be an olefin. The unsaturated hydrocarbon may be an alkene. The alkene may be ethylene (C2H4), propylene (C3H5) or butylene (C4H8), to name a few. Additionally, one or more byproducts may be produced in the process including water and other hydrocarbon products.

[0361] Turning to Figure 25, the main body 6001 of the pyrolysis component 6000 is illustrated in detail. Preferably, the main body 6001 is a ceramic-lined reactor vessel that is suitably profiled, shaped and dimensioned to achieve the effective cracking of a hydrocarbon feed 6013 to maximise product yield, especially olefin yield. The main body 6001 comprises two gas inlets, a preheat gas inlet 6005 and a main gas inlet 6009. In the embodiment shown, there may be two preheat gas inlets 6005 as indicated by the nozzles 6005A and 6005B. However, there may be more than two preheat gas inlets 6005, and preferably, four preheat gas inlets 6005 as shown in the end view of Figure 26. Figure 26 illustrates the end portion 6039 of the main body 6001 adjacent the preheating zone 6200 with four preheat gas nozzles 6005 A-D that are circumferentially spaced around the main gas inlet nozzle 6009A. The spacing may be equidistant as shown or otherwise unevenly spaced. In other embodiments, there may be more than four preheat gas nozzles and inlets. [0362] The main gas inlet 6009 is illustrated as being axially oriented relative to the main body 6001 to direct the main gas flow 6007 towards the cracking zone 6300 (see also Figure 28). The main gas inlet 6009 may be axially aligned with a central axis 6035 indicated by the line Y-Y’ in Figure 25. The axial alignment results in directing the main gas flow 6007 entering the main body 6001 along the central axis 6035 and towards the cracking zone 6300. The main gas inlet 6009 may include at least one nozzle 6009A in fluid communication with the main gas inlet 6009 to direct the gas flow towards the cracking zone 6300. It is to be recognised that some cracking may initiate in the preheating zone 6200 as well as the cracking zone 6300. The pyrolysis component 6000 may allow for progression of increased cracking as soon as the feed material or feedstock 6013 enters the cracker 6000.

[0363] Figures 25 and 26 also illustrate the main body 6001 comprising a feed inlet 6011 for a feed material 6013 and optionally, two feed inlets 6011 with two corresponding nozzles 6011 A and 601 IB that are diametrically opposed in the main body 6001 as shown in Figure 26. The main body 6001 may also comprise a recycle feed inlet 6015 for a feed recycle material 6017 and optionally, two recycle feed inlets 6015 with two corresponding nozzles 6015 A and 6015B that are diametrically opposed in the main body 6001 as shown in Figure 26. The feed recycle material 6017 may include recycled feed material comprising the at least one hydrocarbon. The nozzles 6011 A-B and 6015A-B are illustrated in broken -lines since would not normally be visible in the plane shown in Figure 25 or the end views of Figures 26 and 27.

[0364] The feed nozzles 6011 A-B and 6015 A-B may be circumferentially spaced relative to an external surface 6037 of the main body 6001 (see Figures 26 and 27). The spacing may be equidistant as shown or otherwise unevenly spaced. In other embodiments, there may be more than four feed nozzles. The feed nozzles 6011 A-B and 6015 A-B are ideally angled such that they are not directly aligned with the respective preheat gas nozzles 6005 A and 6005B. The feed nozzles 6011 A-B and 6015 A-B are thus staggered relative to the preheat gas nozzles 6005 A and 6005B as best illustrated in Figures 26 and 27 to achieve preferred flow profiles for the preheating/mixing zone 6200. Although four feed nozzles are illustrated in Figures 26 and 27, the main body 6001 could include any number of feed nozzles, and different numbers of feed nozzles and recycle feed nozzles, and yet all nozzles may be evenly distributed around the circumference of the main body 6001. The feed nozzles and recycle feed nozzles may also not be diametrically opposed and may be adjacent to one another in some alternative arrangements. [0365] In some embodiments, the feed nozzle(s) may also receive a mixture of a feed material or feedstock 6013 and a feed recycle material 6017. Thus, the feed inlet 6011 and feed recycle inlet 6015 may consist merely of feed inlets and corresponding nozzle(s) for the feedstock mixture instead of designated inlets/nozzles depending on the material received at the main body 6001. The feed material 6013 and/or the feed recycle material 6017 and/or a mixture thereof are received in a feed zone 6100 of the pyrolysis component 6000 (see also Figure 32). The preheat gas flow 6003 preheats and mixes with the feed material 6013 and/or the feed recycle material 6017 in the preheating/mixing zone 6200 of the main body 6001. The nozzles 6011A-B and 6015A-B may be configured to direct the flow of the feed material 6013 and/or the feed recycle material 6017 and/or a mixture thereof towards the preheating zone 6200.

[0366] Preferably, the hydrocarbon feed material 6013 is introduced into the reactor 6000 using a plurality of nozzles 6011 A-B equi-distant and oriented along a circumference, similar to nozzles 6005 A-D. The hydrocarbon recycle feed 6017 from a downstream process is introduced into the reactor 6000 using a plurality of nozzles 6015 A-B equi-distant and oriented along a circumference, similar to nozzles 6005 A-D and 6011 A-B. Alternatively, the fresh hydrocarbon feed and recycle hydrocarbon feed 6013, 6017 can be premixed in a header and introduced through nozzles 6011 equi-distant and oriented along a circumference, similar to nozzles 6005. All nozzles 6005 A-D and nozzles 6011, 6015 and 6023 A-B (discussed below) are ideally sized and oriented to maximise the mixing of the volumetric flow rates of the respective flow streams, while achieving the desired preheat temperature within the preheating/mixing zone 6200, illustrated in Figure 28.

[0367] The main body 6001 may also include a fluid inlet 6023 and optionally, two fluid inlets 6023 illustrated with two corresponding nozzles 6023 A and 6023B in Figure 25. Although two nozzles are shown, there may be more than two fluid inlets/nozzles, preferably at least four fluid inlets/nozzles, which may optionally be circumferentially spaced relative to an external surface 6037 of the main body 6001. The spacing may be equi-distant as shown or otherwise unevenly spaced. The fluid inlet 6023 may be configured to receive a fluid flow to reduce the temperature of the gas flow comprising the one or more products in an optional quenching zone 6400 of the main body 6001 adjacent the cracking zone 6300. The quenching zone 6400 may produce only partial quenching of the fluid flow, and a process or quench fluid 6025 may be received through the fluid inlet 6023 and into the main body 6001. The nozzles 6023 A-B may be configured to direct the flow of the fluid 6025 towards the quenching zone 6300. [0368] In some preferred embodiments, the preheat gas flow 6003 and/or the main gas flow 6007 may comprise steam in the form of water vapour (H2O). Thus, the pyrolysis component 6000 may be a steam pyrolysis component or a steam cracker. The preheat steam 6003 and/or the main steam 6007 may be supplied by a gas source 7600 (see Figure 32). The gas source 7600 may be a source of steam which is produced at a particular temperature and/or pressure appropriate for the pyrolysis process.

[0369] In some embodiments, the gas source 7600 comprises at least one combustor assembly 201 according to any one of the embodiments previously described in this specification. The flow of exhaust gases 211 from the combustor assembly 201 may supply the preheat gas flow 6003 and/or the main gas flow 6007 received at the main body 6001 of the pyrolysis component 6000. In some preferred embodiments as illustrated in Figure 32, the gas source 7600 may comprise two combustor assemblies 7100 and 7200 which are each supplied fuel and oxidant via an electrolysis sub-system 7300. A first combustor assembly 7100 may supply the preheat gas flow 6003 received at the preheat gas inlet 6005 of the pyrolysis component 6000. A second combustor assembly 7200 may supply the main gas flow 6007 received at the main gas inlet 6009 of the pyrolysis component 6000. The electrolysis sub-system 7300 may be similar to the electrolysis sub-system 4010 as previously described in this specification. Depending upon the hydrocarbon processing capacity of the pyrolysis component 6000, and particularly when arranged as part of the pyrolysis assembly 9000 shown in Figure 36 and Figure 37, the individual combustor assemblies 7100 and 7200 may each comprise of multiple combustor assemblies 201, arranged to operate in parallel.

[0370] The electrolysis sub-system 7300 may include an electrolyser and sources of hydrogen and oxygen gas. The electrolyser converts a stream of treated water into gaseous hydrogen and oxygen using renewable electricity. The electrolyser employed preferably comprises capillary- fed proton exchange membrane (PEM) electrolytic cells with more than 90% efficiency, but could be of any type to produce hydrogen and oxygen gases. These gases are separated, compressed and stored to optimise the cost of production, considering the variable nature of renewable electricity. The electrolysis sub-system 7300 may also include storage vessels for hydrogen and oxygen gas, and associated compressors to compress the gas for such storage. The electrolyser may include similar features or be of a similar type to the electrolyser 503 as described in relation to Figures 7 and 8. The sources of hydrogen and oxygen gas may include similar features to the hydrogen compressor 505 and storage vessel 509 and oxygen compressor 507 and storage vessel 511 as described in relation to Figures 7 and 8. Each combustor assembly 7100, 7200 may utilise the hydrogen gas from the electrolyser as the fuel and the oxygen gas from the electrolyser as the oxidant. Thus, the flow of exhaust gases 211 from the final combustor components of each combustor assembly 7100, 7200 may comprise steam in the form of water vapour (H2O).

[0371] The preheat gas flow 6003 may be preheat steam produced via the electrolysis subsystem 7300, such that preheat and mixing steam can be produced at temperatures suited to achieve preheat of a steam and hydrocarbon feed mixture. The suitable temperature is preferably in the range of about 500°C to about 700°C, or in the range of about 550°C to about 700°C, or in the range of about 500°C to about 650°C, or in the range of about 550°C to about 650°C, but preferably about 600°C inside the preheating/mixing zone 6200 of the reactor 6000. The preheat steam 6003 is introduced into the reactor 6000 at multiple points using nozzles 6005A-D as shown in Figures 25 and 26. The nozzles 6005A-D may be located circumferentially at pitch circle diameters suitably optimised to produce the required steam velocity, direction and flow profile that will maximise the mixing, while optimising the use of preheat steam 6003. Primary cracking zone heat is provided by cracking steam 6007, which may also be produced from a gas source 7600 as shown in the system 7000 of Figure 32.

[0372] The main gas flow 6007 may be cracking steam produced via the electrolysis sub-system 7300, such that the cracking steam 6007 can be produced at temperatures suited to achieve cracking of a steam and hydrocarbon feed mixture. The suitable temperature is preferably in the range of about 1100°C to about 1400°C, or in the range of about 1250°C to about 1350°C, or in the range of about 1280°C to about 1320°C, but preferably about 1310 °C (for a pure ethane feedstock) in the cracking zone 6300, as shown in a similar theoretical chart of Figure 34. It must be noted that the preferred temperature may vary with the composition of the hydrocarbon feed mixture, its paraffinic content, its cyclical hydrocarbon content, proportion of bio-oil or feedstocks derived from recycled plastics, and the steam to hydrocarbon ratio.

[0373] Axially oriented central nozzle 6009 A introduces the cracking steam at high velocity into the cracker. The desirable velocity determines the nozzle diameter for the cracking steam supply flow, pressure and temperature. Together with the profile 6019 of the cracking zone 6300 of the reactor 6000, the system 7000 controls the residence time of the hydrocarbon feed in the steam cracking zone 6300 for the operating pressure in consideration. The residence time is expected to be approximately less than about 150 milliseconds, and preferably less than about 50 milliseconds (for a pure ethane feedstock), depending on the feed characteristics and high temperatures achieved within the pyrolysis component or steam cracker 6000. It must be noted that the preferred residence time may vary with the composition of the hydrocarbon feed mixture, its paraffinic content, its cyclical hydrocarbon content, proportion of bio-oil or feedstocks derived from recycled plastics, and the steam to hydrocarbon ratio. Temperatures and flow rates of streams 6003 and 6007 are optimised to obtain the preferred temperatures in the various reaction zones within the reactor 6000, obtain the desirable flow regimes while optimising the steam to hydrocarbon ratio in the hydrocarbon and steam mixture to maximise the product yield, particularly ethylene yield, in the cracker 6000.

[0374] In some embodiments, the main body 6001 is shaped and/or dimensionally profiled to direct gases flow towards the cracking zone 6300. As shown in Figures 25 and 28, the main body 6001 is tapered from the preheating zone 6200 to a narrowed or neck portion 6021 of the main body 6001. The narrowing acts to accelerate gases flow towards the cracking zone 6300. Furthermore, the reactor wall 6019 downstream of the mixing zone 6200 may be sloped and/or profiled to also direct gases flow towards the cracking zone 6300. The reactor wall 6019 may be profiled into a parabolic, elliptic, cubic or hyperbolic (or any similar mathematical function) shape, or any similar geometric shape in order to create an efficient Venturi nozzle effect that serves to accelerate the flows entering the main cracker zone 6300 as shown in Figure 28 and corresponding pressure profiles as shown in Figure 30.

[0375] The high-velocity, high-temperature cracking steam 6007 creates an eductor or jet pump effect inducing the premixed and preheated hydrocarbon feed diluted by preheat steam to enter the high-temperature cracking zone 6300. The Venturi profile, converging into a throat section 6021 lowers the cracking zone pressure to the most desirable pressure to maximise product yield, especially olefin yield. The throat section 6021 also achieves maximal velocity and minimal residence time desired for optimal ethylene cracking at very high temperatures (approximately 1310°C in some embodiments for a pure ethane feedstock). Thus, some embodiments of the disclosure provide for an eductor zone 6500 which draws and/or accelerates the mixture of the feed material and preheat gas flow towards the cracking zone 6300.

[0376] Following the cracking zone 6300, chemical quench fluid 6025 from a downstream process (e.g., in the form of low temperature steam, low temperature hydrocarbon or any similar fluid) is introduced through a plurality of equi-spaced nozzles 6023 A-B corresponding to a plurality of fluid inlets 6023 to rapidly drop the temperature of the cracked hydrocarbon leaving the throat section 6021. This thermal quench serves to preserve the composition of the cracked hydrocarbon, while preventing over-cracking of the hydrocarbon, and thus maximise desired product yield, especially olefin yield. The reactor section downstream of the throat section 6021 is profiled as a continuously expanding zone or diverging portion 6027 that expands in dimension from the cracking zone 6300 to an outlet 6029 of the main body 6001. The diverging portion 6027 maximises pressure energy recovery, as the effluent hydrocarbon from the throat section 6021 slows down converting a portion of the kinetic energy into pressure energy.

[0377] The outlet 6029 of the pyrolysis component 6000 can interface as suited for existing and/or new facilities, terminating in a mechanically welded connection to the downstream heat recovery systems and subsequent separation sections, as depicted in the system 7000 of Figure 32 as External Quench 7400 and Separation Sections 7500. The final cracked product, e.g., olefin-rich hydrocarbon stream 6031, thus leaves the reactor 6000 for downstream heat recovery and separation of non-olefin hydrocarbons.

[0378] It is to be appreciated that the physical location and spacing of the nozzles, including all inlets and outlets of the pyrolysis component 6000 may vary from those shown and described with reference to Figures 25 to 31. For example, the feed nozzles (6011 A-B), feed recycle nozzles (6015 A-B) and preheat gas nozzles 6005 A-D may be interchangeable and their location on the main body 6001 varied as long as the feed material 6013, preheat gas flow 6003, and optionally, the recycle feed material 6017 is able to be delivered to the mixing zone 6200 for mixing in the pyrolysis component 6000. Similarly, the location and spacing of the fluid nozzles 6023 A-B may be varied while still delivering a quench fluid 6025 to the diverging portion 6027.

[0379] Figure 28 depicts the various desirable flow regimes created in the pyrolysis component or steam cracker 6000. Multiple streams of preheating steam 6003 are introduced into the reactor 6000 circumferentially as depicted in Figure 28. These streams could be linear or incorporate a swirl in anticlockwise or clockwise direction or a flat fan flow profile or hollow cone flow profile to provide inertial stability and or penetration as the steam enters the preheating/mixing zone 6200. The flow pattern and/or profile of the streams may be varied through design of the nozzle(s) 6005A-D to promote the intimate mixing of the steam and hydrocarbon, and also to promote the rapid vaporization of hydrocarbon feed when it is supplied to the cracker 6000 in liquid state.

[0380] Multiple streams of hydrocarbon feed 6013 and/or recycle feed 6017 and/or a mixture of fresh hydrocarbon feed and recycle hydrocarbon are introduced into the reactor 6000 circumferentially in the feed zone 6100 as depicted in Figure 28. These streams could be linear or incorporate a swirl in anticlockwise or clockwise direction or a flat fan flow profile or hollow cone flow profile to provide inertial stability and or penetration as the steam enters the mixing zone 6200. The flow pattern and/or profile of the streams may be varied through design of the nozzle(s) 6011A-B and 6015A-B to promote the intimate mixing of the steam and hydrocarbon, and also to promote the rapid vaporization of hydrocarbon feed when it is supplied to the cracker 6000 in liquid state.

[0381] The feed inlet 6011, 6015 and the preheat gas inlet(s) 6005 may be positioned on the main body 6001 to provide interfacing flow streams of the feed material 6013 and/or recycle feed 6017 and/or a mixture thereof and the preheat gas flow or steam 6003. The feed inlet 6011, 6015 and the preheat gas inlet(s) 6005 may be angled towards the main gas inlet 6009. The angling of the feed inlet 6011, 6015 and the preheat gas inlet(s) 6005 may promote intimate mixing of the two fluids and also promote the rapid vaporization of hydrocarbon feed when it is supplied to the cracker 6000 in liquid state, while effectively preheating the feed inlet 6011, 6015 prior to flowing towards the main gas inlet 6009 through the eductor zone 6500. A preheating and mixing zone 6200 is established by the flow patterns created by the multiple incoming streams 6003 and 6013, 6017.

[0382] The minimum velocity of the preheat gas flow 6003 may be about 15 m/s. For example, the minimum velocity may be about 15 m/s for gaseous feed materials 6013, 6017, and about 1.5 m/s for liquid feed materials 6013, 6017 As previously discussed, the temperature of the preheating zone 6200 is preferably in the range of about 500°C to about 700°C, or in the range of about 550°C to about 700°C, or in the range of about 500°C to about 650°C, or in the range of about 550°C to about 650°C, but preferably about 600°C inside the preheating/mixing zone 6200 of the reactor 6000. The purpose of the mixing zone 6200 is to preheat the hydrocarbon feed 6013, 6017 to the desired premix temperature of approximately 600°C, while contributing to the optimal final steam to hydrocarbon ratio required for the intense cracking process to occur downstream.

[0383] Central axial very high temperature and high velocity steam in the form of the main gas flow 6007 is injected into the central axial portion 6036 of the reactor 6000 as shown in Figure 28. This flow stream could be linear as shown, or alternatively, incorporate a swirl in anticlockwise or clockwise direction to provide inertial stability and penetration as the steam enters the cracking zone 6300. The flow pattern and/or profile of the streams may be varied through design of the nozzle 6009A of the main gas inlet 6009. The minimum velocity of the main gas flow 6007 may be about 15 m/s. For example, the minimum velocity may be about 15 m/s for gaseous feed materials 6013, 6017, and about 1.5 m/s for liquid feed materials 6013, 6017. As this flow stream penetrates into the central converging reactor section 6036 towards the narrowing throat portion 6021 (see Figure 25), it creates an eductor effect pulling preheated and intimately premixed steam and hydrocarbon mixture into the main cracker reactor zone 6300. Such eductor zone 6500 is depicted in Figure 28. Zone 6500 may see fluid velocities approaching and even exceeding the sonic velocity for the resulting hydrocarbon composition, while lowering the cracking pressure due to the Venturi effect. These features serve to maximise the product yield, especially the ethylene yield, while optimising the residence time to prevent over-cracking of the hydrocarbon feed 6013, 6017.

[0384] Multiple streams of process fluid 6025 (steam or recycled hydrocarbon) are introduced as jets in the circumferential quenching zone 6400 with the intent of quenching the heat contained in the cracked hydrocarbons leaving the cracking zone 6300. These streams could be linear or incorporate a swirl in anticlockwise or clockwise direction or a flat fan flow profile or hollow cone flow profile to provide inertial stability and or penetration into the cracked hydrocarbon feed intimately mixing and effectively “freezing” the hydrocarbon composition with maximal product yield, especially olefin yield, leaving the cracking zone 6300. The flow pattern and/or profile of the streams may be varied through design of the nozzle 6023 A-B. Care is taken to effectively quench the outlet hydrocarbon stream, while retaining sufficient amount of heat for downstream energy recovery by ways of steam generation or feed-product heat exchange. Such measures improve the overall efficiency of the process, reducing the specific energy consumption, especially for olefin production.

[0385] The quenched flow continues along zone 6400, regaining pressure energy, as the fluid slows down with increasing cross-sectional area provided by a diverging conical section 6027. Thus, a portion of the kinetic energy in the fluid may be recovered as pressure energy.

[0386] Figure 29 illustrates the claimed temperature regimes in the pyrolysis component 6000 or steam cracker clearly depicting the preheating/premix zones 6200 at approximately 600°C, the high temperature steam cracking zone 6300, where temperatures increase further to approximately 1310°C and the rapid chemical quench zone 6400 with temperatures approximately lower than 580°C (such temperature profile representative of a pure ethane feed stream at 6013). These temperatures are approximate and will vary with the composition of the hydrocarbon feed mixture, its paraffinic content, its cyclical hydrocarbon content, proportion of bio-oil or feedstocks derived from recycled plastics, the steam to hydrocarbon ratio and various optimisation parameters (pressures, velocities, residence times) to maximise the desired product yield, e.g., olefin yield. The temperatures may comprise the ranges and preferable values as previously described above in relation to the preheating zone 6200, cracking zone 6300 and quench zone 6400. The cracking zone 6300 is thus at a higher temperature than the preheating zone 6200 and/or the diverging portion 6027/quench zone 6400 of the main body 6001.

[0387] Figure 30 illustrates the pressure profile in the pyrolysis component 6000. The cracker design is characterised by a clear pressure transition, while achieving a significantly lower operating pressure in the narrow throat portion 6021 of the main body 6001 and thus, in the cracking zone 6300. Lowering the cracking zone pressure increases product yield, especially olefin yield. Fluid entry zones 6033 in proximity to area are at higher pressures driving the reacting and diluting fluids downstream towards the throat region/cracking zone 6300. The Venturi effect created by the unique reactor profile 6019 greatly increases the velocity of the reacting fluids at maximal temperatures, while lowering the pressure in area 6300. All these factors together maximise product yield, e.g., olefin yield, namely high temperatures, low pressures and minimal residence time created by the high velocity of the hydrocarbon fluid mixed with steam. Pressure regime 6400, characterised by a widening, diverging cross-section serves to recover the kinetic energy in the cracked fluid as pressure energy, gradually increasing in pressure, when compared to the throat pressure regime illustrated as 6300.

[0388] Thus, the cracking zone 6300 is at a lower pressure than the preheating zone 6200 and/or the diverging portion 6027/quenching zone 6400 of the main body 6001. The pressure in the respective zones of the pyrolysis component 6000 is a pressure gradient between about 0.5 bar to about 2 bar as shown in Figure 30. The fluid entry zone 6033 is at higher pressure and is preferably in the range of about 1.5 bar to about 2 bar, or in the range of about 1.8 bar to about 2 bar, or with a maximum pressure of about 2 bar. The pressure in the preheating zone 6200 is preferably in the range of about 1 bar to about 2 bar, or in the range of about 1 bar to about 1.8 bar, or in the range of about 1 bar to about 1.5 bar, or with a maximum pressure of about 1.8 bar. The pressure in the cracking zone 6300 is at lower pressure than either the fluid entry zone 6033 and the preheating zone 6200, and is preferably in the range of about 0.1 bar to about 1 bar, or in the range of about 0.5 bar to about 1 bar, or in the range of about 0.5 bar to about 0.7 bar, or with a minimum pressure of about 0.5 bar, or with a minimum pressure of about 0.1 bar. The pressure in the quenching zone 6400 is at a higher pressure than the cracking zone 6300 and is preferably in the range of about 1 bar to about 2 bar, or in the range of about 1 bar to about 1.5 bar, or with a maximum pressure of about 2 bar.

[0389] The entire extent of the cracking reactor 6000 exposed to the cracking reaction conditions may include an insulating liner 6043 which may comprise a refractory and/or ceramic material. The refractory and/or ceramic material could comprise, but not limited to, silicates of calcium, grades of alumina, magnesia, zirconia or a mixed grade of these materials. Figures 25 to 27 illustrate that an interior 6041 of the main body 6001 comprises an insulating material shown by a liner 6043 on walls of the main body 6001. Additionally, wetted components such as nozzles 6005A-D, 6009A, 6011A-B, 6015A-B and 6023 A-B injecting steam, hydrocarbon feed, recycle hydrocarbon feed and the chemical quench fluid may also be made of insulating refractory or ceramic materials. At times, the nozzles could be made of base metal coated with heatwithstanding ceramic materials of suitable thickness to withstand the operating conditions forming a thermal barrier coating, protecting the base metal by drastically slowing down heat transfer to the base metal.

[0390] The novel pyrolysis component 6000 provides an insulating refractory/ceramic lined reactor with no heat transfer surfaces or coils or metallic tubes used in the prior art. The absence of iron and nickel in the cracking zone 6300 eliminates any possibility of catalytic coke formation. Any amorphous coke formation in the solid state reacts with the high temperature steam to produce carbon monoxide, carbon dioxide and hydrogen gases, resulting in its destruction. Any unreacted residual amorphous coke may deposit on the reactor walls and does not affect the cracking reaction. Thus, the novel pyrolysis component 6000 eliminates decoking interruptions currently required in all existing steam crackers, which rely on heat transfer across metallic tubes containing iron, nickel and chromium or similar as base metals of construction. Additionally, the reactor 6000 is significantly less expensive due to its ceramic-lined construction and can be sized for optimal velocities and short residence times, with little concern of residual amorphous coke formation/deposits on the ceramic lining.

[0391] The external housing and/or surface 6037 of the reactor 6000 may comprise metal capable of withstanding temperatures up to around 400°C. The insulating refractory material ideally protects the outer metallic shell 6037 from exposure to any higher temperatures than the metal capability. The outer metallic shell 6037 also provides means of welding anchors (not shown) that enable adherence of castable refractory, and provides internal reinforcement to the refractory material. When provision for thermal expansion is provided for in the form of expansion joints (not shown) within the refractory material, provision can be made for suitable purge to ensure that hot hydrocarbons from the reaction zone 6300 do not migrate towards the outer metallic shell 6037.

[0392] Figures 27 and 31 illustrate the various dimensional parameters key to the function and desired performance of the pyrolysis component 6000. These parameters will vary depending upon the quality of hydrocarbon feed and recycle feed mixture, its physical state as supplied to the steam cracking unit (liquid or gaseous), its chemical composition (naptha, gas oil, crude, natural gas, alkanes, etc), its supply temperature and supply pressure. Table 2 further describes these individually. Table 2 also provides parameter values of a pyrolysis component 6000 of some embodiments of the disclosure used in a preferred configuration for a 0.108 TPH ethane feed cracker. Where Table 2 includes values or ranges for the parameters, it is to be understood that the values or ranges are approximate only and may be varied. It is also to be appreciated that this example is an example only and not limiting on the scope of the invention that may be claimed.

[0393] Table 2 - Pyrolysis Component: Dimensional Parameter Descriptors

Pyrolysis System

[0394] Figure 32 illustrates a pyrolysis system 7000 according to some embodiments of the disclosure, and the zones in the pyrolysis component 6000. The features shown in broken lines indicate those features which are preferable/optional to the pyrolysis component 6000 and system 7000. The different lines shown in the key represent distinct fluid flows in the system 7000. The pyrolysis system 7000 comprises the pyrolysis component 6000 according to any one of the embodiments as previously described. The pyrolysis system 7000 also comprises a gas source 7600 for supplying the preheat gas flow 6003 and/or the main gas flow 6007 received at the main body 6001 of the pyrolysis component 6000.

[0395] The pyrolysis component 6000 receives feed material 6013, e.g., fresh hydrocarbon feed stock, and also optionally, recycled feed material 6017, in a feed zone 6100 of the pyrolysis component 6000. The feed zone 6100 as illustrated in Figure 28 is located adjacent the feed inlets 6011 (see 6011 A)and recycle feed inlets 6015 (see 6015 A) in an interior 6041 of the main body 6001. As shown in Figure 28, the feed material 6013 and/or optional recycle feed material 6017 are then diluted by the preheat gas flow 6003 in the preheat/dilution zone 6200. In some embodiments, the preheated gas flow 6003 which in some embodiments is steam, preheated, and then the mixture may be ideally cracked in the gas phase into lower olefins, such as ethylene and propylene.

[0396] An important difference to the current technology is that the high temperature heat is added internal to the pyrolysis component or steam cracker 6000 without relying on external heat transfer, thus eliminating problematic metallic heat transfer surfaces. Moreover, the cracking in the pyrolysis component 6000 occurs at significantly higher temperatures e.g., maximising product yield, especially ethylene yield. The cracker operating pressures can be similar to existing processes, although these can be optimised to e.g., maximise ethylene or propylene yield beyond what is currently feasible. As pyrolysis component or steam cracker 6000 is able to operate at temperatures higher than currently available technology, an optional chemical quench in the quench zone 6400 is introduced to “freeze” the reactor effluent composition by rapid cooling of the cracked hydrocarbon using high pressure fluid (steam or hydrocarbon at significantly lower temperatures), to prevent over-cracking. This quench rapidly stops the cracking reaction by establishing a rapid and sudden drop in resulting fluid temperature. The quench may be restricted (partial in extent) to allow downstream heat recovery systems to effectively recover the residual heat in the form of steam production for electricity generation or preheating other hydrocarbon streams, and thus reduce the overall energy consumption. [0397] In some embodiments, the pyrolysis system 7000 comprises a quenching component 7400 external to the pyrolysis component 6000. The quenching component 7400 is configured to reduce the temperature of the gas flow comprising the one or more products produced in the cracking zone 6300. Downstream energy recovery sections can also be provided for quench including the external quench 7400 to lower specific energy consumption for e.g., olefin production. The external quench 7400 may be one or more heat exchangers, and preferably, a bank of shell and tube heat exchangers utilising feedwater which will convert to steam, as is used in the current technology. Such steam can be used for energy recovery within the production facility, reducing the specific energy consumption for e.g., olefin production. In other embodiments, the pyrolysis system 7000 excludes the quenching component 7400 and is instead configured to interface and retrofit with existing quench systems and production facilities e.g., for olefin production.

[0398] In some embodiments, the pyrolysis system 7000 further comprises a separation component 7500 external to the pyrolysis component 6000. The separation component 7500 is configured to recover the one or more products from the gas flow and produce one or more byproducts. The separation sections 7500 may comprise a separator, e.g., distiller or other distillation components, as would be appreciated by a person skilled in the art. The increased yield through application of the steam cracker 6000 is expected to reduce the sizes of certain equipment in the downstream separation sections, while requiring debottlenecking of the product streams (e.g., olefin) due to increased yield of the desirable product. In other embodiments, the pyrolysis system 7000 excludes the separation component 7500 and is instead configured to interface and retrofit with existing separation systems and production facilities e.g., for olefin production.

[0399] The one or more by-products may comprise unused feed material which can be recycled from the separation component 7500 to a recycle feed inlet 6017 of the pyrolysis component 6000 as previously described. The one or more by-products may also comprise water which can be recycled from the separation component 7500, after effective purification and treatment, to the electrolyser sub-unit 7300 for re-use.

[0400] Figure 33 is a flow diagram of another pyrolysis system 7010 comprising the pyrolysis component 6000 and a gas source 7610, which may optionally comprise one or more combustor assemblies 7100, 7200 and an Air Separation Unit (ASU) sub-system 7310. The features shown in broken lines are optional/preferable features of the system 7010. The different lines shown in the key represent distinct fluid flows in the system 7010. The pyrolysis system 7010 is similar to the pyrolysis system 7000 as shown in Figure 32 with corresponding features having the same reference numerals.

[0401] In the pyrolysis system 7010, the electrolysis sub-system 7300 is replaced with a grid electricity powered cryogenic Air Separation Unit (ASU) sub-system 7310. The ASU subsystem 7310 cools atmospheric air to liquefy it at cryogenic temperatures, and then distills it to separate its constituents, in particular liquid oxygen, in this case. This liquid oxygen is then vaporized for use as an oxidant in the combustor assemblies 7100 and 7200. Hydrogen is a byproduct of pyrolysis, separated from the separation sections 7500. A portion of this hydrogen is recycled to the gas source 7610 to provide the fuel hydrogen in the combustor assemblies 7100 and 7200. Thus, in this possible arrangement of the pyrolysis system 7010, olefin producers with limited access to renewable energy, such as olefin producers in Japan may use carbon-free nuclear energy to operate the cryogenic ASU sub-system 7310 and still achieve decarbonization of their steam cracking process.

Pyrolysis Method

[0402] Figure 35 is a flow chart illustrating steps in a pyrolysis method 8000 according to some embodiments of the disclosure. The method 8000 comprises the step 8004 of supplying a feed material 6013 comprising at least one hydrocarbon to a main body 6001 of a pyrolysis component 6000. The method 8000 also comprises the step 8005 of preheating and mixing the feed material 6013 with a preheat gas flow 6003 in a preheating zone 6200 of the main body 6001. The method 8000 also comprises the step 8006 of heating a mixture of the preheated feed material and preheat gas flow in a cracking zone 6300 of the main body 6001 to produce a gas flow 6031 comprising one or more products.

[0403] In the method 8000, the pyrolysis component may be a pyrolysis component 6000 according to any one of the embodiments as previously described. The method 8000 may also include the optional step of providing the pyrolysis component 6000 before performing the step 8004 to 8006.

[0404] The method 8000 may also include one or both of the following optional steps: supplying the preheat gas flow 6003 to a preheat gas inlet 6005 of the main body 6001, and supplying the main gas flow 6007 to a main gas inlet 6009 of the main body 6001. The method 8000 may include performing both steps to supply the gas flows 6003, 6007. [0405] As shown in Figure 35, the method 8000 may include three optional steps 8001-8003 performed before the step 8004 of supplying the feed material 6013. The method 8000 may include the step 8001 of receiving, at an electrolyser (e.g., electrolyser of sub-system 7300) pure water and separating it into hydrogen gas (H2) and oxygen gas (O2). Alternatively, step 8001 may be replaced with a step of producing, at an air separation unit (e.g., see the ASU sub-system 7310 of Figure 33), oxygen gas (O2), and/or directing hydrogen gas (H2) for recycling at at least one combustor assembly 201, 7100, 7200. The method 8000 may also include step 8002 of providing at least one combustor assembly 201, 7100, 7200 according to any one of the embodiments as disclosed herein. The combustor assembly 201, 7100, 7200 may either receive hydrogen and oxygen gas from the electrolyser at step 8001, or alternatively receive oxygen gas from the air separation unit and hydrogen gas recycled from the process. Furthermore, the method 8000 may include the step 8003 of receiving the flow of exhaust gases 211 from the combustor assembly 201, 7100, 7200 to supply the preheat gas flow 6003 and/or the main gas flow 6007.

[0406] In some embodiments, the method 8000 includes the step of providing at least two combustor assemblies 7100, 7200 which each comprise the combustor assembly of any one of the embodiments as disclosed herein. The method 8000 may include the step of supplying the preheat gas flow 6003 from the flow of exhaust gases 211 from at least one first combustor assembly 7100, and the step of supplying the main gas flow 6007 from the flow of exhaust gases 211 from at least one second combustor assembly 7200.

[0407] As shown in Figure 35, the method 8000 may also comprise the optional steps 8007 and 8008 after the mixture is cracked to produce the gas flow 6031 with one or more products. At step 8007, the method 8000 may comprise reducing the temperature of the gas flow 6031 comprising the one or more products in a quenching zone 6400 of the main body 6001 adjacent the cracking zone and/or in a quenching zone 7400 external to the pyrolysis component 6000. In relation to the quenching zone 6400, the step 8007 may comprise supplying a fluid flow to a fluid inlet 6023 of the main body 6001 to reduce the temperature.

[0408] The method 8000 of Figure 35 may also optionally comprise the step 8008 of recovering the one or more products from the gas flow 6031 and producing one or more by-products in a separation component 7500 external to the pyrolysis component 6000. The method 8000 may comprise the step of recycling unused feed material of the one or more by-products to a recycle feed inlet 6017 of the pyrolysis component 6000. [0409] The one or more products resulting from the method 8000 may comprise at least one hydrocarbon and/or hydrogen gas (H2). The hydrocarbon may be an unsaturated hydrocarbon, such as an alkene, alkyne or aromatic hydrocarbon. The unsaturated hydrocarbon may be an olefin. The unsaturated hydrocarbon may be an alkene. The alkene may be ethylene (C2H4), propylene (C3H6) or butylene (C4H8), to name a few.

[0410] The disclosure also relates to an unsaturated hydrocarbon which is produced according to any one of the embodiments of the method 8000 disclosed herein. The disclosure also relates to an olefin produced according to any one of the embodiments of the method 8000 disclosed herein.

Pyrolysis Assembly

[0411] In another aspect, a plurality of pyrolysis components 6000 can be arranged in parallel forming a pyrolysis assembly 9000 according to some embodiments of the disclosure. The assembly 9000 may be retrofit in existing petrochemical facilities, and housed within existing steam cracker furnace housings 1100, 10001, 11001 as previously described, after removing the currently process constraining and problematic heat transfer surfaces. Provision of multiple pyrolysis components 6000 in parallel, allows for seamless turndown of production flow rates while not compromising individual cracker flow regimes for maximal product yield, particularly olefin yield.

[0412] Figure 36 depicts a possible arrangement of a pyrolysis assembly 9000 retrofitted in the firebox 10001 of an existing steam cracker 10000, similar to that shown in Figures 23 and 24 (cracker 1100). The intention is to continue utilisation of existing downstream heat recovery systems and product separation systems. Given the increased yield by the pyrolysis components 6000, de-bottlenecking of the downstream product stream is to be expected. The pyrolysis assembly 9000 in this embodiment comprises four pyrolysis components 6000 installed in parallel, however any number of components may be used as would be understood by a person skilled in the art.

[0413] The pyrolysis assembly 9000 is installed after removal of all the fossil fuel wall burners 1103, floor burners 1109 and vertically suspended heat transfer tubes 1105 shown in Figure 24 as the Radiant Section 1113. Independent steel structures (not shown), supported from the floor or from the walls and the floor of the cracker furnace 10001 enable mounting of the pyrolysis assembly 9000 in the empty space now created by the removal of the Radiant Section 1113. Elimination of all fossil fuel burners from the cracker furnace 10000 decarbonises this process completely, and the exhaust stack section 10011 can be removed.

[0414] In one embodiment of the retrofitted pyrolysis assembly 9000, the upper portion of the Radiant Section 1113 illustrated in Figure 24 is replaced by a refractory -lined pressurised plenum 10005. This refractory -lined pressurised plenum 10005 serves to collect the cracked gas from the pyrolysis assembly 9000, and is particularly economical for retrofitting into steam crackers of relatively smaller sizes. The shape of the refractory-line pressurised plenum 10005 serves to direct the cracked gas to a header 10007. Cracked gas from the header 10007 is then directed through pipes to existing heat recovery units or a new waste heat recovery unit 10009. Cooled cracked gas from headers 10007 emanating from multiple units, each comprising of a plurality of the pyrolysis components 6000 as an assembly 9000, can then be led to a common cracked gas header for further downstream processing. Thus, this embodiments enables the plurality of pyrolysis components 6000 to be configured for common collection of the gas flow 6031 comprising the one or more products.

[0415] Figure 37 depicts another possible arrangement of a pyrolysis assembly 9000 retrofitted in the firebox 110001 of an existing steam cracker 11000, similar to that shown in Figures 23 and 24 with cracker 1100. Similar to Figure 36, the pyrolysis assembly 9000 is installed after removal of the Radiant Section 1113. The pyrolysis assembly 9000 in this embodiment as shown in the example arrangement of Figure 37 comprises multiple rows of seven pyrolysis components 6000 installed in parallel (although any number of components 6000 could be provided) and the gas flow is collected from each individual pyrolysis component 6000 in multiple collection headers 11005. Flow in the multiple collection headers 11005 is then further led into transversely positioned header 11007, allowing a single point of evacuation of the cracked hydrocarbon. Such cracked gas collection system is particularly economical for retrofitting into steam crackers of relatively large sizes, typically requiring a common downstream header without a pressurised plenum. The remaining features of the pyrolysis system 11000 is similar to those corresponding features illustrated in relation to the pyrolysis system 10000 of Figure 36.

Advantages

[0416] By enabling safe, systematically staged and direct combustion of pure hydrogen with pure oxygen, some embodiments of the present disclosure may provide a direct means of electrifying the production of high temperature thermal energy for large scale industrial use (e.g., see Figures 7 to 9). The present disclosure may thus offer a significant breakthrough in decarbonising large steam consumers which currently have no option but to burn fossil fuels to generate large quantities of steam at high pressures and temperatures for use in their industrial processes.

[0417] The foremost distinctive feature of some embodiments of the present disclosure is systematic sequentially staged combustion of hydrogen with oxygen to deliberately distribute the flammability range over multiple stages, thereby achieving safe and stable hydrogen combustion with oxygen.

[0418] Restricting the oxidant supply to each novel individual combustor, and thenceforth staging the novel individual combustor components into a novel composite combustor assembly effectively spreads the combustion to systematically utilise the wide flammability range of hydrogen combustion with oxygen.

[0419] The systematic and staged nature of the combustion, utilising the novel composite combustor assembly, may produce all of its diluent required for stable combustion of pure hydrogen with oxygen, thereby creating a reliable system for combustion. External diluent in small quantity may be added to the first stage to reduce the capital expenditure, but is not necessary.

[0420] Within the individual combustor stage, the novel cyclonic flow pattern imparted to the hydrogen fuel stream may eliminate the need for premixing the fuel and oxidant (oxygen gas) as required in previous combustor designs. This greatly increases the safety of the combustion process by eliminating possibility of flashback, a major problem with previous combustor designs, if applied to the combustion of hydrogen with oxygen.

[0421] The use of the novel conical end cover 107 (e.g., see Figures 1 and 2) may effectively shield and project the restricted oxidant supply jet 106 such that the flame is positioned and held under the most suited conditions for fuel ignition and flame stability, without damaging any of the individual combustor components. Introducing fuel and oxidant into the combustion chamber from opposite ends of the combustor and traveling towards each other greatly limits any adverse effects of the high flame speed associated with combustion of hydrogen or hydrogen rich mixtures of fuel, as such high flame speeds cannot impinge on any physical component in the cyclonic flow field within this novel combustor. [0422] Facilitating the combustion of pure hydrogen with pure oxygen may allow creation of a cycle that can support electrolysis of the produced and condensed water. Through such a cycle, electrification of the production of high grade (high pressure and temperature) thermal energy may be achieved. When the electricity is sourced through green sources the present disclosure directly contributes to the decarbonisation of large scale industrial processes requiring high grade thermal energy.

[0423] Embodiments of the disclosure also provide a novel pyrolysis component or steam cracker, in which the supplied steam not only heats the reactants, but may also achieve high temperatures required to maximise product yield, particularly for ethylene and olefin production. The heat may be added directly into the reaction without requiring an external combustion chamber or heating process using coil tubes involving heat transfer from combustion zone of the furnace to the pyrolysis process across a metallic surface as used in current technology.

[0424] The addition of direct steam as a heat source and reactant may improve the selectivity by optimising the steam to hydrocarbon ratio and reducing the amorphous coking rate as more of the amorphous solid state carbon reacts with the high temperature steam to produce carbon monoxide, carbon dioxide and hydrogen gases. The amorphous coke formation does not affect the reaction rate and further, the reactor design is not constrained by increasing pressure drops due to amorphous coke formation. The novel steam cracker may thus have a higher availability compared to conventional steam cracker technology currently employed.

[0425] The constraints imposed by conventional coil tube metallurgy and the reducing crosssections due to internal coking may be thus removed. The novel pyrolysis component or steam cracker is ideally ceramic lined, creating an inexpensive design that does not require periodic shutdown for decoking, as is presently required for coil tubes.

[0426] Furthermore, the novel steam cracker and pyrolysis system and method may employ the novel combustor component/assembly as disclosed herein. This may allow for electrification of very high temperature heat as required for steam crackers. The combustor component/assembly can thus produce high temperature steam which can be tailored for use in the preheating and cracking zones of the novel pyrolysis component. This may allow for decarbonisation of steam cracker technology and significant reduction in de-coking operations reducing CO2, NOx and Hazardous Air Pollutant (HAP) emissions experienced with the current technology. [0427] It is to be understood that various modifications, additions and/or alternatives may be made to the parts previously described without departing from the ambit of the present invention as defined in the claims appended hereto.

[0428] Where any or all of the terms “comprise”, “comprises”, “comprised” or “comprising” are used in this specification (including the claims) they are to be interpreted as specifying the presence of the stated features, integers, steps or components, but not precluding the presence of one or more other features, integers, steps or components or group thereof.

[0429] It is to be understood that the following claims are provided by way of example only, and are not intended to limit the scope of what may be claimed in any such future application.

Features may be added to or omitted from the claims at a later date so as to further define or redefine the invention or inventions.

Claims

Claims:

1. A combustor component comprising: a combustion chamber comprising: an oxidant inlet configured to receive a gas flow of an oxidant; a fuel inlet configured to receive a gas flow of a fuel into the combustion chamber; and a gases outlet configured to allow passage of a flow of exhaust gases from the combustion chamber, wherein the combustor component is configured to facilitate separation of the gas flows of the oxidant and the fuel entering the combustion chamber prior to combustion of the fuel with the oxidant.

2. The combustor component according to claim 1, wherein the gas flows of the oxidant and the fuel entering the combustion chamber are in opposite directions upon entering the combustion chamber.

3. The combustor component according to claim 1 or claim 2, further configured to direct the gas flow of the fuel towards the oxidant inlet upon entering the combustion chamber through the fuel inlet.

4. The combustor component according to claim 3, wherein the combustion chamber comprises a tapered portion located between the gases outlet and the oxidant inlet to direct the gas flow of the fuel towards the oxidant inlet.

5. The combustor component according to claim 4, wherein the tapered portion is substantially conically-shaped.

6. The combustor component according to any one of claims 1 to 5, further configured to impart a tangential flow pattern to the gas flow of the fuel upon entering the combustion chamber through the fuel inlet. I l l

7. The combustor component according to claim 6, wherein the tangential flow pattern is a cyclonic flow pattern of the gas flow of the fuel around an internal wall of the combustion chamber as it moves towards the oxidant inlet.

8. The combustor component according to any one of claims 1 to 7, further comprising at least one nozzle angled relative to the combustion chamber and in fluid communication with the fuel inlet to direct the gas flow of the fuel at or along an internal wall of the combustion chamber.

9. The combustor component according to claim 8, comprising a plurality of nozzles configured to direct the gas flow of the fuel through a corresponding plurality of fuel inlets into the combustion chamber, wherein the plurality of nozzles and the corresponding plurality of fuel inlets are circumferentially spaced on an external surface of the combustion chamber.

10. The combustor component according to any one of claims 1 to 9, further comprising a shield portion extending into an interior of the combustion chamber and in fluid communication with the gases outlet to provide separation between the gas flow of the fuel entering through the fuel inlet and the flow of exhaust gases exiting through the gases outlet.

11. The combustor component according to any one of claims 1 to 10, wherein the fuel inlet is arranged adjacent to the gases outlet to facilitate separation of the gas flows of the oxidant and the fuel prior to combustion.

12. The combustor component according to any one of claims 1 to 11, further configured to direct the gas flow of the oxidant towards a combustion zone of the combustion chamber.

13. The combustor component according to claim 12, wherein the oxidant inlet is dimensioned to limit an amount of oxidant delivered to the combustion zone of the combustion chamber so that the oxidant is substantially or entirely consumed during combustion with the fuel.

14. The combustor component according to claim 12 or claim 13, wherein the oxidant inlet has an internal diameter sufficient to produce a jet flow of the oxidant into the combustion chamber.

15. The combustor component according to any one of claims 12 to 14, further comprising a guide portion extending into an interior of the combustion chamber and in fluid communication with the oxidant inlet to position the gas flow of the oxidant in the combustion zone of the combustion chamber.

16. The combustor component according to claim 15, wherein the guide portion extends axially into the interior of the combustion chamber and is substantially co-axial with the gases outlet.

17. The combustor component according to claim 15 or claim 16, wherein the combustion chamber further comprises a cover portion at least partly surrounding the guide portion, wherein the cover portion is configured to reverse the direction of the gas flow of the fuel towards the gases outlet.

18. The combustor component according to claim 17, wherein the cover portion is tapered from the oxidant inlet towards an opening of the guide portion.

19. The combustor component according to claim 18, wherein the cover portion is conically- shaped.

20. The combustor component according to any one of claims 1 to 19, further comprising at least one membrane wall located on an internal surface of the combustor component configured to absorb at least a portion of the thermal energy released during combustion of the fuel with the oxidant.

21. The combustor component according to claim 20, wherein the at least one membrane wall comprises a spiraled tube configured to receive a heat transfer fluid and a plurality of membrane fins that together form a contiguous heat transfer surface.

22. The combustor component according to any one of claims 1 to 21, wherein an interior of the combustor component, one or more inlets of the combustor component and/or the gases outlet of the combustor component comprise an insulating liner, wherein the insulating liner comprises a refractory and/or ceramic material.

23. The combustor component according to any one of claims 1 to 22, wherein the fuel comprises hydrogen (H2) gas or a mixture of hydrogen (H2) gas and a diluent gas, and wherein the oxidant comprises oxygen (O2) gas.

24. A combustor assembly for staged combustion of a fuel with an oxidant, the combustor assembly comprising: a plurality of combustor components arranged sequentially for staged combustion of the fuel with the oxidant, wherein each combustor component comprises a combustion chamber, and wherein at least one subsequent combustor component is configured to receive a flow of exhaust gases from a preceding combustor component as the fuel for combustion with a gas flow of the oxidant in the at least one subsequent combustor component, wherein the flow of exhaust gases produced from each combustor component comprises a proportion of the fuel provided to a first combustor component, which reduces in proportion to substantially none of the fuel provided to the first combustor component being present in the flow of the exhaust gases from a final combustor component.

25. A combustor assembly for staged combustion of a fuel with an oxidant, the combustor assembly comprising: a plurality of combustor components arranged sequentially for staged combustion of the fuel with the oxidant, wherein each combustor component comprises a combustion chamber, and wherein at least one subsequent combustor component is configured to receive a flow of exhaust gases from a preceding combustor component as the fuel for combustion with a gas flow of the oxidant in the at least one subsequent combustor component, wherein the flow of exhaust gases produced from each combustor component comprises a proportion of the fuel provided to a first combustor component, which reduces in proportion to a predetermined amount of the fuel being present in the flow of the exhaust gases from a final combustor component.

26. The combustor assembly according to claim 24 or claim 25, wherein an amount of oxidant provided to each of the plurality of combustor components is limited so that the oxidant is substantially or entirely consumed during combustion with the fuel in each combustion chamber.

27. The combustor assembly according to any one of claims 24 to 26, wherein the fuel provided to the first combustor component comprises one of: a pure gas; or a pure gas and a diluent.

28. The combustor assembly according to claim 27, further comprising a mixing device configured to combine the diluent with the pure gas to form a homogenous mixture of the fuel to be provided at the first combustor component.

29. The combustor assembly according to any one of claims 24 to 28, configured to adjust a temperature of the flow of the exhaust gases from at least one combustor component to a target temperature before use as the fuel in a subsequent combustor component.

30. The combustion assembly according to claim 29, further comprising one or both of: a temperature controller configured to operate a control valve for delivering a flow of a fluid for evaporation into the flow of exhaust gases to maintain the target temperature; and a spray device operable by the temperature controller to discharge the flow of the fluid passing through the control valve into the flow of exhaust gases.

31. The combustor assembly according to any one of claims 24 to 30, wherein the at least one subsequent combustor component and/or the final combustor component is configured to receive a flow of exhaust gases from two or more preceding combustor components.

32. The combustor assembly according to any one of claims 24 to 31, further comprising two or more combustor components for at least one stage of combustion.

33. The combustor assembly according to any one of claims 24 to 32, wherein the plurality of combustor components each comprise a combustor component according to any one of claims 1 to 23.

34. A method for staged combustion of a fuel with an oxidant, the method comprising: providing a plurality of combustor components arranged sequentially for staged combustion of the fuel with the oxidant, wherein each combustor component comprises a combustion chamber; and receiving, at at least one subsequent combustor component, a flow of exhaust gases from a preceding combustor component as the fuel for combustion with a gas flow of the oxidant in the at least one subsequent combustor component, wherein the flow of exhaust gases produced from each combustor component comprises a proportion of the fuel provided to a first combustor component, which reduces in proportion to substantially none of the fuel provided to the first combustor component being present in the flow of exhaust gases from a final combustor component.

35. A method for staged combustion of a fuel with an oxidant, the method comprising: providing a plurality of combustor components arranged sequentially for staged combustion of the fuel with the oxidant, wherein each combustor component comprises a combustion chamber; and receiving, at at least one subsequent combustor component, a flow of exhaust gases from a preceding combustor component as the fuel for combustion with a gas flow of the oxidant in the at least one subsequent combustor component, wherein the flow of exhaust gases produced from each combustor component comprises a proportion of the fuel provided to a first combustor component, which reduces in proportion to a predetermined amount of the fuel being present in the flow of the exhaust gases from a final combustor component.

36. A system configured to operate a combustor assembly to produce a flow of exhaust gases with one or more desired characteristics, the system comprising: the combustor assembly according to any one of claims 24 to 33; at least one sensor configured to measure one or more parameters of the flow of exhaust gases from a final combustor component in the combustor assembly; and a system controller configured to: receive a predetermined target flow of exhaust gases comprising the one or more desired characteristics; process the one or more parameters measured by the at least one sensor to determine a deviation from the predetermined target flow of exhaust gases; and modify one or more fluid flows in the system to meet the one or more desired characteristics of the predetermined target flow of exhaust gases.

37. The system according to claim 36, wherein the one or more desired characteristics comprise a desired composition, pressure and/or temperature of the flow of exhaust gases.

38. The system according to claim 37, when claim 36 is appended to claim 25 or any one of claims 26 to 33 when appended to claim 29, wherein the desired composition is the predetermined amount of the fuel being present in the flow of the exhaust gases from the final combustor component.

39. The system according to claim 38, wherein the flow of exhaust gases further comprises steam in the form of water vapour (H2O), and wherein the desired composition is a ratio of the predetermined amount of fuel to steam in the flow of exhaust gases from the final combustor component.

40. The system according to any one of claims 36 to 39, where the at least one sensor is configured to measure a concentration of one or more substances in the flow of exhaust gases from the final combustor component, wherein the one or more substances comprise oxygen (O2), hydrogen (H2) and/or hydroxyl ion (OH") concentration.

41. The system according to any one of claims 36 to 40, wherein the at least one sensor is configured to measure temperature, pressure and/or volume of the flow of exhaust gases from the final combustor component.

42. The system according to claim 41 when appended to claim 37, wherein the system controller is further configured to determine a mass flow of the exhaust gases from the final combustor component based on at least one of the concentration of the one or more substances, the temperature, the pressure and/or the volume of the flow of exhaust gases.

43. The system according to any one of claims 36 to 42, wherein the system controller is configured to modify one or more fluid flows in the system by one or both of: operating a fuel flow controller to modify the gas flow of the fuel provided to the first combustor component; and operating an oxidant flow controller to modify the gas flow of the oxidant provided to the combustor assembly.

44. The system according to claim 43, wherein the system controller is configured to operate the oxidant flow controller to modify the gas flow of the oxidant provided to each of the combustor components of the combustor assembly to limit an amount of oxidant so that the oxidant is substantially or entirely consumed during combustion with the fuel in each combustion chamber.

45. The system according to claim 43 or claim 44, wherein the system controller is further configured to receive a temperature signal of the flow of exhaust gases from at least one temperature controller associated with a combustor component of the combustor assembly, and wherein the system controller is further configured to operate the oxidant flow controller to modify the gas flow of the oxidant provided to each of the combustor components of the combustor assembly based on the temperature signal.

46. The system according to any one of claims 36 to 45, further comprising at least one sensor configured to measure pressure and/or volume of the gas flow of fuel and/or oxidant provided to at least one of the combustor components of the combustor assembly, wherein the system controller is further configured to modify the one or more fluid flows in the system also based on the measured pressure and/or volume of the gas flow of fuel and/or oxidant.

47. The system according to any one of claims 36 to 46, further comprising at least one safety feature to limit the gas flow of fuel and/or oxidant to at least one of the combustor components of the combustor assembly, wherein the at least one safety feature comprises one or both of a valve to stop the gas flow of fuel and/or oxidant to at least one of the combustor components and/or a flow limiter to limit the gas flow of fuel and/or oxidant to at least one of the combustor components; and a flow limiter to limit the gas flow of fuel and/or oxidant to at least one of the combustor components.

48. A system configured to produce high temperature thermal energy for an external process using electrolysis and a combustor assembly, the system comprising: an electrolyser configured to receive pure water (H2O) and separate it into hydrogen gas (H2) and oxygen gas (O2); the combustor assembly according to claim 24 or any one of claims 26 to 33 when appended to claim 24, wherein the fuel comprises the hydrogen gas from the electrolyser and the oxidant comprises the oxygen gas from the electrolyser, and wherein the flow of exhaust gases comprises steam in the form of water vapour (H2O) which is provided as the high temperature thermal energy to the external process; and a condenser for receiving the steam after use by the external process to condense the steam into pure water, wherein the system is configured to return the pure water to the electrolyser for re-use.

49. The system according to claim 48, further comprising a pressure controller configured to modify the pressure of the hydrogen gas and/or oxygen gas produced by the electrolyser to ensure that a desired pressure of the flow of exhaust gases at a final combustor component of the combustor assembly will be satisfied for the external process.

50. The system according to claim 48 or claim 49, further comprising one or both of: a compressor configured to receive the hydrogen gas from the electrolyser and increase its pressure for storage in a hydrogen storage vessel; and a compressor configured to receive the oxygen gas from the electrolyser and increase its pressure for storage in an oxygen storage vessel.

51. The system according to any one of claims 48 to 50, wherein the system further comprises a mixing device for receiving a source of a diluent which is combined with the hydrogen gas produced by the electrolyser to form a homogenous mixture of the fuel to be provided at the first combustor component.

52. The system according to claim 51, further comprising a pressure controller configured to modify the pressure of the diluent to ensure that it is sufficient to combine with the hydrogen gas produced by the electrolyser at the first combustor component.

53. A method for producing high temperature thermal energy for an external process using electrolysis and a combustor assembly, the method comprising: receiving, at an electrolyser, pure water (H2O) and separating it into hydrogen gas (H2) and oxygen gas (O2); providing the combustor assembly according to claim 24 or any one of claims 26 to 33 when appended to claim 24, wherein the fuel comprises the hydrogen gas from the electrolyser and the oxidant comprises the oxygen gas from the electrolyser; providing the flow of exhaust gases comprising steam in the form of water vapour (H2O) from the final combustor component of the combustor assembly as the high temperature thermal energy for use in the external process; receiving, at a condenser, the steam after use by the external process and condensing the steam into pure water; and returning the pure water to the electrolyser for re-use.

54. A system configured to heat hydrogen gas (H2) for use in an external process, the system comprising: the combustor assembly according to claim 24 or any one of claims 26 to 33 when appended to claim 24; and a heat exchanger configured to receive the flow of exhaust gases from the final combustor component and impart thermal energy to heat a flow of hydrogen gas for use in the external process.

55. The system according to claim 54, further comprising an electrolyser configured to receive pure water (H2O) and separate it into hydrogen gas (H2) and oxygen gas (O2), wherein the flow of hydrogen gas to be heated is provided from the electrolyser.

56. The system according to claim 55, further comprising a valve for regulating the pressure of the flow of hydrogen gas from the electrolyser prior to heating in the heat exchanger.

57. The system according to claim 55 or claim 56, wherein the fuel of the combustor assembly comprises hydrogen gas from the electrolyser and the oxidant of the combustor assembly comprises the oxygen gas from the electrolyser, and wherein the flow of exhaust gases from the final combustor component comprises steam in the form of water vapour (H2O).

58. A method configured to heat hydrogen gas (H2) for use in an external process, the method comprising: providing the combustor assembly according to claim 24 or any one of claims 26 to 33 when appended to claim 24; receiving, at a heat exchanger, the flow of exhaust gases from the final combustor component; and heating, using the heat exchanger, a flow of hydrogen gas for use in the external process by imparting thermal energy to the flow of hydrogen gas from the flow of exhaust gases.

59. A calcination system comprising: at least one combustor assembly, wherein the at least one combustor assembly is the combustor assembly of claim 24 or any one of claims 26 to 33 when appended to claim 24; and at least one calcination component configured to calcinate a feed material, wherein the at least one calcination component is configured to receive the flow of exhaust gases from a final combustor component of the at least one combustor assembly to impart thermal energy to the feed material.

60. The calcination system according to claim 59, wherein the at least one combustor assembly comprises one or both of a calciner combustor assembly and a kiln combustor assembly, and wherein the system further comprises one or both of: a calciner, wherein the calciner is configured to receive the feed material and the flow of exhaust gases from a final combustor component of the calciner combustor assembly to impart thermal energy to the feed material being processed by the calciner; and a kiln, wherein the kiln is configured to receive the processed feed material from the calciner and the flow of exhaust gases from a final combustor component of the kiln combustor assembly to impart thermal energy to the processed feed material being processed by the kiln.

61. The calcination system according to claim 59 or claim 60, further comprising: a cooler configured to receive and cool the processed feed material from the at least one calcination component, wherein the cooler comprises a plurality of cooling zones in which heat is recovered from the processed feed material and deployed within the calcination system.

62. The calcination system according to claim 61, comprising one or more of: a first cooling zone adjacent to the kiln, wherein heat recovered from the first cooling zone is provided to the kiln combustor assembly; a second cooling zone adjacent to the first cooling zone, wherein heat recovered from the second cooling zone is provided to the calciner combustor assembly; and a third cooling zone adjacent to an outlet of the cooler, wherein heat recovered from the third cooling zone is provided to a heat exchanger for cooling off-gas from the calciner and the kiln.

63. The calcination system according to any one of claims 59 to 62, further comprising a preheater for heating the feed material to a desired temperature prior to delivery to the at least one calcination component, wherein the heat exchanger imparts thermal energy to a flow of gases from the cooler which is provided to the preheater to heat the feed material.

64. The calcination system according to any one of claims 59 to 63, further comprising an electrolyser configured to receive pure water (H2O) and separate it into hydrogen gas (H2) and oxygen gas (O2), wherein the at least one combustor assembly utilises the hydrogen gas from the electrolyser as the fuel and the oxygen gas from the electrolyser as the oxidant, and wherein the flow of exhaust gases from the final combustor component of the at least one combustor assembly comprises steam in the form of water vapour (H2O).

65. The calcination system according to claim 64, further comprising a condenser for receiving a mixture of carbon dioxide (CO2) and steam from the heat exchanger and/or preheater and condensing the gas mixture to produce a substantially pure gas flow of CO2 and substantially pure water.

66. The calcination system according to claim 65, wherein the system is configured to return the substantially pure water from the condenser to the electrolyser for re-use.

67. A calcination method, comprising: providing at least one combustor assembly, wherein the at least one combustor assembly is the combustor assembly of claim 24 or any one of claims 26 to 33 when appended to claim 24; receiving, at at least one calcination component, the flow of exhaust gases from a final combustor component of the at least one combustor assembly; and calcinating a feed material, using the at least one calcination component, by imparting thermal energy from the flow of exhaust gases to the feed material.

68. A pyrolysis component comprising: a main body comprising: a feed inlet configured to receive a feed material comprising at least one hydrocarbon; a preheat gas inlet configured to receive a preheat gas flow for preheating and mixing with the feed material in a preheating zone of the main body; and a main gas inlet configured to receive a main gas flow for heating a mixture of the preheated feed material and preheat gas flow in a cracking zone of the main body to produce a gas flow comprising one or more products.

69. The pyrolysis component according to claim 68, configured to direct the mixture of the preheated feed material and preheat gas flow towards the cracking zone.

70. The pyrolysis component according to claim 69, wherein the main body further comprises an eductor zone between the preheating zone and the cracking zone to draw and/or accelerate the mixture of the preheated feed material and preheat gas flow towards the cracking zone.

71. The pyrolysis component according to claim 70, wherein the main body further comprises a sloped and/or profiled wall forming the eductor zone to draw and/or accelerate gases flow towards the cracking zone.

72. The pyrolysis component according to claim 71, wherein the main body is tapered from the preheating zone to a narrowed portion of the main body to accelerate gases flow towards the cracking zone.

73. The pyrolysis component according to any one of claims 68 to 72, wherein the main gas inlet is axially oriented relative to the main body to direct the main gas flow towards the cracking zone.

74. The pyrolysis component according to claim 73, wherein the main body further comprises at least one nozzle in fluid communication with the main gas inlet to direct the gas flow towards the cracking zone.

75. The pyrolysis component according to any one of claims 68 to 74, wherein the feed inlet and the preheat gas inlet are positioned on the main body to provide interfacing flow streams of the feed material and the preheat gas flow.

76. The pyrolysis component according to any one of claims 68 to 75, wherein the main body further comprises an outlet to allow passage of a gas flow comprising the one or more products from the main body.

77. The pyrolysis component according to claim 76, wherein the main body further comprises a diverging portion that expands in dimension from the cracking zone to the outlet of the main body.

78. The pyrolysis component according to claim 77, wherein at least a portion of the cracking zone is at a lower pressure than the preheating zone and/or the diverging portion of the main body.

79. The pyrolysis component according to any one of claims 68 to 78, wherein the cracking zone is at a higher temperature than the preheating zone.

80. The pyrolysis component according to any one of claims 68 to 79, wherein the main body further comprises a fluid inlet to receive a fluid flow to reduce the temperature of the gas flow comprising the one or more products in a quenching zone of the main body adjacent the cracking zone.

81. The pyrolysis component according to claim 80, wherein the main body further comprises a plurality of nozzles configured to direct the fluid flow through a corresponding plurality of fluid inlets towards the quenching zone.

82. The pyrolysis component according to any one of claims 68 to 81, wherein the main body further comprises a plurality of nozzles configured to direct the feed material and/or the gas flow through a corresponding plurality of feed inlets and/or preheat gas inlets towards the preheating zone, wherein the plurality of nozzles of the preheat gas inlets circumferentially surround the main gas inlet at an end portion of the main body adjacent the preheating zone.

83. The pyrolysis component according to any one of claims 68 to 82, wherein the main body further comprises a recycle feed inlet configured to receive recycled feed material comprising the at least one hydrocarbon, wherein the preheat gas flow preheats and mixes with the recycled feed material in the preheating zone of the main body.

84. The pyrolysis component according to any one of claims 68 to 83, wherein an interior of the main body, one or more inlets of the main body and/or an outlet of the main body comprise an insulating liner, wherein the insulating liner comprises a refractory and/or ceramic material.

85. The pyrolysis component according to any one of claims 68 to 84, wherein the preheat gas flow and/or the main gas flow comprise steam in the form of water vapour (H2O).

86. A pyrolysis system comprising: a pyrolysis component comprising: a main body comprising: a feed inlet configured to receive a feed material comprising at least one hydrocarbon; a preheat gas inlet configured to receive a preheat gas flow for preheating and mixing with the feed material in a preheating zone of the main body; and a main gas inlet configured to receive a main gas flow for heating a mixture of the preheated feed material and preheat gas flow in a cracking zone of the main body to produce a gas flow comprising one or more products; and a gas source for supplying the preheat gas flow and/or the main gas flow received at the main body of the pyrolysis component.

87. The pyrolysis system according to claim 86, wherein the gas source comprises: at least one combustor assembly, wherein the at least one combustor assembly is the combustor assembly of claim 24 or any one of claims 26 to 33 when appended to claim 24, wherein the flow of exhaust gases from the at least one combustor assembly supplies the preheat gas flow and/or the main gas flow received at the main body of the pyrolysis component.

88. The pyrolysis system according to claim 87, wherein the gas source comprises: two combustor assemblies, wherein the two combustor assemblies each comprise the combustor assembly of claim 24 or any one of claims 26 to 33 when appended to claim 24, wherein a first combustor assembly supplies the preheat gas flow received at the preheat gas inlet of the pyrolysis component, and a second combustor assembly supplies the main gas flow received at the main gas inlet of the pyrolysis component.

89. The pyrolysis system according to any one of claims 86 to 88, wherein the supplied preheat gas flow and/or the main gas flow comprise steam in the form of water vapour (H2O).

90. The pyrolysis system according to claim 89 when appended to claim 87 or claim 88, wherein the gas source further comprises an electrolyser configured to receive pure water (H2O) and separate it into hydrogen gas (H2) and oxygen gas (O2), wherein each combustor assembly utilises the hydrogen gas from the electrolyser as the fuel and the oxygen gas from the electrolyser as the oxidant, and wherein the flow of exhaust gases from the final combustor component of each combustor assembly comprises steam in the form of water vapour (H2O).

91. The pyrolysis system according to claim 89 when appended to claim 87 or claim 88, wherein the gas source further comprises an air separation unit (ASU) configured to produce oxygen gas (O2), wherein each combustor assembly utilises hydrogen gas (H2) as the fuel and the oxygen gas produced from the air separation unit as the oxidant, and wherein the flow of exhaust gases from the final combustor component of each combustor assembly comprises steam in the form of water vapour (H2O).

92. The pyrolysis system according to claim 91, wherein the one or more products comprise hydrogen gas (H2), and wherein at least some of the hydrogen gas is directed for use as the fuel of each combustor assembly.

93. A pyrolysis method comprising: supplying a feed material comprising at least one hydrocarbon to a main body of a pyrolysis component; preheating and mixing the feed material with a preheat gas flow in a preheating zone of the main body; and heating a mixture of the preheated feed material and preheat gas flow in a cracking zone of the main body to produce a gas flow comprising one or more products.

94. The pyrolysis system according to any one of claims 86 to 92 or the pyrolysis method according to claim 93, wherein the pyrolysis component comprises a pyrolysis component according to any one of claims 68 to 85.

95. The pyrolysis component according to any one of claims 68 to 85, the pyrolysis system according to any one of claims 86 to 92 and 94 or the pyrolysis method according to claim 93 or claim 94, wherein the one or more products comprise at least one unsaturated hydrocarbon and/or hydrogen gas (H2).

96. The pyrolysis component, system or method according to claim 95, wherein the at least one unsaturated hydrocarbon comprises an olefin.

97. A pyrolysis assembly comprising a plurality of pyrolysis components arranged in parallel, wherein the plurality of pyrolysis components each comprise a pyrolysis component according to any one of claims 68 to 85.

98. The pyrolysis assembly according to claim 97, wherein the pyrolysis assembly is configured to be retrofit to an existing pyrolysis system.

99. The pyrolysis assembly according to claim 97, wherein the plurality of pyrolysis components are configured for one of individual collection of the gas flow comprising the one or more products; or common collection of the gas flow comprising the one or more products.

100. The pyrolysis assembly according to claim 99, wherein an outlet of each pyrolysis component is coupled with a pressurised plenum for common collection of the gas flows comprising the one or more products.