Self-decarbonizing combustor systems and methods of using same

Abstract

A system comprising a self-decarbonizing combustor and method of using the same are provided. The system comprises a combustor defining: a combustion chamber for combusting oxidizing agent and processed hydrocarbon. The combustor comprises an exhaust and a pyrolytic reactor which comprises a heating region and a separator. The heating region is defined within the combustion chamber for thermally coupling the heating region and the combustion chamber such that thermal energy generated in the combustion chamber is absorbed by the heating region to thermally decompose hydrocarbon feed. The separator is in fluid communication with the heating region for receiving hydrocarbon, where the separator is configured to pyrolyze the hydrocarbon and separate it into processed hydrocarbon and carbon black. The processed hydrocarbon is circulated to the combustion chamber for combustion and to heat the pyrolytic reactor. Carbon black may be removed from the separator as a separate product.

Description

SELF-DECARBONIZING COMBUSTOR SYSTEMS AND METHODS OF USING SAMECROSS REFERENCE TO RELATED APPLICATION AND CLAIM OF PRIORITY

[0001] The present application claims priority to U.S. provisional patent application no. 63 / 514,833 filed on July 21 , 2023, the entire contents of which are hereby incorporated by reference.TECHNICAL FIELD

[0002] The disclosure relates generally to combustion of hydrocarbons, and more particularly to combustors.BACKGROUND

[0003] Traditional methods of power generation from conventional fuels have combustors at the core of all existing technologies. From thermal power plants to gas turbine engines for power or aircrafts, to cement and steel making, combustors play the primary role of converting the chemical energy of fuels into thermal energy. However, the exploitation of these fuels to meet the growing energy demand has led to increased CO2 emissions which has environmental consequences. To reduce CO2 emissions, one possible solution that has been proposed is to transition from fossil fuels to hydrogen fuel. Hydrogen fuel may have a variety of sources. One avenue of hydrogen production involves the pyrolysis of natural gas, which typically utilizes higher-grade energy, like electricity or fossil fuels, to provide the energy for pyrolysis. However, use of an external source of energy for the pyrolysis reaction decreases overall energy efficiency and may cause additional CO2 emissions. Furthermore, the storage and transportation of hydrogen are extremely risky, challenging, and capital-intensive.

[0004] Another solution to reduce CO2 emissions that has been explored is to integrate combustion with chemical sorbents at the exhaust to trap CO2 or with carbon capture and storage (CCS) methods to sequester large amounts of carbon emissions produced therein to truncate the emissions. However, the integration of CCS into combustion processes reduces the net energy produced by the combustion process as external energy may be required to operate these sequestration techniques. CCS and / or CO2 sequestration techniques are themselves external energy-intensive and cost-intensive, and may also pose risks related to isolation, storage, and disposal of CO2.SUMMARY

[0005] To address the above noted challenges, this disclosure describes a combustor that may generate thermal energy by burning hydrogen, amongst other hydrocarbon(s) in some examples, where the hydrogen is generated in situ by pyrolysis of feed hydrocarbon (e.g. natural gas) utilizing a fraction of the thermal energy produced in the combustor for the pyrolysis. Combustors according to this disclose may alleviate the problems of 1) separate higher-grade energy source for pyrolysis, e.g. natural gas pyrolysis, 2) storage and transportation of hydrogen, and / or 3) separation and sequestration of CO2.

[0006] In one aspect, the disclosure describes a system comprising: a combustor defining: a combustion chamber for combusting: oxidizing agent from an oxidizing agent input, and processed hydrocarbon from a processed hydrocarbon stream, and an exhaust for expelling combustion product from the combustion chamber, a pyrolytic reactor comprising: a heating region for heating hydrocarbon feed from a hydrocarbon input in the absence of oxygen to provide pyrolyzed hydrocarbon, the heating region defined within the combustion chamber for thermally coupling the heating region and the combustion chamber such that a fraction of the thermal energy generated in the combustion chamber is absorbed by the heating region to thermally decompose the hydrocarbon feed from the hydrocarbon input into pyrolyzed hydrocarbon; and a separator in fluid communication with the heating region for receiving the pyrolyzed hydrocarbon, the separator configured to convert the pyrolyzed hydrocarbon into the processed hydrocarbon and carbon black, the separator in fluid communication with the processed hydrocarbon stream for sending the processed hydrocarbon to the combustion chamber.

[0007] In an embodiment, when in use: a hydrocarbon flow path is defined by the hydrocarbon input, the heating region, the separator, the processed hydrocarbon stream, and the combustion chamber.

[0008] In an embodiment, the processed hydrocarbon comprises hydrogen.

[0009] In an embodiment, the hydrocarbon feed comprises methane.

[0010] In an embodiment, the separator is in fluid communication with a reservoir for storing a portion of the processed hydrocarbon, wherein the portion of processed hydrocarbon is substantially hydrogen.

[0011] In an embodiment, the separator is in thermal communication with the combustion chamber for receiving thermal energy for catalytic decomposition of the pyrolyzed hydrocarbon.

[0012] In an embodiment, the separator is a catalytic separator, and wherein the hydrocarbon feed is pyrolyzed in the catalytic separator. The separator may be at least one of a fixed bed, a moving bed, and fluidized bed catalytic separator. In an example, the catalytic separator comprises at least one of an iron catalyst, a nickel catalyst, a platinum catalyst, a carbon catalyst, a palladium catalyst, and a catalyst configured to form carbon black during pyrolysis.

[0013] In an embodiment, the separator is a Dielectric Barrier Discharge (DBD) plasma chamber carbon separator.

[0014] In an embodiment, the separator is a cyclone separator.

[0015] In an embodiment, the system comprises a condenser configured to receive and cool the processed hydrocarbon from the separator of the pyrolytic reactor, wherein the condenser is configured to condense a portion of the processed hydrocarbon.

[0016] In an embodiment, the combustion chamber comprises one or more swirlers for stabilizing at least one flame when the oxidizing agent from the oxidizing agent input and the processed hydrocarbon from the processed hydrocarbon stream are combusted.

[0017] In an embodiment, the separator is a first separator, and the system comprises a second separator configured to be operated in parallel to the first separator, wherein each of the first and second separators comprises isolation valves, a separator inlet for receiving regenerated catalyst, and an separator outlet for discharging at least one of spent catalyst and carbon black.

[0018] In an embodiment, the system comprises a heat load thermally coupled to the combustor to provide heat energy from at least one of the combustion chamber or the exhaust to the heat load. In an example, the heat load is a heater, gas flare, or rocket engine, wherein the exhaust is in fluid communication and / or thermal communication theheater, gas flare exhaust or rocket engine exhaust. In another example, the heat load is a turbine, and wherein the exhaust of the combustor is in direct fluid communication with the turbine. The turbine may be any one of a gas turbine, a micro gas turbine, or a micro turbine engine.

[0019] In an embodiment, the system comprises a controller configured to control the flow of oxidizing agent from the oxidizing agent input to the combustion chamber and hydrocarbon feed into the pyrolytic reactor. In an example, the controller may be configured to: receive real time data indicative of at least one of a temperature and pressure in an outlet of the heating region of the pyrolytic reactor; when the at least one of the temperature and pressure is below or equal to a first threshold value, actuate at least one first valve to increase the hydrocarbon feed through the hydrocarbon input; when the at least one of the temperature and pressure is above a second threshold value, actuate at least one first valve to reduce flow of the hydrocarbon feed through the hydrocarbon input.

[0020] In an embodiment, the first threshold value is selected to be equal to or greater than a thermal decomposition point of the hydrocarbon feed.

[0021] In an embodiment, the first threshold value is in a range of about 1125 K - 1375 K, preferably about 1275 K when the hydrocarbon feed is methane.

[0022] In an embodiment, the first threshold valve is in a range of about 1-50 bar.

[0023] In an embodiment, the system comprises a solar concentrator to focus solar energy onto at least one of the heating region and / or the separator of the pyrolytic reactor.

[0024] In an embodiment, the system comprises a solar panel configured to convert solar energy into thermal energy used to heat at least one of the heating region and the separator of the pyrolytic reactor.

[0025] In an embodiment, the heating region of the pyrolytic reactor is substantially a helically-shaped tube.

[0026] In an embodiment, the heating region of the pyrolytic reactor is configured to put the hydrocarbon feed in direct contact with the combustion product, to heat and pyrolyze the hydrocarbon feed. In an embodiment, the combustor is a first combustion, the combustion chamber is a first combustion chamber, and the exhaust is a first exhaustreceiving the processed hydrocarbon and the combustion product; and wherein the system comprises a second combustor comprising: a second combustion chamber for combusting: the oxidizing agent from the oxidizing agent input, and the processed hydrocarbon from the processed hydrocarbon stream, and a second exhaust for expelling combustion product from the second combustion chamber. In an example, the first combustor is configured to rotate about an axis for imparting centrifugal force on the processed hydrocarbon, the combustion product, and carbon black to increase mixing and residence time.

[0027] In an embodiment, the second combustion chamber is connected to the separator in series for receiving the processed hydrocarbon directly from the separator.

[0028] In an embodiment, the system comprises: a heat load thermally coupled to the second combustor to provide heat energy from the second exhaust to the heat load. In an example, the heat load is a heater, gas flare, gas turbine engine, or rocket engine. In another example, the heat load is a gas turbine, micro gas turbine or micro turbine engine, and wherein the exhaust in fluid communication with the turbine and powers the gas turbine.

[0029] Embodiments may include combinations of the above features.

[0030] In another aspect, the disclosure describes a method comprising: providing a system according to this disclosure; heating the hydrocarbon feed from the hydrocarbon input in the pyrolytic reactor; pyrolyzing a portion of the hydrocarbon feed to form pyrolyzed hydrocarbon; separating the pyrolyzed hydrocarbon into processed hydrocarbon and carbon black in the separator; and combusting the processed hydrocarbon to heat the hydrocarbon feed.

[0031] In an embodiment, the separator is a catalytic separator, a cyclone separator, or a DBD plasma chamber carbon separator, and wherein the method comprises forming the carbon black on a catalyst of the catalytic separator, settling denser carbon particles in a hopper through centrifugal action of the cyclone separator, or forming the carbon black on an electrode of the DBD plasma chamber carbon separator.

[0032] In an embodiment, the method comprises: receiving an indication that a temperature of an outlet of the heating region of the pyrolytic reactor is below a first threshold value, actuating a valve to increase a flow of hydrocarbon feed to thehydrocarbon input of the pyrolytic reactor; flowing the hydrocarbon feed into the pyrolytic reactor. In an example, the first threshold is in a range of about 1125 K - 1375 K, preferably about 1275 K when the hydrocarbon feed is methane.

[0033] In an embodiment, the method comprises condensing a portion of the processed hydrocarbon from the separator of the pyrolytic reactor. In an example, the portion of the hydrocarbon condensed is a liquid or solid at STP.

[0034] In an embodiment, the separator is a first separator, and comprises a second separator configured to be operated in parallel to the first separator, wherein the method comprises: actuating a plurality of valves to isolate the second separator; thermally decomposing the pyrolyzed hydrocarbon in the first separator while simultaneously removing carbon black from the second separator. In an example, the first and second separators are at least one of a packed bed catalytic reactor, and a fluidized bed catalytic reactor.

[0035] In an embodiment, the portion of the hydrocarbon feed pyrolyzed to form pyrolyzed hydrocarbon is a first portion of the hydrocarbon feed, and the method comprises: burning a second portion of the hydrocarbon feed to form combustion products; and injecting the first portion of the hydrocarbon feed to mix with the combustion products and form the pyrolyzed hydrocarbon. The method may also comprise forming a vortex to mix the combustion products and the first portion of the hydrocarbon feed. The method may also comprise agglomerating the carbon black by rotating the separator; and collecting the agglomerated carbon black.

[0036] Embodiments may include combinations of the above features.

[0037] Further details of these and other aspects of the subject matter of this application will be apparent from the detailed description included below and the drawings.DESCRIPTION OF THE DRAWINGS

[0038] Reference is now made to the accompanying drawings, in which:

[0039] FIG. 1 shows a schematic view of an example system according to this disclosure;

[0040] FIG. 2 shows a schematic view of an embodiment of the example system shown in FIG. 1 ;

[0041] FIG. 3 shows a chemical thermodynamic analysis of traditional methane combustion in comparison to combustion with energy equivalent example systems according to this disclosure;

[0042] FIG. 4a shows a schematic view of an embodiment of the example system of FIG. 1 where all processed hydrocarbon from a separator is sent to a combustion chamber for combustion. FIG. 4b illustrates another embodiment of the example system of FIG. 1 where a portion of processed hydrocarbon from the separator is sent to a reservoir.

[0043] FIG. 5 shows a schematic view of an example separator, based on thermo- catalytic carbon capture, according to this disclosure;

[0044] FIG. 6 shows a schematic flow chart for operating the example separator of FIG. 5;

[0045] FIG. 7a shows a schematic views of another example separator, based on plasma aided carbon capture, according to this disclosure. FIG. 7b shows a schematic flow chart for operating a separator shown in FIG. 7a;

[0046] FIG. 8 shows a schematic view of an example system of FIG. 1 including a solar concentrator;

[0047] FIG. 9 shows a schematic view of an example system of FIG. 1 integrated into a system comprising a compressor and turbine of a gas turbine engine;

[0048] FIG. 10, detail (a) shows a schematic of an example system of FIG. 1 integrated with a gas turbine engine comprising a compressor, turbine and heat recuperation and detail (b) ideal T-s plot of the thermodynamic cycle governing its operation;

[0049] FIG. 11 shows an illustration of an example system of FIG. 1 with multiple flames integrated with a micro gas turbine used for decarbonized power generation according to this disclosure;

[0050] FIG. 12 shows an image of a prototype self-decarbonizing combustor integrated with micro gas turbine;

[0051] FIG. 13A, detail (a) shows thermodynamic analysis of coupled pyrolysiscombustion processes in an example micro gas turbine shown in Fig. 11 without dilution air, and detail (b) show the corresponding results from numerical simulation for thedistribution of combustor exhaust temperature (Te) for different values of the system equivalence ratio (<t>) and the extent of pyrolysis (i ), and detail (c) shows the variation of thermal efficiency of gas turbine versus compressor pressure ratio for different values of i and effectiveness of heat recuperation (e);

[0052] FIG. 13B, detail (a) shows thermodynamic analysis of coupled pyrolysiscombustion processes in an example of micro gas turbine shown in Fig. 11 with dilution air, and detail (b) to detail (e) show the corresponding results from numerical simulation for the distribution of thermal efficiency of micro gas turbine combustor for different values of compressor pressure ratio (PR) and the extent of pyrolysis (ip) at different values of combustor exhaust temperature (Te), where the compressor and turbine efficiencies are assumed to be 0.75 and 0.8, respectively, and effectiveness of heat recuperation to be 0.8;

[0053] FIG. 14A shows a schematic view of an embodiment of an example system according to this disclosure comprising two tandem combustors that are physically separated, but chemically coupled, to generate decarbonized thermal energy through direct contact combustion-induced thermal decomposition of hydrocarbon and separating carbon in the pyrolyzed fuel using a catalytic reactor;

[0054] FIG. 14B shows a schematic view of another embodiment of an example system according to this disclosure where two tandem combustors are physically separated, but chemically coupled, and are designed to generate decarbonized thermal energy through direct contact combustion-induced thermal decomposition of hydrocarbon and separating carbon in the pyrolyzed fuel using a cyclone generator;

[0055] FIG. 15A shows a schematic view of another embodiment of an example system according to this disclosure where two tandem combustors are physically connected and chemically coupled to generate decarbonized thermal energy through direct contact combustion-induced thermal decomposition of hydrocarbon and separating carbon in the pyrolyzed fuel using a catalytic reactor;

[0056] FIG. 15B shows a schematic view of another embodiment of an example system according to this disclosure where two tandem combustors are physically connected and chemically coupled to generate decarbonized thermal energy through direct contactcombustion-induced thermal decomposition of hydrocarbon and separating carbon in the pyrolyzed fuel using a cyclone generator;

[0057] FIG. 16 shows a schematic of an example direct combustion contact rotary pyrolytic reactor integrated with a micro gas turbine for decarbonized heat and power generation according to this disclosure;

[0058] FIG. 17 shows a schematic diagram illustrating a method of operating a system according to this disclosure;

[0059] FIG. 18 shows a generalized schematic view of example system for controlling a self-decarbonizing combustor in accordance with an embodiment according to this disclosure;

[0060] FIG. 19, detail shows a schematic of flow paths of fuel and air through different components of a prototype self-decarbonizing combustor, details (b) and (c) show images of a prototype self-decarbonizing combustor and an assembly of pyrolytic reactor and catalytic reactor;

[0061] FIG. 20 shows the graph of experimental data of temporal variation in the molar concentrations of in-situ generated H2 in cases with and without the catalyst, when the fuel line is maintained at atmospheric pressure;

[0062] FIG. 21 shows the change in the molar concentration of H2 and CH4 in the processed fuel with variation in the fuel residence time (T), with and without the catalyst. The colorbar depicts the fuel pressure (Pf) upstream of the thermo-catalytic pyrolysis reactor that is used to obtain the residence time, T;

[0063] FIG. 22 shows the percentage change in the molar concentrations of various species due to the addition of catalyst in the reactor in detail (a), and the increase in fuel pressure from 3 bar to 5 bar, in the presence of the catalyst in detail (b);

[0064] FIG. 23A shows the variation in the concentration of H2 generated in the processed fuel with the reduction in the CO2 concentration in the exhaust as compared to the CO2 concentration recorded at the start of the run. The markers are for four independent runs and color-coded in the fuel pyrolysis temperature;

[0065] FIG. 23B shows the decarbonization curve between the molar concentration of H2 and CO2 reduction obtained for the SDC (circle and triangle markers) and H2 doped methane combustor (square marker);

[0066] FIG. 24 shows the solid carbon structures observed using ex-situ microscopy involving, details (a) and (b) Scanning Electron Microscope (SEM), details (c) and (d) Transmission Electron Microscope (TEM), and (e) X-Ray diffraction (XRD) spectrum of the carbon sample from an experiment performed at Pf= 5 bar along with standard peaks of Carbon Nano Tube (CNT) and Graphite.DETAILED DESCRIPTION

[0067] Self-decarbonizing combustors (SDC) according to this disclosure may be a standalone system may be used for power generation, heating, or propulsion, while reducing CO2 emissions. SDCs according to this disclosure may capture carbon and produce hydrogen via thermo-catalytic decomposition of hydrocarbon, e.g. methane, prior to the combustion process, internally using a fraction of the thermal power that combustor generates itself, therefore removing the need for an external energy source. Hydrogen produced in situ within the SDC may be immediately combusted in the combustor, circumventing the storage and transportation of hydrogen fuel while generating energy with a lower carbon footprint.

[0068] Additionally, unlike conventional hydrogen production processes involving multi- step methods - first generating hydrogen in one system at one geographic location, then transporting and storing it at another location, and finally consuming it in a separate combustor to produce decarbonized heat - systems described in this disclosure, comprising SDCs, utilize a one-step approach to produce decarbonized heat in a standalone system without requirement of any additional or separate energy from external sources to produce, transport or store hydrogen. The pyrolysis process occurs in tandem with the combustion process and uses only a fraction of the available energy to generate carbon black and carbon-reduced I hydrogen enriched fuel (“processed hydrocarbon) in comparison with hydrocarbon fed into systems according to this disclosure. At stable operation, the combustor burns reduced carbon and hydrogen- enriched fuel. Carbon black obtained as a residual output reduces the CO2 emissions which minimize the sequestration requirements. Furthermore, carbon black can bemonetized at the expense of a small fraction of low-grade thermal energy produced by the combustor itself.

[0069] Systems described in this disclosure comprising SDCs can be coupled to an appropriate turbine engine, e.g. micro gas turbine engine or a conventional gas turbine engine. It can be integrated to an intake, compressor, turbine, and heat recuperation subsystems of gas turbine engine and can be designed to operate under the elevated pressure and temperature conditions, as recommended by the corresponding thermodynamic cycle and associated design analysis, to maximize the hydrogen generation through fuel pyrolysis within the constrained space of a gas turbine engine.

[0070] Systems according to this disclosure comprising SDCs can be designed as two chemically coupled tandem combustors. In the first combustor, a small amount of fuel, which may for example comprise pure hydrocarbon, or hydrogen and pyrolyzed fuel, can be burned in stoichiometric proportions or in rich conditions in a co-flowing feed of natural gas or other hydrocarbon fuel that needs to be decarbonized. The high sensible enthalpy, oxygen absent products, generated by this combustion may mix with the co-flowing hydrocarbon feed inside the first combustor. Upon mixing, the hydrocarbon fuel is heated up to very high temperature that then thermally breaks down to generate carbon, hydrogen, and small amounts of other products. The carbon can be separated in the solid form using a catalytic separator or a cyclone separator and the hydrogen-enriched fuel can be routed by a fluid coupling into the second combustor that generates decarbonized thermal energy for various purposes.

[0071] DEFINITIONS

[0072] Although terms such as “maximize”, “minimize” and “optimize” may be used in the present disclosure, it should be understood that such terms may be used to refer to improvements, tuning and refinements which may not be strictly limited to maximal, minimal or optimal.

[0073] The term “connected” or "coupled to" may include both direct coupling (in which two elements that are coupled to each other contact each other) and indirect coupling (in which at least one additional element is located between the two elements).

[0074] The term “substantially” as used herein may be applied to modify any quantitative representation which could permissibly vary without resulting in a change in the basicfunction to which it is related. For example, a pyrolytic reactor as disclosed herein comprising a helical coil may permissibly have a somewhat non-coiled section within the scope of the invention if its hydrocarbon heating and / or cracking capability is not materially altered.

[0075] Terms such as "up to", "at least", "greater than", "less than", "more than", "or more", and the like, include the number recited and such terms refer to ranges that can be subsequently broken down into sub-ranges. In the same manner, all ratios recited herein also include all sub-ratios falling within the broader ratio.

[0076] The singular forms "a," "an," and "the" include the plural reference unless the context clearly dictates otherwise. The term "and / or" means any one of the items, any combination of the items, or all of the items with which this term is associated.

[0077] The term "about" can refer to a variation of ±5%, ±10%, ±20%, or ±25% of the value specified. For example, "about 50" percent can in some embodiments carry a variation from 45 to 55 percent. For integer ranges, the term "about" can include one or two integers greater than and / or less than a recited integer at each end of the range. Unless indicated otherwise herein, the term "about" is intended to include values and ranges proximate to the recited range that are equivalent in terms of the functionality of the composition, or the embodiment.

[0078] The term “heat load” refers to systems and / or devices that utilize a combustion process to operate, e.g. system and / or devices that use high enthalpy combustion products from a combustor. Example of heat loads include a heater, which may use exhaust gases carrying the heat output of a Self-Decarbonizing Combustor (“SDC”) according to this disclosure; a gas flare, a turbine for power generation or propulsion, and / or a rocket.

[0079] The term “processed hydrocarbon” refers to carbon-reduced and hydrogen enriched fuel in comparison with hydrocarbon fed into systems according to this disclosure. As described below, hydrocarbon feed may be hydrocarbon supplied as feed to systems according to this disclosure.

[0080] The term “direct contact” refers to mixing hydrocarbon feed to the pyrolysis reactor with combustion product(s) from the combustor for heat exchange.

[0081] Aspects of various embodiments are described through reference to the drawings.

[0082] FIG. 1 illustrates a schematic view of an example system 100 according to this disclosure. System 100, also referred to herein as a Self-Decarbonizing Combustor (SDC), may generate thermal power with a reduced carbon footprint. System 100 may be fuelled by hydrocarbon mfuei, e.g. natural gas comprising for example about 95% methane, but may capture a fraction of the carbon in the hydrocarbon fuel without external energy input. System 100 may comprise combustor 101 defining a combustion chamber 102 for combusting: oxidizing agent mair, e.g. air comprising oxygen, from an oxidizing agent input 103, and processed hydrocarbon rtiH2 + rhnc from a processed hydrocarbon stream 104. In an example, the oxidizing agent may be air, oxygen alone, or oxygen in a mixture with other gases, e.g. O2-N2, Ch-Ar, Ch-He. Oxidizing agent may comprise oxygen having a concentration in a range of about 20-100%. In another embodiment, processed hydrocarbon comprises hydrogen rtiH2 as the major species among other hydrocarbon species. Combustor 101 may comprise an exhaust 105 for expelling combustion product from the combustion chamber. Combustor 101 may also comprise a fuel injection system (not shown) and / or an ignitor (not shown) injecting the process hydrocarbon / oxygen and igniting the mixture, respectively. A swirler 121 as shown in FIG. 2 may also be provided for stabilizing a flame when the oxidizing agent from the oxidizing agent input 103 and processed hydrocarbon from the processed hydrocarbon stream 104 are combusted. Swirler 121 may be an axial swirler with blade angle 30 - 60 degrees or a bluff body that can stabilize the flame.

[0083] System 100 also comprises a pyrolytic reactor 110. The pyrolytic reactor 110 may comprise a heating region 111 for heating hydrocarbon mfueifrom hydrocarbon input 106 in the absence of oxygen to provide pyrolyzed hydrocarbon to carbon separator 112 (also referred to as a “separator 112” herein). In the illustrated example of FIG. 1 , heating region 111 is defined within combustion chamber 102 to thermally couple heating region111 and combustion chamber 102 such that a fraction of the thermal energy generated in combustion chamber 102 is absorbed by heating region 111 to thermally decompose hydrocarbon rhfUeifrom the hydrocarbon input 106 into pyrolyzed hydrocarbon. Separator112 may be in fluid communication with heating region 111 for receiving the pyrolyzed hydrocarbon. Separator 112 may be configured to convert pyrolyzed hydrocarbon into processed hydrocarbon rtiH2 +rriHc and carbon black mc. Further pyrolysis of thehydrocarbon fuel may occur within separator 112, e.g. in the presence of a catalyst. Separator 112 may be in fluid communication with processed hydrocarbon stream 104 for sending processed hydrocarbon rtiH2 + rhnc to the combustion chamber where the fuel mH2 + rriHc is burned in the oxidizing agent. Processed hydrocarbon may comprise hydrogen mH2 and hydrocarbon product mHc from the pyrolysis reaction in pyrolytic reactor 110.

[0084] System 100 may capture a large fraction of the carbon in the hydrocarbon mfueiwithout external energy input. As shown in FIGs. 1 and 2, combustor 101 generates and burns processed hydrocarbon mH2 + rhnc, including hydrogen m^and other hydrocarbons such as non-pyrolyzed feed fuel while capturing carbon in the form of solid carbon black prior to the combustion of the processed hydrocarbon rtiH2 + rhnc. Consequently, CO2 emissions are significantly reduced unlike conventional combustors which directly combust natural gas in the oxidizing agent. The reduction in CO2 emissions is realized with a pyrolytic reactor 110 which is thermally and chemically coupled with combustor 101 such that pyrolytic reactor 110 and combustor 101 operate solely using the energy of hydrocarbon rhfUeiwithout any additional external energy input, to produce the processed hydrocarbon rtiH2 + rhnc while simultaneously capturing carbon. Captured carbon may be in the form of carbon black. Hydrocarbon rhfUeimay be routed through pyrolytic reactor 110 before injecting the processed hydrocarbon rtiH2 + rhnc into combustion chamber 102 for combustion, as shown in FIGs. 1 and 2. At stable operation, processed hydrocarbon rtiH2 + rhnc temperature at pyrolytic reactor 110 exit may be maintained in a range of 1000-3000 K and total pressure in the pyrolytic reactor 110 exit may be maintained in a range of 1-10 bar for operation of system 100. In an embodiment, the temperature range may be 1125 K-1375 K, and the pressure range may be 1-10 bar, when the hydrocarbon mfueiis methane for example when an SDC according to this disclosure is integrated with a micro turbine reactor.

[0085] In an embodiment, when system 100 is in use, a first hydrocarbon flow path is defined by hydrocarbon input 106, heating region 111 , separator 112, processed hydrocarbon stream 104, and combustion chamber 102. At separator 112, a fraction of hydrocarbon rhfUeimay be separated as carbon black mc. As such, a second hydrocarbon flow path may be defined by hydrocarbon input 106, heating region 111 , separator 112; after which the solid carbon black may be removed from separator 112.

[0086] Hydrocarbon rhfUeiflow to pyrolytic reactor 110 may be controlled with a mass flow controller (MFC) 15 to maintain a desired thermal output of combustor 101 , a desired chemical output of pyrolytic reactor 110, a desirable fuel-air ratio or equivalence ratio for combustor 101 , and a desired temperature and pressure in pyrolytic reactor 110 at stable operation. After start-up, as system 100 progresses towards stabilization, i.e. stable temperatures, pressure, and flow rates through system 100, the temperature inside pyrolytic reactor 110 and at the exhaust 105 of combustor 101 gradually attain stable values. In an example, pyrolytic reactor exit temperature may be maintained between 1100-1500 K and pressure may be maintained between 1-10 bar. Hydrocarbon rhfUeiis thermally decomposed in the pyrolytic reactor 110 to produce hydrogen among other hydrocarbons. The pyrolyzed fuel mixture may then be processed in separator 112 (e.g., a catalytic reactor) to enhance the pyrolysis process and capture carbon in the form of solid carbon black. Processed hydrocarbon rtiH2 + rriHc may comprise a mixture of various hydrocarbon species which may be liquefied or separated by appropriate adsorbents in the condenser 113, shown in FIG. 2, to condense out heavier hydrocarbons and tar. The remaining processed hydrocarbon may then be fed into combustion chamber 102, where the fuel may be fully / partially premixed with air and combusted. Turbulent flame may be stabilized by swirler 116 or a suitable bluff body. These components are connected through required regulators, fittings, and valves to ensure leakproof and safe operation. Various sensors and control circuits are installed on the SDC for monitoring and maintaining stable and continuous operation.

[0087] In an embodiment, heating region 111 of pyrolytic reactor 110 is substantially a helically-coiled tube as shown in FIG. 1. In another embodiment, heating region 111 may comprise one or more U-shaped tubes connected in series. In another embodiment, heating region 111 may be an annular tube surrounded by one or more burners of the combustion chamber. Other shapes and configurations of heating region 111 maybe used to efficiently heat hydrocarbon rhfUei. In an example, heating region 111 may be configured to provide a residence time of hydrocarbon rhfUeiwithin heating region 111 to heat hydrocarbon rhfUeiuntil it optimally maximises its thermal decomposition. Length and diameter of the tubing of heating region 111 , and the velocity of hydrocarbon rhfUeimay be selected to provide a desired residence time of hydrocarbon rhfUeiin heating region 111. In another example, the radius of combustion chamber 102 is at minimum four times thediameter of burner exit and / or swirler 116. The diameter of pyrolytic reactor 110 may be designed to be entirely accommodated within the combustion chamber 102 to facilitate efficient heat transfer and maintain a required fuel temperature in the pyrolytic reactor. The residence time inside the pyrolytic reactor may be at least four seconds to heat hydrocarbon mfueito a temperature adequate for pyrolysis, as well as breakdown and consequent hydrogen generation. In a non-limiting example, heating region 111 may be made of a material that is resistant to oxidation and corrosion, withstand high fuel pressure, and has a high melting point, e.g. Inconel 625, Silicon Carbide (SiC).

[0088] FIG. 2 is a schematic view of an embodiment of example system 100 shown in FIG. 1. Processed hydrocarbon from separator 112 may comprise hydrogen and other hydrocarbons, e.g. organic compounds. In an example, separator 112 may accelerate formation of heavier hydrocarbon fractions such as Polycyclic Aromatic Hydrocarbons (PAHs) through thermo-catalytic decomposition of the hydrocarbon rhfUei. These PAHs may account for the maximum carbon content with the highest carbon to hydrogen ratio (C / H ratio) among the hydrocarbon species obtained at the exit of the carbon separator. PAHs that do not condense to form solid carbon in the catalytic reactor may be carried in the processed hydrocarbon rtiH2 + rriHc stream. In an embodiment, system 100 comprises a condenser 113 configured to receive, quench, and separate the heavier hydrocarbons from the processed hydrocarbon rtiH2 + rriHc from the separator 112, where the condenser is configured to condense or adsorb a portion of processed hydrocarbon, e.g. the PAHs. Condenser 113 may cool, liquefy or solidify, a portion of processed hydrocarbon for separation and removal, e.g. as black tar. In an example, the heavy hydrocarbons removed comprise a carbon chain of at least five carbon atoms Condenser 113 may allow for further decarbonization of fuel channels leading to combustor 101 , e.g. at processed hydrocarbon stream 104. Hydrocarbons having lower molecular weight and / or less density not retained in condenser 113 may be routed to combustion chamber 102 for combustion.

[0089] FIG. 3 illustrates chemical thermodynamic analysis 300a of traditional methane combustion for an equivalence ratio of <|) in comparison to a thermodynamic analysis 300b of combustion using example systems according to this disclosure. The enthalpies ACHCH4= -802.70 kj / mol, ACHH2= -241.82 kj / mol and AfH^ = -74.87 kj / mol are the standard enthalpy of combustion of CH4, the standard combustion enthalpy of H2, in air,and the standard formation enthalpy of CH4, respectively. Equivalence ratio <|) is defined as the actual fuel-air mass ratio divided by the stoichiometric fuel-air mass ratio. As shown, traditional combustion of methane using a conventional combustor, i.e. combusting methane feed to produce heat and combustion products, produces 802.70 <|) kJ / mol of thermal energy when CH4is supplied to the conventional combustor. When using example systems producing the same sensible enthalpy output, according to this disclosure, e.g. system 100, a portion of hydrocarbon feed will be converted into carbon black which reduces CO2 emissions. In the illustrated example of FIG. 3, if 80% of the supplied methane undergoes complete pyrolysis (i = 0.8), the self-decarbonizing combustor theoretically yields thermal energy of 487.56 kJ / mol of CH4supplied to the example systems in the disclosure. This system produces the equivalent thermal energy of a traditional, lean methane combustor operating at an equivalence ratio <|) of about 0.6. The example system reduces about 67% CO2 emissions compared to a traditional, lean methane combustor producing the same power output, as denoted by Anco2 in FIG. 3, assuming complete conversion of CH4to only carbon (C) and hydrogen (H2).

[0090] FIG. 4a shows a schematic view of an embodiment of system 100 where the processed hydrocarbon from a separator is sent to a combustion chamber for combustion and high enthalpy gases may be obtained as output for various applications. FIG. 4b illustrates another embodiment of system 100 where a portion of processed hydrocarbon rtiH2 + rriHc from separator 112 is sent to a reservoir 114. In an example, processed hydrocarbon rtiH2 + rriHc sent to reservoir 114 may be substantially hydrogen. Hydrocarbon in reservoir 114 may sent back to processed hydrocarbon stream 104 to be combusted when more energy is required, or it may be used or sold as a by-product. As shown in FIG. 4b, separator 112 and / or processed hydrocarbon stream 104 may be in fluid communication with reservoir 114. System 100 may also comprise a heat exchanger 115 for transferring thermal energy from the gases of exhaust 105 to hydrocarbon rhfUeimoving toward hydrocarbon input 106. Heat exchanger 115 may improve the extent of pyrolysis in this embodiment of system 100.

[0091] FIG. 5 shows a schematic view of an example carbon separator 112 according to this disclosure. Separator 112 may be a reactor where carbon black formation and carbon capture happens. Separator 112 may be connected in series with heating region 111 of pyrolytic reactor 110 to receive heated and / or pyrolyzed hydrocarbon. Separator112 may be thermally coupled to combustor 101. In an embodiment, the pyrolytic reactor 110 comprises first separator 112a, and a second separator 112b configured to be operated in parallel to the first separator, where each of the first and second separators comprises isolation valves, a separator inlet for receiving regenerated catalyst, and a separator outlet for discharging at least one of spent catalyst and carbon black. First and second separators 112a, 112b may also be referred to herein as first and second reactors.

[0092] Separator 112 may be defined within combustion chamber 102 to use the heat from flue gases for pyrolysis of hydrocarbon fed into separator 112. In an embodiment, separator 112 may be a catalytic separator where the hydrocarbon rhfUeiis pyrolyzed to provide hydrogen and carbon black. In a non-limiting example, the catalyst of the catalytic separator may be at least one of an iron catalyst, a carbon catalyst, a nickel catalyst, a platinum catalyst, and a palladium catalyst. Any other catalyst suitable for forming carbon black may be used in separator 112. Examples of reactor wall materials may include SS 304, Inconel 625, and / or Silicon Carbide. The catalytic reactor bed may be comprised of a fixed bed matrix of steel mesh and iron beads or a fluidized bed of granular particles of iron which have an optimal operating temperature range of 973 K to 1173 K. The surface of the catalyst may facilitate heterogeneous nucleation on its active sites for carbon black formation and capture. Flue gases from the combustor 101 may activate the catalytic reactor bed at a temperature required to thermally decompose the hydrocarbon rhfUei. In an example, a catalytic reactor bed of separator 112 may activate at greater than or equal to 973 K. As shown in FIG. 5, in an embodiment, separator 112 may comprise a plurality of reactors, shown as first and second reactors 112a, 112b to allow continuous operation of system 100. As carbon, e.g. carbon black, accumulates in the online reactor 112a, pressure may rise upstream of separator 112. At a threshold pressure, hydrocarbon mfueifrom heating region 111 may be introduced into the offline reactor 112b, and the online reactor 112a may be isolated to remove and clean carbon, e.g. carbon black from reactor 112a. First and second reactors 112a, 112b may be provided with valves 116a, 116b to direct flow of hydrocarbon rhfUeito one of reactors 112a, 112b. As shown in FIG. 5, catalyst loading valves 117a, 117b, 117c, 117d may also be provided to allow catalyst loading and / or removal from reactors 112a, 112b.

[0093] In an embodiment, the catalytic separators may be configured to chemically accentuate the process of carbon black formation over the catalyst surface. Examples of catalytic reactor beds may be comprised of a fixed bed and / or a fluidized bed of coarse pellets and / or a sintered matrix made up of a suitable catalyst (e.g. iron or nickel) sized to minimize pressure drop across the online reactor 112a, 112b. Reactors 112a, 112b may be configured to open for unloading catalyst for cleaning and / or removal of accumulated carbon, e.g. carbon black, on the surface of the catalyst. Fresh catalyst may then be inserted into the offline reactor. For example, when reactor 112a is online, catalyst from reactor 112b may be removed through valve 117c and fresh catalyst may be loaded through valve 117d.

[0094] FIG. 6 shows a schematic flow chart for operating example system 100 and separator 112 shown in FIG. 5. Hydrocarbon mass flow rate rhfUeimay be controlled by mass flow controller 15, shown in FIG. 2. The hydrocarbon rhfUeiflowing through pyrolytic reactor 110 absorbs a fraction of the heat produced by the combustor to initiate the pyrolysis process. The pyrolyzed hydrocarbon may be further pyrolyzed in first or second separators 112a, 112b to capture solid carbon via heterogeneous nucleation reactions on the catalyst surface. For continuous operation of system 100, valves 116a, 116b may direct hydrocarbon rhfUeito first and second separators 112a, 112b, for example first separator 112a. The flow may be switched to the other separator 112b when the fuel pressure upstream of separators 112a, 112b exceeds a predetermined threshold pressure value, indicating significant carbon deposition on the catalyst surface.

[0095] Valves 116a, 116b may be actuated to route hydrocarbon mfueifrom pyrolytic reactor 110 to second separator 112b. First separator 112a may then be isolated. Valves 117a, 117b may then be actuated to open to remove or clean spent catalyst from first separator 112a. Fresh catalyst may then be inserted into first separator 112a.

[0096] Captured carbon, e.g. carbon black mc, and hydrogen in processed hydrocarbon rtiH2 + rriHc stream may be measured and monitored along with pyrolytic reactor 110 exit temperature. The measured temperature may be used by a controller 2001 , shown in FIG. 2, to control the input hydrocarbon rhfUeiflow into hydrocarbon input 106. In an example, the controller 2001 may be a Proportional - Integral - Derivative (PID) circuit to maintain exhaust 105 at a desired thermal output.

[0097] FIG. 7a shows a schematic view of another example separator according to this disclosure. In an embodiment, separator 112 may be a plasma-reactor based carbon separator comprising one or more Dielectric Barrier Discharge (DBD) plasma chamber carbon separator(s) 112-1 , 112-2 (referred to as herein as a “DBD Separator”). DBD Separators 112-1 , 112-2 may be connected in series with heating region 111 of pyrolytic reactor 110 to receive heated and / or pyrolyzed hydrocarbon. In an embodiment, the pyrolytic reactor 110 comprises first DBD Separator 112-1 , and second separator 112-2 configured to be operated in parallel to the first separator, where each of the first and second DBD separators comprises valves 116a-1 , 116b- 1 for routing hydrocarbon, a separator outlet 117a-1 , 117b- 1 for discharging carbon black. DBD Separators 112-1 , 112-2 may each comprise an electrode 118-1 , 118-2 positioned within a dielectric chamber 120-1 , 120-2 respectively. Electrodes 118-1 , 118-2 may be connected to a high voltage electric current source (not shown) with switch 117. Electrodes 118-1 , 118-2 and dielectric chamber 120-1 , 120-2 may be electrically insulated from each other to create a dielectric barrier plasma on supply of high voltage electricity (concentrated stream of free electrons) in dielectric chamber 120-1 , 120-2 that expedites the chemical process of pyrolysis. Generated carbon particles are statically charged in this process and deposited on the electrode 118-1 , 118-2 via attraction by Coulomb’s force. As such, during operation, electrons may move from electrodes 118-1 , 118-2 through a gas (e.g. air, pyrolyzed fuel) within the dielectric chamber 120-1 , 120-2 into ground connection 119. The electrons may statically charge carbon with a positive charge which is attracted to negative electrode 118-1 , 118-2 while processed hydrocarbon mH2 + mHc leaves the separator.

[0098] In an embodiment, analogous to the continuous operation of the separator illustrated in FIG. 5, one of the DBD separators 112-1 , 112-2 may be operated while carbon is removed from the other DBD separator 112-1 , 112-2. Valves 116a-1 , 116b- 1 may be actuated to isolate one of the DBD separators 112-1 , 112-2 and route hydrocarbon rhfUeithrough the other DBD separator 112-1 , 112-2.

[0099] FIG. 7b shows a schematic flow chart for operating a separator shown in FIG. 7a. Initially valve 116a-1 may direct hydrocarbon rhfUeito DBD Separator 112-1 (indicated by the dotted arrow) where electrode 118-1 provided with a voltage configured to pyrolyze the hydrocarbon fuel in dielectric chamber. As pyrolyzed hydrocarbon flows throughdielectric chamber 120-1 , the hydrocarbon may be further pyrolyzed while carbon is separated from gas and deposited on electrode 118-1. Valve 116b- 1 may be actuated to direct processed hydrocarbon rtiH2 + rriHc out of DBD Separator 112-1 to processed hydrocarbon stream 104 and combustion chamber 102. While pressure upstream of dielectric chamber 120-1 is below a threshold pressure value, flow of hydrocarbon mfueimay continue to DBD Separator 112-1. When electrode 118-2 is spent, it may be regenerated by removing carbon on the electrode and / or replaced with a fresh electrode. As such, if pressure upstream of dielectric chamber 120-1 is above a threshold pressure value, valves 116a-1 , 116b-1 may be actuated to direct hydrocarbon rhfUeito DBD Separator 112-2, and switch 117 may direct a voltage to electrode 118-2.

[0100] FIG. 8 shows a schematic view of an example system 100 according to this disclosure including a solar concentrator 130. In an embodiment, system 100 may comprise a solar concentrator 130 to focus solar energy onto at least one of the heating region 111 and / or separator 112 of pyrolytic reactor 110. Solar concentrator 130 may comprise a plurality of collection optics 131 and focusing optics 132. Collection optics 131 may receive and direct solar energy onto the focusing optics 132 which in turn focuses the solar energy on heating region 111 and / or separator 112 of pyrolytic reactor 110. In places where solar energy is easily and uninterruptedly available, solar concentrator 130 may be utilized to supplement the energy from combustor 101 to thermo-catalytically pyrolyze the hydrocarbon rhfUeiand thereby improve the energy efficiency of system 100. Separator 112 may be energized by focused solar energy from solar concentrator 130.

[0101] In an embodiment, system 100 comprises a solar panel configured to convert solar energy into thermal energy used to heat at least one of the heating region 111 and the separator 112 of the pyrolytic reactor 110.

[0102] System 100 may be incorporated into many different systems that utilize combustion to produce energy, referred to herein as a “heat load”. A heat load may be thermally coupled to combustor 101 such that heat energy is provided from at least one of combustion chamber 102 or exhaust 105 to the heat load.

[0103] In an example, the heat load may be a heater where system 100 may be used to provide thermal energy. In the example, flue gases from exhaust 105 and / or thermalenergy from combustor 101 may be used as a heat source in a variety of applications such as household heaters, or industrial burners.

[0104] In another example, the heat load may be a flare. System 100 may be incorporated into industrial gas flaring systems to reduce CO2 output while generating a valuable product stream, i.e. carbon black. Industrial gas flares may emit CO2 continuously as hydrocarbon is burned. Instead, system 100 could be incorporated into the flare to pyrolyze hydrocarbon sent to the flare before burning processed hydrocarbon from system 100. Here, CO2 emissions would be reduced by sequestering the carbon, e.g. as carbon black before combustion.

[0105] In another example, the heat load may be a combustion system for producing turquoise and / or blue hydrogen. System 100 may be utilized in the production of turquoise and / or blue hydrogen to reduce CO2 emission by maximizing pyrolysis of hydrocarbon (methane) feed into system 100 to produce H2 while capturing the carbon, e.g. carbon black.

[0106] In another example, the heat load may be a turbine. In an embodiment, system 100 may be used in electrical power generation applications. In another embodiment, system 100 may be used in aircraft or marine propulsion applications. As shown in FIG. 9, system 100 may be incorporated into gas turbine system 900. Input 901 may provide air to compressor 902 which is in mechanical communication with, and driven by high pressure turbine 903 and / or low pressure turbine 904. As shown, oxidizing agent input 103 may be pressurized such that exhaust 105 of combustor 101 comprises high enthalpy gas which may be used to drive high pressure turbine 903 to power the compressor and low pressure turbine 904 to rotate a motor (not shown) for electrical power generation or rotate a fan for generating thrust. Separator 112 and heating region 111 may be positioned within combustor 101 to maximize heat transfer and rate of heat transfer from the combustor and flue gasses to the hydrocarbon in heating region 111. Positioning separator 112 in combustor 101 may also improve performance of a catalyst of separator 112. In an embodiment, system 100 may be used for aircraft propulsion. Gas turbine system 900 shown in FIG. 9 may be part of an aircraft engine or marine propulsion engine where exhaust 105 from system 100 is in fluid communication with gas turbines 903, 904 to provide high enthalpy exhaust 105 to power turbines 903, 904.

[0107] FIG. 10, detail (a) shows a schematic of the SDC according to disclosure having a combustor chamber (102) coupled to a pyrolytic reactor (110) which are integrated with a Compressor C and Turbine T; and detail (b) shows the ideal T-s plot of the thermodynamic cycle governing its operation. The underlying principle behind the generation of decarbonized power in SDC is achieved from the thermo-chemical coupling of the pyrolysis and combustion reactions. The endothermic fuel pyrolysis process harnesses a portion of the highly exothermic combustion process. This renders the chemical to thermal energy conversion process in the combustor non-adiabatic. In all gas turbine cycles this process is inherently adiabatic. The non-adiabaticity arises since some portion of the thermal energy must be expended in accomplishing the methane pyrolysis towards hydrogen and carbon production. This may change all sub-processes and equipment design. With a design engineered to optimally match the required time scale of operation of the pyrolysis and combustion processes, in-situ decarbonization followed by immediate combustion of the generated hydrogen can be realized. While a fraction of the energy released on combustion is used for fuel pyrolysis, the significant fraction of energy can be used for generation of useful, decarbonized electrical power.

[0108] The T-s plot of FIG. 10 detail (b) is described with reference to FIG. 11 which shows an embodiment of the schematic of SDC presented in FIG. 10, detail (a). Specifically, FIG. 11 illustrates an example micro gas turbine incorporating the SDC of this disclosure. The operation of the SDC integrated with a head load, i.e. the micro gasturbine of FIG. 11 , is elaborated with reference to each component and its corresponding function as mapped on the T-s plot shown in FIG. 10, detail (b). As shown, air is drawn into the engine through the converging intake (1 to 02) and compressed in the compressor (02 to 03). Blades of diffuser 905 guide the compressed air into the combustion chamber for combustion of reduced-carbon, hydrogen-enriched fuel at high pressure (03a to 04). The originally fed natural gas is processed in pyrolysis reactor 110 and separator 112, e.g. thermo-catalytic reactor, capturing and separating carbon and injecting the resulting hydrogen-enriched fuel into combustor 101. A separate fuel flow path is shown in FIG. 11 to demonstrate the in-situ decarbonization of fuel, e.g. natural gas. On combustion, a fraction of the heat is consumed for capturing the carbon while the rest of the major portion of the enthalpy contained in the exhaust 105 is fully expanded in the turbine 903. Turbine 903 optimally expands the flow (04 to 05) and the resultant work done is used todrive the compressor 902 and generator 904 to produce electric power or shaft power that can be used for e.g. small aircraft propulsion. Bearing 906, e.g. an air bearing, may be provided on the shaft between generator 904 and turbine 903 to separate intake 901 from flue gases entering exhaust 105. A recuperator (05 to 06) may be added to utilize the heat content of the exhaust in preheating the air used for combustion (03 to 03a), thus maximizing the engine efficiency. This conceptualized design and operation of the SDC integrated with a gas-turbine shown may provide, in some embodiments, a self-sufficient method of generating decarbonized electrical power or propulsive power. Unlike any other technique of generating electricity or propulsive power using natural gas, SDC may eliminates the need for an external source of energy and hence make power generation carbon-neutral and scalable. This may provide a micro gas turbine combined with the proposed concept of decarbonized energy generation. FIG. 12 shows an example model of the SDC in FIG. 11 integrated with a gas-turbine.

[0109] In an aspect, SDC integrated with a gas-turbine powered by hydrogen generated in-situ from thermally coupled pyrolysis of hydrocarbon, e.g. natural gas, over conventional natural gas based electrical power generators may include the following: (1) the basic thermodynamic cycle underpinning the SDC integrated with a gas-turbine is a novel variant of the Brayton cycle with the combustion process being non-adiabatic. The cycle and engine design parameters may be optimized to maximize the efficiency while ensuring decarbonization of the natural gas feed. The system integration may provide continuous removal of the captured carbon black. (2) The disclosed concept and design may provide a decarbonized power generator that can generate electricity from natural gas but with significantly mitigated carbon emissions enabled by pre-combustion carbon separation without using any external energy sources. This enables the SDC to burn H2rich fuel with much reduced CO2emissions compared to any existing state of the art micro-gas turbine engine powered by natural gas. (3) Given the in-situ hydrogen generation and carbon capture mechanism, the self sustaining operation of the SDC relies only on continuous hydrocarbon, e.g. natural gas, supply. By effectively consuming in-situ generated H2, the need for costly H2storage and transportation infrastructure is eliminated. (4) If used for aircraft / marine propulsion, SDC integrated with a gas-turbine may burn hydrogen but alleviates the necessity to carry hydrogen on board which is technically very challenging due to its low volumetric energy density in contrast to carryinga hydrocarbon such as natural gas which is far simpler and more efficient. (5) The SDC integrated with the turbine described with reference to FIGs 9-12 is comprised of diffuser 905 and radial compressor 902 to supply air for the SDC that comprises pyrolytic reactor 110, a catalytic reactor 112, and a combustor 101 allowing homogeneous fuel-air mixing, flame stabilization and effective heat transfer for thermo-catalytic pyrolysis of the fuel. While a fraction of energy from the combustion process is harnessed for decarbonization of the fuel, the significant fraction is used to rotate the radial turbine that drives the compressor and produces power using a generator, all coupled using a drive shaft. (6) The continuous carbon capture mechanism may be maintained using the a replaceable cartridge type design to allow for withdrawing the separator and / or pyrolysis reactor from each combustor head in sequence, regenerating it and inserting it back in place. The continuous carbon capture can also be achieved by incorporating a fluidized bed mechanism in the catalytic reactor, allowing spent catalyst to be continuously replaced via a valve or fast-fluidization, while simultaneously filling the reactor with fresh catalyst to maintain stable decarbonization operation. Captured carbon can be easily monetized given the growing demand of solid carbon for a variety of applications. (7) The SDC allows production and immediate combustion of hydrogen while capturing carbon using e.g. a catalyst bed. This may eliminate requirement of additional energy and a separate gas turbine to consume the produced hydrogen whose storage and transportation need additional investment of energy and resources. Catalyst(s) in the separator may minimize the energy required to expedite the pyrolysis and carbon black separation that further minimizes the energy loss. Additionally, as the system may be in continuous fluid connection, the loss in the sensible enthalpy is minimal which can potentially make the SDC highly energy efficient system of producing decarbonized electricity. (8) SDCs according to this disclosure may use natural gas as a fuel source which has a well established supply chain infrastructure in most parts of the world that eliminates the losses and infrastructure required for the transmission of electricity from carbon emitting power plants.

[0110] FIG. 13A, detail (a) is a schematic of an example coupled pyrolysis-combustion processes for fundamental energy balance analysis which delineates the principle behind the decarbonizing operation of the SDC integrated with a turbine. FIG. 13A, detail (a), illustrates pyrolytic reactor according to this disclosure as reactor a-b and the combustoris illustrated as reactor c-d. These reactors are integrated into a single system as described above. As depicted, hydrocarbon, e.g. natural gas / methane,is supplied to the pyrolytic reactor. The continuously supplied fuel may be maintained at a constant pressure Pp(greater than the combustor pressure Pc) and temperature of Tp, harnessing a fraction of energy (Qp) from the combustor for pyrolysis. The pyrolytic reactor design may allow sufficient heat transfer for i fraction of the supplied fuel to be fully pyrolyzed into molecular H2and solid carbon black. The carbon black generated in the process is separated out and the resulting hydrogen-enhanced fuel (mf- mc) may be injected into the combustor for combustion with a constant supply of air (ma / r) having a temperature Tair. The combustor may be maintained at a constant system equivalence ratio ( ) that is based on the originally supplied fuel. Using enthalpy balance across the SDC, turbine, and generator, the combustor exhaust temperature, Teand the power output can be said to be governed by the extent of decarbonization by the pyrolytic reactor (i ), combustor equivalence ratio ( ) and fuel pyrolysis temperature (Tp), for atmospheric pressure condition.

[0111] The combustion process may be characterized by <p, the system equivalence ratio of the system based on the CH4supplied originally to the SDC. For a given fuel flow rate (rhz) and <p, the air flow rate (m™-) is constant, emulating a typical gas turbine engine. A fraction of the heat of combustion, is transferred through a diathermal wall to enable the pyrolysis process. At stable operation of SDC, the fuel temperature may be maintained at Tpsuch that xp fraction of the supplied fuel is fully pyrolyzed. The two processes of pyrolysis and combustion are represented by simplified one-step global chemical reactions, as shown in Fig. 13A, detail (a). Hence, i moles of CH4undergoes complete pyrolysis into 2ip moles of H2and ip moles of solid C. The solid C is separated and the resulting processed hydrocarbon (mz- mc) is injected into the combustor. Thus, in contrast to traditional combustors, the in-situ pre-combustion decarbonization in the SDC enables the combustion of fuel with reduced carbon content compared to the originally supplied CH4. Consequently, the combustion of the processed hydrocarbon results in the emission of -i moles of CO2due to the capture of ip moles of C. Therefore, when ip > 0, a proportional amount of CO2is reduced, substantiating the decarbonization action of the SDC. Thermodynamic analysis is performed to underpin the feasibility of the SDC by evaluating the energy budget of the system. Given the standard enthalpies of methanepyrolysis (-Af / 7CH4= 74.87 kJ / mol) and combustion of CH4 (ACW CH4= -802.70 kJ / mol) and H2 (AC / TH2 = -241.82 kJ / mol), the net thermal energy output of the system is determined by performing a simple energy balance. The net heat produced in the combustor is contributed from the combustion of an unpyrolyzed fraction of CH4and in- situ generated H2. Subtracting the thermal energy, Qprequired for the pyrolysis of ip fraction of methane gives the total thermal output of the SDC. Assuming the SDC to be an adiabatic system, the net sensible enthalpy output A / 70Utis expressed as Eq. (1). The efficiency of the SDC, 77, is defined as the ratio of the net thermal output and the standard combustion enthalpy of CH4. Using the values of the standard enthalpies, is simplified as shown in Eq. 1

[0112] The example analysis is further extended to perform steady state enthalpy balance across the combustor and the pyrolytic reactor. The two energetically coupled reactors are simultaneously solved considering fuel and air to be originally at the ambient temperature of 298.15 K, to evaluate the combustor exhaust temperature (Te). The standard enthalpies of formation and specific heat capacity for the involved species are described in Linstrom, P. J., and Mallard, W. G. NIST Chemistry Web-Book, NIST Standard Reference Database Number 69. National Institute of Standards and Technology, Gaithersburg MD, 20899 (retrieved July 15, 2023) where are herby incorporated by reference in their entirety.

[0113] Figure 13A, detail (b) illustrates a contour plot of Teas a function of xp and <p, for a fixed value of Tp= 1000 K. The contour plot for Tevaries with i and <p and considers a feasibility limit governed by Tp, as Tes Tpfor heat transfer to the pyrolytic reactor assuming heat exchanger effectiveness, E < 1 . As Tegoverns the heat transfer between the two reactors, it must always be higher than Tp. Thus, Te< Tpas shown in FIG. 13A, detail (b), are invalid. In an example, by fixing <p and increasing i , the degree of decarbonization is enhanced at the cost of the net thermal output as reflected in the decreasing Te. However, higher values of Tecan be realized for 1 until the localequivalence ratio in the combustor limits the adiabatic flame temperature of the processed hydrocarbon. As seen from Eq. (2) and detail (c) of FIG. 13A, the combustion efficiency of the SDC decreases with increasing i but with increasing carbon output. However, the energy required for the process of decarbonization is internalized in the SDC, eliminating its reliance on external sources of energy and the associated inefficiencies. In addition to the energy analysis, evaluating the coupled chemical kinetics of methane pyrolysis is required for a holistic understanding of the SDC. The fuel residence time, T, is one of the parameters that govern hydrogen yield. The Arrhenius equation gives the reaction rate constant, k, given the frequency or pre-exponential factor (A), the activation energy (Ea), and Tp. Considering a first-order global one-step reaction, the rate law for the pyrolysis reaction is evaluated from the molar concentration of CH4 or H2. Assuming a convection dominated flow at steady state operation, the one dimensional transport equation for species conservation is solved. The mole fraction of H2 generated along distance x of the process reactor is derived as Eq. (3), with U as the characteristic flow velocity.

[0114] The energy budget of the system coupled with the kinetics of the pyrolysis process determines the performance of the SDC as a decarbonized thermal energy generator.

[0115] FIG. 13A, detail (c) is a plot of thermal efficiency of gas turbine in detail (a) versus compressor pressure ratio (PR) for different values of xp and effectiveness of heat recuperation (E). The thermal efficiency (nth) of the ideal gas turbine cycle is defined as the ratio of the net work output to the chemical energy of the fuel supplied (mz) to the system. This plot shows that the energy utilized in decarbonization is reflected as the reduction in r|th, while heat recuperation helps in maximizing it.

[0116] For the SDC design discussed in FIG. 13A, although the global equivalence ratio of the system is kept constant for a given input of air and fuel mass flow rates, the local equivalence ratio of the combustion varies due to the change in the extent of pyrolysis ( - This change in the local equivalence ratio, in turn, affects the adiabatic flame temperature, heat transfer to the pyrolytic reactor (Qp), and the turbine inlet temperature (Te). To control the variation in these key parameters affecting the performance of gas turbine, another embodiment of SDC is proposed wherein these parameters can be appropriately controlled externally, as shown in FIG. 13B, detail (a).

[0117] Continuing the example show in FIG. 13A, in this system, depending on the value of i , the mass flow rate of air (ml a) supplied to the burner of the combustor is externally adjusted such that the local equivalence ratio of combustion is held constant at a particular value throughout the operation of SDC. The value of the local equivalence ratio is chosen such that Qprequired for pyrolysis is maximized while maintaining the adiabatic flame temperature to minimize the thermal NOx levels. The remaining mass of air (m2,a) is added as secondary dilution injection downstream of the combustor to attain the required turbine inlet temperature (Te). For the real analysis of SDC integrated with a compressor and turbine, e.g. the embodiment shown in FIG. 10, with a given component adiabatic efficiencies (T]Cand ??t), effectiveness (e) of the heat exchanger, the desired turbine inlet temperature Te, the compressor pressure ratio PR, the extent of pyrolysis ip, the input mass flow rate of fuel mf, and the pyrolysis temperature Tp, the net work output of the engine, the global and local equivalence ratios, and the thermal efficiency can be calculated using thermodynamic cycle analysis. Figure 13B, detail (b) to detail (d), highlight the contour plots of the thermal efficiency (r]th) of gas turbine in the parameter space of ip and PF? for different values of Te, maintaining a local equivalence ratio of unity, and when = 0.8, rjc= 0.75, and s = 0.8. These contour plots are the performance charts of the gas turbine in FIG. 10 and can be used to select parameters that maximize its thermal efficiency.

[0118] FIG. 14A illustrates a schematic view of an example system 1400 according to this disclosure. System 1400, comprises an SDC as described in this disclosure; however, the pyrolytic reactor 110 and / or the separator 112 (e.g. catalytic reactor as shown), may be positioned in combustion chamber 102, with a larger fraction of the inputhydrocarbon stream in direct contact with flue gases from combustor 101. System 1400 may be fuelled by hydrocarbon rhf, e.g. natural gas (methane), but may capture carbon in the hydrocarbon fuel without external energy input. System 1400 comprises combustor 101 defining a combustion chamber 102 for combusting: oxidizing agent mair, e.g. air comprising oxygen, from an oxidizing agent input 103, and processed hydrocarbon mpfrom a processed hydrocarbon stream 104. The combustion reaction in burner 108 can be carefully controlled to minimize excess oxygen in the combustion products, preferably by maintaining an equivalence ratio of stoichiometric or rich ( 1). The mass flow rates of the pyrolyzed hydrocarbon stream 104 and the oxidizing agent input 103 for combustion in burner 108 should be the minimum required to generate the necessary thermal energy for decarbonizing the unreacted hydrocarbon (e.g. pure natural gas or methane) input 106, thus minimizing the amount of H2O generated in the combustion products. A large fraction of H2O in the combustion product can cause the methane reforming reaction according to the chemical equation: CH4+ H2O — > CO + 3H2, with WR= 206 kJ / mol. This is undesirable as it can lead to the production of carbon containing gases, which runs counter to the goal of SDC systems according to this disclosure of sequestering carbon in a solid state. Chemical equilibrium analyses suggest that to maximize the rate of pyrolysis (i ) with the formation of solid carbon while minimizing CO formation, the ratio of the unreacted hydrocarbon feed from hydrocarbon input 106 to the pyrolyzed hydrocarbon feed from input 104 combusted in burner 108 should be greater than 2. Furthermore, the smaller this ratio, the higher the mixture temperature, which increases the rate of pyrolysis. The flame of burner 108 may be surrounded by co-flowing streams 106 of unreacted hydrocarbon that are to be decarbonized. In an example, the oxidizing agent may be air, oxygen alone, or oxygen in a mixture with other gases, e.g. O2-N2, O2-Ar, O2-He. Oxidizing agent may comprise oxygen having a concentration in a range of about 20-100%. In another embodiment, processed hydrocarbon comprises hydrogen as the major species among other hydrocarbon species. Combustor 10T may comprise an exhaust 105 for expelling combustion product from the combustion chamber. Energy output (Qout), from flue gas may be useful for commercial purposes as a heat load such as to power a turbine as described in this disclosure. Combustor 101 may also comprise a fuel injection system 107 and / or an ignitor 108 (also referred to herein as a burner) injecting the processed hydrocarbon / oxygen and igniting the mixture respectively. Combustor 101 may alsocomprise a fuel injection system of unreacted hydrocarbon 106 that need to be decarbonized. A swirler 121 , 12T may also be provided for stabilizing a flame 108, 108’ when the oxidizing agent from the oxidizing agent input 103 and processed hydrocarbon from the processed hydrocarbon stream 104 are combusted. Swirler 121 may be an axial swirler with blade angle 30 - 60 degrees or a bluff body that can stabilize the flame. In some embodiments, valves may control the flow of processed hydrocarbon and oxidizing agent to combustors 101 , 10T respectively.

[0119] As shown in FIG. 14A, pyrolytic reactor 110 and separator 112 are in direct fluid communication with the combustion products from ignitor 108 to directly mix high sensible enthalpy and oxygen-free combustion products with hydrocarbon feed rhf, e.g. natural gas (methane) itself. In contrast with the pyrolytic reactor described in this disclosure with reference to FIG. 1 , the heating region for the pyrolysis reactor 110 is the combustion chamber 102 causing the hydrocarbon rhfUeito come into direct contact with the hot combustion products from burner 108. A fraction of the thermal energy generated in combustion chamber 102 is absorbed by the hydrocarbon rhf to thermally decompose hydrocarbon rhf from the hydrocarbon input 106 into pyrolyzed hydrocarbon, without forming excess CO. Continuing the example of FIG. 14A, hydrocarbon rhf may enter pyrolysis reactor 110 and is heated and pyrolyzed with heat from the combustion products from burner 108. Products of the pyrolysis, e.g. carbon black, may form in separator 112 which is positioned in direct fluid communication with pyrolysis reactor 110 and the combustion products from burner 108. In an embodiment, separator 112 is a catalytic reactor comprising a catalyst, e.g. a catalyst to reduce the energy required to form carbon black. The product stream from the combined pyrolysis reactor 110 and separator 112 is processed hydrocarbon mpwhich comprises unreacted hydrocarbon mf, from hydrocarbon input 106 or gaseous products thereof, and combustion products of oxidizing agent (e.g. air) m’aand m'pcombusted by burner 108. As such, the mass flow rate of processed hydrocarbon rhp may equal (rhf + mg) - mcwhere rhf is the mass flow rate of unreacted hydrocarbon from hydrocarbon input 106, e.g. natural gas or methane, entering pyrolysis reactor 110, mgis the mass flow rate of gas (i.e. combustion products from the processed hydrocarbon m'pdirected to burner 108 and oxidizing agent m’adirected to burner 108), and mcis the amount pyrolysis product, e.g. carbon black, that is separated by separator 112. The remained of the processed hydrocarbon rh”pmay bedirected by fuel injection system 107’ to burner 108’ to be combusted for providing energy output (Qout) for a heat load such that the flue gas may be useful for commercial purposes.

[0120] The presence of a catalyst in separator 112 may expedite the methane pyrolysis process by lowering the global activation energy. The catalyst may also facilitate heterogeneous nucleation over its surface sites for effective conversion and separation of solid carbon. In an embodiment, spent catalyst and / or substrates on which solid pyrolyzed products are deposited, may be removed from separator 112 to collect the pyrolysis products, e.g. carbon black, and regenerate the catalyst for reuse.

[0121] In an embodiment, when system 1400 is in use, a first hydrocarbon flow path is defined by hydrocarbon input 106, pyrolytic reactor 110 which comprises combustion chamber 102, separator 112, processed hydrocarbon stream 104, and combustor 10T. At separator 112, a fraction of hydrocarbon rhf may be separated as carbon black mc. As such, a second hydrocarbon flow path may be defined by hydrocarbon input 106, pyrolytic reactor 110 which comprises combustion chamber 102, separator 112; after which the solid carbon black may be removed from separator 112. In another embodiment, a third hydrocarbon flow path may be defined by hydrocarbon input 106, pyrolytic reactor 110 which comprises combustion chamber 102, separator 112, processed hydrocarbon stream 104, burner 108, pyrolytic reactor 110 comprising combustion chamber 102 for a second instance, and combustor 10T.

[0122] FIG. 14B illustrates a schematic view of an embodiment of example system 1400 according to this disclosure. In the illustrated embodiment, system 1400-1 , comprises the SDC as described above in this disclosure with reference to FIG. 14A; where, the pyrolytic reactor 110 and / or the separator 112, are positioned to directly contact hydrocarbon mfwith flue gases from combustor 101 with stoichiometric or rich (<|)>1 ) for pyrolysis of the hydrocarbon rhf from hydrocarbon input 106. However, in this embodiment, separator 112 is a cyclone separator configured to remove solids, such as carbon black, from the gaseous product(s) from combustor 101. Carbon black mcmay be collected as a batch or continuous process.

[0123] FIG. 15A illustrates a schematic view of another example system 1500 according to this disclosure. System 1500, comprises an SDC as described in this disclosure.Similar to system 1400, the pyrolytic reactor 110 and / or the separator 112 (e.g. a catalytic reactor), may be positioned in combustion chamber 102 in direct contact with flue gases from combustor 101. System 1500 may be fuelled by hydrocarbon rhf, e.g. natural gas (methane), but may capture the carbon in the hydrocarbon fuel without external energy input. System 1500 comprises combustor 101 defining a combustion chamber 102 for combusting: oxidizing agent mair, e.g. air comprising oxygen, from an oxidizing agent input 103, and processed hydrocarbon mpfrom a processed hydrocarbon stream 104. The combustion reaction from ignitor 108 can be carefully controlled to minimize excess oxygen in the combustion products, preferably achieved by maintaining an equivalence ratio of stoichiometric or rich (<|)>1). This flame is surrounded by co-flowing streams of hydrocarbon (e.g. pure natural gas or methane) that are to be decarbonized. In an example, the oxidizing agent may be air, oxygen alone, or oxygen in a mixture with other gases, e.g. O2-N2, Ch-Ar, Ch-He. Oxidizing agent may comprise oxygen having a concentration in a range of about 20-100%. In another embodiment, processed hydrocarbon comprises hydrogen as the major species among other hydrocarbon species. Combustor 10T may comprise an exhaust 105 for expelling combustion product from the combustion chamber. Energy output (Qout), from flue gas may be useful for a heat load such as to power a turbine as described in this disclosure. Combustor 101 may also comprise a fuel injection system 107 and / or an ignitor 108 (also referred to herein as a burner) injecting the processed hydrocarbon / oxygen and igniting the mixture respectively. Combustor 101 also contains a fuel injection system of unreacted hydrocarbon 106 that need to be decarbonized. A swirler 121 , 12T may also be provided for stabilizing a flame 108, 108’ when the oxidizing agent from the oxidizing agent input 103 and processed hydrocarbon from the processed hydrocarbon stream 104 are combusted. Swirler 121 may be an axial swirler with blade angle 30 - 60 degrees or a bluff body that can stabilize the flame.

[0124] As shown in FIG. 15A, pyrolytic reactor 110 and separator 112 are in direct fluid communication with the combustion products from ignitor 108 to directly mix high sensible enthalpy and oxygen-free combustion products with hydrocarbon feed rhf, e.g. natural gas (methane) itself. In contrast with the pyrolytic reactor described in this disclosure with reference to FIG. 1 , the heating region for the pyrolysis reactor 110 is the combustion chamber 102 causing the hydrocarbon rhfUeito come into direct contact with the hotcombustion products from burner 108. Another difference is that burner 180’ may be connected in series with separator 112 to receive a portion of processed hydrocarbon m"pdirectly from separator 112. In an example, fuel injection system 107 and burner 108 thereof may be coupled directly to the exhaust of separator 112 to receive gaseous hydrocarbon from processed hydrocarbon stream 104. A fraction of the thermal energy generated in combustion chamber 102 is absorbed by the hydrocarbon mfto thermally decompose hydrocarbon mffrom the hydrocarbon input 106 into pyrolyzed hydrocarbon, without forming excess CO. Continuing the example of FIG. 15A, hydrocarbon mfmay enter pyrolysis reactor 110 and is heated and pyrolyzed with heat from the combustion products from burner 108. Products of the pyrolysis, e.g. carbon black, may form in separator 112 which is positioned in direct fluid communication with pyrolysis reactor 110 and the combustion products from burner 108. In an embodiment, separator 112 is a catalytic reactor comprising a catalyst, e.g. a catalyst to reduce the energy required to form carbon black. The product stream from the combined pyrolysis reactor 110 and separator 112 is processed hydrocarbon mpwhich comprises unreacted hydrocarbon rhf, from hydrocarbon in put 106 or gaseous products thereof, and combustion products of oxidizing agent (e.g. air) m’aand m'pcombusted by burner 108. As such, the mass flow rate of processed hydrocarbon rhp may equal (rhf + mg) - mcwhere rhf is the mass flow rate of unreacted hydrocarbon 106, e.g. natural gas or methane, entering pyrolysis reactor 110, mgis the mass flow rate of gas (i.e. combustion products from the processed hydrocarbon m'pdirected to burner 108 and oxidizing agent m’adirected to burner 108), and mcis the mass flow rate of carbon black, that is separated by separator 112. The remainder of the processed hydrocarbon rh”pmay be directed by fuel injection system 107’ to burner 108’ to be combusted for providing energy output (Qout) to a heat load such that the flue gas may be useful for commercial purposes. In some embodiments, valves may control the flow of processed hydrocarbon and oxidizing agent to combustors 101 , 10T respectively.

[0125] Similar to the embodiment described in FIG. 14A, the presence of a catalyst in separator 112 of FIG. 15A may expedite the methane pyrolysis process by lowering the global activation energy. The catalyst may also facilitate heterogeneous nucleation over its surface sites for effective conversion and separation of solid carbon. In an embodiment, spent catalyst and / or substrates on which solid pyrolyzed products aredeposited, may be removed from separator 112 to collect the pyrolysis products, e.g. carbon black, and regenerate the catalyst for reuse.

[0126] In an embodiment, when system 1500 is in use, a first hydrocarbon flow path is defined by hydrocarbon input 106, pyrolytic reactor 110 which comprises combustion chamber 102, separator 112, processed hydrocarbon stream 104, and combustor 101’. At separator 112, a fraction of hydrocarbon mfmay be separated as carbon black mc. As such, a second hydrocarbon flow path may be defined by hydrocarbon input 106, pyrolytic reactor 110 which comprises combustion chamber 102, separator 112; after which the solid carbon black may be removed from separator 112. Processed hydrocarbon may also be combusted to provide heat for pyrolysis reactor 110; as such in another embodiment, a third hydrocarbon flow path may be defined by hydrocarbon input 106, pyrolytic reactor 110 which comprises combustion chamber 102, separator 112, processed hydrocarbon stream 104, burner 108, pyrolytic reactor 110 for a second instance, and combustor 10T.

[0127] FIG. 15B illustrates a schematic view of an embodiment of example system 1500- 1 according to this disclosure. In the illustrated embodiment, system 1500-1 , comprises the SDC as described above in this disclosure with reference to FIG. 15A; where, the pyrolytic reactor 110 and / or the separator 112, are positioned to directly contact hydrocarbon rhf with flue gases from combustor 101 with stoichiometric or rich (<|)>1 ) for pyrolysis of the hydrocarbon rhf from hydrocarbon feed 106. However, in this embodiment, separator 112 is a cyclone separator configured to remove solids, such as carbon black, from the gaseous product(s) from combustor 101. Carbon black mcmay be collected as a batch or continuous process. Burner 180’ may be also be connected in series with separator 112 to receive a portion of processed hydrocarbon m"pdirectly from separator 112. In an example, fuel injection system 107 and burner 108 thereof may be coupled directly to the exhaust of separator 112 to receive gaseous processed hydrocarbon from processed hydrocarbon stream 104.

[0128] FIG. 16 presents a schematic of an example system 1600 comprising a direct contact pyrolytic reactor 1610 integrated with a micro gas turbine 1603 to generate decarbonized electricity. Unlike the systems involving direct contact combustion-induced thermal decomposition of hydrocarbons described in FIGs. 14A and 15B, system 1600 features a pyrolytic reactor 1610 that rotates at high speed, driven by micro gas turbine,e.g. a radial or axial turbine. Turbine 1603 may also power compressor 1602, e.g. a radial or axial compressor, and electricity generator 1650.

[0129] As shown, hydrocarbon feed 1606 may initially be supplied through a central shaft 1601 that connects compressor 1602 and turbine 1603. Central shaft may define a lumen for supplying the hydrocarbon feed to the pyrolysis reactor 1610 and burner 1608. A small fraction of input hydrocarbon 1606 is used to establish controlled piloted combustion in the pyrolytic reactor 1610, ensuring the combustion equivalence ratio is stoichiometric or slightly richer ( 1). This controlled combustion may minimize the formation of carbon monoxide (CO) and water H2O vapour by avoiding excess oxygen in the combustion products. A plurality of burners 1608, e.g. swirl burners, may be used to maintain a near-uniform combustion temperature across the reactor. These burners may rotate at the frequency co of the pyrolytic reactor, or they may be static while only the pyrolytic reactor rotates at the frequency co.

[0130] The remaining hydrocarbon may be injected downstream of the piloted flames at injector 1609, allowing the hot combustion products from burner 1608 to mix with the unreacted hydrocarbons from injector 1609. In an example, injector 1609 may be an opening defining by in shaft 1601 in fluid communication with a valve for controlling flow through injector 1609. This process breaks down the hydrocarbon (e.g., methane or natural gas) into hydrogen and solid carbon. Due to the high-speed rotation of the pyrolytic reactor 1610, it exerts a centrifugal force (Fc = m Fr, where m is the mass of the gas, t is the rotational speed, and r is the radius of rotation) on the gas and solid carbon inside. Consequently, the gas and solid carbon particles move outward, perpendicular to the reactor's axis of rotation, toward the reactor walls. The rotational motion of the reactor may form a vortex, creating a low-pressure zone at the center. This vortex may enhance the mixing of hot combustion products and unreacted hydrocarbons, increasing their residence time in the reactor. Low-density gas flows out of the reactor during steady-state operation, while high-density carbon particles remain. The continuous accumulation of carbon particles near the wall can form large agglomerates, which eventually fall due to gravity into the carbon collector 1651 once their weight exceeds the centrifugal force. In an embodiment, the wall of the rotating pyrolytic reactor 1610 may be perforated with holes of different sizes or slotted with sufficient spacing to allow carbon agglomerates to escape and fall into the carbon collector 1651.

[0131] Processed hydrocarbon 1604, now enriched with hydrogen, is supplied to the combustion chamber 1622. The oxidizing agent input (e.g., air from the atmosphere) may enter the compressor 1602, e.g. a radial or axial compressor, where it is pressurized to high levels (e.g. greater than 5 bar, preferably between 5 to 10 bar). A portion of this pressurized air may then be sent through control valve 1623 and used for piloted combustion in combustion chamber 1624 to heat pyrolytic reactor 1610, while the remaining air is mixed with the processed hydrocarbon 1604 to achieve stable combustion in combustion chamber 1622. As shown in FIG. 16, air may be directed through shaft 1601 to burner(s) 1608 of the pyrolytic reactor 1610. The decarbonized exhaust 1605 from the combustor is directed toward the radial turbine 1603, whose rotation provides the necessary work to drive compressor 1602, pyrolytic reactor 1610, and generator 1650 for electricity production. The flow rates of hydrocarbon and oxidizer to the pyrolytic reactor may be controlled using separate mass flow control valves 1623.

[0132] FIG. 17 shows a schematic diagram illustrating a method 1700 of operating a system according to this disclosure.

[0133] At 1702, method 1700 comprises providing a system according to this disclosure. In an embodiment, the system may be system 100 described above.

[0134] At 1704, method comprises heating hydrocarbon feed from the hydrocarbon input in the pyrolytic reactor.

[0135] At 1706, method 1700 comprises pyrolyzing the hydrocarbon feed to form pyrolyzed hydrocarbon. In an example, pyrolyzing the hydrocarbon feed may occur at a temperature greater than or equal to 1100 K. In an embodiment, pyrolyzing the hydrocarbon feed occurs in heating region 111 and / or separator 112 of system 100.

[0136] At 1708, method 1700 comprises separating the pyrolyzed hydrocarbon into processed hydrocarbon and carbon black in the separator. In an embodiment, the separator is a catalytic separator or a Dielectric Barrier Discharge (DBD) plasma chamber carbon separator. The method may comprise forming carbon black on a catalyst bed of the catalytic separator or on an electrode of the DBD plasma chamber; and removing the carbon black from the catalytic separator or the DBD plasma chamber carbon separator.

[0137] In an embodiment, the separator is a first separator, and the system comprises a second separator configured to be operated in parallel to the first separator. Method 1700may comprise actuating a plurality of valves to isolate the second separator; and thermally decomposing the pyrolyzed hydrocarbon in the first separator while simultaneously removing carbon black from the second separator. These separators can either be packed bed catalytic reactors or fluidized bed catalytic reactors.

[0138] At 1710, method 1700 comprises combusting the processed hydrocarbon to heat the hydrocarbon feed.

[0139] In an embodiment, method 1700 comprises receiving an indication that a temperature of an outlet of the heating region of the pyrolytic reactor is below a first threshold value, and actuating a valve to increase a flow of hydrocarbon feed to the hydrocarbon input of the pyrolytic reactor. Hydrocarbon may then be flowed into the pyrolytic reactor to increase thermal output with substantial processed hydrocarbon for combustion to raise temperatures in the combustor and pyrolytic reactor. In an example, the first threshold is in a range of about 1125 K - 1375 K, preferably about 1275 K when the hydrocarbon feed to the system is methane.

[0140] In an embodiment, method 1700 comprises condensing a portion of the processed hydrocarbon from the separator of the pyrolytic reactor. In an example, the portion of the hydrocarbon condensed is a liquid or solid at STP, e.g. PAHs.CONTROLLER

[0141] FIG. 18 shows a generalized schematic view of example system 2000 for controlling a system in accordance with an embodiment according to this disclosure, e.g. system 100. System 2000 may comprise controller 2001 , described herein.The embodiment illustrated in FIG. 18 references the system 100 shown in FIG. 1 as a non-limiting example to explain how system 2000 may control systems comprising selfdecarbonizing combustors according to this disclosure. System 2000 may comprise controller 2001 which, in an example, may be part of an operating system for a selfdecarbonizing combustor system. Controller 2001 includes a processor 2002 configured to implement processor readable instructions that, when executed, configures the processor 2002 to conduct operations described herein. The processor 2002 may be a microprocessor or microcontroller, a digital signal processing (DSP) processor, an integrated circuit, a field programmable gate array (FPGA), a reconfigurable processor, a programmable read-only memory (PROM), or combinations thereof. In a non-limitingexample the micro-controller may be a 32-bit AU RIX™ TriCore™ microcontroller. The controller 2001 may include a communication interface 2004 to communicate with other computing or sensor devices, to access or connect to network resources, or to perform other computing applications by connecting to a network (or multiple networks) capable of carrying data. Communication interface 2004 may comprise a universal asynchronous receiver-transmitter (UART) to allow communication with other devices, e.g. a smartphone or a computer, for transmitting data for analysis and / or storage. UART may include or be coupled to a wireless transceiver for wireless communication with such other devices, e.g., by way of infra-red, Bluetooth, Wi-Fi, or the like. In some examples, the communication interface 2004 may include one or more busses, interconnects, wires, circuits, and / or any other connection and / or control circuit, or combination thereof. The communication interface 2004 may provide an interface for communicating data between the components of system 100, such as temperature sensor(s) 11 , 12, pressure sensor 13, processed gas composition sensor 14, mass flow control valve 15, display 2015, alarm 2016, exhaust gas composition sensor 16 and data storage 2014. Display 2015 may be a display on system 100 and / or a remote device such as a computer or remote communication device such as mobile phone. An alarm 2016 described herein, may be any indication that separator upstream temperature and / or pressure, measured by sensor 13, is below a threshold value; and / or composition sensor 14 indicated that H2 composition in the processed hydrocarbon is below a threshold valve; and / or combustor exit temperature, measured by sensor 11 is below a desired combustor output. Nonlimiting examples of alarms are visual alerts on the display or a light; or auditory alerts from a speaker.

[0142] Controller 2001 may also comprise connection for communicating with any component of system 100, e.g. temperature sensor(s) 11 , 12, pressure sensor 13, processed gas composition sensor 14, mass flow control valve (MFC) 15, display 2015, exhaust gas composition sensor 16, or an alarm 2016 via a network 2050. The network 2050 may include any wired or wireless communication path, such as an electrical circuit. In some embodiments, the network 2050 may include one or more busses, interconnects, wires, circuits, and / or any other connection and / or control circuit, or a combination thereof. In some embodiments, the network 2050 may include a wired or a wireless wide area network (WAN), local area network (l_AN), a combination thereof, or the like. In someembodiments, the network 2050 may include a Bluetooth® network, a Bluetooth® low energy network, a short-range communication network, or the like.

[0143] Controller 2001 may include memory 2006. The memory 2006 may include one or a combination of computer memory, such as static random-access memory (SRAM), random-access memory (RAM), read-only memory (ROM), electro-optical memory, magneto-optical memory, erasable programmable read-only memory (EPROM), and electrically-erasable programmable read-only memory (EEPROM), Ferroelectric RAM (FRAM) or the like.

[0144] The memory 2006 may store an application 2012 including processor readable instructions for conducting operations described herein. In some examples, application 2012 may include operations for operating a system comprising a self-decarbonizing combustor according to any one of the methods described herein such as method 1000.

[0145] In an embodiment, application 2012 may include operations for controlling the flow of oxidizing agent from the oxidizing agent input and hydrocarbon feed into the pyrolytic reactor. This may provide a desired oxidizing agent / fuel mixture in the combustion chamber for complete combustion of the hydrocarbon.

[0146] In an embodiment, application 2012 may include operations for receiving real time data indicative of a temperature and / or pressure in an outlet of the heating region of the pyrolytic reactor, e.g. from temperature sensor 11 , 12 shown in FIG. 2. When the temperature is below or equal to a first threshold value, at least one valve, e.g. MFC valve 15, is actuated to increase the hydrocarbon feed through the hydrocarbon input. When the temperature is above the second threshold value, then at least one valve, e.g. MFC valve 15, is actuated to reduce flow of the hydrocarbon feed through the hydrocarbon input. In an example, the first threshold value is selected to be equal to or greater than a thermal decomposition point of the hydrocarbon feed. When the hydrocarbon feed is methane, the first threshold may be about 1275 K. In another example, the first threshold value is in a range of about 1125 K - 1375 K, preferably about 1275 K. In another example, the first threshold value is in a range of about 1-50 bar, preferably 1-10 bar for an SDC integrated with a micro gas turbines. The second threshold may be selected to prevent overheating of the pyrolysis reactor or based on a desired combustortemperature. In an example, the second threshold may be in a range of 1575 K - 3500 K.

[0147] In an embodiment, application 2012 may include operations for receiving real time data indicative of a hydrocarbon feed pressure, e.g. at hydrocarbon input 106, which may be communicated by pressure sensor 13 shown in FIG. 2. When the pressure is below or equal to a threshold value, MFC valve 15 may be actuated to increase hydrocarbon flow to the pyrolysis reactor.EXAMPLES

[0148] FIG. 19, detail (b), shows a prototype self-decarbonizing combustor. The SDC illustrated in FIG. 19 is a swirl-stabilized lab scale model combustor operating at a pressure in a range from atmospheric pressure to 5 bar upstream of the combustor, with a heat shield acting as a metal liner, integrated with a pyrolytic reactor, thermo-catalytic reactor acting as the carbon separator, and condenser that were used to demonstrate a working prototype. As shown in FIG. 19, detail (a), both the catalytic reactor and pyrolytic reactor may be positioned within the combustor. A helical coil heat exchanger serves as the pyrolytic reactor and a tubular packed bed catalytic reactor acting as the carbon separator, shown in detail (c) of FIG. 19, through which the fuel is routed. The fuel flows through the pyrolytic reactor, thermo-catalytic reactor, condenser and fuel composition measurement circuit before being injected into the combustor. A fuel flow chart of the same is shown in detail (a) of FIG. 19 and actual images of the prototype are shown in detail (b) and detail (c) of FIG. 19. On ignition, the fuel in the pyrolytic reactor coil began to pyrolyze and eventually produced hydrogen, solid carbon, and other hydrocarbon species. Of the produced hydrocarbon proportion, higher hydrocarbons or aromatics that are responsible for solid carbon formation were trapped in the carbon separator and the condenser, while the hydrogen rich species were used for combustion with reduced CO2 emissions. The combustor supplies the required energy for the pyrolysis phenomenon to ensue in the pyrolytic reactor.

[0149] Thermocouples were placed at the center of the combustor exit to account for the enthalpy content of exhaust gases, at the exit of the pyrolytic reactor to monitor the pyrolysis temperature, TP. The effect of temperature and catalyst on fuel pyrolysis and consequent quantification of hydrogen produced is shown in FIG. 20. Gas samples werecollected prior to injection into the burner, post pyrolysis, using gas-tight syringes during the experiment as the pyrolyzed fuel temperature at the reactor exit increases up to about 1150 K. These samples were analyzed by Gas Chromatography (GC) using a Thermal Conductivity Detector (TCD) to measure generated hydrogen H2and unpyrolyzed methane CH4concentrations. A grade 4.0 hydrogen gas of 500 pL sample volume was used as the calibration standard in the analysis. The same volume of the pyrolyzed fuel sample is also analyzed using an optimized GC method.

[0150] FIG. 20 shows a graph of temporal variation in the molar concentration of in-situ generated H2in cases with and without the catalyst, when the fuel line is maintained at atmospheric pressure. The experiment was conducted with the experimental setup shown in FIG. 19 (a schematic of which is shown in FIG. 1). Higher fuel temperature Tp at the exit of the pyrolytic reactor coil and the presence of a catalyst increases the extent of pyrolysis. To investigate these effects in SDC, two separate experiments were performed in replicated setups. In both cases, fuel pressure (Pf) was maintained at atmospheric pressure, with one in the presence of the catalyst (considered as the base case), and the other without the catalyst.

[0151] The temporal changes in the concentration of in-situ generated H2in the processed hydrocarbon, as presented in Fig. 20, provide a proportional measure of the extent of pyrolysis. The time dependent concentrations of H2are coded based on representative Tp, as indicated by a colormap. It was observed that as the experiments progress, the increase in Tp results in an increase in the molar concentration of H2in processed hydrocarbon. Eventually, as the value of Tp steadies at around 1130 K, and as the operation of the SDC stabilizes the H2concentration reaches a relatively constant value. Notably, the H2concentration increases with Tp, highlighting the influence of Tp on the extent of pyrolysis. Furthermore, comparing the two independent cases, a clear distinction in the growth in H2concentration in the presence of the catalyst was shown. During stable operation, the maximum value of the H2concentration with the catalyst is 18.21 % compared to 7.18% in the absence of the catalyst. The catalyst was shown to enable the formation and separation of solid carbon. Consequently, the chemical equilibrium is pushed forward as carbon is captured in the solid phase, to enhance the molar concentration of H2.

[0152] FIG. 21 shows a graph illustrating the change in molar concentration of H2 and CH4 in the processed hydrocarbon with variation in the fuel residence time by setting fuel pressure (Pf) up-stream of the thermo-catalytic pyrolysis reactor for the two cases, with and without the catalyst. The experiment was conducted with the experimental setup shown in FIG. 19 (a schematic of which is shown in FIG. 1). Having substantiated the role of Tp and catalyst as described above with reference to FIG. 20, the effect of residence time T = VPfWNCH4hhfRTf, where R is the universal gas constant, V is reactor volume based on standard dimensions and MWCH4 is the molar mass of CH4; and fuel pressure Pfon methane pyrolysis are investigated. While P is an independent operating parameter, T is a dependent design parameter. For a constant volume reactor supplied with a fixed mfand at a constant Tp, any increase in Pfis reflected as a proportional increase in fuel density, a decrease in fuel flow velocity, and hence an increase in T in the reactor. Hence, Pfgoverns the fuel flow properties that impact T, and consequently, the kinetics of the methane pyrolysis process, as captured in Eq. (3) above. To resolve the effect of fuel flow properties, two separate experiments were performed involving systematically varying T, achieved by changing Pfin both cases - with and without the catalyst. The experiment was allowed to stabilize for the first 30 min at atmospheric pressure, after which Pfwas increased by 1 bar every 10 min. The variation in the molar concentrations of H2 and CH4 quantified for a value of Pfis plotted against the corresponding T in FIG. 21. A monotonically increasing trend in the molar concentrations of H2was observed with an increase in T in both cases, irrespective of the presence of the catalyst.

[0153] Consequently, as H2is generated from CH4, the concentration of CH4decreases with increasing T. Thus, the increase in the yield of H2 is strongly influenced by T as observed from both the experimental trends. Observed variations in molar concentrations of CH4 and H2 are the resultant effects of change in fuel flow properties on top of the established effect of Tpand the catalyst. In the presence of the catalyst, the molar concentration of H2 is approximately 41.26%, while in the absence of the catalyst, it is observed to be about 29.90%. The effect of the catalyst is evident from the noted difference in the yield of H2, as also established in FIG. 21.

[0154] Cumulative effect of increasing Pfin the presence of the catalyst enhances the H2yield. However, it is known that the effect of Pfis to impede the process of methanepyrolysis when all other parameters are held constant. Thus, the yield of H2 is expected to reduce slightly as Pfis increased. For constant values of A and Ea, the trend deduced from Eq. (3) is expected to increase steadily. However, as A and Eaare pressuredependent parameters, it is projected that Pfrestrains the yield of H2 to some extent. Thus, the increase in the molar concentration of H2 is not due to, but despite the increase in Pf as it results in an increase in T that increases the extent of methane pyrolysis. Moreover, the catalyst independently augments the yield further. This observation further suggests the importance of having a catalyst at higher Tp, especially at higher Pf, to enhance the pyrolysis process in the limited space of a practical combustor.

[0155] FIG. 22 shows graphs illustrating the percentage change in the molar concentrations of various species due to (a) addition of catalyst in the reactor, and (b) increase in the fuel pressure from 3 bar to 5 bar, in the presence of the catalyst. As discussed above with reference to FIGs. 20 and 21 , the performance of the SDC is characterized based on the amount of H2 generated and subsequently combusted. Although the process of methane pyrolysis can be simplified as a one-step global reaction, it involves the formation of intermediate species and reactions governed by its chemical mechanism. While close to 95% of the processed hydrocarbon by volume is mainly comprised of CH4 and H2 (refer to FIG. 20), the minor intermediate species of Polycyclic Aromatic Hydrocarbons (PAHs) affect the net carbon content of the processed hydrocarbon that is eventually combusted. Consequently, these species along with the carbon captured upstream of the combustor dictate the carbon emission in the combustion exhaust. Therefore, species other than H2 and CH4 were identified to be present in the processed hydrocarbon and corroborate the effects of pressure and catalyst on their formation. The percentage change in the major species of H2 and CH4, and the minor aromatic species are presented in FIG. 22. While the major species of CH4 and H2, and C2 species are quantified using gas chromatography thermal conductivity (GC-TCD), the minor aromatic species are analyzed using Gas chromatography-mass spectrometry (GCMS). In FIG. 22, detail (a) the fuel is maintained at atmospheric pressure for both cases - with and without the catalyst. In Fig. 22, detail (b), the fuel is maintained at pressures of 3 bar and 5 bar, both in the presence of the catalyst. It was observed from both the comparisons that the percentage change in Xll2is positive because of higher yield of H2 observed in the presence of the catalyst and at Pf= 5 bar,as evident from FIG. 21. Consequently, the percentage change in the concentration of unpyrolyzed CH4 is negative, indicating a higher reduction in the concentration of CH4 due to pyrolysis in the same cases. Similarly, the percentage change in concentrations of the PAHs is negative due to relative reduction in the concentrations of these species in the presence of catalyst and increasing Pffrom 3 to 5 bar. Thus, there is a corresponding change in the carbon content contributed by these PAHs species due to in-situ carbon capture in catalytic reactor and condenser. Furthermore, we note that these aromatic species eventually contribute to the net carbon content of the processed hydrocarbon injected into the combustor.

[0156] FIG. 23A shows a graph illustrating theoretically calculated CO2 reduction in comparison to experimental data using the test reactor shown in FIG. 18, a schematic of which is shown in FIG. 1. As shown in FIG. 23A, as fuel pyrolysis temperature (Tp) is increased and with elapsed experimental time, more carbon is captured causing the combustor to produce less CO2.

[0157] FIG 23B shows a graph of the decarbonization curve between molar concentration of H2 and CO2 reduction obtained for the SDC (circle and triangle markers) and H2 doped methane combustor (square markers). Apart from the thermal coupling, the pyrolysis and combustion processes are also chemically coupled in the SDC. As a result of the pre-combustion separation of carbon in the process of methane pyrolysis, the fuel subsequently injected into the combustor has a lower carbon content by mass compared to the originally supplied methane. Hence, a reduction in CO2 emissions was expected from the subsequent combustion process. This decarbonization operation of the SDC can be substantiated by correlating the quantified molar concentration of H2 in fuel and the consequent change in the concentration of CO2 in the combustor exhaust from its initial value. As shown in FIG. 23B, triangle markers indicates experimental results when a catalyst was used in the separator; and circles markers for experimental results when no catalyst was used. Figure 23B illustrates the molar concentrations of H2 and the corresponding reduction in CO2 emission for both cases — with and without the catalyst. In addition, the H2-CO2 curve obtained for the same methane-fueled combustor, doped with H2to simulate decarbonization through a fuel-flex combustor is also shown. Here, bottled H2(Messer Grade 4.0 UHP H2) was mixed homogeneously with CH4in known volumetric proportions and injected directly into the combustor, maintaining thesame input thermal power of 5.95 kW. In contrast to the SDC, such H2 doped, fuel-flex combustor represents a two-step approach to generating decarbonized thermal energy. As evident from FIG. 23B, the processes of H2 generation through pyrolysis and mitigation of CO2 in the combustor exhaust are intertwined. Higher operating pressure and the presence of the catalyst enhance the degree of decarbonization. Without the catalyst, the maximum H2 concentration due to the increase in Pfis approximately 29.90%, resulting in a 14.33% reduction in CO2 emissions. In contrast, the presence of a catalyst as increased Pf, increases the H2 concentration up to 41.26%, simultaneously mitigating CO2 by approximately 25.86%. Thus, around 11.53% more reduction in CO2 emissions is observed in the presence of the catalyst when the SDC is operated at the highest Pf. It is observed that the decarbonization curve obtained from the combustion of the processed hydrocarbon in the SDC deviates slightly from the curve obtained for the H2doped combustor. The percentage of CO2 reduction for a given concentration of H2, is observed to be more for the later case. This is because, the partially pyrolyzed fuel in the SDC contains a small fraction of PAHs that slightly increases the CO2 emissions in the SDC. However, it is expected that the two trends to converge as the intermediate species will be converted into C when the extent of pyrolysis increases up to 100%. Thus, the decarbonization plot presented in FIG. 23B delineates the overall performance characteristics of the SDC, substantiating its in-situ decarbonized thermal energy generation potential, which is comparable to fuel-flex or H2 doped combustors. Therefore, the SDC may provide an alternative to H2 doped systems that require a separate H2 supply to reduce CO2 emissions.

[0158] The sample of solid carbon shown in FIG. 24 was collected from the catalytic reactor after the culmination of the experiment performed at Pf= 5 bar in the presence of a catalyst. The analysis involves optically resolving the deposition structures of carbon black on mesh and iron beads using the standard Scanning Electron Microscope (SEM) and Transmission Electron Microscope (TEM) techniques, shown in FIG. 24 detail (a), (b), and (c), (d). The visualization of carbon structure was further complemented with XRD analysis shown in FIG. 24 detail (e) to infer the morphology of carbon deposition through powder crystallography. As shown in detail (b), the growth of stacked sphericalshaped carbon particles on the mesh surface was observed. TEM analysis, shown in detail (c), (d) observed coexistence of both spherical particles with an average diameterof 179.72 nm and the hollow tubular structures in carbon aggregates (identified by arrows). The observed tubular structures are akin to that of carbon nanotubes (CNTs). To confirm the presence of CNTs, a separate XRD analysis was performed which revealed the lattice structure of the carbon powder sample. The XRD spectrum of the sample along with peaks of matching standard spectra are shown in FIG. 24, detail (e). The peaks observed on the XRD spectrum are representative of the orientation of the lattice planes, as indicated by their corresponding Miller indices. As shown, peaks (100), (004), and (110) are influenced by the presence of CNTs, indicating a good match and ascertaining their presence.

[0159] Alternate embodiments

[0160] Although the embodiments have been described in detail, it should be understood that various changes, substitutions and alterations can be made herein without departing from the scope. Moreover, the scope of the present application is not intended to be limited to the particular embodiments of the process, machine, manufacture, composition of matter, means, methods and steps described in the specification. The present disclosure may be embodied in other specific forms without departing from the subject matter of the claims. The present disclosure is intended to cover and embrace all suitable changes in technology. Modifications which fall within the scope of the present invention will be apparent to those skilled in the art, in light of a review of this disclosure, and such modifications are intended to fall within the appended claims. Also, the scope of the claims should not be limited by the preferred embodiments set forth in the examples, but should be given the broadest interpretation consistent with the description as a whole.

[0161] As one of ordinary skill in the art will readily appreciate from the disclosure, processes, machines, manufacture, compositions of matter, means, methods, or steps, presently existing or later to be developed, that perform substantially the same function or achieve substantially the same result as the corresponding embodiments described herein may be utilized. Accordingly, the appended claims are intended to include within their scope such processes, machines, manufacture, compositions of matter, means, methods, or steps.

[0162] The description provides many example embodiments of the inventive subject matter. Although each embodiment represents a single combination of inventiveelements, the inventive subject matter is considered to include all possible combinations of the disclosed elements. Thus, if one embodiment comprises elements A, B, and C, and a second embodiment comprises elements B and D, then the inventive subject matter is also considered to include other remaining combinations of A, B, C, or D, even if not explicitly disclosed.

[0163] The embodiments of the devices, systems and methods described herein may be implemented in a combination of both hardware and software. These embodiments may be implemented on programmable computers, each computer including at least one processor, a data storage system (including volatile memory or non-volatile memory or other data storage elements or a combination thereof), and at least one communication interface.

[0164] Program code is applied to input data to perform the functions described herein and to generate output information. The output information is applied to one or more output devices. In some embodiments, the communication interface may be a network communication interface. In embodiments in which elements may be combined, the communication interface may be a software communication interface, such as those for inter-process communication. In still other embodiments, there may be a combination of communication interfaces implemented as hardware, software, and combination thereof.

[0165] Throughout the foregoing discussion, numerous references will be made regarding servers, services, interfaces, portals, platforms, or other systems formed from computing devices. It should be appreciated that the use of such terms is deemed to represent one or more computing devices having at least one processor configured to execute software instructions stored on a computer readable tangible, non-transitory medium. For example, a server can include one or more computers operating as a web server, database server, or other type of computer server in a manner to fulfill described roles, responsibilities, or functions.

[0166] The technical solution of embodiments may be in the form of a software product. The software product may be stored in a non-volatile or non-transitory storage medium, which can be a compact disk read-only memory (CD-ROM), a USB flash disk, or a removable hard disk. The software product includes a number of instructions that enablea computer device (personal computer, server, or network device) to execute the methods provided by the embodiments.

[0167] The embodiments described herein are implemented by physical computer hardware, including computing devices, servers, receivers, transmitters, processors, memory, displays, and networks. The embodiments described herein provide useful physical machines and particularly configured computer hardware arrangements.

[0168] The claims are not intended to include, and should not be interpreted to include, means-plus- or step-plus-function limitations, unless such a limitation is explicitly recited in a given claim using the phrase(s) “means for” or “step for,” respectively.

[0169] All documents disclosed herein are incorporated by reference.REFERENCES

[0170] 1. Sanchez-Bastardo N, Schlogl R, Ruland H. Methane pyrolysis for zeroemission hydrogen production: A potential bridge technology from fossil fuels to a renewable and sustainable hydrogen economy. Industrial & Engineering Chemistry Research. 2021 Aug 9;60(32): 11855-81.

[0171] 2. Schneider S, Bajohr S, Graf F, Kolb T. State of the art of hydrogen production via pyrolysis of natural gas. ChemBioEng Reviews. 2020 Oct;7(5): 150-8.

[0172] 3. Davis, S. M., Merrifield, M. L., Kuechler, K. H., & Starcher, L. K. (2016). U.S. Patent No. 9,346,721. Washington, DC: U.S. Patent and Trademark Office.

[0173] 4. Denton, R. D., Noyes, D. B., Koveal Jr, R. J., & Ring, T. A. (2019). U.S. Patent No. 10,343,104. Washington, DC: U.S. Patent and Trademark Office

[0174] 5. Gaiffi, S., & Cleland, J. G. (2011). U.S. Patent Application No. 11 / 912,743.

Claims

WHAT IS CLAIMED IS:

1. A system comprising: a combustor defining: a combustion chamber for combusting: oxidizing agent from an oxidizing agent input, and processed hydrocarbon from a processed hydrocarbon stream, and an exhaust for expelling combustion product from the combustion chamber, a pyrolytic reactor comprising: a heating region for heating hydrocarbon feed from a hydrocarbon input in the absence of oxygen to provide pyrolyzed hydrocarbon, the heating region defined within the combustion chamber for thermally coupling the heating region and the combustion chamber such that a fraction of the thermal energy generated in the combustion chamber is absorbed by the heating region to thermally decompose the hydrocarbon feed from the hydrocarbon input into pyrolyzed hydrocarbon; and a separator in fluid communication with the heating region for receiving the pyrolyzed hydrocarbon, the separator configured to convert the pyrolyzed hydrocarbon into the processed hydrocarbon and carbon black, the separator in fluid communication with the processed hydrocarbon stream for sending the processed hydrocarbon to the combustion chamber.

2. The system of claim 1 , wherein when in use: a hydrocarbon flow path is defined by the hydrocarbon input, the heating region, the separator, the processed hydrocarbon stream, and the combustion chamber.

3. The system of any one of claims 1-2, wherein the processed hydrocarbon comprises hydrogen.

4. The system of any one of claims 1-3, wherein the hydrocarbon feed comprises methane.

5. The system of claims 1-4, wherein the separator is in fluid communication with a reservoir for storing a portion of the processed hydrocarbon, wherein the portion of processed hydrocarbon is substantially hydrogen.

6. The system of any one of claims 1-5, wherein the separator is in thermal communication with the combustion chamber for receiving thermal energy for catalytic decomposition of the pyrolyzed hydrocarbon.

7. The system of any one of claims 1-6, wherein the separator is a catalytic separator, and wherein the hydrocarbon feed is pyrolyzed in the catalytic separator.

8. The system of claim 7, wherein the separator is at least one of a fixed bed, a moving bed, and fluidized bed catalytic separator.

9. The system of claim 7 or 8, wherein the catalytic separator comprises at least one of an iron catalyst, a nickel catalyst, a platinum catalyst, a carbon catalyst, a palladium catalyst, and a catalyst configured to form carbon black during pyrolysis.

10. The system of any one of claims 1-6, wherein the separator is a Dielectric Barrier Discharge (DBD) plasma chamber carbon separator.

11. The system of any one of claims 1-5, wherein the separator is a cyclone separator.

12. The system of any one of claims 1-11, comprising a condenser configured to receive and cool the processed hydrocarbon from the separator of the pyrolytic reactor, wherein the condenser is configured to condense a portion of the processed hydrocarbon.

13. The system of any one of claims 1-12, wherein the combustion chamber comprises one or more swirlers for stabilizing at least one flame when the oxidizing agent from the oxidizing agent input and the processed hydrocarbon from the processed hydrocarbon stream are combusted.

14. The system of any one of claims 1-13 wherein the separator is a first separator, and the system comprises a second separator configured to be operated in parallel to the first separator, wherein each of the first and second separators comprises isolation valves, a separator inlet for receiving regenerated catalyst, and an separator outlet for discharging at least one of spent catalyst and carbon black.

15. The system of any one of claims 1-14 comprising: a heat load thermally coupled to the combustor to provide heat energy from at least one of the combustion chamber or the exhaust to the heat load.

16. The system of claim 15, wherein the heat load is a heater, gas flare, or rocket engine, wherein the exhaust is in fluid communication and / or thermal communication the heater, gas flare exhaust or rocket engine exhaust17. The system of claim 16, wherein the heat load is a turbine, and wherein the exhaust of the combustor is in direct fluid communication with the turbine.

18. The system of claim 17, wherein the turbine is any one of a gas turbine, a micro gas turbine, or a micro turbine engine.

19. The system of any one of claims 1-18, comprising a controller configured to control the flow of oxidizing agent from the oxidizing agent input to the combustion chamber and hydrocarbon feed into the pyrolytic reactor.

20. The system of claim 19, wherein the controller is configured to: receive real time data indicative of at least one of a temperature and pressure in an outlet of the heating region of the pyrolytic reactor;when the at least one of the temperature and pressure is below or equal to a first threshold value, actuate at least one first valve to increase the hydrocarbon feed through the hydrocarbon input; when the at least one of the temperature and pressure is above a second threshold value, actuate at least one first valve to reduce flow of the hydrocarbon feed through the hydrocarbon input.

21. The system of claim 20, wherein the first threshold value is selected to be equal to or greater than a thermal decomposition point of the hydrocarbon feed.

22. The system of claim 20, wherein the first threshold value is in a range of about 1125 K - 1375 K, preferably about 1275 K when the hydrocarbon feed is methane.

23. The system of claim 20, wherein first threshold value is in a range of about 1-50 bar.

24. The system of any one of claims 15-23, comprising: a solar concentrator to focus solar energy onto at least one of the heating region and / or the separator of the pyrolytic reactor.

25. The system of any one of claims 15-23, comprising: a solar panel configured to convert solar energy into thermal energy used to heat at least one of the heating region and the separator of the pyrolytic reactor.

26. The system of any one of claims 1-25, wherein the heating region of the pyrolytic reactor is substantially a helically-shaped tube.

27. The system of any one of claims 1-25, wherein the heating region of the pyrolytic reactor is configured to put the hydrocarbon feed in direct contact with the combustion product, to heat and pyrolyze the hydrocarbon feed.

28. The system of claim 27, wherein the combustor is a first combustor, the combustion chamber is a first combustion chamber, and the exhaust is a first exhaust receiving the processed hydrocarbon and the combustion product; and wherein the system comprises a second combustor comprising: a second combustion chamber for combusting: the oxidizing agent from the oxidizing agent input, and the processed hydrocarbon from the processed hydrocarbon stream, and a second exhaust for expelling combustion product from the second combustion chamber.

29. The system of claim 28, wherein the first combustor is configured to rotate about an axis for imparting centrifugal force on the processed hydrocarbon, the combustion product, and carbon black to increase mixing and residence time.

30. The system of claim 28 or claim 29, wherein the second combustion chamber is connected to the separator in series for receiving the processed hydrocarbon directly from the separator.

31. The system of claim 28 - 30 comprising: a heat load thermally coupled to the second combustor to provide heat energy from the second exhaust to the heat load.

32. The system of claim 31, wherein the heat load is a heater, gas flare, gas turbine engine, or rocket engine.

33. The system of claim 31, wherein the heat load is a gas turbine, micro gas turbine or micro turbine engine, and wherein the exhaust in fluid communication with the turbine and powers the gas turbine.

34. A method comprising: providing the system of any one of claims 1-33; heating the hydrocarbon feed from the hydrocarbon input in the pyrolytic reactor;pyrolyzing a portion of the hydrocarbon feed to form pyrolyzed hydrocarbon; separating the pyrolyzed hydrocarbon into processed hydrocarbon and carbon black in the separator; and combusting the processed hydrocarbon to heat the hydrocarbon feed.

35. The method of claim 34 wherein the separator is a catalytic separator, a cyclone separator, or a DBD plasma chamber carbon separator, and wherein the method comprises: forming the carbon black on a catalyst of the catalytic separator, settling denser carbon particles in a hopper through centrifugal action of the cyclone separator, or forming the carbon black on an electrode of the DBD plasma chamber carbon separator.

36. The method of any one of claims 34-35, comprising: receiving an indication that a temperature of an outlet of the heating region of the pyrolytic reactor is below a first threshold value, actuating a valve to increase a flow of hydrocarbon feed to the hydrocarbon input of the pyrolytic reactor; flowing the hydrocarbon feed into the pyrolytic reactor.

37. The method of claim 36, wherein the first threshold is in a range of about 1125 K - 1375 K, preferably about 1275 K when the hydrocarbon feed is methane.

38. The method of any one of claims 34-37, comprising condensing a portion of the processed hydrocarbon from the separator of the pyrolytic reactor.

39. The method of claim 38, wherein the portion of the hydrocarbon condensed is a liquid or solid at STP.

40. The method of any one of claims 34-39 wherein the separator is a first separator, and comprises a second separator configured to be operated in parallel to the first separator, wherein the method comprises:actuating a plurality of valves to isolate the second separator; thermally decomposing the pyrolyzed hydrocarbon in the first separator while simultaneously removing carbon black from the second separator.

41. The method of claim 40, wherein the first and second separators are at least one of a packed bed catalytic reactor, and a fluidized bed catalytic reactor.

42. The method of claim 34, wherein the portion of the hydrocarbon feed pyrolyzed to form pyrolyzed hydrocarbon is a first portion of the hydrocarbon feed, the method comprising: burning a second portion of the hydrocarbon feed to form combustion products; and injecting the first portion of the hydrocarbon feed to mix with the combustion products and form the pyrolyzed hydrocarbon.

43. The method of claim 42, comprising forming a vortex to mix the combustion products and the first portion of the hydrocarbon feed.

44. The method of claim 42 or 43, comprising agglomerating the carbon black by rotating the separator; and collecting the agglomerated carbon black.

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