Combustion process using hydrogen-nitrogen mixture as fuel gas

Abstract

1. A combustion process comprising: a) generating a dual fuel gas consisting of hydrogen and at least 5-50% by volume of nitrogen, preferably 15-35% by volume of nitrogen; b) a combustion step using the dual fuel gas as the only fuel gas in a combustion chamber capable of accepting the dual fuel gas as a fuel gas, wherein the combustion chamber is selected from the group of a furnace or a direct fired process heater.

Description

[Technical field]

[0001] The present invention relates to a fuel gas, a combustion process using this fuel gas, and a combustion plant capable of receiving this fuel gas and suitable for carrying out such a process.

[0002] In particular, the present invention relates to a combustion process that does not emit carbon dioxide. [Background technology]

[0003] Burning fossil fuels such as natural gas contributes to the emission of carbon dioxide, a greenhouse gas.

[0004] Carbon dioxide emissions can be avoided by using renewable energy or by burning fossil fuels in combination with carbon capture and storage (sequestration).

[0005] Conventional methods for carbon-free fuel combustion utilize pure hydrogen gas or ammonia fuel.

[0006] Hydrogen is expected to play a central role in the energy future, either produced from renewable energies or from fossil fuels in combination with carbon capture and storage.

[0007] However, hydrogen fuel has the following problems: - high costs due to fuel quality requirements; -High peak flame temperature and high NOx emissions - Hydrogen fuel burns too fast, Hydrogen fuel produces less flue gas compared to natural gas or methane. As a result, furnaces designed for natural gas fuel suffer from a lack of flue gas mass velocity and flue gas enthalpy in the convection zone. Summary of the Invention

[0008] An object of the present invention is to overcome these problems and provide a new combustion process.

[0009] The solution of the present invention is a dual fuel gas consisting of hydrogen and at least 5-50% by volume of nitrogen.

[0010] Advantageously, the dual fuel gas according to the invention contains between 15 and 35% by volume of nitrogen, preferably between 20 and 30% by volume of nitrogen.

[0011] According to the present invention, the expression "dual fuel gas" means that the fuel gas has two main components, namely hydrogen and nitrogen, and is free of contaminants such as NH3, CO, CO2, CH4, C2H6, or contains only small amounts of contaminants, less than 1% by volume in total.

[0012] Another object of the present invention is a combustion process using the dual fuel gas defined in the present invention as the only fuel gas.

[0013] Advantageously, the process according to the invention comprises the steps of: a) generating a dual fuel gas; b) a combustion step using the dual fuel gas as the only fuel gas; Includes.

[0014] In an embodiment, the combustion process includes: a) generating a dual fuel gas consisting of hydrogen and at least 5-50% by volume of nitrogen; and b) combusting the dual fuel gas as the sole fuel gas in a combustion chamber capable of accepting the dual fuel gas as a fuel gas, the combustion chamber being selected from a furnace or a direct fired process heater.

[0015] Depending on the case, the process according to the invention comprises one or more of the following features: the production step a) comprises an electrolysis sub-step to produce hydrogen, a cryogenic air separation sub-step to produce nitrogen and a hydrogen and nitrogen mixing sub-step; - the production step a) comprises an ammonia cracking sub-step; ammonia cracking is a process in which ammonia is decomposed over a catalyst into hydrogen and nitrogen; - The process includes a NOx removal sub-step; for example, selective catalytic reduction (SCR) can be used. SCR consists of the reduction of nitrogen oxides (NOx) by injecting ammonia or urea (liquid) upstream of a catalyst. - the generating step a) comprises at least one of the following sub-steps: steam methane reforming, autothermal reforming, and partial oxidation; - the feedstock used in the generating step is selected from natural gas, liquefied petroleum gas (LPG), naphtha, diesel, gas oil, diesel, gas condensate, and biogas; The purification step a) comprises a sub-step of purification of the feedstock, for example purification by hydrodesulfurization and / or absorption to remove sulfur and chlorine. - The production step a) comprises the following sub-steps: a cooling sub-step, a water-gas shift sub-step, and a carbon dioxide removal sub-step; the water-gas shift sub-step is referred to as the "CO shift sub-step". - the generation step a) comprises a pre-reforming sub-step; - the carbon dioxide removal sub-step is a chemical absorption sub-step using a solvent such as an aqueous amine solution; - The process includes a heat recovery step, for example from the hot flue gases leaving the combustion chamber, for example by a combustion air preheater or a convection section to recover heat from the flue gases and heat the feed gas. Using pinch techniques, all streams can be evaluated for heat content.

[0016] Another object of the invention is a combustion plant equipped with a combustion chamber capable of accepting as the only fuel gas a dual fuel gas as defined in the invention.

[0017] Advantageously, the combustion plant comprises: i) a dual fuel gas generation unit; ii) a combustion chamber capable of accepting dual fuel gas as a fuel gas; Equipped with.

[0018] It should be noted that later on, the combustion chamber may be assimilated into the furnace. In fact, the furnace always has a combustion chamber in which heat is generated and recovered. [Brief description of the drawings]

[0019] [Figure 1] Combining an SMR with a carbon capture unit is shown to be just one option. [Diagram 2] Another method is shown to use autothermal reforming with air or oxygen-enriched gas. [Diagram 3] As an alternative, it is noted that the combustion plant may also be equipped with a pre-reforming reactor to increase the efficiency of the conversion to hydrogen. [Figure 4] Another alternative is shown to include a convective (or parallel) reformer, such as that described in EP 85110117. [Diagram 5] Another alternative is shown to include a pre-reformer and a convective reformer. [Figure 6] 1 shows the H2:N2 ratio in the fuel product versus the oxygen content in O2 enriched air. [Figure 7] 4 shows the effect of ammonia content in fuel gas on NOx emissions. [Figure 8] 1 shows the effect of nitrogen content in hydrogen fuel on thermal NOx formation in a typical low NOx burner. [Figure 9] The ratio of heat convection area to absorption and radiation area of ​​H2 / N2 fuel mixtures versus nitrogen content in a standard ethylene cracking furnace is shown.

[0020] In an embodiment, a combustion plant comprises: i) a generation unit configured to generate a dual fuel gas as defined herein; and ii) a combustion chamber selected from a furnace or a direct fired process heater capable of accepting the dual fuel gas as the only fuel gas.

[0021] Depending on the case, the combustion plant according to the invention comprises one or more of the following features: the production unit comprises an electrolyser capable of producing hydrogen, a cryogenic air separation unit capable of producing nitrogen, and means for mixing hydrogen and nitrogen; - the production unit comprises at least one ammonia cracker; The production unit is equipped with at least one NOx removal means downstream of the combustion chamber; for example, an SCR (selective catalytic reduction) device can be used. the production unit comprises one of the following devices: a steam methane reformer (SMR), an autothermal reformer (ATR), and a partial oxidation reactor; - the production unit comprises a cooler, a water gas shift reactor, and a carbon capture unit downstream of a steam methane reformer, an autothermal reformer, or a partial oxidation reactor; the water gas shift reactor is referred to as the "CO shift reactor"; - the carbon capture unit is an absorption unit, in particular a chemical absorption unit that includes a solvent such as an aqueous amine solution; - the production unit comprises a pre-reformer upstream of the production reactor; - the combustion chamber comprises at least a burner; The combustion plant comprises means for heat recovery; for example from the hot flue gases leaving the combustion chamber, for example by means of a combustion air preheater or a convection zone for recovering heat from the flue gases and heating the feed gas.

[0022] The combination of an SMR with a carbon capture unit is just one option (see FIG. 1). There are several possibilities for the location of the carbon capture unit in the flue gas of the steam methane reformer, downstream of the CO shift reactor, or both in the flue gas stream and downstream of the CO shift reactor. The fuel to the SMR reformer can be derived from the feedstock, or it can be a decarbonized product, or it can be a process stream such as the effluent of the carbon capture unit, or it can be a combination of these.

[0023] Another method for producing a hydrogen-nitrogen gas mixture, described in US Pat. No. 1,901,884, uses a hydrocarbon feedstock, such as natural gas, in contact with hot coke to make the hydrogen-nitrogen gas mixture.

[0024] Another method for producing a hydrogen-nitrogen gas mixture is described in US Pat. No. 1,921,856.

[0025] Another method for producing a hydrogen-nitrogen gas mixture is described in US Pat. No. 2,996,458.

[0026] Another method of producing a hydrogen-nitrogen gas mixture is by ammonia cracking as described in U.S. Patent No. 5,976,723. The problem with ammonia cracking is that the hydrogen-nitrogen gas effluent contains trace amounts of ammonia.

[0027] Another method is to use autothermal reforming with air or oxygen-enriched gas (see FIG. 2).

[0028] This method is efficient and produces favorable hydrogen-nitrogen fuel gas qualities as shown in Table 1.

[0029] [Table 1]

[0030] Oxidative steam reforming combines conventional steam reforming with some additional amount of air or oxygen to provide a supplemental source of exothermic reaction heat to assist in the completion of the steam conversion reaction. It is possible to balance the amount of heat released by the exothermic partial oxidation with the endothermic energy consumption from the steam reforming reaction so that the reaction is theoretically self-sustaining. This process is known as autothermal reforming, and the net enthalpy change for this process is zero.

[0031] A corresponding plant comprises a partial oxidation reactor combined with a steam methane reforming catalyst, a syngas cooler, a CO shift reactor(s) and a carbon capture unit. Optional feedstock processing such as dechlorination and / or desulfurization catalysts may be added.

[0032] The CO shift reactor may have a high temperature shift catalyst, a medium temperature shift catalyst, or a low temperature shift catalyst, or a combination of two or more catalysts. High temperature shift catalysts typically operate at inlet temperatures of 320-350°C for the bulk conversion of carbon monoxide to hydrogen, with a typical exotherm of 50-80°C, and consist primarily of magnetite (Fe3O4) with trivalent chromium oxide (Cr2O3) added as a stabilizer. The catalyst is usually supplied in the form of ferric oxide (Fe2O3) and hexavalent chromium oxide (CrO3), and is reduced by hydrogen and carbon monoxide in the shift feed gas as part of the start-up procedure to produce the desired form of catalyst. However, care must be taken, as the catalyst may be further reduced to metallic iron if the feed steam / carbon ratio is too low and the reducing environment is too strong.

[0033] The medium temperature shift catalyst typically operates at an inlet temperature of about 240° C. and is a copper-based catalyst.

[0034] Low temperature shift catalysts typically operate at inlet temperatures of about 200°C and employ copper-based catalysts that are more susceptible to sulfur poisoning and thermal stability. Low temperature catalysts typically contain copper and zinc. They are used when very low carbon monoxide concentrations are required in the product gas. These catalysts are highly susceptible to poisoning by sulfur compounds, so the feed gas must be thoroughly desulfurized before contacting the catalyst.

[0035] Because the CO shift reaction is exothermic, cooling is required between subsequent CO shift catalyst beds.

[0036] Alternatively, the combustion plant may also be equipped with a pre-reforming reactor to increase the efficiency of the conversion to hydrogen (see FIG. 3).

[0037] Another alternative involves a convective (or parallel) reformer, for example as described in EP 85110117 (see FIG. 4).

[0038] The parallel reformer uses the heat from the partial oxidation effluent to produce more hydrogen.

[0039] Another alternative includes a pre-reformer and a convective reformer (see FIG. 5).

[0040] Another variation uses partial oxidation of hydrocarbons with air or an oxygen-enriched gas.

[0041] Partial oxidation of hydrocarbons occurs when a substoichiometric amount of oxygen is supplied to the reaction, causing partial combustion. Like combustion, partial oxidation is an exothermic reaction, but the amount of heat released is much less than that caused during complete combustion of the fuel. The main products are hydrogen and carbon monoxide (also known as synthesis gas).

[0042] A corresponding plant of this variation includes a partial oxidation reactor, a syngas cooler, a CO shift reactor(s), and a carbon capture unit. Optional feedstock processing such as dechlorination and / or desulfurization catalysts may be added. The CO shift reactor may have a high-temperature shift catalyst, a medium-temperature shift catalyst, or a low-temperature shift catalyst, or a combination of two or more catalysts. Because the CO shift reaction is exothermic, cooling is required between subsequent CO shift catalyst beds.

[0043] Alternatively, a corresponding plant of this variant may include a pre-reforming reactor to increase the efficiency of the conversion to hydrogen.

[0044] Oxygen enrichment is known as the increase in the percentage of O2 in air. The process for oxygen enrichment can be carried out by using either cryogenic distillation or non-cryogenic methods such as pressure swing adsorption (PSA) or membrane separation techniques. Non-cryogenic methods are generally less energy intensive than cryogenic distillation and can result in lower energy requirements and costs compared to air separation processes.

[0045] The power consumption of oxygen enrichment by membrane separation is typically 0.30-0.70 kWh / Nm3 EPO2 (pure oxygen equivalent), depending on the capacity. Current membrane separation units can produce enriched oxygen with oxygen content up to 40%. On the other hand, the power consumption to achieve the same % O2 enriched air with a cryogenic process can be 0.30-0.55 kWh / Nm3 EPO2. PSA is reported to be more energy intensive (around 1.00 kWh / Nm3 EPO2) but is a more mature technology.

[0046] Air separation can be described by two main methods, either by directly achieving the desired proportion of oxygen-enriched air or by mixing an equal amount of pure oxygen with atmospheric air to obtain the desired oxygen concentration in the air.

[0047] To produce a 75:25 H2:N2 fuel mixture by autothermal reforming, 25-45% O2 enriched air is required, while an 80:20 ratio requires 30-50% O2 enriched air, depending on the overall process conditions. Depending on the enrichment method selected, the energy efficiency of the overall system can be improved.

[0048] Producing a 75:25 H2:N2 fuel mixture by autothermal reforming combined with a parallel convective reformer would require a much lower percentage of O2 enriched air, as shown in FIG. 6.

[0049] Figure 6 shows the H2:N2 ratio in the fuel product versus the oxygen content in O2-enriched air. Curves are shown for a plant with an autothermal reformer and for a plant with an autothermal reformer in combination with a parallel convective reformer.

[0050] With regard to burners, a wide variety of burners are available and may be used in the present invention, but the selection of the most suitable burner depends on several factors.

[0051] One of the first considerations in burner selection is the range of fuels to be burned. Process heater burners must be capable of burning a wide range of fuels. In addition, the materials being processed have a limited heat flux. Before burner selection can be considered, the degree of heat uniformity required must be established. Flame impingement and localized overheating of the furnace tube must be avoided. There must be adequate space for complete combustion.

[0052] The burner must be able to meet the maximum heat demand and must be flexible enough to accommodate any fluctuations (turndown capability).

[0053] The air pollutants commonly considered are oxides of sulfur, oxides of nitrogen, carbon monoxide, unburned hydrocarbons, and particulates. The burner must be capable of burning all available fuels in a safe, efficient, reliable, and environmentally clean manner.

[0054] In forced draught burners, combustion air is forced through an annulus in the burner head. Fuel is injected through the tip into the air stream where it is mixed and burned. Forced draught burners are used for gas, oil, or mixed combustion. The air pressure required ranges from 30 to 250 mm H2O. The flame of a forced draught burner can be designed to burn more intensely with a shorter flame than that of a natural draught burner.

[0055] In natural draft burners, air is drawn through the burner by the furnace draft. Natural draft burners can be used for gas, oil, or mixed firing. The problem is that the gas / air ratio of these burners cannot be precisely controlled. The pressure drop through the burner is typically 5-15mm H2O and is limited by the available draft in the heater.

[0056] In premixed burners, the combustion air is drawn in by the fuel gas pressure (self-aspirating, premixed type). This principle is often used for radiant sidewall burners. The advantage of premixed burners is that the air flow rate varies with the fuel flow rate, so the fuel / air ratio can be controlled to some extent by varying the heat release. The disadvantages of premixed burners are: -The fuel gas composition must be of constant quality to avoid low gas / air ratios; - Risk of "flash back" at low capacity; - Risk of "blow off" at high volumes; -Typical turndown ratio is 3:1.

[0057] "Blow-off" is the term used when the flow velocity is so high that it is not possible to stabilize the flame (keep it in a fixed position), causing the flame to propagate downstream.

[0058] The turndown of a burner is the ratio of the maximum firing rate to the minimum firing rate.

[0059] The fuel and combustion air do not mix until they exit the exhaust port. This eliminates the problem of flashback. The fuel / air mixture begins to burn in the (metallic) flame holder or cone (refractory) of the burner. The burner may be forced draft or natural draft. The turndown ratio may be 10 to 1.

[0060] Independent fuel and air flows allow for a wide range of fuel gas qualities to be burned.

[0061] The length of the flame shall not exceed 2 / 3 of the firebox height to avoid overheating the convection section tube. Adequate lateral clearances shall be provided between the edge of the flame and the front face of the radiant tube. Standards such as API-560 give recommendations for these clearances.

[0062] When the theoretically required amount of combustion air is supplied in normal practice, ideal mixing is not achieved in commercial burners, resulting in less than complete combustion.

[0063] Therefore, an excess amount of air must always be supplied. The amount of excess combustion air is usually expressed as a percentage of the amount of air theoretically required.

[0064] The amount of excess air that must be supplied to avoid a smoky flame and / or carbon monoxide in the flue gases is highly dependent on the burner and fuel type. The problem with a lot of excess combustion air is that it reduces the efficiency of the combustion chamber (or firebox). Excess combustion air reduces the temperature of the flame and flue gases, which in turn reduces the amount of heat transferred to the process stream, which in turn reduces the firebox efficiency. In addition, the excess combustion air must also be heated to flue gas temperatures in the stack, reducing the heat available for the process steam in the convection zone. Typical design excess combustion air levels for gaseous fuels are 5-10% for forced draft burners and 10-20% for natural draft burners.

[0065] In the combustion of fuel gases, the main source of NOx formation is the reaction of atmospheric nitrogen with oxygen at high temperatures (e.g., the Zel'dovich mechanism). The reactions, which may also involve radicals formed during the combustion process, are highly temperature dependent, with very little thermal NO being formed below 1300°C, but increasing exponentially thereafter.

[0066] If the fuel itself contains nitrogen compounds (e.g., HCN), NOx will also be formed by the reaction of these compounds with oxygen. The inventors have found that the presence of, for example, ammonia in the fuel gas increases NOx formation. See FIG. 7 for the effect of ammonia content in the fuel gas on NOx emissions.

[0067] The following parameters control NOx formation in direct fired process heaters and furnaces: -Excessive combustion air levels -Combustion air preheat temperature -Fuel quality -Fuel nitrogen (combined) content increases NOx formation

[0068] Techniques to reduce NOx formation essentially limit the availability of oxygen to the fuel and / or peak flame temperature.

[0069] To reduce the formation of nitrogen oxides, the following techniques are often used in burner design: -Staged combustion (air staging or fuel staging) - Flue gas recirculation (internal or external) -Steam / water injection

[0070] In addition to the above techniques, the inventors have found that diluting the fuel gas with inert nitrogen gas reduces NOx emissions in process furnace burners. Figure 8 shows the effect of nitrogen content in hydrogen fuel on thermal NOx formation in a typical low NOx burner.

[0071] Additionally, the inventors have found that inert nitrogen gas significantly reduces the flame speed of hydrogen fuel, as shown in Table 2:

[0072] [Table 2]

[0073] The addition of small amounts of nitrogen in hydrogen fuel significantly reduces the fuel flame speed, thereby reducing the risk of flashback in premixed burners.

[0074] Additionally, the nitrogen gas in the fuel acts as a diluent to reduce NOx emissions. Another advantage of nitrogen in the fuel gas is that the production costs of the less pure carbon-free fuel are much lower than the cost of pure hydrogen fuel.

[0075] For the above reasons, it is recommended to use hydrogen-nitrogen fuel mixtures ranging from hydrogen + 5% nitrogen by volume to hydrogen + 50% nitrogen by volume, preferably the hydrogen-nitrogen fuel mixtures should be in the range from hydrogen + 20% nitrogen by volume to hydrogen + 30% nitrogen by volume.

[0076] As for furnaces, direct fired process heaters are widely used in industry to heat liquids, gases and to vaporize duties. The process fluids in the tubes are heated by radiative and convective heat transfer from the hot combustion gases. Process heaters can be gas, oil or dual fired. Fluid exit temperatures are typically in the range of 200°C to 1000°C and unit sizes can vary with absorption duty of about 0.3MW to 500MW.

[0077] A typical list of loads is as follows: -High temperature oil heater, - Refinery Charge Heater -Reactor charge heater -Fired reboiler -Regenerative heater - Cracking furnace -Reformer -Direct Reduction Iron (DRI) heaters, which thermally reduce gases to produce iron.

[0078] It should be noted that all of these furnaces may be relevant to the present invention.

[0079] Cracking and reforming furnaces involve chemical reactions taking place within tubes.

[0080] A direct fired process heater consists of the following components: -The firebox, which includes the radiant tube and burners and is sometimes called the radiant section - Convection Zone -burner -Combustion air preheating -Tube supports and crossovers - Flue gas and combustion air fans, sometimes called induced draft (ID) fans and forced draft (FD) fans -stack

[0081] Not all heaters have all of the above components. A wide variety of layouts are possible. A common configuration is a firebox, a convection section, and a stack.

[0082] Furnaces and fired heaters have temperature limitations such as operating pressure, fluid operating temperature, and heater tube wall temperature. In contrast, gas turbines generally operate at higher pressures and with more limited allowable temperatures, e.g., maximum turbine inlet temperature, due to the so-called creep limits of the materials used in gas turbines.

[0083] The inventors have found that the convection zone absorption heat load and the radiant zone absorption heat load change when the fuel composition is changed. Pure hydrogen fuel produces a lower flue gas mass compared to conventional natural gas fuel. Therefore, the flue gas leaving the radiant zone of the furnace has a lower thermal enthalpy. Therefore, when pure hydrogen fuel is used in the burner, the convection zone load is lower. On the other hand, an increase in the radiant zone load leads to a higher heat flux in the radiant tube, which creates a risk of overheating.

[0084] The inventors have found through rigorous SPYRO® software simulations that nitrogen-hydrogen fuel with 25% nitrogen gas content by volume has the same heat convection / radiation area ratio as methane fuel. Furthermore, the inventors have found that nitrogen-hydrogen fuel with 25% nitrogen gas content by volume can be used in commercial industrial premixed burners, but pure hydrogen fuel is not suitable for this type of premixed burner due to the high burning rate of hydrogen fuel. Figure 9 shows the heat convection / radiation area ratio for H2 / N2 fuel mixtures versus nitrogen content for a standard ethylene cracking furnace.

[0085] Ethylene cracking furnaces are often designed for natural gas fuel as the (start-up) design fuel. For natural gas fuel, the ratio of absorption heat convection / absorption heat radiation area is 1.3. Figure 9 shows that a nitrogen-hydrogen fuel with 25% nitrogen by volume has the same absorption heat convection / absorption heat radiation area ratio as for methane (or natural gas) fuel.

[0086] For most applications, hydrogen fuel gas mixtures with nitrogen content in the range of 20% to 30% by volume will provide the same absorbed heat convection / absorbed heat radiation area ratios. For this reason, fuel gas mixtures with nitrogen content in the range of 20% to 30% by volume are preferred.

[0087] The present invention has the following advantages: - The ratio of the absorption heat radiation area to the absorption heat convection area is the same as for natural gas fuel. The heat flux of the heat transfer area in the radiation area does not change. -Because the fuel flame speed is much slower than pure hydrogen fuel, in many cases traditional premixed burners can be used with fine tuning of the fuel orifices. -Hydrogen / nitrogen fuel mixtures can be produced at low cost compared to pure hydrogen. -Nitrogen gas in the fuel acts as an inert gas, lowering the peak flame temperature of combustion, thereby reducing the formation of nitrogen oxides.

[0088] Alternative solutions are pure hydrogen combustion, ammonia combustion, and oxy-fuel combustion.

[0089] Pure hydrogen firing has the disadvantage of high fuel costs. In addition, pure hydrogen firing requires special nozzle mix burners suitable for hydrogen fuel. Pure hydrogen firing has a higher ratio of absorption load in the radiant section to absorption load in the convection section compared to natural gas fuel. This can limit the capacity of the furnace.

[0090] Ammonia-fuel combustion has the disadvantage that the heat of combustion of ammonia is fairly low. Additionally, it has the disadvantage of high emissions of nitrogen oxides and unburned ammonia, which results in the need for expensive selective catalytic DeNOx reactors. Oxy-fuel combustion has the disadvantage that it requires expensive oxygen. Oxy-fuel combustion requires highly combustion-controlled flue gas recirculation fans and additional piping to the burner.

[0091] Furthermore, oxyfuel combustion requires an additional carbon dioxide transport line from the furnace to the (remote) CO2 compressor station.

[0092] As used herein, the expression "carbon dioxide-free combustion process" will be understood to mean that the products of combustion of dual fuel gas are essentially free of CO2, notwithstanding the presence of CO2 resulting from the combustion of small amounts of pollutants.

[0093] In some embodiments, a combustion process is provided that includes: a) generating a dual fuel gas consisting of hydrogen and at least 5-50% by volume of nitrogen gas, the dual fuel gas being contaminant-free or having a total amount of contaminants less than 1% by volume; and b) combusting the dual fuel gas as the sole fuel gas in a combustion chamber capable of accepting the dual fuel gas as a fuel gas.

[0094] As discussed herein, the combustion process may favor a furnace or direct-fired process heater, or, stated differently, combustion may be used to provide heat to an industrial furnace or direct-fired process heater, for example, by providing a dual fuel as discussed herein as the sole fuel to a burner, e.g., a burner of a furnace or direct-fired process heater, such as a burner contained within a firebox. In a preferred embodiment, the combustion process is applied to a plant comprising a hydrogen / nitrogen generation unit as disclosed herein, a radiant section comprising a firebox having a radiant tube, a burner disposed within the firebox for combusting the dual fuel, and a convection section for recovering heat from flue gases resulting from the combustion.

[0095] In this regard, the present invention also provides a combustion plant. In some embodiments, the plant may comprise at least i) a production unit configured to produce a dual fuel gas as claimed in claim 1, and ii) a combustion chamber capable of receiving the dual fuel gas as the only fuel gas. The combustion chamber may be that of a furnace or a direct-fired process heater.

[0096] According to some aspects, the present invention provides a dual fuel gas, combustion process, and combustion plant, as described in the following clauses.

[0097] Clause 1. A dual fuel gas consisting of hydrogen and at least 5-50% by volume of nitrogen.

[0098] Clause 2. A combustion process using the dual fuel gas described in clause 1 as the only fuel gas.

[0099] Article 3. a) generating a dual fuel gas; b) a combustion step using the dual fuel gas as the only fuel gas; 3. The combustion process of claim 2, comprising:

[0100] Clause 4. The generating step, a) A combustion process as described in clause 3, comprising an electrolysis sub-step to produce hydrogen, a cryogenic air separation sub-step to produce nitrogen, and a hydrogen and nitrogen mixing sub-step.

[0101] Clause 5. The generating step, a) A combustion process as described in clause 3, comprising an ammonia cracking sub-step.

[0102] Clause 6. The combustion process according to clause 5, including a NOx removal sub-step.

[0103] Clause 7. The generating step a) the combustion process of clause 3, comprising at least one of the following sub-steps: steam methane reforming, autothermal reforming, and partial oxidation.

[0104] Clause 8. The combustion process of clause 7, wherein the feedstock used in the generating step is selected from natural gas, liquefied petroleum gas (LPG), naphtha, diesel, gas oil, diesel, gas condensate, and biogas.

[0105] Clause 9. The combustion process of clause 7 or 8, wherein the producing step a) comprises the following sub-steps: a cooling sub-step, a water-gas shift sub-step, and a carbon dioxide removal sub-step.

[0106] Clause 10. A combustion plant having a combustion chamber capable of accepting as the sole fuel gas a dual fuel gas as defined in clause 1 or clause 2.

[0107] Article 11. i) a dual fuel gas generation unit; ii) a combustion chamber capable of accepting dual fuel gas as a fuel gas; 11. A combustion plant as claimed in claim 10, comprising:

[0108] Clause 12. A combustion plant according to clause 11, wherein the production unit comprises an electrolyser capable of producing hydrogen, a cryogenic air separation unit capable of producing nitrogen, and means for mixing the hydrogen and nitrogen.

[0109] Clause 13. A combustion plant according to clause 11, wherein the production unit comprises at least one ammonia cracker.

[0110] Clause 14. A combustion plant according to clause 13, wherein the production unit is provided with NOx removal means downstream of the combustion chamber.

[0111] Clause 15. The combustion plant according to clause 11, wherein the production unit comprises one of the following devices: a steam methane reformer (SMR), an autothermal reformer (ATR), and a partial oxidation reactor.

[0112] Clause 16. A combustion plant according to clause 15, wherein the production unit comprises a cooler, a water gas shift reactor and a carbon capture unit downstream of the steam methane reformer, autothermal reformer or partial oxidation reactor.

Claims

1. 1. A combustion process comprising: a) generating a dual fuel gas consisting of hydrogen and at least 5-50% by volume of nitrogen; b) a combustion step using the dual fuel gas as the sole fuel gas in a combustion chamber capable of accepting the dual fuel gas as a fuel gas, wherein the combustion chamber is a furnace or a direct fired process heater.

2. 2. The combustion process of claim 1, wherein the producing step a) includes an electrolysis substep to produce hydrogen, a cryogenic air separation substep to produce nitrogen, and a hydrogen and nitrogen mixing substep.

3. 3. The combustion process according to claim 1 or 2, wherein the producing step a) comprises an ammonia cracking sub-step.

4. A combustion process according to any one of claims 1 to 3, comprising a NOx removal sub-step.

5. 2. The combustion process of claim 1, wherein the producing step a) comprises at least one of the following substeps: steam methane reforming, autothermal reforming, and partial oxidation.

6. 6. The combustion process of claim 5, wherein the feedstock used in the producing step is selected from natural gas, liquefied petroleum gas (LPG), naphtha, gas oil, diesel, gas condensate, and biogas.

7. 7. The combustion process of claim 5 or 6, wherein the producing step a) comprises the following sub-steps: a cooling sub-step, a water gas shift sub-step, and a carbon dioxide removal sub-step.

8. A combustion process as claimed in any preceding claim, wherein the dual fuel gas has a nitrogen content in the range of 20 to 30% by volume.

9. 1. A combustion plant comprising: i) a production unit configured to produce the dual fuel gas of claim 1; ii) a combustion chamber selected from the group of furnaces and direct fired process heaters capable of accepting the dual fuel gas as the only fuel gas; A combustion plant comprising:

10. 10. The combustion plant of claim 9, wherein the production unit comprises an electrolyser capable of producing hydrogen, a cryogenic air separation unit capable of producing nitrogen, and means for mixing hydrogen and nitrogen.

11. 11. The combustion plant of claim 9 or 10, wherein the production unit comprises at least one ammonia cracker.

12. A combustion plant according to any one of claims 9 to 11, wherein the production unit comprises NOx removal means downstream of the combustion chamber.

13. 10. The combustion plant of claim 9, wherein the generation unit comprises one of the following devices: a steam methane reformer (SMR), an autothermal reformer (ATR), and a partial oxidation reactor.

14. 14. The combustion plant of claim 13, wherein the production unit comprises a cooler, a water gas shift reactor, and a carbon capture unit downstream of the steam methane reformer, autothermal reformer, or partial oxidation reactor.

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