Systems and methods for producing hydrocarbon products having negative carbon strength

Abstract

Provided herein are systems and methods for controlling the production of liquid hydrocarbons (e.g., for fuels and chemicals) with negative carbon strength. In various embodiments, the methods utilize feedstocks with negative carbon strength, produce by-products from the feedstock, sequester a portion of the CO2 derived from the feedstock, or utilize a portion of the O2 in a process that consumes O2 and emits CO2.

Description

[Technical Field]

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS This application claims the benefit of U.S. Provisional Patent Application No. 63 / 474,744, filed September 8, 2022, which is incorporated herein by reference in its entirety.

[0002] FIELD OF THE INVENTION The present invention relates generally to the production of hydrocarbon products. More particularly, the present invention relates to the production of hydrocarbon products having negative carbon strength. [Background technology]

[0003] Carbon dioxide (CO2) is produced by many industrial and biological processes. However, CO2 is recognized as a significant greenhouse gas, and there is a need to significantly reduce CO2 emissions from these processes.

[0004] The Intergovernmental Panel on Climate Change (IPCC) published a report documenting progress toward the goal of limiting global warming to 1.5°C (2.7°F) above pre-industrial times by 2022, with the primary goal being to keep it below 2.0°C (3.6°F) (IPCC, 2022). However, several published studies have indicated that a 1.5°C increase could be achieved by 2025–2027, at which point the Earth has likely reached a “tipping point” (Schuetzle, 2020; WMO, 2021). This tipping point occurs when small increases in temperature significantly increase global climate change. Reducing CO2 emissions alone may not be sufficient to achieve this goal and limit the impacts of global warming. Removing more of the CO2 emitted throughout the life cycle from various processes will be essential.

[0005] As a result, global efforts to mitigate climate change are expanding, and several important strategies have been implemented to reduce greenhouse gas emissions.

[0006] Carbon pricing is an effective means of incentivizing the production and use of low-carbon fuels, materials, and chemicals. Emissions trading can also be used as a policy tool to ensure that companies collectively keep their greenhouse gas (GHG) emissions within certain limits (typically referred to as emissions caps). Carbon markets can be voluntary or mandatory, and costs are achieved in different ways depending on the carbon pricing instrument. A carbon credit is equivalent to one metric ton of CO2 or equivalent GHG that has been reduced, avoided, or removed.

[0007] Carbon intensity (CI) is used to measure all greenhouse gas emissions associated with the production, distribution, and consumption of fuels. CI scores are developed based on life cycle analysis methods, with different scores depending on the type of feedstock, its origin, feedstock processing efficiency, and its use in transportation. Net zero means that total emissions are equal to or less than the emissions removed from the environment. Carbon neutrality, or "net zero," means that CO2 released into the atmosphere by human activities is offset by an equal amount of CO2 reduction. A carbon-negative process requires removing more CO2 from the atmosphere than it emits over its life cycle (Budina, 2022). Carbon-negative processes effectively reduce atmospheric CO2 while producing valuable products.

[0008] Carbon intensity (CI) is determined by measuring the amount of greenhouse gas (GHG) emissions over the life cycle per unit of energy supplied to the hydrocarbon production process. CI is expressed in grams of CO2 equivalent per megajoule (g CO2e / MJ) (US EIA, 2021). The CI values ​​presented in this document are a measure of GHG emissions associated with the various production, distribution, and consumption stages in a well-to-wheel life cycle assessment (WTW-LCA) for the production of low-carbon transportation fuels and commodity chemicals.

[0009] A negative CI is achieved when a particular process removes more CO2 from various processes than the CO2 emitted over its entire life cycle. Negative CI emissions are needed to 1) offset residual emissions that are difficult to abate in industries such as cement, 2) reduce atmospheric CO2 if emissions reductions do not occur fast enough, and 3) remove past emissions from the atmosphere on a path to a stable long-term climate. Proposed negative CI solutions for CO2 are categorized as biological solutions, capture and storage solutions, and technological solutions. Some examples of these potential negative CI solutions include:

[0010] biological solution 1. Large-scale afforestation and sustainable land management that stores carbon in soil and biomass. 2. Adaptive land management to increase and permanently bind carbon from atmospheric CO2 in the soil, for example by incorporating crop residues and reducing tillage. 3. Pyrolysis of biomass to form charcoal (biochar), which retains carbon in the soil (or more precisely, charcoal) for many years. 4. Restoration of coral reefs and seagrass in shallow waters to efficiently store CO2.

[0011] Capture and store solutions 1. Removal of CO2 from industrial process emissions and its storage. 2. Removal of CO2 from the atmosphere and its storage.

[0012] technical solution 1. Conversion of CO2 captured from industrial processes and the atmosphere into fuels and valuable products.

[0013] For many years, scientists and engineers have recognized the potential economic and environmental benefits of using CO2 as a feedstock for the synthesis of commodity chemicals and fuels. However, despite a significant amount of fundamental research into converting CO2 into more valuable products, relatively few examples of industrially feasible processes exist. The challenges associated with CO2 conversion primarily relate to both its kinetic and thermodynamic stability. Because CO2 is a molecule containing strong bonds that are not particularly reactive, it cannot be converted into commodity chemicals or fuels without significant energy input. As a result, many available CO2 conversions require stoichiometric amounts of energy-intensive reagents. This can often result in significant waste generation and, consequently, increased greenhouse gas emissions. The grand challenge for converting CO2 waste streams into useful products is to develop processes that require minimal nonrenewable energy, are economically competitive, and significantly reduce greenhouse gas emissions compared to existing technologies (National Academies of Sciences, Engineering, and Medicine, 2019).

[0014] Current technology has reported many processes for converting CO2 into liquid fuels and chemicals, but these processes still have positive CI values. Biomethane is a potential gas-phase transportation fuel and is the only transportation fuel produced to date with a negative CI value (California Air Resources Board, 2022). The art is seeking novel processes for converting CO2 into liquid fuels and chemicals. Summary of the Invention

[0015] This disclosure describes systems and methods for producing carbon-negative hydrocarbon liquid fuels and chemicals from CO2. These fuels are produced in a carbon-negative e-fuel process that converts CO2, low-carbon electricity, and other optional feedstocks into various products, including e-fuels, which effectively remove CO2 from the atmosphere relative to a base case. The carbon intensity or well-to-wheel greenhouse gas content (WTW-GGC) of the e-fuel can be calculated using any suitable method. When hydrocarbons are transportation fuels, the GREET model can be used (Argonne National Laboratory, 2021).

[0016] The need for carbon-negative technologies to reduce atmospheric CO2 levels has led to the carbon-negative e-hydrocarbon refinery (CNER) process of the present invention, as shown in Figure 4. In a CNER, CO2 from the atmosphere or point sources, renewable or low-carbon electricity, and additional optional feedstocks are processed. The additional feedstocks are also common, including renewable natural gas (RNG) and industrial waste gases such as waste gas from steel mills, coke oven gas, and other carbon-containing gases. Carbon-negative hydrocarbons are produced in the CNER, along with optional non-combustible products. The hydrocarbons may be transportation fuels or chemical products (e-fuels).

[0017] E-fuels are non-biologically derived renewable fuels (RFNBOs). Fuels produced from negative carbon processes may also be recycled carbon fuels (RCFs) or other categories of fuels that achieve negative carbon intensity. Non-combustible products are products used for non-fuel applications, such as producing plastics or other industrial products, where the carbon in the product is effectively stored in the product and has little chance of returning to the atmosphere through the combustion process. Additional replacement products are optionally produced by the CNER. Replacement products are products that replace the use of fossil energy or products produced from fossil fuels in the market. The CNER uses renewable or low-carbon electricity to electrolyze water into H2 and O2.

[0018] The employed method is based on the use of renewable or low-carbon electricity to electrolyze water into hydrogen (H) and oxygen (O). In one embodiment, H is reacted with CO in a reverse water-gas shift (RWGS) or CO hydrogenation reaction, thereby producing synthesis gas, which can then be reacted to form hydrocarbons. In one embodiment, H is reacted directly with CO to produce hydrocarbons. In various aspects, the systems and methods provided herein achieve an overall negative carbon intensity by (a) utilizing a feedstock (e.g., a feedstock such as renewable natural gas) with a negative carbon intensity; (b) generating by-products from the feedstock that are not combusted and / or do not release CO into the atmosphere; (c) sequestering a portion of the CO from the feedstock; or (d) enabling the offsetting use or substitution of other products, such as O, in another industrial process. Intelligent process design and strategic optimization of feedstocks, by-products, and products are fundamental to this overall carbon-negative process.

[0019] Because e-fuels produced by CNER are synthesized from base molecules, the resulting e-fuels have improved properties over the fossil fuels they replace. For example, diesel fuel produced by CNER can have sulfur contents less than 0.1 ppm, cetane numbers greater than 65, cetane indexes greater than 65, aromaticity less than 1% by volume, and negative WWGCC or carbon intensity. [Brief explanation of the drawings]

[0020] [Figure 1] Figure 1 shows an example of fossil fuel oil refining. The elements listed are: 1.1 - oil refinery, 1.2 - fuel destination, 101 - fossil source (natural gas and oil), 102 - electricity from the grid (fossil fuel electricity and renewable electricity), 103 - fossil fuel (e.g., gasoline, diesel), 104 - other refinery products, 105 - CO2 to the atmosphere. [Figure 2]Figure 2 shows a biorefinery that converts renewable biomass into biofuel. The elements listed are: 2.1 - Biorefinery (Renewable Diesel or Ethanol Plant), 2.2 - Fuel Use Destination, 201 - CO2 from Air (to produce renewable biomass), 202 - Natural Gas, 203 - Electricity from the Grid (Fossil and Renewable), 204 - Biofuel (Ethanol or Renewable Diesel), 205 - CO2 to Air, 206 - CO2 to Air. [Figure 3] Figure 3 shows a carbon neutral e-fuel facility. The elements listed are: 3.1 - Carbon Neutral e-fuel Facility, 3.2 - Fuel Use Destination, 301 - CO2 from Atmosphere or Point Source, 302 - Renewable or Low Carbon Electricity, 303 - Carbon Neutral e-Fuel, 304 - CO2 to Atmosphere. [Figure 4] Figure 4 is a block flow diagram of a carbon negative e-fuel refinery. The elements listed are: 4.1 - carbon negative e-fuel refinery, 4.2 - fuel use destination, 401 - CO2 from atmosphere or point source, 402 - renewable or low carbon electricity, 403 - other feedstocks, 404 - carbon negative e-fuel, 405 - non-combustible products, 406 - other products, 407 - CO2 to sequestration, 408 - CO2 to atmosphere. [Figure 5] Figure 5 shows an example of a process for producing carbon-negative e-fuel. The elements listed are: 5.1 - electrolyzer, 5.2 - RWGS module, 5.3 - LFP module, 5.4 - fractionation module, 5.5 - autothermal reforming module, 5.6 - utilities, 501 - power, 502 - water, 503 - hydrogen, 504 - oxygen, 505 - CO2, 506 - CO, 507 - hydrogen, 508 - syngas, 509 - liquid hydrocarbons, 510 - tail gas, 511 - oxygen, 512 - additional feedstock for LFP. [Figure 6]Figure 6 shows an example of a process for producing e-fuel. The elements listed are: 6.1 - Electrolysis, 6.2 - Infinium Process (RWGS / LFP), 601 - Water, 602 - Power, 603 - Power, 604 - H2, 605 - O2, 606 - O2, 607 - Wastewater, 608 - CO2, 609 - e-Fuel, 610 - Wastewater, 611 - Purge. DETAILED DESCRIPTION OF THE INVENTION

[0021] Transportation accounts for more than 25% of global CO2 emissions. E-fuels are considered one way to support the decarbonization of aviation, shipping, and trucking. A key advantage of e-fuels is that they are drop-in fuels and can be used in existing processes and engines. An additional key advantage of negative CI fuels is that their production and use have a CI below zero, effectively removing CO2 from the atmosphere. While electric battery technologies to wean vehicles off fossil fuels are meeting growing consumer demand, e-fuels can decarbonize difficult-to-electrify long-haul sectors such as shipping, trucking, and aviation. Heavy goods transport and aviation are some of the most carbon-intensive transportation sectors. From an atmospheric CO2 perspective, it may be advantageous to transition difficult-to-decarbonize applications to carbon-negative e-fuels instead of electric battery technologies, which at best will maintain atmospheric CO2 levels at current levels.

[0022] For comparison, Figure 1 shows the overall process for producing fossil fuels. Stream 101 is an input, a fossil resource such as oil and natural gas. Additionally, electricity from the grid, including fossil and renewable sources, is used as an input. Unit 1.1 is an oil refinery that produces petroleum-based fuels (diesel and gasoline, stream 103, and other refinery products, stream 104). This petroleum-based fuel is used in a fuel use unit, labeled Unit 1.2, which converts the fuel to CO2. This process results in an overall increase in atmospheric CO2 over time, as carbon is removed from the ground and released into the atmosphere after the fuel is burned. This is carbon positive, with a calculated carbon intensity significantly greater than zero.

[0023] A first- and second-generation solution to this problem has been the use of biorefineries, as shown in Figure 2. Stream 201 is CO2 removed from the atmosphere to produce renewable biomass or other renewable feedstock. Stream 202, natural gas, and Stream 203, electricity from the grid, are processed along with Stream 201 in Unit 2.1, a biorefinery. The biorefinery can be an ethanol production facility that uses corn or other grain sugars, which are fermented to produce ethanol and separated to produce end products. The biorefinery can also be a renewable diesel facility that uses oils and greases and produces renewable diesel by hydroprocessing them into products that meet diesel fuel specifications. Stream 204, a biofuel, can be renewable diesel or ethanol. The biofuel is used by Unit 2.2, a fuel consumer, which produces CO2 from the fuel and releases it into the atmosphere. Additionally, biorefineries may emit CO2 from the fermentation of sugars or the production of hydrogen from natural gas. Although the carbon intensity of biofuel stream 204 in biorefineries is typically 50-80% lower than fuels produced by petroleum refining, the carbon intensity is still positive, and global CO2 emissions will continue to increase.

[0024] The need for better, lower-carbon-intensity fuels led to the development of the carbon-neutral e-fuel process. Figure 3 shows a typical configuration of this process. CO2 from air or a point CO2 source is used in a carbon-neutral e-fuel facility, Unit 3.1, along with renewable or low-carbon electricity to produce carbon-neutral e-fuel, Stream 303. This e-fuel is then used by a fuel consumer, Unit 3.2, which produces CO2. Overall, this process results in the production of carbon-neutral e-fuel, Stream 303. The carbon intensity of this fuel is zero or very close to zero. The amount of CO2 produced as a result of combustion by the fuel consumer is the same as the amount of CO2 captured from the atmosphere or point source. While this is a substantial improvement over the processes of Figures 1 and 2, at best, this process will maintain atmospheric CO2 levels at current levels.

[0025] The need for carbon-negative technologies to reduce atmospheric CO2 levels gave rise to the CNER process of the present invention, as shown in Figure 4. Stream 401, CO2 from air or a point CO2 source, stream 402, renewable or low-carbon electricity, and additional optional feedstock stream 403 are processed in CNER unit 4.1. Electrolysis of water to H2 and O2 is the CNER's primary process block. Reaction of CO2 stream 401 with the produced H2 is another CNER primary process block. Additional feedstock stream 403 can be a variety of streams, including renewable natural gas (RNG), industrial waste gases such as waste gas from steel mills, coke oven gas, and other carbon-containing gases.

[0026] In one embodiment, RNG is used as fuel gas in direct-fired heaters to raise the temperature of various streams in the CNER, including heating H2 and CO2 to reaction temperatures.

[0027] In one embodiment, stream 403, an industrial waste gas, may be converted to synthesis gas by reaction with O2 produced by an electrolysis process block.

[0028] In one embodiment, the electricity used in the CNER may come from a bioenergy carbon capture and sequestration (BECCS) facility and have a negative carbon intensity.

[0029] In one embodiment, low-carbon electricity is generated from wind, solar, or hydroelectric facilities near CNER, or low-carbon electricity is generated from wind, solar, or hydroelectric facilities far from CNER, but supplied through the grid. Alternatively, nuclear power, including existing nuclear technology and next-generation small modular reactors (SMRs) under development, may be used to supply low-carbon electricity to CNER.

[0030] Carbon-negative e-fuel is produced and is shown as stream 404. Stream 405 is a stream containing one or more non-combustible products. The non-combustible products produced in the CNER can be any material in which the carbon from the CO in the CNER feed can be effectively converted into a product in the CNER, and the product can be effectively sequestered in the product. Such non-combustible products include C5-C 12 This includes naphtha containing materials, C5-C 12 By "materials" is meant hydrocarbons with 5 to 12 carbon atoms per molecule, which can be used to produce plastic or polymer products. Similarly, C2-C4 olefins means hydrocarbon alkenes with 2 to 4 carbon atoms per molecule, which can be used to produce polymers or plastics. Ethane and propane products can be used in ethylene crackers to produce polymer products and can be used to produce olefins.

[0031] Stream 406 includes other products that can be produced in the CNER. These products can be broadly classified as replacement products. These products are used in other applications, but replace products produced using fossil fuels. Examples of replacement products include O2 and H2.

[0032] Stream 407 in Figure 4 shows CO2, which is optionally sent to geological sequestration, which also reduces the WTW-GGC of CNER e-fuel. This CO2 is captured from the combustion of fuel gases such as RNG or from the optional feedstock waste gas (stream 403).

[0033] In one embodiment, a portion of the CO2 in stream 407 is part of the CO2 feed to the CNER.

[0034] In one embodiment, the CO2 in stream 407 is CO2 produced within the CNER.

[0035] FIG. 4 also shows that the produced e-fuel is sent to a fuel consumer, unit 4.2, which ultimately combusts the fuel, thereby producing CO 2 , shown as stream 408 .

[0036] The life cycle assessment (LCA) or WTW-GGC (well-to-wheel greenhouse gas content) of e-fuels produced at CNER is negative. Carbon intensity can be calculated using any appropriate method. When hydrocarbons are transportation fuels, the GREET model can be used. "Well-to-Wheel Greenhouse Gas Content (WTW-GGC)" refers to calculations made using a life cycle greenhouse gas model, such as Argonne National Laboratory's GREET ("Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation") model or other similar greenhouse gas models, which allows for the calculation of the amount of greenhouse gases produced throughout the entire life cycle of a product ("well to wheel"). This model takes into account, among other things, the production method, the feedstocks used in production, the type of fuel produced, the transportation of the fuel to market, and the emissions generated from combustion when the fuel is used.

[0037] Some versions of GREET include over 100 fuel pathways, including petroleum fuels, natural gas fuels, biofuels, hydrogen, and electricity generated from various energy feedstock sources. GREET software for calculating WTW-GGC is readily available and publicly downloadable. The GREET model can be used to calculate the energy use and greenhouse gas (GHG) emissions associated with the production and use of specific types of fuels. Other models for calculating WTW-GGC are also available. For example, CA-GREET is an improved version of GREET used by the California Air Resources Board (CARB).

[0038] The WTW-GGC calculation involves two parts. First, the well-to-tank (WTT) life cycle analysis of a petroleum-based fuel pathway includes all steps from crude oil recovery to the final finished fuel. Second, the tank-to-wheel (TTW) analysis includes the actual combustion of the fuel for power in a vehicle. The WTT and TTW analyses are combined to produce a well-to-wheel (WTW) analysis, and this comprehensive WTW analysis calculates the well-to-wheel greenhouse gas content (WTW-GGC).

[0039] Therefore, using GREET or other WTW-GGC calculation models, the WTW-GGC score of a particular fuel from a particular pathway can be compared to petroleum-derived fuels, such as gasoline or diesel, whose scores are closer to 100 g CO2e / MJ. The lower the WTW-GGC, the less greenhouse gases a particular fuel will produce during its life cycle. The current version of GREET used in the examples of this application is GREET version 13868. However, other life cycle analyses can be used and will show similar results. In fact, ISO has published two standards for life cycle assessment, ISO 14040 and 14044.

[0040] Chemicals that can be produced in the CNER include non-combustible products, stream 405, such as ammonia, methanol, and high-value chemicals (e.g., as starting materials and / or intermediates for commodity chemicals or fine chemical production), such as formaldehyde, acetic acid, acetic aldehyde, or lower olefins and aromatics. The e-fuel production process in this category can be referred to as "Power to X," meaning that renewable electricity is the primary input in producing X, where X is fuel, chemicals, natural gas, etc. In the CNER, the production of these non-combustible chemicals reduces the WTW-GC of the e-fuel produced.

[0041] In one aspect, provided herein is a method for producing carbon-negative hydrocarbons. The method may include obtaining a feedstock containing CO, electrolyzing water using renewable electricity to thereby produce H and O, reacting the H with CO from the feedstock to thereby produce synthesis gas, and synthesizing hydrocarbons from the synthesis gas. The method may further include at least one of utilizing a feedstock having a negative carbon intensity, producing non-combustible by-products from the feedstock, sequestering a portion of the CO from the feedstock, or utilizing a portion of the O in a product or process such that the method is carbon-negative.

[0042] Greenhouse gas emissions due to hydrocarbons, O2, and their by-products have a negative carbon footprint. The greenhouse gas emissions due to hydrocarbons, O2, and by-products can be less than the greenhouse gas emissions due to the raw material. In some cases, the negative carbon footprint is based on kg CO2.

[0043] One such process for producing fuels and chemicals is described herein and depicted schematically in FIG. 5. Overall, the process converts electricity, CO, and water into fuels and chemicals. Here, an electrolyzer 5.1 can use electricity 501 to convert water 502 into hydrogen 503 and oxygen 504. The hydrogen can be fed to a reverse water gas shift module 5.2 and combined with CO 505 to produce synthesis gas (syngas) 508 containing carbon monoxide (CO) 506 and hydrogen 507. The synthesis gas can be reacted in a liquid fuel production module 5.3 to produce liquid hydrocarbons 509, which can be separated into fuel and chemical products in a fractionation module 5.4. The productivity of this process allows tail gas 510 to be sent from the liquid fuel production module to an autothermal reforming module 5.5 where it can be reacted with oxygen 511 to produce additional feedstock 512 for the liquid fuel production module.

[0044] The majority of the total power consumed in the process is supplied to the electrolyzer 5.1. Additional power from 501 can be supplied to utilities 5.6 or to modules other than the electrolyzer (e.g., reverse water gas shift module, liquid fuel production module, fractionation module, autothermal reforming module, etc.). However, such additional power is typically much smaller than the amount of power consumed in electrolysis.

[0045] The ratio of H2 to CO2 entering the RWGS reactor can be between 2.5 and 3.5. In some cases, the first and / or second ratio of H2 to CO2 is 2.5, 2.6, 2.7, 2.8, 2.9, 3.0, 3.1, 3.2, 3.3, 3.4, or 3.5. In some embodiments, the first and / or second ratio of H2 to CO2 is between 2.5 and 4.0, 2.6 and 4.0, 2.7 and 4.0, 2.8 and 4.0, 2.9 and 4.0, 3.0 and 4.0, 3.1 and 4.0, 3.2 and 4.0, 3.3 and 4.0, 3.4 and 4.0, or 3.5 and 4.0. In some embodiments, the first and / or second ratio of H2 to CO2 is between 2.0 and 2.5, between 2.0 and 2.6, between 2.0 and 2.7, between 2.0 and 2.8, between 2.0 and 2.9, between 2.0 and 3.0, between 2.0 and 3.1, between 2.0 and 3.2, between 2.0 and 3.3, between 2.0 and 3.4, or between 2.0 and 3.5.

[0046] CO2 can be obtained from several sources. Industrial manufacturing plants that produce ammonia for fertilizer generate large amounts of CO2. Ethanol plants that convert corn or wheat into ethanol generate large amounts of CO2. Power plants that generate electricity from various sources (e.g., natural gas, coal, and other sources) generate large amounts of CO2. Chemical plants, such as nylon production plants, ethylene production plants, and other chemical plants, generate large amounts of CO2. Some natural gas processing plants generate CO2 as part of the process of refining natural gas to meet pipeline specifications. Capturing CO2 for uses such as those described herein often involves separating CO2 from a flue gas stream or another stream in which CO2 is not the primary component. Some CO2 sources are already relatively pure and can be used in the processes described herein with only minor processing, which may include compressing the gas. Some processes may require alkylamine adsorbents (liquid or solid phase) or other methods to be used to remove CO2 from the flue gas vapor. Alkylamines used in the process include monoethanolamine, diethanolamine, methyldiethanolamine, diisopropylamine, aminoethoxyethanol, or combinations thereof. Metal-organic framework (MOF) materials and zeolite derivatives have also been used as a means of separating CO2 from dilute streams using chemisorption or physisorption to capture CO2 from the stream. Other methods of obtaining concentrated CO2 include chemical looping combustion, in which a circulating metal oxide material captures CO2 produced during a combustion process through a carbonation or other mineralization pathway. CO2 can also be captured from the atmosphere (through many of the same mechanisms) in a process called direct air capture (DAC).

[0047] A renewable source of H2 can be produced from water by electrolysis. [ka] This reaction uses electricity to split water into hydrogen and oxygen. Electrolyzers consist of an anode and a cathode separated by an electrolyte solution. Different electrolyzers function slightly differently, primarily due to the different types of electrolyte materials they contain.

[0048] However, for each electrolysis technology, the theoretical minimum electrical energy input is 39.4 kWh / kgH2 (hydrogen HHV) when water is fed to the system at ambient pressure and temperature and all energy input is provided in the form of electricity. The required electrical energy input can be less than 39.4 kWh / kgH2 if adequate thermal energy is provided to the system. In addition to electrolysis, significant current research is investigating methods for splitting water into hydrogen and oxygen using light energy and photocatalysis.

[0049] A variety of different electrolyzer designs are possible using different electrolysis technologies, including alkaline electrolysis, membrane electrolysis, solid polymer electrolyte membrane (PEM), solid oxide electrolysis (SOE), and high temperature electrolysis. Alkaline electrolysis is commercially capable of large-scale operation exceeding 1 MW. A variety of different electrolytes are available, including liquid KOH and NaOH, with or without activating compounds.

[0050] As described herein, the reverse water gas shift (RWGS) reaction can be used to produce synthesis gas according to the following equation: [ka] This reaction converts CO2 and hydrogen to carbon monoxide and water. The reaction is endothermic at room temperature and requires heat to drive the reaction, and high temperatures and good catalysts to achieve significant CO2 conversion.

[0051] Hydrogen and CO2 are mixed. The H2 / CO2 ratio can be 2.0 mol / mol to 4.0 mol / mol, and in some cases 3.0 to 4.0 mol / mol. The mixed RWGS feedstock can be heated to temperatures in excess of 900°F by indirect heat exchange. This initial temperature increase can be achieved without using direct combustion of carbon-containing gases to provide heat. This means that CO2 is being produced, and the impact of converting CO2 to useful fuels and chemicals can be negated.

[0052] The RWGS feed gas, which comprises a mixture of hydrogen and CO, may be heated to an inlet temperature, which may be any suitable temperature for carrying out the RWGS reaction, such as 1550°F to 1599°F, 1600°F to 1649°F, 1650°F to 1699°F, 1700°F to 1749°F, 1750°F to 1799°F, or 1800°F to 1850°F.

[0053] The RWGS feed gas may be at least partially heated in a preheater outside the primary reactor vessel to produce a heated feed gas. The preheater may be electrically heated and may increase the temperature of the feed gas through indirect heat exchange.

[0054] Electric heating of the feed gas can be accomplished in a variety of ways. One method is in an electrically heated radiant furnace. In some embodiments, at least a portion of the feed gas passes through a heating coil in the furnace. In the furnace, the heating coil is surrounded by a radiant electric heating element, or the gas passes directly over the heating element, thereby heating the gas by some form of convective heat transfer. Electric heating elements can be made from multiple materials. The heating elements can be nickel-chromium alloys. These elements can be rolled strip or wire, or cast in a zigzag pattern. The elements are typically lined with an insulated steel shell, usually ceramic fiber insulation. The radiant elements can be divided into multiple sections to control the heating pattern. Multiple coils and multiple sections may be required to supply heat to the feed gas to produce the heated feed gas. Radiant furnaces require proper design of the heating elements and fluid coils to ensure good coverage and good heat transfer. It is recommended that the power consumption of a radiant furnace be as low as possible. The power consumption of the radiant furnace is less than 0.5 MWh (megawatt-hours) per tonne (MT) of CO2 in the feed gas, in some cases less than 0.40 MWh / MT CO2, and in some cases less than 0.20 MWh / MT CO2.

[0055] The heated RWGS feed gas stream may then be fed into a main RWGS reactor vessel. There are at least two possible embodiments for the main RWGS reactor vessel. In some embodiments, the main RWGS reactor vessel is adiabatic or nearly adiabatic and designed to minimize heat loss, but no heat is added to the main reactor vessel, and the temperature within the main reactor vessel will decrease from the inlet to the outlet of the reactor. In some embodiments, the main RWGS reactor vessel is similarly designed, but additional heat is added to the vessel to maintain an isothermal or nearly isothermal temperature profile within the vessel. The main RWGS reactor vessel may be a reactor with a length greater than its diameter. The inlet of the main reactor vessel may be smaller than the overall diameter of the vessel. The main reactor vessel may be a steel vessel. The steel vessel may be internally insulated to reduce heat loss. Various insulation materials, including poured or castable refractory lining or insulating bricks, may be used to reduce heat loss to the environment.

[0056] The catalyst bed may reside within the main RWGS reactor vessel. The catalyst may be in the form of granules, pellets, spheres, tri-lobes, tetra-lobes, monoliths, or any other engineered shape to minimize pressure drop across the reactor. In some cases, the shape and particle size of the catalyst particles are controlled to provide a pressure drop across the reactor of less than 100 pounds per square inch (psi) (345 kPa), and in some cases, less than 0-20 psi (139 kPa). The size of the catalyst form may have characteristic dimensions of 1 mm to 10 mm. The catalyst particles may have an internal surface area of ​​10 m 2 / g, and in some cases 40m 2 / g, and in some cases, 100m 2 The material may be a structured porous material having a surface area of ​​1000 nm / g or more.

[0057] The RWGS catalyst can be a versatile and high-performance solid solution catalyst that efficiently carries out the RWGS reaction.

[0058] In some cases, the pressure of the RWGS step and the pressure of the hydrocarbon synthesis or liquid fuel production (LFP) step are within 200 psi of each other, in some cases within 100 psi of each other, and in some cases the pressures are equivalent. Operating the two processes at pressures close to each other reduces the required compression of the synthesis gas stream.

[0059] The conversion of CO2 to CO per pass in the main RWGS reactor vessel can be 60-90 mol%, and in some cases 70-85 mol%. When an adiabatic reactor is used, the temperature in the main RWGS reactor vessel can decrease from the inlet to the outlet. The outlet temperature of the main RWGS reactor vessel is 100°F to 200°F lower than the inlet temperature of the main reactor vessel, and in some cases 105-160°F lower than the inlet temperature of the main reactor. The RWGS weight hourly space velocity (WHSV) is the mass flow rate of the RWGS reactants (H2 + CO2) per hour divided by the mass of catalyst in the main RWGS reactor bed, which is expressed as a function of time from 1,000 to 50,000 hr -1 In some cases, it can be 5,000 to 30,000 hours. -1 It could be.

[0060] The gas exiting the main RWGS reactor vessel is the RWGS product gas stream. The RWGS product gas contains CO, H, unreacted CO, and H O. Additionally, the RWGS product gas may also contain small amounts of methane (CH) and / or elemental carbon (C) produced by side reactions within the main reactor vessel.

[0061] The RWGS product gas can be used in a variety of ways at this point in the process. It can be cooled and compressed for use in downstream processes to produce fuels and chemicals. It can be cooled and compressed and returned to the preheater for re-supply to the main reactor vessel. It can be reheated in a second electric preheater and sent to a second reactor vessel where additional conversion of CO to CO can occur.

[0062] By catalytically hydrogenating carbon monoxide (CO) from the RWGS reaction and hydrogen from the electrolysis of water to hydrocarbons. There is potential for useful products. The mixture of H2 and CO is called synthesis gas or syngas. Synthesis gas can be used as a feedstock for the production of a wide range of chemical products, including liquid fuels, alcohols, organic acids, ethers, aldehydes, ketones, ammonia, and many other chemicals.

[0063] Catalytic hydrogenation of carbon monoxide to produce heavier hydrocarbons (C 100 The production of light gases, liquids and waxes, as well as oxygen-containing hydrocarbons, from crude oil to crude oils (C ) is typically referred to as Fischer-Tropsch (or FT) synthesis. Conventional low-temperature (below 250°C) FT processes produce a large weight (or weight percentage) of FT wax (C ) primarily from a catalytic conversion process. 25 These FT waxes are then hydrocracking and / or further processed to produce diesel, naphtha, and other fractions. The hydrocracking process also produces light hydrocarbons, which may require further performance upgrades to produce viable products. Catalysts commonly used in FT are cobalt (Co)- or iron (Fe)-based catalysts, which are also active in the water-gas shift (WGS) reaction, which converts the carbon monoxide feed to CO2.

[0064] In addition to the FT, a liquid fuel production (LFP) module, as described herein, can be used. The LFP reactor converts CO and H2 into long-chain hydrocarbons that can be used as liquid fuels and chemicals. This reactor can use a catalyst for producing liquid fuel-range hydrocarbons from syngas. The syngas obtained from cooling and condensing the syngas can be blended with tail gas to produce the LFP reactor feed. The LFP reactor feed contains hydrogen and carbon monoxide. Ideally, the hydrogen to carbon monoxide ratio is 1.9 to 2.2 mol / mol. The LFP reactor can be a multi-tubular fixed-bed reactor system. The diameter of each LFP reactor tube can be 13 mm to 26 mm. The length of the reactor tube is generally greater than 6 m, and in some cases, greater than 10 m. The LFP reactor is generally vertically oriented, with the LFP reactor feed entering the top of the LFP reactor. However, in some situations a horizontal orientation of the reactor is also possible, and in some situations where height is limited it may also be advantageous to install the reactor at an angle.

[0065] The majority of the length of the LFP reactor tubes may be filled with LFP catalyst. The LFP catalyst may be blended with a diluent, such as silica or alumina, to aid in the distribution of the LFP reactor feed into and throughout the LFP reactor tubes. The chemical reactions occurring within the LFP reactor produce a mixture of mostly hydrocarbons with carbon numbers between 5 and 24 (C5-C 24An LFP product gas is produced that contains carbon monoxide (carbons) and also contains water, although some hydrocarbons are outside this range. LFP reactors typically do not produce significant amounts of CO2. 0% to 2% of the carbon monoxide in the LFP reactor feed is typically converted to CO2 in the LFP reactor. Only limited amounts of carbon monoxide in the LFP reactor feed are typically converted to hydrocarbons with carbon numbers greater than 24. 0% to 25% of the hydrocarbon fraction of the LFP product has a carbon number greater than 24. In some cases, 1 to 10 wt% of the hydrocarbon cut of the LFP product has a carbon number greater than 24. In some cases, 0 to 4 wt% of the hydrocarbon fraction of the LFP product has a carbon number greater than 24. In some cases, 0 to 1 wt% of the hydrocarbon fraction of the LFP product has a carbon number greater than 24.

[0066] As discussed above, the Fischer-Tropsch (FT) process generally produces hydrocarbon products with lengths between 1 and 125 carbon atoms. The LFP catalysts described herein do not produce heavy hydrocarbons in the same yields as other catalysts used in the FT process. In some embodiments, the LFP catalyst does not have significant activity for converting carbon monoxide to CO via the water gas shift reaction. In some embodiments, the water gas shift conversion of carbon monoxide to CO is between 0% and 5% of the carbon monoxide in the feed. In some embodiments, the LFP catalyst includes cobalt as the active metal. In some embodiments, the LFP catalyst includes iron as the active metal. In some embodiments, the LFP catalyst includes a combination of iron and cobalt as the active metals. The LFP catalyst can be supported on a metal oxide support selected from the group consisting of alumina, silica, titania, activated carbon, carbon nanotubes, zeolites, or other support materials, or mixtures thereof, of sufficient size, shape, pore diameter, surface area, crush strength, and effective pellet radius. The catalyst may have a variety of shapes, including lobed supports having three, four, five or more lobes, where two or more lobes are longer than the other two shorter lobes, and both long lobes are symmetrical. The distance from the midpoint of the support or the midpoint of each lobe is referred to as the effective pellet radius, and is expressed as C5-C 24 The LFP catalyst promoter may contribute to achieving the desired hydrocarbon selectivity. The LFP catalyst promoter may include one of nickel, cerium, lanthanum, platinum, ruthenium, rhenium, gold, or rhodium. The LFP catalyst promoter is present in an amount of 0.01 to 1 wt. % of the total catalyst, in some cases 0.01 to 0.5 wt. %, and in some cases 0.01 to 0.1 wt. %.

[0067] LFP catalyst supports have pore diameters between 8 nanometers (nm) and 25 nanometers (nm), average effective pellet radii between 25 microns and 600 microns, crush strengths between 3 lbs / mm and 10 lbs / mm, and a pore size of 100m 2 / g~200m 2 / g. After the metals are impregnated, the catalyst may have a metal dispersion of 3.5% to 4.5%. Some types of supports are C5-C 24 Hydrocarbon yields may be maximized. These may include alumina / silica combinations, activated carbon, alumina, carbon nanotubes, and / or zeolite-based supports.

[0068] LFP fixed bed reactor is C5-C 24 The LFP reactor may be operated in a manner that maximizes hydrocarbon yield. The LFP reactor may be operated at a pressure of 150-450 psi. The reactor may be operated in a temperature range of 350-460°F, more typically 405-415°F. The reaction is exothermic. The reactor temperature may be maintained inside the LFP reactor tubes by placing a bundle of reactor tubes into a heat exchanger where boiling steam is present on the outside of the LFP reactor tubes. Because the steam temperature is lower than the LFP reaction temperature, heat flows from the LFP reactor tubes to the cold steam. The steam temperature may be maintained by maintaining the steam pressure. The steam is generally saturated steam. In some embodiments, the catalytic reactor may be a slurry reactor, a microchannel reactor, a fluidized bed reactor, or other reactor types known in the art.

[0069] CO conversion within the LFP reactor can be maintained at 30-80 mole % CO conversion per pass. The CO can be recycled for extra conversion or sent downstream to additional LFP reactors. Carbon selectivity to CO can be minimized to 0%-4% of the converted CO, and in some cases, 0%-1%. C5-C 24 Carbon selectivity to hydrocarbons can be 60-90%. The LFP reactor product gas is then converted to the desired C5-C6 hydrocarbons, which are condensed as liquid fuel. 24 Hydrocarbons and water, as well as unreacted carbon monoxide, hydrogen, small amounts of C1-C4 hydrocarbons and small amounts of C 24+The desired products may be separated from the stream by cooling, condensation and / or distillation of the products, or other acceptable means. The unreacted carbon monoxide, hydrogen, and C1-C4 hydrocarbons may be part of the feed to an autothermal reformer (ATR).

[0070] In one embodiment, the liquid fuel production module produces a diesel fuel product that has significantly improved WTW-GGC content and improved physical properties. Table 1 shows a comparison of key performance parameters between CNER-produced diesel and petroleum diesel fuel. As can be seen, CNER diesel is superior in many performance criteria.

[0071] [Table 1]

[0072] In one embodiment, the LFP product is further hydrotreated and hydroisomerized to produce a sustainable aviation fuel (SAF) that meets ASTM D7566. The properties of this fuel are improved over petroleum-based jet fuel and are shown in Table 2. As can be seen, CNER jet fuel is superior in many performance criteria.

[0073] [Table 2]

[0074] In an autothermal reformer (ATR), the ATR hydrocarbon feed contains CO, H2, and C1-C4 hydrocarbons. CO and H2 are obtained by autothermal reforming of natural gas, which is primarily CH4.

[0075] In some embodiments, the ATR hydrocarbon feed contains unreacted CO, H2, and C1-C4 hydrocarbons. In some cases, the feed also contains natural gas. Natural gas contains methane and may contain CO2 and light hydrocarbons. In some embodiments, the fuels and chemicals produced may not be zero-carbon fuels but still have improved carbon intensity over conventional fuels and chemicals. The ATR feed can be converted to synthesis gas (containing a large proportion of hydrogen). This can reduce the amount of water that needs to be electrolyzed to produce hydrogen, thereby reducing the size of the electrolyzer. This can be more economical in producing low-carbon fuels and chemicals. In the ATR hydrocarbon feed, the ratio of natural gas to unreacted carbon monoxide, hydrogen, and C1-C4 hydrocarbons of the LFP can be less than 2.0 kg / kg. In some cases, it can be less than 1.25 kg / kg.

[0076] ATR can produce a carbon monoxide-rich product. CO2 in the product gas can be 0 mol% to 10 mol%. The ATR oxidant feed can contain steam and oxygen, where the oxygen is produced by electrolysis of water. The ATR oxidant feed and ATR hydrocarbon feed are preheated and then reacted in an ATR burner, where the oxidant and hydrocarbons are partially oxidized at temperatures of 2000°C to 3000°C. The ATR reactor can be divided into multiple zones. The combustion zone (or burner) is where at least a portion of the ATR hydrocarbon feed is completely combusted to water and CO2. The thermal zone is where thermal reactions occur. Further conversion occurs in the thermal zone through homogeneous gas-phase reactions, which can be slower than combustion reactions such as CO oxidation and pyrolysis of higher hydrocarbons. The primary overall reactions in the thermal zone include homogeneous gas-phase reforming reactions of steam with hydrocarbons and shift reactions. In the catalytic zone, final conversion of hydrocarbons occurs via heterogeneous catalytic reactions, including steam methane reforming and water-gas shift reactions. The resulting ATR product gas can have a composition close to the predicted thermodynamic equilibrium composition. The actual ATR product gas composition can be the same as the thermodynamic equilibrium composition within a difference of 5°C to 70°C. This is the so-called equilibrium approach temperature. To minimize the amount of CO2 produced in the ATR, the amount of steam in the ATR oxidant feed is kept low. This results in a low-soot ATR product gas that is close to the predicted equilibrium composition. Typically, the total steam to carbon ratio (mol / mol) in this combined ATR feed (oxidant + hydrocarbon) is 0.4 to 1.0, optimally 0.55 to 0.65.

[0077] The ATR product can exit the ATR catalyst zone at temperatures in excess of 800° C. It can be cooled to a lower temperature through a waste heat boiler where heat is transferred to generate steam that can be used to generate electricity, similar to the lower pressure steam produced in the LFP reactor.

[0078] ATR catalysts suitable for the reaction in the catalytic zone are typically nickel-based. The novel solid solution catalysts described herein can be used as ATR catalysts. Other suitable ATR catalysts are nickel-supported alpha-phase alumina or magnesium alumina spinel (MgAl2O4), with or without a noble metal promoter. Noble metal promoters can include gold, platinum, rhenium, or ruthenium. Spinels can have higher melting points, higher thermal strength, and greater stability than alumina-based catalysts.

[0079] The ATR product can be blended with the RWGS product and used as the LFP reactor feed, resulting in a reduction of the feedstock CO2 to C5-C 24 Availability for conversion to hydrocarbon products may be increased.

[0080] In some embodiments, the LFP product gas is not suitable for direct feed to the ATR and must be pre-reformed. In such cases, the LFP product gas, containing unreacted carbon monoxide, hydrogen, C1-C4 hydrocarbons, and CO2, comprises the pre-reformed hydrocarbon feed gas. The abundance of higher hydrocarbons and carbon oxides in this stream may prevent direct use as the ATR hydrocarbon feed and require the use of a pre-reformer. The pre-reformer is generally an adiabatic reactor. The adiabatic pre-reformer converts the higher hydrocarbons in the pre-reformer feed to a mixture of methane, steam, carbon oxides, and hydrogen that is suitable as the ATR hydrocarbon feed. One advantage of using a pre-reformer is that it allows for pre-heating of the higher ATR hydrocarbon feed, which may reduce the oxygen used in the ATR. The resulting integrated process, as described above, converts CO2 into C5-C hydrocarbons suitable for use as fuels or chemicals. 24 High conversions to hydrocarbon products are obtained.

[0081] In some embodiments, it is an autothermal reforming (ATR) process that converts tail gas (and potentially other hydrocarbon feedstocks) from the fuel / chemical production stage and oxygen from the electrolysis process into additional synthesis gas. In some embodiments, it is the use of thermal energy from the ATR process to operate a (CO)RWGS (hydrogenation) catalyst. In some embodiments, it is the separation and conversion of CO from the ATR process into additional synthesis gas using a CO hydrogenation catalyst. In some embodiments, it is the RWGS catalyst, reactor, and process that converts CO and hydrogen into synthesis gas, and the RWGS operation is operated at a pressure close to that of the fuel / chemical production process where the synthesis gas is converted into fuels or chemicals. In some cases, these fuels or chemicals are paraffinic or olefinic hydrocarbon liquids, the majority of which are C5-C 24 is in the range.

[0082] The systems and methods described herein may utilize sensors, which may be flow sensors, sensors that detect the chemical composition of a process stream, temperature sensors, pressure sensors, or sensors coupled to the price or availability of a process input such as CO or electricity.

[0083] In one aspect, the systems and methods described herein efficiently capture and utilize CO2 to convert it into useful products, such as fuels (e.g., diesel fuel, gasoline, gasoline blend stock, jet fuel, kerosene, etc.) and chemicals (e.g., solvents, olefins, alcohols, aromatics, lubricants, waxes, ammonia, methanol, etc.), which can replace fuels and chemicals produced from fossil resources such as petroleum and natural gas, thereby reducing the total amount of CO2 emitted into the atmosphere. Zero-carbon, low-carbon, and ultra-low-carbon fuels and chemicals minimize the amount of fossil fuels burned in the process. In some cases, heating of the feed to the integrated process is achieved by indirect means (e.g., cross-flow heat exchangers) or electrical heating supplied from zero-carbon or renewable energy sources such as wind, solar, geothermal, and nuclear power. [Example]

[0084] The following are certain embodiments of a process for converting CO2, water, and renewable electricity into carbon-negative, high-quality fuels and chemicals:

[0085] Example 1 In this previously performed example, water was supplied to an electrolysis system powered by renewable electricity, which produced hydrogen and oxygen. CO was captured from a supply source. This CO was mixed with hydrogen from the electrolysis system to form a stream (reverse water gas shift feed, or "RWGS" feed), which was heated and supplied to an RWGS reactor vessel containing RWGS catalyst. The RWGS reactor converted the feed to an RWGS product gas containing CO, H, unreacted CO, and HO. Figure 6 shows a typical e-fuel facility. Water (1) and electricity (2) were used in the electrolysis.

[0086] A summary of the major process streams is provided in Table 3. Stream numbers are as shown in Figure 6. This is an example of a carbon-neutral e-fuel facility producing carbon-neutral e-fuel, previously shown in Figure 3 as Unit 3.1.

[0087] [Table 3]

[0088] As shown in Figure 3, the base case corresponding to a carbon-neutral e-fuel facility has carbon inputs and outputs as shown in Table 4.

[0089] [Table 4]

[0090] The carbon intensity of this process is 0 g CO2e / MJ. This assumption is based on a life cycle analysis of the process and does not include the transportation of fuel to distribution markets. Typically, the latter adds 0.5–5 g CO2e / MJ, depending on the transportation method used. Other assumptions include: all anthropogenic CO2 thus has a negative carbon intensity (avoided emissions); all hydrogen is produced from renewable energy sources and therefore has no associated carbon intensity; and all carbon that enters the process and is not purged or captured in canisters by wastewater treatment is emitted as fuel and then combusted. Although CO2 is emitted to the atmosphere, it is counted as a net balance because the source is anthropogenic and emissions were considered avoided on entry. All materials sent to purge are oxidized and emitted as CO2. Also, transportation of fuel to distribution markets is not considered.

[0091] Example 2 The above process (Example 1) was performed using renewable natural gas, which has a negative carbon intensity associated with it. In this previously performed example, the carbon intensity of the fuel produced by the process was -3.33 g CO2e / MJ. This was an example of carbon-negative e-fuel refining (CNER).

[0092] [Table 5]

[0093] Assumptions include: replacing all electric heating with RNG-fired direct-fired heaters; all carbon that enters the process and is not purged or captured in canisters by wastewater treatment is emitted as fuel and then combusted. CO2 is emitted to the atmosphere but is counted as a net balance because the source is anthropogenic and emissions were considered avoided on entry. CARB Standard: Pathway T2N-1019.

[0094] Example 3 The above process (Example 1) was carried out using excess O2 to replace O2 used in another process. Oxygen is one of the most important technological gases. Oxygen finds many uses in glassmaking, steelmaking, mining, wastewater treatment plants, and medical applications. Typically, industrial oxygen is produced using air separation units (ASUs), pressure swing adsorption (PSA), and vacuum pressure swing adsorption (VPSA). These methods rely on cryogenic, membrane, or adsorption processes. Typical energy consumption in cryogenic O2 units exceeds 200 kWh per ton of O2 produced. Using stream 6 instead of carbon-intensive conventional O2 production results in an e-fuel produced by this process with a carbon intensity of -4.57 g CO2e / MJ. This is an example of carbon-negative e-fuel refining (CNER).

[0095] [Table 6]

[0096] Assumptions include: all carbon that enters the process and is not purged or captured in canisters by wastewater treatment is emitted as fuel and then combusted; CO2 is emitted to the atmosphere but is counted as a net balance because the source is anthropogenic and emissions were considered avoided on entry; and clean oxygen not consumed by the hydrocarbon process can be exported and sold on the market, replacing fossil-based oxygen.

[0097] Example 4 The above process (Example 1) was carried out where the naphtha by-product was sequestered into a product that did not produce CO upon combustion, where the carbon intensity of the process was -19.43 g COe / MJ. This is an example of carbon-negative e-fuel refining (CNER).

[0098] [Table 7]

[0099] Assumptions include: all carbon that enters the process and is not purged or captured in a canister by wastewater treatment is emitted as fuel and then combusted; CO2 is emitted to the atmosphere but is counted as a net balance because the source is anthropogenic and emissions were considered avoided on entry; carbon content in the naphtha product stream for the 2500 bbl / day facility in Model 207.08; mass of input CO2 sent to naphtha based on carbon content; and percentage of input CO2 ultimately found in naphtha based on carbon tracking.

[0100] Example 5 In this example, the base case (Example 1) was modified as follows. 1. RNG is used as fuel gas to the heater, but the CO2 produced by combustion is captured and sent to CO2 sequestration. 2. 10% of the CO2 feed to the facility will be sent to CO2 sequestration. 3. 10% of the hydrogen produced by the electrolyzer will be sold as product, replacing the hydrogen produced by steam methane reforming, which will offset 9.33 kg CO2 / kg H2 (Sun et al, 2019). 4. Oxygen is sold to replace O2 produced from fossil energy. 5. Naphtha is sold as non-combustible.

[0101] The WWGC for the e-fuel in this example is -68.10 g CO2 / MJ.

[0102] [Table 8]

[0103] The above-described embodiments may be implemented in any of numerous ways. For example, they may be implemented using hardware, software, or a combination thereof. If implemented in software, the software code may be executed on any suitable processor or collection of processors, whether located on a single computer or distributed across multiple computers. It should be appreciated that any component or collection of components that perform the functions described above may be generally considered to be one or more controllers that control the functions described above. The controller or controllers may be implemented in numerous ways, such as using dedicated hardware or one or more processors programmed using microcode or software to perform the functions described above.

[0104] In this regard, it should be understood that one implementation of embodiments of the present invention includes at least one non-transitory computer-readable storage medium (e.g., computer memory, portable memory, compact disc, etc.) encoded with a computer program (i.e., a plurality of instructions), which, when executed on a processor, performs the functions described above in embodiments of the present invention. The computer-readable storage medium may be portable such that the program stored on the storage medium may be loaded onto any computer resource to implement the aspects of the present invention discussed herein. Furthermore, it should be recognized that reference to a computer program that, when executed, performs the functions described above is not limited to an application program running on a host computer. Rather, the term computer program is used herein in a generic sense, i.e., to refer to any type of computer code (e.g., software or microcode) that may be employed to program a processor to implement the above-described aspects of the present invention.

[0105] Various aspects of the invention may be used alone or in combination, and may be used in various arrangements not specifically discussed in the embodiments of the foregoing description, and therefore are not limited in their application to the details and arrangements of components set forth in the foregoing description or illustrated in the drawings. For example, aspects described in one embodiment may be combined in any manner with aspects described in other embodiments.

[0106] Also, embodiments of the invention may be implemented as one or more methods, and examples of such are provided. The acts performed as part of the method(s) may be ordered in any suitable manner. Thus, even if an example embodiment shows acts as sequential, embodiments may be constructed in which acts are performed in an order different from that shown, including performing some acts simultaneously.

[0107] The use of ordinal numbers such as "first," "second," and "third" to modify claim elements in the claims does not, by itself, imply a priority, precedence, or order of one claim element relative to other claim elements, or the chronological order in which acts of a method are performed. Such terms are used merely as labels to distinguish a claim element having a certain name from another element having the same name (except for the use of the ordinal number).

[0108] The phraseology and terminology used herein are for purposes of description and should not be regarded as limiting. The use of "including," "comprising," "having," "containing," "involving," and variations thereof, is meant to encompass the items listed thereafter and additional items.

[0109] While several embodiments of the present invention have been described in detail, various modifications and improvements will readily occur to those skilled in the art. Such modifications and improvements are intended to be within the spirit and scope of the present invention. Accordingly, the foregoing description is by way of example only and is not intended to be limiting. The present invention is limited only as defined by the following claims and equivalents thereof.

[0110] It should be recognized that all combinations of the foregoing concepts, and additional concepts described in more detail below, provided that such concepts are not mutually inconsistent, are contemplated as being part of the inventive subject matter disclosed herein. In particular, all combinations of subject matter within this disclosure are contemplated as being part of the inventive subject matter disclosed herein.

[0111] Further aspects, embodiments, and advantages of these exemplary aspects and embodiments are described in detail below. Furthermore, it should be understood that all of the foregoing information and the following detailed description are merely exemplary of various aspects and are intended to provide an overview or framework for understanding the nature and characteristics of the claimed aspects and embodiments. Any embodiment disclosed herein may be combined with other embodiments in any manner consistent with at least one of the objectives, goals, and requirements disclosed herein, and references to "an embodiment," "some embodiments," "alternative embodiments," "various embodiments," "one embodiment," "at least one embodiment," "this embodiment and other embodiments," etc. are not necessarily mutually exclusive and are intended to indicate that a particular feature, structure, or characteristic described in connection with an embodiment may be included in at least one embodiment. Appearances of such terms herein do not necessarily all refer to the same embodiment.

[0112] References Argonne National Laboratory: GREET Model, ANL, Argonne, IL (2021). www.greet.es.anl.gov Budina, S.: Going carbon negative: what are the technology options, International Energy Administration (Jan. 2020). California Air Resources Board, LCFS pathway certified carbon intensities (2022). www.ww2.arb.ca.gov / resources / documents / lcfs-pathway-certified-carbon-intensities. IPCC: Synthesis reports I, II and III on climate change 2022, Intergovernmental Panel on Climate Change, Sixth Assessment Report (AR6) (April 5, 2022). National Academies of Sciences, Engineering, and Medicine: Gaseous carbon waste streams utilization: status and research needs, Chapter 4: Chemical utilization of CO2into chemicals and fuels, The National Academies Press pp. 63-97 (2019). https: / / doi.org / 10.17226 / 25232. Ransom, C., Rvalitera, N.: State of the global climate 2021, World Meteorological Organization (2021). www.public.wmo.int / en / our-mandate / climate / wmo-statement-state-of-global-climate Schuetzle, D.: Historical and predicted global climate changes and some potential accelerated climate moderation approaches, Global Climate Action Summit, San Francisco, CA (Sept. 10-14, 2018) and the Under2 Coalition, ResearchGate, 1-42 (2020). www.researchgate.net U.S. Energy Information Administration (EIA): U.S. energy related CO2emissions (Dec. 22, 2021). www.eia.gov. / environment / emissions / carbon

Claims

1. A fuel, the fuel comprising: ５ -C ２４ and the fuel contains hydrocarbons, the fuel having a well-to-wheel greenhouse gas content of -68.1g CO ２ e / MJ ~ 0g CO ２ e / MJ, a sulfur content of 0 ppm to 1.0 ppm, and an aromaticity of 0 to 1.0 vol.%.

2. 10. The fuel of claim 1, wherein the fuel is a diesel fuel.

3. The fuel of claim 1 , wherein the fuel is jet fuel.

4. 3. The fuel of claim 2, wherein the ash content of the fuel is in the range of 0 to 0.01% by mass.

5. 4. The fuel of claim 3, wherein the fuel has an acidity of between 0 mg KOH / g and 0.02 mg KOH / g.

6. 3. The fuel of claim 2, wherein the fuel has a sulfur content of 0 ppm to 1.0 ppm.

7. 4. The fuel of claim 3, wherein the fuel has a sulfur content of 0 ppm to 1.0 ppm.

8. 3. The fuel of claim 2, wherein the fuel has a copper strip corrosion rating of 1a.

9. 4. The fuel of claim 3, wherein the fuel has a copper strip corrosion rating of 1a.

10. 3. The fuel of claim 2, wherein the fuel has an ash content of 0 to 0.01 by weight, a sulfur content of 0 ppm to 1.0 ppm, and a copper strip corrosion rating of 1a.

11. 4. The fuel of claim 3, wherein the fuel has an acidity of 0 mg KOH / g to 0.02 mg KOH / g, a sulfur content of 0 ppm to 1.0 ppm, and a copper strip corrosion rating of 1a.

12. 1. A method of producing a fuel, the fuel having a well-to-wheel greenhouse gas content of less than zero, the method comprising: a.CO ２ obtaining a raw material comprising: b. Electrolyzing water using renewable electricity, thereby producing H ２ and O ２ generating a c. The H ２ and the CO ２ catalytically reacting a feedstock comprising: d. reacting said synthesis gas with one or more catalysts, thereby producing fuel-related products, said fuel-related products being selected from the group consisting of C ５ -C ２４ comprising a hydrocarbon; e. C ５ -C ２４ capturing hydrocarbons, the hydrocarbons having a sulfur content of 0 ppm to 1.0 ppm, an aromaticity of 0 to 1.0 vol.%, and a well-to-wheel greenhouse gas content of less than zero; thereby producing a fuel having a well-to-wheel gas content of less than zero.

13. The method of claim 12 wherein the fuel is diesel fuel.

14. The method of claim 12 , wherein the fuel is jet fuel.

15. H ２ and the CO ２ 14. The method of claim 13, wherein a feedstock comprising a carbon-containing gas is reacted with the catalyst, thereby producing synthesis gas.

16. H ２ and the CO ２ 15. The method of claim 14, wherein a feedstock comprising a carbon-containing gas is reacted with the catalyst, thereby producing synthesis gas.

17. The method of claim 13 , wherein the fuel-related products further include one or more non-combustible products.

18. The method of claim 14 , wherein the fuel-related products further include one or more non-combustible products.

19. The CO ２ CO in the feedstock containing ２ The method of claim 13 , wherein a portion of

20. The CO ２ CO in the feedstock containing ２ The method of claim 14 , wherein a portion of

21. 16. The method of claim 15, wherein the carbon-containing gas comprises renewable natural gas, flare gas, or landfill gas.

22. 17. The method of claim 16, wherein the carbon-containing gas comprises renewable natural gas, flare gas, or landfill gas.

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