Patent Application
20250093023
This disclosure relates to the production of synthetic hydrocarbons. More particularly, the disclosure relates to synthesis of sustainable liquid hydrocarbons from sea water, renewable electricity, and carbon dioxide. Even more particularly, the disclosure relates to a system and process using an oxygen fired heater for improved efficiency and flexibility.
The vast majority of vehicles worldwide are powered by hydrocarbon fuels, including automobiles, ships, aircraft, and trains. This demand for hydrocarbon fuels is supplied by a global infrastructure of production and distribution. Global efforts to reduce carbon dioxide emissions associated with hydrocarbon fuel consumption have included combinations of electrolysis, autothermal reforming, and Fischer-Tropsch technologies, sometimes in combination with electricity from renewable sources, to synthesize hydrocarbon fuels. These technologies are often implemented in ways that reduce carbon dioxide (CO2) to the environment with a goal of creating a CO2 neutral production and use cycle.
However, operation of implementations of these technologies still requires use of electrical power. With more renewable energy coming on stream on the electricity grid, the stability of the grid is becoming more critical. Renewable energy production fluctuates with wind/solar conditions and at the same time grid demand fluctuates depending on the time of the day and/or time of year. A facility for production of synthetic fuels is a relatively large demand center on the electrical grid servicing such a facility.
There is a need to provide improved processes to produce hydrocarbon fuels sustainably, wherein such processes have a higher overall energy efficiency, a net lower carbon footprint and/or operate to help stabilize the electrical grid. Ideally, such processes would be highly flexible and could be implemented with commonly used equipment and familiar techniques to produce a wide variety of products.
In some embodiments, a process for producing one or more synthetic hydrocarbon products is implemented in an eFuels plant, comprising a hydrocarbon synthesis (HS) system and a renewable feed and carbon/energy recovery (RFCER) system. The RFCER system comprises a feed system producing hydrogen and carbon dioxide feed streams to the HS system. In some embodiments, the eFuels plant further comprises one or more of a thermal desalination unit, a direct air capture unit, a hydrogen storage system (and optionally a hydrogen compression system), a carbon dioxide compression and storage system, an oxygen-fired heater, a steam turbine generator, an anaerobic biodigestion unit, and an aerobic biodigestion unit. In some embodiments, the eFuels plant comprises an anaerobic biodigestion unit and an aerobic biodigestion unit. The feed system and the other processing units of the RFCER system are integrated with processes within the HS system and with each other to minimize the carbon footprint of the eFuels plant, to maximize energy efficiency of the eFuels plant (i.e., minimize the amount of energy required from external sources for operation of the eFuels plant), to maximize hydrogen and carbon efficiency of the eFuels plant, to support electrical grid frequency stability, and to maximize operating flexibility to permit continued operations in spite of fluctuations in power available from the electrical grid supplying power to the eFuels plant.
In some embodiments, a fired heater comprises one or more burners, a radiant section, a convection section, and a carbon dioxide recovery section. The one or more burners are suitable for accepting feeds comprising a hydrocarbon stream, an oxygen stream, and a diluent gas stream and producing combustion products comprising heat, carbon dioxide, and water. The radiant section comprises a firebox and a radiant coil within the firebox. The firebox is suitable for accepting the combustion products. The radiant coil absorbs a first portion of the heat to produce first cooled combustion products. The convection section comprises a convection coil and a convection inter-tube space defined by the outer surface of the convection coil. The convection inter-tube space is suitable for accepting the first cooled combustion products to produce second cooled combustion products. The carbon dioxide recovery section comprises a condensing coil and a condensing inter-tube space defined by the outer surface of the condensing coil. The condensing inter-tube space is suitable for accepting the second cooled combustion products to produce third cooled products comprising a non-condensables stream, comprising carbon dioxide, and a water stream.
In some embodiments, the diluent gas stream to the one or more burners comprises a portion of the carbon dioxide product stream from the carbon dioxide recovery section.
In some embodiments, the hydrocarbon stream is free of any components derived from petroleum.
In some embodiments, the hydrocarbon stream comprises a hydrocarbon synthesis (HS) system purge gas, a HS system off gas, a synthetic liquid gas (SLG), a synthetic light distillate (SLD), or a combination thereof.
The above paragraphs present a summary of the presently disclosed subject matter in order to provide a basic understanding of some aspects thereof. The summary is not an exhaustive overview, nor is it intended to identify key or critical elements to delineate the scope of the subject matter claimed below. Its sole purpose is to present some concepts in a simplified form as a prelude to the more detailed description set forth below.
The claimed subject matter may be understood by reference to the following description taken in conjunction with the accompanying drawings, in which like reference numerals identify like elements, equipment to which reference is made is defined in the description, and in which:
While the disclosed process and system are susceptible to various modifications and alternative forms, the drawings illustrate specific embodiments herein described in detail by way of example. It should be understood, however, that the description herein of specific embodiments is not intended to limit the invention to the particular forms disclosed, but on the contrary, the intention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the invention as defined by the appended claims.
Illustrative embodiments of the subject matter claimed below will now be disclosed. In the interest of clarity, some features of some actual implementations may not be described in this specification. It will be appreciated that in the development of any such actual embodiments, numerous implementation-specific decisions must be made to achieve the developer's specific goals, such as compliance with system-related and business-related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort, even if complex and time-consuming, would be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure.
The words and phrases used herein should be understood and interpreted to have a meaning consistent with the understanding of those words and phrases by those skilled in the relevant art. No special definition of a term or phrase, i.e., a definition that is different from the ordinary and customary meaning as understood by those skilled in the art, is intended to be implied by consistent usage of the term or phrase herein. To the extent that a term or phrase is intended to have a special meaning, i.e., a meaning other than the broadest meaning understood by skilled artisans, such a special or clarifying definition will be expressly set forth in the specification in a definitional manner that provides the special or clarifying definition for the term or phrase. It must also be noted that, as used in the specification and the appended claims, the singular forms “a,” “an,” and “the” include plural references unless otherwise specified.
For example, the following discussion contains a non-exhaustive list of definitions of several specific terms used in this disclosure (other terms may be defined or clarified in a definitional manner elsewhere herein). These definitions are intended to clarify the meanings of the terms used herein. It is believed that the terms are used in a manner consistent with their ordinary meaning, but the definitions are nonetheless specified here for clarity.
As used herein, “eFuels,” means synthetic hydrocarbon products produced as disclosed herein, including, but not limited to one or more of synthetic liquefied gas (SLG), a synthetic light distillate (SLD), a synthetic middle distillate (SMD), and a synthetic heavy distillate (SHD). eFuels are produced using electricity, carbon dioxide and water feed streams. In some embodiments, eFuels are produced using electricity generated without the use of a petroleum feedstock to the eFuels plant. In some embodiments, the carbon dioxide is derived without the use of petroleum feedstock. In some embodiments, the electricity originates from renewable sources.
As used herein, “HS system off gas” means byproducts and/or impurities separated from light overhead streams from one or more process units in the HS system. In some embodiments, the one or more petrochemical process units comprise a Fischer Tropsch unit, a hydrocracker unit, a distillation unit, or a combination thereof. In some embodiments, HS system off gas comprises primarily unreacted syngas (CO and H2), light hydrocarbons (such as methane, ethane, and propane), CO2, water vapor, or a combination thereof.
As used herein, “HS system purge” means the intentional flow of gas withdrawn from a system to prevent the accumulation of unwanted gases and/or impurities to prevent concentrations of such gases and/or impurities that could lead to inefficiencies, contamination, and/or hazardous conditions in one or more petrochemical process units. In some embodiments, the one or more process units comprise a Fischer Tropsch unit. In some embodiments, HS system purge comprises a purge stream from a Fischer Tropsch unit. In some embodiments, the purge stream comprises inert gases (e.g., nitrogen and CO2) and light hydrocarbons (C1-C4 hydrocarbons) that have built up in the system, as well as trace amounts of CO and H2, or a combination thereof.
As used herein, “petroleum” means crude oil or a fossil fuel, which is a liquid mixture of hydrocarbons present in certain rock strata that can be extracted and refined to produce fuels including gasoline, kerosene, and diesel oil.
As used herein, “synthetic heavy distillate (SHD)” means a synthetic hydrocarbon product produced as disclosed herein and not containing any molecules derived from petroleum. SHD consists of hydrocarbons having carbon numbers predominantly in the range of C14 through C20 and a boiling in the range of approximately 150° C. to 360° C. and is analogous to diesel produced from a petroleum feedstock.
As used herein, “synthetic light distillate (SLD)” means a synthetic hydrocarbon product produced as disclosed herein and not containing any molecules derived from petroleum. SLD consists of hydrocarbons having carbon numbers predominantly in the range of C5 through C10 and a boiling in the range of approximately 20° C. to 200° C. and is analogous to naphtha produced from a petroleum feedstock.
As used herein, “synthetic liquefied gas (SLG)” means a synthetic hydrocarbon product produced as disclosed herein and not containing any molecules derived from petroleum. SLG consists primarily of propane, butane, propylene, butylene, and isobutane and is analogous to liquefied petroleum gas (LPG) produced from a petroleum feedstock.
As used herein, “synthetic middle distillate (SMD)” means a synthetic hydrocarbon product produced as disclosed herein and not containing any molecules derived from petroleum. SMD consists of hydrocarbons having carbon numbers predominantly in the range of C10 through C16 and a boiling in the range of approximately 140° C. to 300° C. and is analogous to kerosene produced from a petroleum feedstock.
The following abbreviations are used herein:
It is noted that in this disclosure and particularly in the claims and/or paragraphs, terms such as “comprises”, “comprised”, “comprising” and the like can have the meaning attributed to it in U.S. patent law; e.g., they can mean “includes”, “included”, “including”, and the like; and that terms such as “consisting essentially of” and “consists essentially of” have the meaning ascribed to them in U.S. patent law, e.g., they allow for elements not explicitly recited, but exclude elements that are found in the prior art or that affect a basic or novel characteristic of the disclosure.
The eFuels plant disclosed herein comprises a hydrocarbon synthesis (HS) system and a renewable feed and carbon/energy recovery (RFCER) system. In some embodiments, the HS system comprises a reverse water-gas shift (RWGS) reactor to convert hydrogen and carbon dioxide feed stream to syngas, comprising hydrogen and carbon monoxide. In some embodiments, syngas from the RWGS is fed to a Fischer-Tropsch (FT) reactor to produce FT hydrocarbon products, including one or more of FT wax, FT condensate, and FT tail gas. In some embodiments, FT tail gas is recycled as additional feed to the FT reactor and/or the RWGS reactor. In some embodiments, FT wax, FT condensate, and a portion of the hydrogen produced in the electrolysis unit are fed to a hydrocracking reactor to produce a hydrocarbon product. In some embodiments, the hydrocarbon product is then introduced to one or more distillation columns to separate the hydrocarbon product into one or more of a synthetic liquefied gas (SLG), a synthetic light distillate (SLD), a synthetic middle distillate (SMD), and a synthetic heavy distillate (SHD).
In some embodiments, the process implemented in the HS system comprises introducing electricity and the hydrogen stream and carbon dioxide stream produced in the RFCER system to a reverse water-gas shift (RWGS) reactor under reaction conditions sufficient to produce a RWGS product stream comprising syngas. In some embodiments, syngas can be produced in a syngas production process, such as, but not limited to, through reforming (e.g., steam and/or auto-thermal) and/or (partial) gasification of suitable feedstocks including biogas, pipeline natural gas, and biomass. In some embodiments, gasification includes process using useful feedstock, including but not limited to biomass and biomass derived feedstocks.
In some embodiments, the electricity consumed in the RWGS reaction comprises electricity from the electrical power grid supporting the eFuels plant and/or electricity delivered from the RFCER system. In some embodiments, all or a majority of the power from the electrical grid is derived from renewable sources, such as, but not limited to, solar energy, wind energy, hydroelectric energy, geothermal energy, biomass combustion, nuclear energy, tidal energy, wave energy, hydrogen fuel cells, or a combination thereof. Further, in some embodiments, synthetic hydrocarbon fuels produced by the process disclosed herein are inventoried for on-premise generation of electricity to permit continued operation of the process disclosed herein in spite of fluctuations in power available from the electrical grid and/or the RFCER system. Maximizing renewable energy sources used to power water electrolysis results in minimizing the CO2 footprint and/or carbon intensity attributable to hydrogen production since fossil fuels are not used or are used only minimally in its production.
Reaction conditions with respect to RWGS reactants include, but are not limited to, pressure, temperature, and composition of reactants.
Reaction conditions within the RWGS reactor include, but are not limited to, pressure, temperature, and specific energy consumption sufficient to produce a syngas product stream, comprising carbon monoxide and hydrogen in relative amounts and at conditions suitable for use as a feed stream to a FT process.
RWGS reactions and reactors useful in the process disclosed herein are described in more detail in U.S. Pub. App. Nos. 2018/0243711A1, 2020/0317514A1, 2021/0130965A1, 2021/0340015A1, and 2022/0410109A1; PCT Pub. Nos. WO 2022/112309A1 and WO 2022/253965A1; and Ind. Eng. Chem. Res. 2022, 61, 34, 12857-12865, Pub. Aug. 19, 2022, https://doi.org/10.1021/acs.iecr.2c00305, Copyright 2022 The Authors, published by American Chemical Society; Bown, R. M., Joyce, M., Zhang, Q., Reina, T. R. and Duyar, M. S. (2021), Identifying Commercial Opportunities for the Reverse Water Gas Shift Reaction. Energy Technol., 9: 2100554. https://doi.org/10.1002/ente.202100554; and Zhu, M., Ge, Q. & Zhu, X. Catalytic Reduction of CO2 to CO via Reverse Water Gas Shift Reaction: Recent Advances in the Design of Active and Selective Supported Metal Catalysts. Trans. Tianjin Univ. 26, 172-187 (2020), https://doi.org/10.1007/s12209-020-00246-8, all of which are fully incorporated by reference herein for all jurisdictions in which such incorporation is permitted.
The process disclosed herein is primarily directed to production of synthetic hydrocarbon products through reacting syngas in a FT reaction followed by hydrocracking of the FT product. Alternatively, syngas can be used as a source of hydrogen or as a fuel. Chemical uses include the production of methanol, which is a precursor to acetic acid and many acetates. Liquid fuels, waxes, fine chemicals, and lubricants can be derived from syngas via the FT process and previously by the Mobil methanol to gasoline process. Ammonia can be produced from syngas by the Haber process, which converts atmospheric nitrogen (N2) into ammonia, which is used as a fertilizer. Syngas may further be converted to oxo alcohols via an intermediate aldehyde. Furthermore, the syngas produced is converted to methanol that is used in ExxonMobil's gas to olefins process.
In some embodiments, the process implemented in the HS system further comprises adding at least a portion of the syngas stream to a FT reactor under reaction conditions sufficient to form a FT tail gas stream, a FT condensate stream, and a FT wax stream, wherein the FT unit includes common equipment associated with FT reactors, such as heat exchangers, decanters, pumps, compressors, valves, reflux loops, and the like. The FT tail gas can be further processed and recycled as additional feed to the RWGS reactor or the FT reactor. The FT condensate stream, the FT wax stream, and hydrogen are optionally introduced as feed to a hydrocracking and/or (mild) hydroisomerization reactor.
Fischer-Tropsch technology, reactions and reactors useful in the process disclosed herein are described in more detail in U.S. Pub. No. 2022/0081292A1; U.S. Pat. Nos. 9,752,080, 8,889,746, 6,872,753, and 9,890,041; PCT Pub. Nos. WO 2023/064089A1. WO 2022/038230A1, WO 2023/060707A1, WO 2023/064150A1, WO 2022/053260A1, WO 2022/049148A1, WO 2021/180805A1, WO 2021/110754A1, WO 2022/171643A1, and WO 2022/079002A1; and Michela Martinelli, Muthu Kumaran Gnanamani, Steve LeViness, Gary Jacobs, Wilson D. Shafer, An overview of Fischer-Tropsch Synthesis: XtL processes, catalysts and reactors, Applied Catalysis A: General, Volume 608, 2020, 117740, ISSN 0926-860X, https://doi.org/10.1016/j.apcata.2020.117740; Marco Marchese, Emanuele Giglio, Massimo Santarelli, Andrea Lanzini, Energy performance of Power-to-Liquid applications integrating biogas upgrading, reverse water gas shift, solid oxide electrolysis and Fischer-Tropsch technologies, Energy Conversion and Management: X, Volume 6, 2020, 100041, ISSN 2590-1745, https://doi.org/10.1016/j.ecmx.2020.100041;. Dieterich, Vincent and Buttler, Alexander and Hanel, Andreas and Spliethoff, Hartmut and Fendt, Sebastian, Power-to-liquid via synthesis of methanol, DME or Fischer-Tropsch-fuels: a review, Energy Environ. Sci., 2020, vol. 13, issue 10, pp. 3207-3252, The Royal Society of Chemistry, http://dx.doi.org/10.1039/DOEE01187H, all of which are fully incorporated by reference herein for all jurisdictions in which such incorporation is permitted.
In some embodiments, the process implemented in the HS system comprises adding a portion of the hydrogen stream produced in the electrolysis unit, the FT condensate, and the FT wax to a hydrocracking and/or (mild) hydroisomerization reactor under reaction conditions sufficient to produce a hydrocracking product comprising a synthetic hydrocarbon stream, wherein the hydrocracking unit includes common equipment associated with hydrocracking reactors, such as heat exchangers, decanters, pumps, compressors, valves, reflux loops, and the like.
Hydrocracking reactions and reactors useful in the process disclosed herein are described in more detail in U.S. Publication No. 202139562A1; U.S. Pat. Nos. 3,268.436, 4,618,412, 4,935.120, 5,378,348, 6,583,186, 10,487,273, and 11,485,918; PCT Pub. Nos. WO 2022/034181A1, WO 2021/204621A1, and WO 2023/001695A1; and Hydrocracking of Fischer-Tropsch Paraffin Mixtures over Strong Acid Bifunctional Catalysts to Engine Fuels, Tomasek, Lonyi, Valyon, Wollmann, & Hancsók, 2020/10/20, 2020, doi: 10.1021/acsomega.0c02711, ACS Omega, 26413, 26420, vol. 5, issue 41, American Chemical Society, doi: 10.1021/acsomega.0c02711; Pleyer, O.; Vrtiška, D.; Straka, P.; Vráblik, A.; Jenčik, J.; Šimãček, P. Hydrocracking of a Heavy Vacuum Gas Oil with Fischer-Tropsch Wax. Energies 2020, 13, 5497, https://doi.org/10.3390/en13205497; and Pleyer, Olga & Petr, Straka & Vrtiška, Dan & Hájek, Jiri & Čern{tilde over (y)}, Radek. (2020). Hydrocracking of Fischer-Tropsch Wax. Paliva. 26-33. 10.35933/paliva.2020.02.01, all of which are fully incorporated by reference herein for all jurisdictions in which such incorporation is permitted.
In some embodiments, the process implemented in the HS system further comprises feeding a synthetic hydrocarbon stream to one or more distillation columns to form one or more synthetic hydrocarbon products. The one or more distillation columns include common equipment associated with distillation columns, such as heat exchangers, decanters, pumps, compressors, valves, reflux loops, and the like.
Process wastewater is generated as a byproduct of the processes within the HS system, in particular the FT process. In some embodiments, the process implemented in the HS system further comprises treating process wastewater with a sour water stripper and a water degasifier.
In some embodiments, wastewater to be treated is fed to a sour water stripper. A sour wastewater feed stream is added to a sour water stripper, wherein the sour wastewater feed stream has a first content of hydrogen sulfide, a first content of ammonia, or a combination thereof. Stripping conditions are implemented in the sour water stripper. Products withdrawn from the sour water stripper comprise a sour gas stream and a stripped water stream. The sour gas comprises hydrogen sulfide, ammonia, or a combination thereof. The stripped water stream comprises a second content of hydrogen sulfide, a second content of ammonia, or a combination thereof. The second content of hydrogen sulfide is less than the first content of hydrogen sulfide, the second content of ammonia is less than the first content of ammonia, or a combination thereof.
Sour water stripping reactions and apparatuses useful in the process disclosed herein are described in more detail in U.S. Pat. Nos. 3,761,409, 4,076,621, 8,685,236, and 9,394,188; and Assessment of a Sour Water Treatment Unit Using Process Simulation, Parametric Sensitivity, and Exergy Analysis, Mestre-Escudero, R., Puerta-Arana, A., González-Delgado, A., 2020/09/22, 2020, ACS Omega, SP—23654, EP—23661, vol. 5, issue 37, American Chemical Society, doi: 10.1021/acsomega.0c02300; Umer Zahid, Techno-economic evaluation and design development of sour water stripping system in the refineries, Journal of Cleaner Production, Volume 236, 2019, 117633, ISSN 0959-6526, https://doi.org/10.1016/j.jclepro.2019.117633; Alvaro de Farias Soares, Eduardo Dellosso Penteado, Anthony Andrey Ramalho Diniz, Andrea Komesu, Influence of operational parameters in sour water stripping process in effluents treatment, Journal of Water Process Engineering, Volume 41, 2021, 102012, ISSN 2214-7144, https://doi.org/10.1016/j.jwpe.2021.102012, all of which are fully incorporated by reference herein for all jurisdictions in which such incorporation is permitted.
In some embodiments, process wastewater is further treated by feeding the stripped sour water to a water degasifier. The stripped sour water feed stream is added to a water degasifier, wherein the feed stream comprises a first content of oxygen, a first content of carbon dioxide, or a combination thereof. Degasifying conditions are implemented in the water degasifier. Products withdrawn from the water degasifier comprise a removed gas stream and a degassed water stream. The removed gas comprises oxygen, carbon dioxide, or a combination thereof. The degassed water stream comprises a second content of oxygen, a second content of carbon dioxide, or a combination thereof. The second content of oxygen is less than the first content of oxygen, the second content of carbon dioxide is less than the first content of carbon dioxide, or a combination thereof.
Water degasifying reactions and apparatuses useful in the process disclosed herein are described in more detail in U.S. Pat. Nos. 9,611,154 and 10,875,767; and Pon Saravanan, N., and Marlene J. Van Vuuren. “Process Wastewater Treatment and Management in Gas-to-Liquids Industries.” Paper presented at the SPE Oil and Gas India Conference and Exhibition, Mumbai, India, January 2010. doi: https://doi.org/10.2118/126526-MS (https://onepetro.org/SPEOGIC/proceedings-abstract/10OGIC/All-10OGIC/109660), all of which are fully incorporated by reference herein for all jurisdictions in which such incorporation is permitted.
The eFuels plant disclosed herein comprises a hydrocarbon synthesis (HS) system and a renewable feed and carbon/energy recovery (RFCER) system. In some embodiments, the RFCER system comprises an electrolysis unit, one or more of a thermal desalination unit, a direct air capture unit, a hydrogen storage system (and optionally a hydrogen compression system), a carbon dioxide compression and storage system, an oxygen-fired heater, a steam turbine generator, a heat integration system, and anaerobic and/or aerobic biodigestion units.
Electricity and a water feed stream are introduced into the electrolysis unit under reaction conditions sufficient to form a hydrogen stream and an oxygen stream. In some embodiments, the electricity consumed in the electrolysis reaction comprises electricity from the electrical power grid supporting the eFuels plant and/or electricity delivered from the RFCER system. In some embodiments, all or a majority of the power from the electrical grid is derived from renewable sources, such as, but not limited to, solar energy, wind energy, hydroelectric energy, geothermal energy, biomass combustion, nuclear energy, tidal energy, wave energy, hydrogen fuel cells, or a combination thereof. Further, in some embodiments, synthetic hydrocarbon fuels produced by the process disclosed herein are inventoried for on-premise generation of electricity to permit continued operation of the process disclosed herein in spite of fluctuations in power available from the electrical grid and/or the RFCER system. In some embodiments, water electrolysis can be powered by renewable sources. Maximizing renewable energy sources used to power water electrolysis results in minimizing the CO2 footprint and/or carbon intensity attributable to hydrogen production since fossil fuels are not used or are used only minimally in its production.
Water electrolysis is a process that uses electrical energy to split water molecules (H2O) into hydrogen gas (H2) and oxygen gas (O2) through an electrochemical reaction. The overall chemical equation for water electrolysis is: 2H2O→2H2+O2.
Water electrolysis typically involves the use of an electrolysis cell, which consists of two electrodes, an anode and a cathode, immersed in a water-based electrolyte solution. When an electric current is applied to the electrodes, the water molecules at the anode are oxidized to release oxygen gas and positively charged hydrogen ions (H+). At the cathode, the hydrogen ions and electrons (e−) combine to form hydrogen gas.
The anode and cathode are typically made of a conductive material, such as platinum or other metals that are resistant to corrosion and are separated by a membrane or diaphragm that prevents the gases from mixing.
The efficiency of water electrolysis depends on several factors, including the current density, the temperature and pressure of the electrolyte, and the quality of the electrodes and the membrane. High current density and low electrolyte temperature and pressure can increase the rate of reaction but may also lead to reduced efficiency and increased energy consumption. The use of high-quality electrodes and membranes can improve the efficiency and durability of the electrolysis cell.
In some embodiments, a hydrogen feed stream is provided by an electrolysis unit, comprising one or more alkaline electrolysis cells (AECs) and one or more proton exchange membrane cells (PEMs). Alkaline electrolysis is an electrochemical process for the production of hydrogen gas and oxygen gas from water using an alkaline electrolyte, typically a solution of potassium hydroxide (KOH) or sodium hydroxide (NaOH). In alkaline electrolysis, a voltage is applied across the anode and cathode, which are separated by a porous diaphragm or membrane to prevent mixing of the products. Proton exchange membrane (PEM) electrolysis is an electrochemical process for the production of hydrogen gas and oxygen gas from water. In PEM electrolysis, a voltage is applied across a proton exchange membrane, which separates the anode and cathode compartments of the electrolyzer. The electrolysis reaction occurs at the electrodes, where water is oxidized at the anode to form oxygen gas and hydrogen ions (protons), while the hydrogen ions are reduced at the cathode to form hydrogen gas.
In some embodiments, the one or more AECs comprise one or more low pressure AECs, one or more high-pressure AECs, or any combination thereof. In some embodiments, the one or more PEMs comprise one or more low pressure PEMs, one or more high-pressure PEMs, or any combination thereof. In some embodiments, the electrolysis unit comprises one or more low pressure AECs and one or more one or more low pressure PEMs or any combination thereof. In some embodiments, the electrolysis unit comprises one or more low pressure AECs, one or more high-pressure AECs, and one or more one or more high-pressure PEMs, or any combination thereof.
In some embodiments, the electrolysis unit comprises one or more high-pressure AECs and one or more one or more high-pressure PEMs, or any combination thereof. As used in this context, “low pressure” means atmospheric pressure or less than or equal to 10 barg, and “high pressure” means greater than or equal to 10 barg, greater than or equal to 20 barg, greater than or equal to 30 barg, and/or less than or equal to 40 barg, less than or equal to 60 barg, less than or equal to 80 barg, and/or less than or equal to 100 barg. In the electrolysis unit, electricity and a water feed stream are reacted to form hydrogen and oxygen product streams.
Reaction conditions with respect to electrolysis reactants include, but are not limited to, pressure, temperature, and composition of reactants.
In some embodiments, water is fed to the electrolysis apparatus has one or more of: a) a temperature in the range of from 0° C. to 100° C., from 5° C. to 50° C., or from 10° C. to 35° C.; b) a pressure in the range of from 10 kPa to 10,000 kPa, from 50 kPa to 7,000 kPa, or from 100 kPa to 5,000 kPa; c) a water hardness, as measured by electrical conductively in microsiemens per centimeter, in the range of from 0.01 μS/cm to 10 μS/cm, from 0.02 μS/cm to 8 μS/cm, or from 0.05 μS/cm to 5 μS/cm; and a mineral content in the range of from 0.1 mg/L to 20 mg/L, from 1 mg/L to 15 mg/L, or from 2 mg/L to 10 mg/L.
Reaction conditions within the electrolysis apparatus include, but are not limited to, pressure, temperature, and specific energy consumption.
In some embodiments, reaction conditions in the electrolysis apparatus are one or more of: a) a temperature in the range of from 20° C. to 95° C., from 30° C. to 90° C., or from 40° C. to 80° C.; b) a pressure in the range of from atmospheric pressure or less than or equal to 10 barg to 20 barg, 30 barg, 40 barg, 60 barg, 80 barg, or 100 barg; and c) a specific energy consumption in the range of from 3.0 kWh/Nm3 to 6.0 kWh/Nm3, from 3.2 kWh/Nm3 to 5.5 kWh/Nm3, or from 3.5 kWh/Nm3 to 5.3 kWh/Nm3.
In some embodiments, an anode catalyst is selected from one or more of Group 8 to 10 transition metals or from nickel, cobalt, and iron, and cathode catalyst is selected from one or more of Group 4 transition metals or from titanium, nickel, and zirconium.
Reaction conditions with respect to electrolysis products include, but are not limited to, pressure, temperature, and composition of products.
In some embodiments, hydrogen withdrawn from the electrolysis apparatus has one or more of: a) a temperature in the range of from 20° C. to 160° C., from 30° C. to 140° C., or from 40° C. to 120° C.; b) a pressure in the range of from atmospheric pressure or less than or equal to 10 barg to 20 barg, 30 barg, 40 barg, 60 barg, 80 barg, or 100 barg; and c) impurities less than 1.5 wt %, or in the range of from 0.03 wt % to 1.2 wt %, or from 0.05 wt % to 1 wt %.
In some embodiments, oxygen withdrawn from the electrolysis apparatus has one or more of: a) a temperature in the range of from 20° C. to 160° C., from 30° C. to 140° C., or from 40° C. to 120° C.; b) a pressure in the range of from atmospheric pressure or less than or equal to 10 barg to 20 barg, 30 barg, 40 barg, 60 barg, 80 barg, or 100 barg; and c) impurities less than 1.5 wt %, or in the range of from 0.03 wt % to 1.2 wt %, or from 0.05 wt % to 1 wt %.
Alkaline water electrolysis apparatuses useful in the process disclosed herein are described in more detail in U.S. Pub. Nos. 2023/0131407A1, 2023/0096320A1, 2022/0333260A1, 2022/0325425A1, 2022/0325424A1, and 2021/0115573A1; WO 2021/229963A1, WO 2022/258394A1, WO 2022/243441A1, and WO 2022/200315A1; and (Brochure) Nel Hydrogen Electrolysers, The World's Most Efficient and Reliable Electrolysers, copyright 2021 Nel ASA, PD-0600-0125 Rev D, https://nelhydrogen.com/wp-content/uploads/2020/03/Electrolysers-Brochure-Rev-D.pdf; (Brochure) Large-scale water electrolysis for green hydrogen production, Copyright thyssenkrupp nucera AG & Co. KGaA, https://thyssenkrupp-nucera.com/wp-content/uploads/2022/11/thyssenkrupp-nucera-green-hydrogen-solutions-brochure.pdf; (Brochure) Plug EX-4250D Electrolyzer (English), Published Date Apr. 20, 2022, https://resources.plugpower.com/electrolyzers/ex-4250d-f041122; (Brochure) DQ1000 Alkaline Electrolyser, DQ1000 ©John Cockerill Renewables, hydrogen@johncockerill.com, h2.johncockerill.com https://h2.johncockerill.com/wp-content/uploads/2022/02/DQ-1000-def-2-HD.pdf; all of which are fully incorporated by reference herein for all jurisdictions in which such incorporation is permitted.
Proton exchange membrane (PEM) electrolysis is an electrochemical process for the production of hydrogen gas and oxygen gas from water. In PEM electrolysis, a voltage is applied across a proton exchange membrane, which separates the anode and cathode compartments of the electrolyzer. The electrolysis reaction occurs at the electrodes, where water is oxidized at the anode to form oxygen gas and hydrogen ions (protons), while the hydrogen ions are reduced at the cathode to form hydrogen gas.
The efficiency of PEM electrolysis is dependent on several process conditions, including, but not limited to current density, electrolyte concentration, temperature, and pressure. The rate of hydrogen production is directly proportional to the current density applied in the cell. However, higher current densities lead to increased energy consumption. The rate of reaction increases with temperature due to increased kinetic energy of the reactant molecules. However, higher temperatures also increase the potential for degradation of the membrane and catalysts. Higher pressures can increase the solubility of hydrogen and oxygen gases in the electrolyte and reduce the energy required for gas compression. However, high-pressures also increase the cost and complexity of the system. Overall, PEM electrolysis is an attractive method for hydrogen production due to its high efficiency, fast response time (e.g., in the range of from 0.25 to 1 second per percent electrolyzer electrical load), and low environmental impact.
Reaction conditions with respect to electrolysis reactants include, but are not limited to, pressure, temperature, and composition of reactants.
In some embodiments, water is fed to the electrolysis apparatus has one or more of: a) a temperature in the range of from 0° C. to 100° C., from 5° C. to 50° C., or from 10° C. to 35° C.; b) a pressure in the range of from atmospheric pressure or less than or equal to 10 barg to 20 barg, 30 barg, 40 barg, 60 barg, 80 barg, or 100 barg; and c) a water hardness, as measured by electrical conductively in microsiemens per centimeter, in the range of from 0.01 μS/cm to 10 μS/cm, from 0.02 μS/cm to 8 μS/cm, or from 0.05 μS/cm to 5 μS/cm; and a mineral content in the range of from 0.1 mg/L to 20 mg/L, from 1 mg/L to 15 mg/L, or from 2 mg/L to 10 mg/L.
Reaction conditions within the electrolysis apparatus include, but are not limited to, pressure, temperature, and specific energy consumption.
In some embodiments, reaction conditions in the electrolysis apparatus are one or more of: a) a temperature in the range of from 20° C. to 95° C., from 30° C. to 90° C., or from 40° C. to 80° C.; b) a pressure in the range of from atmospheric pressure or less than or equal to 10 barg to 20 barg, 30 barg, 40 barg, 60 barg, 80 barg, or 100 barg; and c) a specific energy consumption in the range of from 3.0 kWh/Nm3 to 6.0 kWh/Nm3, from 3.2 kWh/Nm3 to 5.5 kWh/Nm3, or from 3.5 kWh/Nm3 to 5.3 kWh/Nm3.
In some embodiments, anode catalyst is selected from one or more of Group 13 post-transition metals or indium, and cathode catalyst is selected from one or more of Group 10 transition metals or platinum.
Reaction conditions with respect to electrolysis products include, but are not limited to, pressure, temperature, and composition of products.
In some embodiments, hydrogen withdrawn from the electrolysis apparatus has one or more of: a) a temperature in the range of from 20° C. to 160° C., from 30° C. to 140° C., or from 40° C. to 120° C.; b) a pressure in the range of from atmospheric pressure or less than or equal to 10 barg to 20 barg, 30 barg, 40 barg, 60 barg, 80 barg, or 100 barg; and c) impurities less than 1.5 wt %, or in the range of from 0.03 wt % to 1.2 wt %, or from 0.05 wt % to 1 wt %.
In some embodiments, oxygen withdrawn from the electrolysis apparatus has one or more of: a) a temperature in the range of from 20° C. to 160° C., from 30° C. to 140° C., or from 40° C. to 120° C.; b) a pressure in the range of from atmospheric pressure or less than or equal to 10 barg to 20 barg, 30 barg, 40 barg, 60 barg, 80 barg, or 100 barg; and c) impurities less than 1.5 wt %, or in the range of from 0.03 wt % to 1.2 wt %, or from 0.05 wt % to 1 wt %.
Proton exchange membrane electrolysis apparatuses useful in the process disclosed herein are described in more detail in U.S. Pat. No. 10,053,788; U.S. Pub. Nos. 2016/0089658A1, 2013/0092549A1, 2008/0118807A1, 2008/0026276A1, 2004/0214065A1, and 2004/0013925A1; PCT Pub. Nos. WO 2022/243441A1, and WO 2022/200315A1; and (Brochure) Nel Hydrogen Electrolysers, The World's Most Efficient and Reliable Electrolysers, copyright 2021 Nel ASA, PD-0600-0125 Rev D, https://nelhydrogen.com/wp-content/uploads/2020/03/Electrolysers-Brochure-Rev-D.pdf; all of which are fully incorporated by reference herein for all jurisdictions in which such incorporation is permitted.
In some embodiments, hydrogen from the electrolysis unit is produced at a pressure less than the pressure required for hydrogen feed to the HS system. Such embodiments additionally comprise a hydrogen compression system. Such hydrogen compression systems comprise one or more hydrogen compressors and ancillary equipment are well known to those skilled in the art and can be designed to impart a pressure increase to any or all hydrogen produced from the electrolysis unit as needed to be compatible with HS system feed requirements.
Discharge from the hydrogen compression system can be fed directly to the HS system, to pressurized hydrogen storage (wherein hydrogen is maintained at or about the discharge pressure of the hydrogen compression system), or a combination thereof. In some embodiments, hydrogen produced from the electrolysis unit can be stored at the pressure as produced, wherein hydrogen is withdrawn from such storage is routed to the hydrogen compression system prior to being fed to the HS system.
In some embodiments, the process for producing one or more synthetic hydrocarbon products further comprises sending hydrogen produced in the electrolysis apparatus to a hydrogen storage system. Such storage provides for optimization of electrical costs and/or stabilization of eFuels plant operations, and/or control of the process with fluctuating supply of electricity.
In some embodiments, overall reduction of electrical costs is achieved by use of stored hydrogen to allow intentional reduction in hydrogen production by reducing, idling, or shutting down all or a portion of the electrolysis unit. Electrical grids often have different costs in terms of monetary units per kilowatt-hour (mu/kWh). The cost of electricity in a green electrical grid can vary depending on several factors, including the availability of renewable energy sources, the demand for electricity, and the cost of operating and maintaining the grid infrastructure. Green electrical grids rely on renewable energy sources such as solar, wind, hydro, and geothermal power to generate electricity. These sources of energy are dependent on the weather and the availability of natural resources, which can cause fluctuations in the electricity supply and, therefore, the cost of electricity. For example, if there is a high demand for electricity on a sunny day, when solar power is abundant, the cost of electricity may be lower due to the abundance of supply. However, if there is low demand for electricity during periods of high wind or solar power generation, the availability and cost of electricity may be higher as renewable energy sources may be curtailed or excess power may need to be stored. In addition, the cost of electricity in a green electrical grid may also vary depending on the cost of maintaining and upgrading the grid infrastructure to accommodate the integration of renewable energy sources. This can include upgrading transmission lines and distribution networks to ensure reliable and efficient power delivery.
In some embodiments, stored hydrogen can be intentionally used to supplement or replace direct production of hydrogen from the electrolysis unit during time periods when costs of electricity from the grid are higher. Conversely, when the availability is high and costs of electricity from the grid are lower, the electrolysis unit can produce hydrogen in excess of the amount required for operation and the eFuels plant in order to build an inventory of high-pressure hydrogen in storage for use during a future time period of lower electricity availability from the grid. An availability and/or cost optimized cycle of higher, lower, and intermediate hydrogen production rates from the electrolysis unit in a specific eFuels plant is determined by parameters related to such eFuels plant, such as, but not limited to the availability and cost structure of the grid supplying electricity to such eFuels plant, the hydrogen storage capacity of such eFuels plant, and the desired production rate of eFuels products from the eFuels plant during a particular time period. In some embodiments, the eFuels plant further comprises a control system to assist the operator in balancing the timing and/or production rates and disposition of hydrogen produced by the electrolysis unit and timing and/or withdrawal rates of hydrogen withdrawn from the hydrogen storage system over a selected time period. Such a control system can assist the operator in minimizing the disruptions to operations and/or electrical costs of operation of the electrolysis unit and/or the eFuels plant on an hourly basis, a daily basis, a monthly basis, a yearly basis, or a combination thereof.
In some embodiments, timing and/or withdrawal rates of hydrogen from the storage system are determined by fluctuations in the amount of or outages of electricity available to be supplied to the eFuels plant from the grid. The inventory of high-pressure hydrogen in the hydrogen storage system provides an instantaneous response to unplanned reductions in hydrogen production rates from the electrolysis unit caused by an unplanned reduction in electricity supplied for the eFuels plant from the grid. This instantaneous withdrawal of hydrogen from the hydrogen storage system serves to offset the instantaneous loss of hydrogen production from the electrolysis unit and thereby stabilize the supply of hydrogen to the downstream units in the eFuels plant which are hydrogen consumers. This minimizes perturbations of operation of the eFuels plant in spite of fluctuations in the amount of electricity available for the eFuels plant from the grid.
Hydrogen can be stored physically as either a gas or a liquid. Storage of hydrogen as a gas typically requires high-pressure tanks (200 to 700 barg tank pressure). Storage of hydrogen as a liquid requires cryogenic temperatures because the boiling point of hydrogen at one atmosphere pressure is −252.8° C. In some embodiments, hydrogen is stored at conditions comprising one or more of: a) a temperature in the range of from 0° C. to 150° C., from 30° C. to 120° C., or from 40° C. to 100° C.; and b) a pressure in the range of from 2,000 kPa to 65,000 kPa, from 2,500 kPa to 45,000 kPa, or from 3,000 kPa to 35,000 kPa.
In some embodiments, hydrogen is stored in the form of a metal hydride, such as disclosed in more detail in U.S. Pub. Nos. 2019/0359483A1, 20200270126A1, and 2019/0359483A1; Gkanas, E. I.; Wang, C.; Shepherd, S.; Curnick, O. Metal-Hydride-Based Hydrogen Storage as Potential Heat Source for the Cold Start of PEM FC in Hydrogen-Powered Coaches: A Comparative Study of Various Materials and Thermal Management Techniques. Hydrogen 2022, 3, 418-432. https://doi.org/10.3390/hydrogen3040026; K. Malleswararao, Pradip Dutta, Srinivasa Murthy S, Applications of metal hydride based thermal systems: A review, Applied Thermal Engineering, Volume 215, 2022, 118816, ISSN 1359-4311, https://doi.org/10.1016/j.applthermaleng.2022.118816, (https://www.sciencedirect.com/science/article/pii/S1359431122007578); and https://www.gknhydrogen.com/technology/, the substance of which is fully incorporated by reference herein for all jurisdictions in which such incorporation is permitted. A metal hydride storage system typically requires moderate temperature and pressure conditions (e.g., from 0° C. to 80° C., from 0 barg to 50 barg).
Considerations for implementation of hydrogen storage can be found in (1) US Dept. of Energy, Office of Energy Efficiency & Renewable Energy, Hydrogen Storage, Hydrogen and Fuel Cell Technologies Office, https://www.energy.gov/eere/fuelcells/hydrogen-storage#:˜:text=Hydrogen%20can%20be%20stored%20physically, pressure%20is%20%E2%88%92252.8% C2% BOC, and (2) International Energy Agency, Hydrogen Implementing Agreement, Hydrogen Production and Storage, R&D Priorities and Gaps, IEA Publications, 9, rue de la Fédération, 75739 Paris Cedex 15, printed in France by Stedi Média, January 2006, https://www.iea.org/reports/hydrogen-production-and-storage, both of which are fully incorporated by reference herein for all jurisdictions in which such incorporation is permitted.
In some embodiments, the process implemented in the eFuels plant further comprises obtaining the first carbon dioxide stream as a feed stream to the RWGS reactor. Carbon dioxide feed can be supplied by one or more of: a) importing carbon dioxide from a source external to the process; b) feeding air to a direct air capture (DAC) unit to recover carbon dioxide; and c) combusting biomass or biogas to recover carbon dioxide. In some embodiments, imported CO2 can be petroleum-derived, biogenic, or a combination thereof. Biogenic CO2 relates to carbon in wood, paper, grass trimmings, and other biofuels that was originally removed from the atmosphere by photosynthesis and, under natural conditions, would eventually cycle back to the atmosphere as CO2 due to degradation processes. Use of biogenic CO2, CO2 extracted from the atmosphere, and/or other CO2 sources unrelated to fossil fuels result in synthetic hydrocarbon products (SLG, SLD, SMD, and SHD) that have a unique quality in terms of radioactive carbon dating, different from hydrocarbon products derived from fossil fuel feedstocks and/or CO2 derived from fossil fuel or petroleum sources.
In some embodiments, at least a portion of the electricity consumed in the DAC reaction is derived from solar sources, wind sources, or a combination thereof from the electrical grid. Further, in some embodiments, synthetic hydrocarbon fuels produced by the process disclosed herein are inventoried for on-premise generation to electricity to permit continued operation of the process disclosed herein in spite of fluctuations in power available from the electrical grid.
In some embodiments, the carbon dioxide feed stream to the RWGS reactor has one or more of: a) a temperature in the range of from −60° C. to 200° C., from 0° C. to 120° C., or from 5° C. to 100° C.; b) a pressure in the range of from 100 kPa to 10,000 kPa, from 500 kPa to 7,000 kPa, or from 700 kPa to 5,000 kPa; and c) a content of gases other than carbon dioxide of less than 6 wt %, or in the range of from 0.1 wt % to 5 wt %, or from 0.05 wt % to 4 wt %.
In some embodiments, the process implemented in the eFuels plant further comprises recovering carbon dioxide from ambient air by means of a direct air capture (DAC) unit.
DAC reactions and apparatuses useful in the process disclosed herein are described in more detail in U.S. Pat. Nos. 11,623,863 and 11,560,343; PCT Pub. Nos. WO 2021/168498A1, WO 2021/253010A1, WO 2023/049952A1, WO 2023/056011A1, WO 2021/239748A1, WO 2021/156457A1, and WO 2023/043843A1; and (Brochure) Climeworks, Direct air capture: our technology to capture CO2, https://climeworks.com/direct-air-capture; (Brochure) Carbon Engineering, Our Technology, Carbon Engineering Ltd., Copyright 2023, https://carbonengineering.com/our-technology/; (Brochure) Global Thermostat, A carbon negative solution, https://globalthermostat.com/; (Brochure) Mosaic Materials, Our Technology, https://mosaicmaterials.com/technology/; all of which are fully incorporated by reference herein for all jurisdictions in which such incorporation is permitted.
In some embodiments, the process for producing one or more synthetic hydrocarbon products further comprises sending carbon dioxide produced by one or more of the direct air capture (DAC) unit and/or other carbon dioxide sources utilized in a specific eFuels plant to a carbon dioxide storage system. Such storage provides for optimization of electrical costs and/or stabilization of eFuels plant operations.
In some embodiments, overall reduction of electrical costs is achieved by use of stored carbon dioxide to allow intentional reduction in carbon dioxide production by reducing, idling, or shutting down all or a portion of the DAC unit and/or other carbon dioxide sources utilized in a specific eFuels plant. Electrical grids often have different costs in terms of monetary units per kilowatt-hour (mu/kWh). The cost of electricity in a green electrical grid can vary depending on several factors, including the availability of renewable energy sources, the demand for electricity, and the cost of operating and maintaining the grid infrastructure. Green electrical grids rely on renewable energy sources such as solar, wind, hydro, and geothermal power to generate electricity. These sources of energy are dependent on the weather and the availability of natural resources, which can cause fluctuations in the electricity supply and, therefore, the cost of electricity, the same as those discussed above for managing hydrogen supply.
In some embodiments, stored carbon dioxide can be intentionally used to supplement or replace direct production of carbon dioxide from the DAC unit and/or other carbon dioxide sources utilized in a specific eFuels plant during time periods. Conversely, when power supply from the grid is readily available, the DAC unit and/or other carbon dioxide sources utilized in a specific eFuels plant can produce carbon dioxide in excess of the amount required for operation and the eFuels plant in order to build an inventory of high-pressure carbon dioxide in storage for use during a future time period. Availability and cost optimized cycle of higher, lower, and intermediate carbon dioxide production rates from the DAC unit and/or other carbon dioxide sources utilized in a specific eFuels plant is determined by parameters related to such eFuels plant, such as, but not limited to the cost structure of the grid supplying electricity to such eFuels plant, the carbon dioxide storage capacity of such eFuels plant, and the desired production rate of eFuels products from the eFuels plant during a particular time period. In some embodiments, the eFuels plant further comprises a control system to assist the operator in balancing the timing and/or production rates and disposition of carbon dioxide produced by the DAC unit or other carbon dioxide sources utilized in a specific eFuels plant and timing and/or withdrawal rates of carbon dioxide withdrawn from the carbon dioxide storage system over a selected time period. Such control system can assist the operator in minimizing the electrical costs of operation of the DAC unit or other carbon dioxide sources utilized in a specific eFuels plant and/or the eFuels plant on an hourly basis, a daily basis, a monthly basis, a yearly basis, or a combination thereof.
In some embodiments, timing and/or withdrawal rates of carbon dioxide from the storage system are determined by fluctuations in the amount of or outages of electricity available to be supplied to the eFuels plant from the grid. The inventory of high-pressure carbon dioxide in the carbon dioxide storage system provides an instantaneous response to unplanned reductions in carbon dioxide production rates from the DAC unit or other carbon dioxide sources utilized in a specific eFuels plant caused by an unplanned reduction in electricity supplied for the eFuels plant from the grid. This instantaneous withdrawal of carbon dioxide from the carbon dioxide storage system serves to offset the instantaneous loss of carbon dioxide production from the DAC unit and/or other carbon dioxide sources utilized in a specific eFuels plant and thereby stabilize the supply of carbon dioxide to the downstream units in the eFuels plant which are carbon dioxide consumers. This minimizes perturbations of operation of the eFuels plant in spite of fluctuations in the amount of electricity or CO2 available for the eFuels plant.
In some embodiments, the required changes to HS system operation triggered by intentional or unintentional changes in the DAC unit carbon dioxide production rates are mitigated or eliminated by decoupling the HS system from direct dependence on DAC production rates through the use of carbon dioxide storage.
In some embodiments, carbon dioxide is stored at conditions comprising one or more of: a) a temperature in the range of from −5° C. to −60° C., from −10° C. to −40° C., or from −15° C. to −35° C.; and b) a pressure in the range of from 600 kPa to 40,000 kPa, from 1,000 kPa to 3,000 kPa, or from 1,200 kPa to 2,500 kPa.
In some embodiments, the process implemented in the eFuels plant further comprises sending carbon dioxide produced to storage. Considerations for implementation of carbon dioxide storage can be found in (1) Linde, Safety advice, Carbon Dioxide, https://www.linde-gas.com/en/images/LMB_Safety%20Advice_01_66881_tcm17-165650.pdf, and (2) Pentair, Liquid CO2 Storage Tanks, https://foodandbeverage.pentair.com/en/products/pentair-liquid-co2-storage-tanks, both of which are fully incorporated by reference herein for all jurisdictions in which such incorporation is permitted.
In some embodiments, stored SLG and/or SLD can be used to supplement feed to processing units in the HS system and/or as an additional or alternative fuel to the combustion zone of the oxygen-fired heater. Additional heat value and/or volume of SLG and/or SLD transfers additional heat to the heating zone of the oxygen-fired heater, which is translated to additional electricity from the steam turbine generator. In some embodiments, SLG and/or SLD fed to the HS system replaces direct production of hydrogen from the electrolysis apparatus. The reduced electrical consumption from reducing or shutting down hydrogen production from the electrolysis apparatus would permit continued operation of the process disclosed herein in spite of fluctuations in power available from the electrical grid.
In some embodiments, SLG is stored at conditions comprising one or more of: a) a temperature in the range of from −40° C. to 60° C., from −30° C. to 50° C., or from −20° C. to 40° C.; and b) a pressure in the range of from 500 kPa to 3,500 kPa, from 750 kPa to 2,500 kPa, or from 1,000 kPa to 2,000 kPa.
In some embodiments, the process implemented in the eFuels plant further comprises sending SLG produced in the HS system to storage. Considerations for implementation of SLG storage can be found in EuroTanks, LPG Storage, https://www.eurotanks.eu/lpg-storage-tank/, which is fully incorporated by reference herein for all jurisdictions in which such incorporation is permitted.
In some embodiments, the eFuels plant further comprises facilities to supply a back-up source of electrical power to provide an uninterrupted power supply and mitigate power outages to the eFuels plant. The commercially viable range of electrical back-up capacities for one or more process units in the RFCER system or the eFuels plant can range from a few hundred kilowatt-hours to several hundred megawatt-hours, depending on the specific needs of the facility. In some embodiments, a back-up electrical power source comprises energy storage in an array of batteries, energy production from a stack of fuel cells, or a combination thereof.
In some embodiments, one or more grid-scale battery arrays have sufficient electrical storage to temporarily run one or more process units in the RFCER system or the eFuels plant. In some embodiments, the electrical power storage facility comprises grid-scale arrays of lead-acid batteries, lithium-ion batteries, flow batteries, or a combination thereof. These types of batteries are designed to deliver high energy output over an extended period, making them suitable for industrial applications that require a significant amount of power. Lead-acid batteries are the most commonly used type of battery in industrial applications due to their low cost and high reliability. They are suitable for short-duration applications, such as backup power during an outage. Lithium-ion Batteries have a higher energy density and longer cycle life than lead-acid batteries, making them suitable for longer-duration applications. They are more expensive than lead-acid batteries but offer better performance. Flow Batteries use chemical reactions to store and release energy, making them suitable for long-duration applications. They have a longer cycle life than lithium-ion batteries and can store energy for extended periods.
In some embodiments, grid-scale batteries are arranged in banks or arrays to provide the necessary electrical storage capacity. The arrangement of the batteries will depend on the specific requirements of the one or more process units being powered and the desired time for which the one or more process unit is to be powered by the battery array. The batteries will be connected in series or parallel configurations to increase voltage or current output, respectively.
In some embodiments, one or more grid-scale fuel cell stacks have sufficient electrical storage to temporarily run one or more process units in the RFCER system. Fuel cells are devices that convert the chemical energy of a fuel into electrical energy through an electrochemical process. In some embodiments, the fuel cells are powered by hydrogen, such as from the hydrogen storage system, and/or seawater, as disclosed in Chinese pat. no. CN218919069U. Each fuel cell stack consists of individual fuel cells connected in series or parallel configurations, depending on the required output voltage and current. The fuel cells themselves are typically made up of a membrane electrode assembly (MEA), which includes an electrolyte membrane, catalyst layers, and gas diffusion layers.
In some embodiments, a battery array further comprises a battery management system (BMS) to ensure that the batteries are operating efficiently and to protect them from damage. The BMS monitors the battery's state of charge, temperature, and other factors to optimize its performance and prevent overcharging or over-discharging. Like batteries, fuel cells also require a management system to ensure optimal performance and prevent damage. This may include a control system to manage the fuel flow and voltage output, as well as monitoring systems to measure the temperature and pressure of the fuel cell stack.
The specific arrangement of batteries and/or fuel cells in the RFCER system or the eFuels plant would depend on a variety of factors, including the specific requirements of the process unit being powered and the available space for the battery system. Typically, large-scale battery systems are designed with a series of modules, each containing multiple individual battery cells, that can be configured in a variety of ways to meet the specific needs of the application. The modules can then be linked together to create a larger battery array that can provide the necessary electrical storage and power output. Large-scale fuel cell systems typically consist of multiple individual fuel cells that can be connected in series or parallel to provide the necessary power output. The fuel cells themselves are often arranged in stacks, with each stack containing multiple individual cells connected in series. Multiple stacks can then be connected in parallel to create a larger fuel cell array. The batteries systems and/or the fuel cell systems may also be coupled with inverters, transformers, and other equipment to ensure that the electrical output is compatible with the needs of the one or more process units being powered.
There are several manufacturers of large-scale batteries that could potentially provide enough electrical storage to temporarily run a process unit in a refinery. Some of the most prominent manufacturers in this space include Tesla, LG Chem, Samsung SDI, and BYD. Unlike batteries, which store electrical energy chemically, fuel cells generate electricity through a chemical reaction between hydrogen and oxygen. There are several manufacturers of large-scale fuel cells, including Ballard Power Systems, Bloom Energy, and FuelCell Energy.
In some embodiments, the process implemented in the eFuels plant further comprises adding sea water to a desalinization unit and withdrawing a first treated water effluent to produce the first water stream, and optionally feeding at least a portion of the first treated water effluent to a demineralization unit and withdrawing a second treated water effluent to produce the first water stream.
In some embodiments, cooling of the RWGS product stream for recovery of the syngas is implemented in a first heat exchanger wherein a cooling medium comprises the first treated water effluent, the second treated water effluent, or a combination thereof. The cooling medium is converted to a first high-pressure steam stream.
The thermal desalination unit can run in at least two extreme modes of operation, the overall efficiency of the integrated process depends on whether there is an option for export of low-grade heat or an option for export of potable water from the RFCER system.
In some embodiments, low-grade heat export from the RFCER system is available. The thermal desalination distillate production is reduced to balance the water requirements and low grade heat balance. While operating in low distillate extraction mode, the seawater return quality has low salinity increased compared to the maximum distillate operating mode.
In some embodiments, low-grade heat export is not available. All low-grade heat from the electrolysis unit and HS are utilized within the thermal desalination unit, and surplus potable water for export is produced. As the salinity of the seawater return will be higher than generally allowed for discharge to sea in some jurisdictions, a salt crystallization unit be added to treat the effluent from the thermal desalinization unit to produce clean water for export from the RFCER system with zero liquid discharge to the sea.
Desalination technology and apparatuses useful in the process disclosed herein are described in more detail in U.S. Pub. Nos. 2008/0277344A1, 2012/0234664A1, and 2010/0072136A1; U.S. Pub. Nos. 6,783,682, 8,696,908, and 9,126,149; and Commercial Thermal Technologies for Desalination of Water from Renewable Energies: A State of the Art Review, https://www.mdpi.com/2227-9717/9/2/262; Thermodynamic, Exergy, and Thermoeconomic analysis of Multiple Effect Distillation Processes, https://www.sciencedirect.com/science/article/pii/B978012815244700012X; and Energy consumption and water production cost of conventional and renewable-energy-powered desalination processes, https://www.sciencedirect.com/science/article/abs/pii/S1364032113000208; Entropie-Veolia Technologies, https://www.entropie.com/solutions/technologies; all of which are fully incorporated by reference herein for all jurisdictions in which such incorporation is permitted.
Demineralization processes and apparatuses useful in the process disclosed herein are described in more detail in U.S. Pub. No. 2006/0243647; U.S. Pat. Nos. 3,425,937, 3,444,079, 3,658,674, 4,648,976, 4,820,421, and 5,468,395; all of which are fully incorporated by reference herein for all jurisdictions in which such incorporation is permitted.
An oxygen fired heater (OFH) as disclosed herein recovers heat and carbon through combustion of waste gases and unsaleable liquid fuels. Oxygen from the eFuels plant electrolysis unit is supplied as an oxidant. OFH flue gas is processed to recover concentrated CO2, which is sent to the carbon dioxide recovery unit (CDRU) for purification, recycled to the burners and/or firebox to control combustion temperatures, or a combination thereof. Following the CDRU recovered CO2 is sent to the storage, the HS system (e.g., as feed to an RWGS unit), or a combination thereof. Heat is recovered from the OFH flue gas in radiant and convection sections. In some embodiments, the radiant section comprises a radiant coil wherein heat is added to high pressure steam to produce superheated high pressure steam. In some embodiments, the convection section comprises a convection coil wherein heat is added to medium pressure steam to produce superheated medium pressure steam. Recovered heat is used in the eFuels process, to generate electricity, and to upgrade waste low-grade heat sufficiently for use with thermal desalination.
In some embodiments, the process implemented in the eFuels plant further comprises adding at least a portion of the oxygen stream produced from the electrolysis apparatus and a fuel gas stream comprising one or more of HS system purge gas, HS system off gas, and SLG withdrawn from the HS system and/or the SLG storage system as fuel to an oxygen-fired heater. a second carbon dioxide stream is recovered from combustion products from the oxygen-fired heater (“OFH”). In some embodiments, at least a portion of the second carbon dioxide stream is added as feed to the HS. Use of an OFH also reduces the carbon footprint of the process disclosed herein by capturing carbon dioxide for use as a feed to the HS system, such as to an RWGS reactor, instead of releasing carbon dioxide to the atmosphere such as in the flue gas of conventionally fired heaters.
In some embodiments, in contrast to conventional operation of an OFH, where flue gas comprising CO2 is emitted to the atmosphere, all flue gas from the OFH combustion zone is captured for used in the eFuels plant. CO2 capture and recovery are enhanced by replacing combustion air (predominantly N2) with oxygen. This significantly increases the concentration of CO2 in the flue gas relative to a conventionally fired heater, making capture and recovery much more energy efficient. Furthermore, capturing all flue gas any emissions, including but not limited to CO2, PM, NOx, VOC, and CO.
In some embodiments, an OFH comprises one or more burners, suitable for accepting feeds comprising a hydrocarbon stream, an oxygen stream, and a diluent gas stream and producing combustion products comprising heat, carbon dioxide, and water. Combustion products and heat from the one or more burners enter a radiant section of the OFH. The radiant second comprises a firebox and a radiant coil within the firebox. The firebox is suitable for accepting the combustion products, and the radiant coil absorbs a first portion of the heat to produce first cooled combustion products. The first cooled combustion products enter a convection section of the OFH. The convection section comprises a convection coil and a convection inter-tube space defined by the outer surface of the convection coil. The convection inter-tube space is suitable for accepting the first cooled combustion products to produce second cooled combustion products. The second cooled combustion products enter a carbon dioxide recovery section of the OFH. The carbon dioxide recovery section comprises a condensing coil and a condensing inter-tube space defined by the outer surface of the condensing coil. The condensing inter-tube space is suitable for accepting the second cooled combustion products to produce third cooled products comprising a non-condensables stream, comprising carbon dioxide, and a water stream.
In some embodiments, the diluent gas stream to the one or more burners comprises a portion of the carbon dioxide product stream from the carbon dioxide recovery section. Adding CO2 as a diluent gas is an effective method for controlling flame temperature. Controlling flame temperature is important because the use of pure oxygen for combustion results in extremely high flame temperatures. Without nitrogen as a diluent, the flame temperature in an oxygen fired burner can become extremely high. CO2 addition moderates the combustion temperature by absorbing heat, which helps protect the burner and furnace components from thermal damage. CO2 addition also allows for better heat management by reducing localized hot spots, promoting more even heat distribution within the firebox, or a combination thereof.
In some embodiments, CO2 is injected using dedicated lines that mix with the oxygen and fuel streams at controlled rates. The flow rate of CO2 is regulated based on the desired temperature control requirements and combustion conditions. In some embodiments, automated control systems monitor firebox temperatures in real time and the CO2 flow is adjusted to maintain target temperatures. Temperature sensors and feedback loops help modulate the CO2 addition, ensuring stable operation. In some embodiments, CO2 flow is further modified to accommodate changes in fuel composition, changes in heat load (e.g., steam mass flow rate and/or temperature in radiant coil and/or convection coil), changes in oxygen flow changes, or a combination thereof.
In some embodiments, CO2 is added at the burner tip, in the combustion zone near the burner, downstream of the combustion zone in the firebox, or a combination thereof. Adding CO2 at the burner tip provides direct dilution of the fuel/oxygen mixture thereby reducing flame temperature at the ignition point. This approach creates a stable flame with a lower peak temperature, protecting burner components and enhancing flame uniformity. Injecting CO2 just downstream of the burner helps cool the flame in the primary combustion area while still allowing complete combustion to occur efficiently. This approach provides temperature control while limiting disruption of combustion efficiency. Adding CO2 in the firebox or downstream of the combustion zone does not affect flame temperature directly but helps reduce the temperature of hot gases before they reach heat-sensitive equipment. This is useful for controlling overall furnace temperature, protecting downstream equipment from excess heat, and ensuring even heat distribution within the furnace.
In some embodiments, the hydrocarbon stream comprises a hydrocarbon synthesis (HS) system purge gas, a HS system off gas, a synthetic liquified gas (SLG), a synthetic light distillate (SLD), or a combination thereof. In some embodiments, the hydrocarbon stream is free of any components derived from petroleum.
In some embodiments, the one or more burners are sized to consume SLD in an amount in the range of from 0 tonne/hr to 2.0 tonne/hr, SLG in an amount in the range of from 0 tonne/hr to 0.15 tonne/hr, combined HS system purge gas and HS system off gas in an amount in the range of from 0.0 tonne/hr to 1.5 tonne/hr; or a combination thereof.
In some embodiments, the one or more burners are sized to combust vaporized SLD in an amount sufficient to produce heat energy in the range of from 0.0 MW to 21.0 MW, vaporized SLG in an amount sufficient to produce heat energy in the range of from 0 MW to 2.1 MW, or a combination thereof.
In some embodiments, the one or more burners are sized to consume oxygen from an electrolysis unit in an amount sufficient to enable complete combustion of the hydrocarbon stream, wherein complete combustion requires x+y/4 moles of O2, wherein x is the total moles of carbon in the hydrocarbon fuel and y is the total moles of hydrogen in the hydrocarbon fuel.
In some embodiments, the one or more burners are sized to produce a heat flux in the range of from 155 kW/m2 to 330 kW/m2, based on the combined surface area of the radiant coil and the convection coil. In some embodiments, the radiant coil is sized to facilitate a heat flux in the range of from 150 kW/m2 to 315 kW/m2, based on the surface area of the radiant coil. In some embodiments, the convection coil is sized to facilitate a heat flux in the range of from 5 kW/m2 to 15 kW/m2, based on the surface area of the convection coil.
In some embodiments, the combination of the radiant coil and the convection coil is sized to facilitate heat recovery greater than or equal to 5.0 MW, greater than or equal to 6.0 MW, greater than or equal to 7.0 MW, or greater than or equal to 8.0 MW, based on the surface area of the radiant and convection coils. In some embodiments, the combination of the radiant coil and the convection coil is sized to facilitate heat recovery less than or equal to 18.0 MW, less than or equal to 17.0 MW, less than or equal to 16.0 MW, or less than or equal to 15.0 MW, based on the surface area of the radiant and convection coils. In some embodiments, the combination of the radiant coil and the convection coil is sized to facilitate heat recovery in the range of from 5.0 MW to 18.0 MW, from 6.0 MW to 17.0 MW, from 7.0 MW to 16.0 MW, or from 8.0 MW to 15.0 MW, based on the surface area of the radiant and convection coils.
In some embodiments, the radiant section has a maximum inlet temperature in the range of from 1,000° C. to 2,100° C. In some embodiments, the radiant section has an exit temperature in the range of from 200° C. to 600° C. In some embodiments, the difference between the maximum temperature in the radiant section and the exit temperature of the radiant section is greater than or equal to 100° C., greater than or equal to 200° C., greater than or equal to 300° C., or greater than or equal to 400° C. In some embodiments, the difference between the maximum temperature in the radiant section and the exit temperature of the radiant section is less than or equal to 1900° C., less than or equal to 1500° C., less than or equal to 1100° C., or less than or equal to 700° C. In some embodiments, the difference between the maximum temperature in the radiant section and the exit temperature of the radiant section is in the range of from 100° C. to 1900° C., from 200° C. to 1500° C., from 300° C. to 1100° C., or from 400° C. to 700° C.
In some embodiments, the radiant section has an exit temperature (i.e., entrance temperature to the convection section) in the range of from 200° C. to 600° C. In some embodiments, the convection section has an exit temperature in the range of from 50° C. to 150° C. In some embodiments, the difference between the exit temperature of the radiant section (i.e., entrance temperature to the convection section) and the exit temperature of the convection section is greater than or equal to 100° C., greater than or equal to 200° C., greater than or equal to 300° C., or greater than or equal to 400° C. In some embodiments, the difference between the exit temperature of the radiant section (i.e., entrance temperature to the convection section) and the exit temperature of the convection section is less than or equal to 550° C., less than or equal to 450° C., less than or equal to 350° C., or less than or equal to 150° C. In some embodiments, the difference between the exit temperature of the radiant section (i.e., entrance temperature to the convection section) and the exit temperature of the convection section is in the range of from 100° C. to 550° C., from 200° C. to 450° C., from 300° C. to 350° C., or from 400° C. to 150° C.
In some embodiments, steam enters the radiant coil at a temperature in the range of from 250° C. to 425° C. and exits the radiant coil as superheated steam at a temperature in the range of from 450° C. to 650° C. In some embodiments, the radiant coil is configured to add sensible heat to incoming steam to produce superheated steam without any phase change on the steam side of the radiant coil. In some embodiments, the temperature difference between the steam entering the radiant coil and the superheated steam exiting the radiant coil is greater than or equal to 100° C., greater than or equal to 125° C., greater than or equal to 150° C., or greater than or equal to 175° C. In some embodiments, the temperature difference between the steam entering the radiant coil and the superheated steam exiting the radiant coil is less than or equal to 400° C., less than or equal to 350° C., less than or equal to 300° C., or less than or equal to 250° C. In some embodiments, the temperature difference between the steam entering the radiant coil and the superheated steam exiting the radiant coil is in the range of from 100° C. to 400° C., from 125° C. to 350° C., from 150° C. to 300° C., or from 175° C. to 250° C.
In some embodiments, the steam enters the convection coil at a temperature in the range of from 125° C. to 315° C. and exits the convection coil at a temperature in the range of from 315° C. to 425° C. In some embodiments, the convection coil is configured to add sensible heat to incoming steam to produce superheated steam without any phase change on the steam side of the convection coil. In some embodiments, the temperature difference between the steam entering the convection coil and the superheated steam exiting the convection coil is greater than or equal to 25° C., greater than or equal to 50° C., greater than or equal to 75° C., or greater than or equal to 100° C. In some embodiments, the temperature difference between the steam entering the convection coil and the superheated steam exiting the convection coil is less than or equal to 300° C., less than or equal to 250° C., less than or equal to 200° C., or less than or equal to 150° C. In some embodiments, the temperature difference between the steam entering the convection coil and the superheated steam exiting the convection coil is in the range of from 25° C. to 300° C., from 50° C. to 250° C., from 75° C. to 200° C., or from 100° C. to 150° C.
In some embodiments, the convection section is sized to facilitate heat recovery greater than or equal to 0.2 WM, greater than or equal to 0.4 MW, greater than or equal to 0.6 MW, or greater than or equal to 0.8 MW, based on the surface area of the radiant and convection coils. The fired heater of claim 1, wherein the convection section is sized to facilitate heat recovery less than or equal to 1.6 MW, less than or equal to 1.4 MW, less than or equal to 1.2 MW, or less than or equal to 1.0 MW, based on the surface area of the radiant and convection section coils. The fired heater of claim 1, wherein the convection section is sized to facilitate heat recovery in the range of from 0.2 MW to 1.6 MW, from 0.4 MW to 1.4 MW, from 0.6 MW to 1.2 MW, or 0.8 MW to 1.0 MW, based on the surface area of the radiant and convection coils.
In some embodiments, the convection section is sized to process second cooled combustion products in an amount in the range of from 7.5 tonne/hr to 15.0 tonne/hr. In some embodiments, the convection section is sized to process carbon dioxide in an amount in the range of from 1.5 tonne/hr to 7.5 tonne/hr.
Also disclosed herein is a process for operating a fired heater system comprising: i) one or more burners configured to accept a hydrocarbon stream, an oxygen stream, and a diluent gas stream; ii) a radiant section comprising a firebox and radiant coil; iii) a convection section comprising a convection coil and a convection inter-tube space defined by the outer surface of the convection coil; and iv) a carbon dioxide recovery section. The process comprises: a) feeding the hydrocarbon stream and the oxygen stream to the one or more burners, and the diluent gas stream to the one or more burners and/or the firebox; b) combusting the hydrocarbon stream and the oxygen feed stream to produce heat and combustion products; c) transferring a first heat flux from the combustion products to the radiant coil to produce first cooled combustion products at a discharge from the radiant section and high pressure superheated stream from high pressure steam in the radiant section coil; d) transferring a second heat flux from the first cooled combustion products to the convection coil to produce second cooled combustion products at a discharge from the convection section and medium pressure superheated stream from medium pressure steam in the convection section coil; and e) transferring a third heat flux from the second cooled combustion products to the condensing coil to produce third cooled products comprising a non-condensables stream, comprising carbon dioxide, and a water stream.
In some embodiments of the process, the hydrocarbon stream comprises a hydrocarbon synthesis (HS) system purge gas, a HS system off gas, a synthetic liquid gas (SLG), a synthetic light distillate (SLD), light oxygenates steam, or a combination thereof.
In some embodiments of the process, the oxygen stream is produced from an electrolysis unit.
In some embodiments of the process, the diluent gas stream added to the one or more burners and/or the firebox comprises a portion of the carbon dioxide product stream from the carbon dioxide recovery section.
In some embodiments of the process, the hydrocarbon stream is free of any components derived from petroleum.
In some embodiments of the process, the one or more burners consume SLD in an amount in the range of from 0 tonne/hr to 2.0 tonne/hr, SLG in an amount in the range of from 0 tonne/hr to 0.15 tonne/hr, combined HS system purge gas and HS system off gas in an amount in the range of from 0 tonne/hr to 1.5 tonne/hr; or a combination thereof.
In some embodiments of the process, the one or more burners combust vaporized SLD in an amount sufficient to produce heat energy in the range of from 0 MW to 21.0 MW, vaporized SLG in an amount sufficient to produce heat energy in the range of from 0.0 MW to 2.1 MW, or a combination thereof.
In some embodiments of the process, the oxygen fed to the one or more burners is produced from an electrolysis unit. In some embodiments, the amount of oxygen fed to the one or more burners is sufficient to enable complete combustion of the hydrocarbon stream, wherein complete combustion requires x+y/4 moles of O2, x is the total moles of carbon in the hydrocarbon fuel, and y is the total moles of hydrogen in the hydrocarbon fuel.
In some embodiments of the process, the one or more burners produce a heat flux in the range of from 155 kW/m2 to 330 kW/m2, based on the combined surface area of the radiant coil and the convection coil. In some embodiments, the radiant coil is sized to facilitate a heat flux in the range of from 150 kW/m2 to 315 kW/m2, based on the surface area of the radiant coil. In some embodiments, the convection coil is sized to facilitate a heat flux in the range of from 5 kW/m2 to 15 kW/m2, based on the surface area of the convection coil.
In some embodiments of the process, the composition for the combined hydrocarbon fuel stream comprising HS system purge gas, HS system off gas, optionally SLG, and optionally SLD comprises each of the constituents in the table below in an amount greater than or equal to one of the lower limits in the alternative, less than or equal to the upper limits in the alternative, or in a range defined by one of the lower limits and one of the upper limits, wherein the sum of the constituents is 100% of the hydrocarbon fuel stream.
In some embodiments of the process, the operating condition parameters for the combined hydrocarbon fuel stream comprising HS system purge gas, HS system off gas, optionally SLG, and optionally SLD are shown in the table below.
In some embodiments of the process, the combination of the radiant coil and the convection coil recovers greater than or equal to 5.0 MW, greater than or equal to 6.0 MW, greater than or equal to 7.0 MW, or greater than or equal to 8.0 MW, based on the surface area of the radiant and convection coils. In some embodiments, the combination of the radiant coil and the convection coil recovers less than or equal to 18.0 MW, less than or equal to 17.0 MW, less than or equal to 16.0 MW, or less than or equal to 15.0 MW, based on the surface area of the radiant and convection coils. In some embodiments, the combination of the radiant coil and the convection coil recovers heat in the range of from 5.0 MW to 18.0 MW, from 6.0 MW to 17.0 MW, from 7.0 MW to 16.0 MW, or from 8.0 MW to 15.0 MW, based on the surface area of the radiant and convection coils.
In some embodiments of the process, the carbon dioxide recovery section recovers greater than or equal to 0.8 MW, greater than or equal to 1.0 MW, greater than or equal 1.2 MW, or greater than or equal to 1.4 MW, based on the surface area of the radiant, convection and carbon dioxide recovery coils. The fired heater of claim 1, wherein the carbon dioxide recovery section recovers less than or equal to 2.6 MW, less than or equal to 2.4 MW, less than or equal to 2.2 MW, or less than or equal to 2.0 MW, based on the surface area of the radiant, convection and carbon dioxide recovery coils. The fired heater of claim 1, wherein the carbon dioxide recovery section recovers heat in the range of from 0.8 MW to 2.6 MW, from 1.0 MW to 2.4 MW, from 1.2 MW to 2.2 MW, or from 1.4 MW to 2.0 MW, based on the surface area of the radiant, convection and carbon dioxide recovery coils.
In some embodiments of the process, the radiant section has a maximum inlet temperature in the range of from 1,000° C. to 2,100° C. In some embodiments, the radiant section has an exit temperature in the range of from 200° C. to 600° C. In some embodiments, the difference between the maximum temperature in the radiant section and the exit temperature of the radiant section is greater than or equal to 100° C., greater than or equal to 200° C., greater than or equal to 300° C., or greater than or equal to 400° C. In some embodiments, the difference between the maximum temperature in the radiant section and the exit temperature of the radiant section is less than or equal to 1900° C., less than or equal to 1500° C., less than or equal to 1100° C., or less than or equal to 700° C. In some embodiments, the difference between the maximum temperature in the radiant section and the exit temperature of the radiant section is in the range of from 100° C. to 1900° C., from 200° C. to 1500° C., from 300° C. to 1100° C., or from 400° C. to 700° C.
In some embodiments of the process, the radiant section has an exit temperature (i.e., entrance temperature to the convection section) in the range of from 200° C. to 600° C. In some embodiments, the convection section has an exit temperature in the range of from 50° C. to 150° C. In some embodiments, the difference between the exit temperature of the radiant section (i.e., entrance temperature to the convection section) and the exit temperature of the convection section is greater than or equal to 100° C., greater than or equal to 200° C., greater than or equal to 300° C., or greater than or equal to 400° C. In some embodiments, the difference between the exit temperature of the radiant section (i.e., entrance temperature to the convection section) and the exit temperature of the convection section is less than or equal to 550° C., less than or equal to 450° C., less than or equal to 350° C., or less than or equal to 150° C. In some embodiments, the difference between the exit temperature of the radiant section (i.e., entrance temperature to the convection section) and the exit temperature of the convection section is in the range of from 100° C. to 550° C., from 200° C. to 450° C., from 300° C. to 350° C., or from 400° C. to 150° C. The process of claim 22, wherein steam enters the radiant coil at a temperature in the range of from 250° C. to 425° C. and exits the radiant coil at a temperature in the range of from 450° C. to 650° C.
In some embodiments of the process at normal flow conditions, the operating condition parameters for the combustion products in the fire box are shown in the table below.
In some embodiments of the process, the composition for the combustion products exiting the radiant section and entering the convection section comprises each of the constituents in the table below in an amount greater than or equal to one of the lower limits in the alternative, less than or equal to the upper limits in the alternative, or in a range defined by one of the lower limits and one of the upper limits, wherein the sum of the constituents is 100% of the hydrocarbon fuel stream.
In some embodiments of the process at normal flow conditions, the operating condition parameters for the combustion products exiting the radiant section and entering the convection section are shown in the table below.
In some embodiments of the process, the steam enters the convection coil at a temperature in the range of from 125° C. to 315° C. and exits the convection coil at a temperature in the range of from 315° C. to 425° C. In some embodiments, the convection coil is configured to add sensible heat to incoming steam to produce superheated steam without any phase change on the steam side of the convection coil. In some embodiments, the temperature difference between the steam entering the convection coil and the superheated steam exiting the convection coil is greater than or equal to 25° C., greater than or equal to 50° C., greater than or equal to 75° C., or greater than or equal to 100° C. In some embodiments, the temperature difference between the steam entering the convection coil and the superheated steam exiting the convection coil is less than or equal to 300° C., less than or equal to 250° C., less than or equal to 200° C., or less than or equal to 150° C. In some embodiments, the temperature difference between the steam entering the convection coil and the superheated steam exiting the convection coil is in the range of from 25° C. to 300° C., from 50° C. to 250° C., from 75° C. to 200° C., or from 100° C. to 150° C.
In some embodiments of the process, the composition for the combustion products exiting the convection section and entering the carbon dioxide recovery section comprises each of the constituents in the table below in an amount greater than or equal to one of the lower limits in the alternative, less than or equal to the upper limits in the alternative, or in a range defined by one of the lower limits and one of the upper limits, wherein the sum of the constituents is 100% of the hydrocarbon fuel stream.
In some embodiments of the process at normal flow conditions, the operating condition parameters for the combustion products exiting the convection section and entering the carbon dioxide recovery section are shown in the table below.
In some embodiments of the process, the carbon dioxide recovery section processes second cooled combustion products in an amount in the range of from 7.5 tonne/hr to 15.0 tonne/hr. In some embodiments of the process, the carbon dioxide recovery section processes carbon dioxide in an amount in the range of from 0.0 tonne/hr to 7.5 tonne/hr.
Also disclosed herein is a method of optimizing operating conditions of a fired heater. The method comprises monitoring composition and amount of a hydrocarbon stream and oxygen to one or more burners in a fired heater in real-time, adjusting oxygen flow based on changes to the composition and amount of the hydrocarbon stream, and, controlling a combustion temperature of the hydrocarbon stream and the oxygen through addition of a diluent gas.
In some embodiments, the method further comprises analyzing historical operating data using machine learning algorithms and refining control strategies based on the analysis.
In some embodiments, the method further comprises monitoring overall thermal efficiency, monitoring CO2 capture rate and/or purity, monitoring load following capability, monitoring net power output considering electrolyzer consumption, or a combination thereof.
In some embodiments, the method further comprises using digital twin models for system simulation and optimization.
In some embodiments, the method further comprises performing advanced exergy analysis to identify areas of thermodynamic inefficiency.
In some embodiments, the method further comprises monitoring multiple fuel source compositions, adjusting oxygen flow rates in response to composition changes, and maintaining stable combustion conditions.
In some embodiments, the method further comprises implementing model predictive control for multi-variable optimization.
In some embodiments, the method further comprises analyzing heat transfer effectiveness, optimizing heat recovery, and minimizing energy losses.
In some embodiments, the method further comprises managing multiple operating modes, transitioning between modes, and maintaining stable operation during transitions.
The process disclosed herein has a number of nonsaleable hydrocarbon byproduct streams, including but not limited to HS system purge gas, HS system off gas, SLG, SMD, oxygenates, or a combination thereof. Use of steam methane reforming (SMR), partial oxidation (POx), or autothermal reforming (ATR) might also be considered for processing these hydrocarbon streams.
SMR reactors are designed to process light hydrocarbons like methane. Processing such a variety of hydrocarbon feeds in a steam methane reformer would require extensive pretreatment, compression, heating, and purification. Heavier hydrocarbons, such as naphtha, tend to create issues like carbon formation (coking), which can deactivate the SMR catalyst, create hot spots which leads to thermal damage, reduce reactor efficiency, and/or require a process shutdown to remove. Therefore, use of SMR in the disclosed process would require significantly more process steps to make the feed more compatible with the SMR process, increase cost, increase complexity, and reduce plant reliability.
The hydrocarbon feeds and oxygen from the electrolysis unit could be fed to a POx reactor to produce syngas. However, processing such a variety of hydrocarbon feeds in a POx would require extensive pretreatment, compression, heating, and purification. Additionally, the broad spectrum and composition of hydrocarbon fuels makes it difficult to achieve careful control oxygen rates in the feed to the POx reactor during different modes of plant operation. Therefore, use of a POx in the disclosed process would require significantly more process steps to make the feed more compatible, additional intermediate storage, online monitoring of hydrocarbon streams, increased cost, increased complexity, and reduced plant reliability.
An autothermal reformer (ATR) combines features of both SMR and partial oxidation processes by using oxygen and steam together to convert hydrocarbons into syngas (a blend of hydrogen and carbon monoxide) through partial oxidation. High pressure and medium pressure steam from the HS system and O2 from the electrolysis unit could be combined with the hydrocarbon streams to feed an ATR to produce syngas directly. As with the SMR the ATR requires extensive processing steps to condition the feedstock and like the POx the unit requires careful control to ensure correct quantities of oxygen are provided to reform the broad spectrum of hydrocarbon streams. Therefore, use of the ATR in the disclosed process would require more processing steps, increased cost, increased complexity, and reduced plant reliability.
Any of SMR, POx, or ATR might also superheat medium and high pressure steam returning from the HS system. Any of SMR, POx, or ATR also require significant additional compressors since they have operating pressures of 20-30 bar or more, while an OFH operates at atmospheric pressure. This adds complexity, reduces plant reliability, and requires steam from the process utilities to drive the compressors. However, none of SMR, POx, or ATR produce heat at the quantity and quality required to achieve integration with the RCFER. Therefore, neither the SMR, POx or ATR provide for the overall improved energy efficiency, improved carbon efficiency, increased water recovery, reduced flaring, and/or reduced environmental footprint of the RCFER system or the combined RCFER and HS systems as is accomplished by the use of an OFH as described herein.
Oxygen-fired heater reactions and apparatuses useful in the process disclosed herein are described in more detail in U.S. Pub. Nos. 2022/0033324A1, 2018/0237323A1, 2013/0095437A1, 2004/0259045A1; U.S. Pat. Nos. 6,416,317, 5,921,771, 5,516,279, 4,986,748, and 4,954,076; and Oxyfuel combustion for CO2 capture in power plants, https://www.sciencedirect.com/science/article/abs/pii/S1750583615002637; Oxy-Combustion, https://netl.doe.gov/node/7477; Oxy Combustion with CO2 Capture, https://www.globalccsinstitute.com/archive/hub/publications/29761/co2-capture-technologies-oxy-combustion.pdf; and Oxy Combustion Processes for CO2 Capture from Power Plant, https://ieaghg.org/docs/General_Docs/Reports/Report%202005-9%20oxycombustion.pdf, all of which are fully incorporated by reference herein for all jurisdictions in which such incorporation is permitted.
In some embodiments, in addition to environmentally compliant aspects of the core process of producing synthetic hydrocarbons, the process herein includes improvements to peripheral and/or infrastructure processes, such as, but not limited to processing of wastewater.
Historically, process wastewater produced in a FT reactor and/or hydrocracking reactor is treated in a Water Fractionation Unit (WFU) followed by a Bio-Treatment Unit (BTU). The treated water is then typically discharged to local waterways. The BTU also produces a significant bio-sludge stream which requires dewatering and offsite disposal.
The process disclosed herein replaces the BTU with an anaerobic biodigester. This change reduces bio-sludge production, reduces equipment, reduces plot space, and provides a biogas stream (CO2 and CH4), which is recovered and consumed in the HS.
The biogas recovery stream (from the anaerobic biodigester) is added to the HS improving carbon and hydrogen efficiency. Water from the anaerobic biodigester is recovered to the process via the desalinization unit. This improves water efficiency and reduces environmental impact.
In some embodiments, the process implemented in the eFuels plant further comprises feeding wastewater withdrawn from the HS system to an anaerobic biodigester. Anaerobic biodigestion conditions are implemented in the anaerobic biodigester to convert the process wastewater stream to a first gas product stream, a first treated water stream, and a first digestate solid. The first gas product stream comprises carbon dioxide, methane, or a combination thereof.
In some embodiments, the process disclosed herein further comprises adding the first treated water stream from the anaerobic biodigester to an aerobic biodigester, wherein the first treated water stream comprises a second organic material. Aerobic biodigestion conditions are implemented in the aerobic biodigester to convert the first treated water stream to a second gas product stream, a second treated water stream, and a second digestate solid. The second treated water stream is introduced to the thermal desalination unit as additional feed. Alternately, if the thermal desalination unit is not available, the second treated water stream can be discharge to the seawater outfall.
The foregoing discloses and describes processing units, an arrangement of processing flow units, and process streams flowing between such processing units in the RFCER system. Various aspects of the processing units, the arrangement of processing flow units, and the process streams flowing between such processing units disclosed herein contribute to a reduced carbon footprint, improved carbon efficiency, improved hydrogen efficiency, and/or improved energy efficiency of the eFuels plant and disclosed herein relative to conventional production of synthetic hydrocarbon fuels.
The disclosed RFCER system provides an ability to continue stable operations of the eFuels plant in spite of fluctuations in the electrical grid, or the stability of the electrical grid, all through providing a plurality of operational modes and an ability to switch between such operational modes while maintaining a stable production rate of synthetic liquid hydrocarbon products from the process of the disclosed invention. Electrical flexibility is provided by deployment of electrolyzer technology and optimal use of hydrogen storage, carbon dioxide storage, SLG storage, and batteries. Emissions are minimized and carbon efficiency is maximized by deployment of oxygen-fired heater technology. Carbon and hydrogen efficiency are maximized by recycling SLG produced by the HS system and gas, comprising methane and/or carbon dioxide, produced by anaerobic wastewater treatment.
In some embodiments, in addition to the carbon efficiency, hydrogen efficiency, and/or energy efficiency of the basic arrangement and operation of the RFCER system, additional incremental improvements in carbon efficiency, hydrogen efficiency, and/or energy efficiency are achieved by Electrical Load Balancing/Electrical Grid Stabilization, Integration of eFuels Plant with External Facilities, Desalination Optimization, Heat Recovery from Electrolysis Unit, Oxygen-fired heater Optimization, Heat Transport to the HS System, Wastewater Containment Flexibility, DAC Optimization, Electrically Heated Steam Boiler.
In some embodiments, the combination of PEMs, AECs, batteries and/or fuel cells, H2 storage, and SLG storage provides a fast response time for electrical load balancing and electrical grid stabilization and a significant range for maximum electrical load to minimum electrical load (i.e., from maximum electrolysis unit rates to shutting down all or a portion of the electrolysis unit or any rate in between for some period).
In some embodiments, batteries and/or fuels cells can activate to maintain electrolysis unit stability even with a nearly instantaneous reduction in power for the electrical supplier (the grid). When grid power is prevalent, electricity can by routed to charge batteries to be ready for low power excursion of the grid or when grid power is more limited.
In some embodiments, SLG withdrawn from storage can be added to the HS system to reduce H2 feed requirements to the HS systems. This provides another measure to permit turning down electrolysis unit rates with minimal or no effect on HS system operations. Alternatively, SLG withdrawn from storage can be added to the HS system while maintaining electrolysis unit rates and HS system rates constant, thus allowing production of excess H2 to build inventory in H2 storage. Alternatively, H2 rates to the HS system, from electrolysis unit production, H2 storage, or combination thereof, can be maximized to back out SLG feed to the HS system and permit building SLG inventory.
In some embodiments, CO2 production rates and addition to or withdrawal from CO2 storage can be varied independently from H2 production rates and addition to or withdrawal from H2 storage while maintaining the required ratio of CO2 and H2 feed to the HS system. This allows strategic control of both CO2 and H2 inventories to further isolate HS system operations from grid fluctuations.
In some embodiments, any one of the above steps can be taken independently to the minimum or maximum extent for that step individually, or maintained at some intermediate level between the minimum and maximum for a period of time as needed to accommodate grid fluctuations. In some embodiments, any two or more of the above steps can be taken in combination, wherein each step is implemented to its minimum extent, its maximum extent, or any level in between the minimum and maximum, to accommodate larger and/or more extended grid fluctuations.
These control steps, taken individually or in combination, serve to isolate the HS system from short term grid fluctuations and/or provide time for the HS system operations to be controllably adjusted to more extended reductions in grid power.
Integration of eFuels Plant with External Facilities
In some embodiments, the eFuels plant is integrated with an adjacent biomass anaerobic biodigestion plant, where low-grade heat is supplied to facilitate production of renewable methane. Biomass can be any plant-based material including straw, wood chips, bamboo, and agricultural waste. The biodigestion produces a biogas stream which comprises of CO2 and CH4. Purification is used to produce pipeline specification natural gas by removing the CO2. Hence biogenic CO2 is made as a byproduct. To prevent venting, this CO2 is supplied to the eFuels plant as feedstock. Low-grade heat from the eFuels Plant would normally be removed via air cooling. Co-location and heat/CO2 integration improves material, energy, and cost efficiencies for both facilities.
In some embodiments, the steam turbine generator receives excess steam and generates electricity, and the turbine operating conditions are optimized for electricity production. Dependent on the temperature required for low-grade heat export, the STG exhaust pressure can be optimized for production of heat for export to customers.
In some embodiments, the water produced through desalination is used in the process only.
In some embodiments water production is maximized through extended heat integration to enable export to customers.
In some embodiments, the desalination brine is recovered, and in combination with a zero liquid discharge unit, will maximize utilization of heat produced by the process, and remove the environmental impact of the effluent streams when discharged to the environment.
Heat Recovery from Electrolysis Unit
In some embodiments waste heat generated by the electrolysis unit is recovered and either used directly or upgraded using a heat pump system.
In some embodiments, a tempered water loop is used to supply heat for export and thermal desalination. Low-grade heat is first recovered from the electrolysis unit and then increased in temperature using the heat pump heat recovery system. Tempered water returned from users is cooled in the heat pump evaporator and supplied to the electrolysis unit for heat recovery. The heat pump comprises an evaporator, a compressor, a condenser, an expansion valve, and a recirculating heat transfer medium, such as, but not limited to, a high-pressure gas with a low boiling point, such as LPG, ammonia or freon.
The heat pump process begins with the evaporator, which is typically a heat exchanger located to recover waste heat from one or more locations in the electrolysis unit requiring heat removal to control the process. A refrigerant is circulated through the evaporator, absorbing the heat from the process stream and turning it into a low-pressure vapor. The vapor then passes through the compressor, which raises the pressure and temperature of the refrigerant. The high-pressure vapor is then directed to the condenser, which is another heat exchanger located in the thermal desalination unit for use in the desalination process. The refrigerant gives off its heat to the thermal desalination unit, which is at a lower temperature than the waste heat stream. As the refrigerant cools, it condenses back into a high-pressure liquid. The high-pressure liquid then passes through the expansion valve, where the pressure is lowered and the refrigerant is allowed to expand back into a low-pressure vapor, thus completing the heat pump cycle.
This recovered and/or upgraded heat is exported to adjacent users and/or supplied to the thermal desalination unit as a heating medium, thus further improving energy efficiency of the eFuels plant.
In some embodiments, a portion of the flue gas produced in the combustion zone of the oxygen-fired heater is cooled and recirculated to the oxygen-fired burner to control the combustion temperature and prevent excessive combustion zone temperatures resulting in mechanical damage (overheating) to flue gas duct heat exchangers.
In some embodiments, the flue gas generated in the combustion zone of the oxygen-fired heater is cooled to condense water from the flue gas exiting the oxygen-fired heater. The condensed water is separated from the cooled flue gas and is recovered as additional feed to the desalination process. Recovery of OFH condensed water reduces the plant seawater consumption.
In some embodiments, when the HS is offline at least a portion or all of the anaerobic biodigester biogas stream, comprising methane and carbon dioxide, is sent as a fuel to the combustion zone of the oxygen-fired heater. The biogas combustion provides heat and CO2 for recovery. Since oxygen is used in the combustion of fuel instead of air, no additional N2 is added to the combustion zone to generate additional NOx.
In some embodiments, a portion of the superheated steam is provided to the HS system to provide heat to one or more processes in the HS system. This reduces or removes the requirement for one or more conventional fired heaters in the HS system. In combination with the OFH, this eliminates fired point sources thus reducing flue gas emissions comprising carbon dioxide and other criteria pollutants to the environment including nitrogen oxide compounds (NOx).
In some embodiments, if the anaerobic biodigester is offline, the process wastewater stream, comprising a first organic material, can be bypassed and fed directly to the aerobic biodigester, maintaining treatment capacity and keeping discharged water within discharge limits.
In some embodiments, intermediate tank storage is included downstream of the HS systems and upstream of the anaerobic biodigestion unit to act as a buffer between the HS system and the anaerobic biodigestion unit. This buffer ensures a consistent quality of feed to the anaerobic biodigestion unit, thus improving reliability of the anaerobic biodigestion unit and consistency of the treated water product from the anaerobic biodigestion unit. The intermediate tank storage also allows streams containing organic material to be diverted to the OFH if the anaerobic biodigestion unit is unavailable. This further enhances operational flexibility and efficiency of both the wastewater system and the eFuels plant. The storage tanks also allow the anaerobic digestor to be bypassed and wastewater streams from the HS system to instead be fed directly to the aerobic system, further improving operational flexibility and efficiency of both the wastewater system and the eFuels plant.
In some embodiments, the DAC unit can be co-located and integrated with the HS system and RFECR for exchange of heat and maximum energy efficiency. The DAC unit removes CO2 from air into a liquid or solid substrate. To desorb CO2, the DAC substrate or liquid is heated producing a CO2 stream. This stream is then cooled, compressed, and purified. The DAC unit requires low-grade heat for the desorption of CO2 and other utilities. The HS produces surplus low-grade heat in the form of hot water which can be provided for DAC desorption. The OFH CO2 compression and purification can also be integrated with the DAC unit for treatment of the DAC produced CO2. This integration improves the overall energy and cost efficiency of the DAC and eFuels Plant.
In some embodiments, an electrically heated steam boiler (eBoiler) is used to supply pressurized steam for start-up, shutdown, and normal operation. Boiler feed water is supplied to the eBoiler from the boiler feed water pump. Steam is produced between the electrodes within the eBoiler steam drum. Steam accumulates in the upper part of the steam drum and is released to the eFuels Plant steam system through the main steam valve. The eBoiler replaces the traditional natural gas fired boiler removing an emissions source, further reducing the carbon and pollutant footprint of the eFuels plant.
Alternate Configurations of the eFuels Plant
In alternate embodiments of the process disclosed herein, eMethanol and related products are produced instead of SLG, SLD, SMD, and SHD. In these embodiments, a methanol synthesis (MS) system is substituted for the HS system, such that an eMethanol plant comprises a RFCER system and a MS system. The MS system comprises a syngas unit, methanol synthesis unit, and methanol purification (distillation). Products withdrawn from the MS system include: 1) topping column light products including TMA, etc. (analogous to SLG from HS system); 2) methanol from refining column (analogous to SLD from HS system); 3) fusel oil from refining column including ethanol, butanol, and/or DME (analogous to SMD from HS system); and refining column bottoms comprising water (analogous to SHD from HS system). In some embodiments, purge gas from methanol synthesis is sent to OFH as fuel. High pressure steam from the MS syngas unit, and medium pressure steam from the MS methanol synthesis are sent to the OFH for superheating. Steam/heat is provided to the MS methanol purification for methanol refining. Process wastewater from the MS system is sent to the anaerobic unit.
In alternate embodiments of the process disclosed herein, eGasoline and related products, such as eKerosene, are produced instead of SLG, SLD, SMD, and SHD. In these embodiments, a gasoline synthesis (GS) system is substituted for the HS system, such that an eGasoline plant comprises a RFCER system and a GS system. The GS system comprises the units described above in a MS system plus a methanol-to-gasoline (MTG) reactor and/or a methanol-to-kerosene (MTK) reactor to produce gasoline and/or kerosene from methanol/DME. To produce eChemicals, comprising fine chemicals (e.g., cosmetics and pharmaceuticals) and other chemical products (solvent feedstock, detergent feedstock, base oil waxes, Fischer-Tropsch liquids as synthetic crude oil) the GS refining section can be modified by introducing one or more of the following: vacuum distillation columns, isomerization reactor, hydrogenation reactor, and/or normal paraffin extraction units to produce solvent feedstock, detergent feedstock, base oil waxes, and/or Fischer-Tropsch liquids as synthetic crude oil.
In some embodiments, the process implemented in an eFuels plant as described herein produces one or more synthetic hydrocarbon products which have a carbon dioxide intensity of less than a few percent to approximately zero.
In a first set of embodiments, a fired heater, comprises:
A second set of embodiments of the fired heater comprises each embodiment of the first set of embodiments, wherein each such embodiment is further characterized by one or more of:
In another aspect, a third set of embodiments comprises a process for operating a fired heater system. The process comprises:
A fourth set of embodiments comprises each embodiment of the third set of embodiments, wherein each such embodiment is further characterized by one or more of:
In another aspect, a fifth set of embodiments comprises a method of optimizing operating conditions of a fired heater. The method comprises:
A sixth set of embodiments comprises each embodiment of the fifth set of embodiments, wherein each such embodiment further comprises:
A seventh set of embodiments comprises each embodiment of the fifth and sixth sets of embodiments, wherein each such embodiment further comprises:
An eighth set of embodiments comprises each embodiment of the fifth, sixth, and seventh sets of embodiments, wherein each such embodiment further comprises using digital twin models for system simulation and optimization.
A ninth set of embodiments comprises each embodiment of the fifth, sixth, seventh, and eighth sets of embodiments, wherein each such embodiment further comprises performing advanced exergy analysis to identify areas of thermodynamic inefficiency.
A tenth set of embodiments comprises each embodiment of the fifth, sixth, seventh, eighth, and ninth sets of embodiments, wherein each such embodiment further comprises:
An eleventh set of embodiments comprises each embodiment of the fifth, sixth, seventh, eighth, ninth, and tenth sets of embodiments, wherein each such embodiment further comprises implementing model predictive control for multi-variable optimization.
An twelfth set of embodiments comprises each embodiment of the fifth, sixth, seventh, eighth, ninth, tenth and eleventh sets of embodiments, wherein each such embodiment further comprises:
A thirteenth set of embodiments comprises each embodiment of the fifth, sixth, seventh, eighth, ninth, tenth, eleventh, and twelfth sets of embodiments, wherein each such embodiment further comprises:
Specific stream rate information herein is based on a nominal capacity of an eFuels production system producing SLG, SLD, SMD, and SHD totaling approximately 2 kB/D. The split between the various product streams can vary based on selection of RWGS catalyst, FT catalyst, and hydrocracking catalyst as well as other operating conditions on individual process units. One of ordinary skill in the art would recognize that the compositions of synthetic hydrocarbons as disclosed herein are consistent once catalysts and operating conditions are selected. Petroleum-based operations are subject to high variability of both the amounts of products in various boiling ranges and the molecular compositions of such products based on the source of crude oil used as a starting material (e.g., heavy dirty crudes high in sulfur and asphaltenes vs. light sweet crudes low in sulfur and asphaltenes). Petroleum-based products can exhibit significant variability in their composition, even when derived from the “same” crude oil, due to the inherent complexity and variability of natural crude sources and the refining process. Crude oil is a naturally occurring mixture of hydrocarbons with varying molecular structures, along with non-hydrocarbon impurities such as sulfur, nitrogen, and metals. Even crude extracted from the same reservoir can vary over time or across different batches due to changes in reservoir conditions or production methods. Additionally, the refining process, which involves distillation, cracking, reforming, and other chemical processes, introduces further variability depending on operational conditions, equipment, and the specific cutpoints selected for different products. In contrast, synthetic hydrocarbons, such as those described herein, are manufactured under precisely regulated conditions. This consistency allows predictable scale-up of the rates established in a smaller production facility. For example, rates herein based on a nominal 2 kB/D of total products could be ratioed for plants having a total production capacity of 100 kB/D, 200 kB/D, or even 500 kB/D.
Although the disclosed apparatus, process, method, and system have been described in detail, it should be understood that various changes, substitutions and alterations can be made herein without departing from the spirit and scope of the invention as defined by the appended claims. Moreover, the scope of the present application is not intended to be limited to the particular embodiments of the processes, machines, compositions, means, methods, and/or steps described in the specification. As one of the ordinary skill in the art will readily appreciate from the present disclosure, processes, machines, compositions, means, methods, and/or steps, presently existing or later to be developed that perform substantially the same function or achieve substantially the same result as the corresponding embodiments described herein, may be utilized according to the present invention. Accordingly, the appended claims are intended to include within their scope such processes, machines, compositions, means, methods, and/or steps.
The following investigations and examples are intended to be illustrative only, and are not intended to be, nor should they be construed as limiting the scope of the present invention in any way. Overall energy efficiency is improved by maximizing deployment of heat integration between subprocesses of the overall process. Such process integration solutions have been achieved by comprehensive integrated process modelling. The model combines the standard inputs received from the various core technologies deployed with a complete integrated process model of all auxiliary processes.
In Examples 1-7, an AspenTech Hysys computer simulation (ASPENTECH HYSYS V12.1 steady-state simulation) of process streams and conditions was used to simulate embodiments of the invention. The simulated process flow diagram (“PFD”) is shown in
A simplified flow diagram of an eFuels plant 1000 is shown in
In some embodiments, seawater 1402 is collected and sent as feed to desalinization unit 1010 via stream 1402. Desalinated water product from desalinization unit 1010 is sent to demineralization unit 1020 via stream 1012. Brine remaining after removal of the desalinated portion of the seawater is returned to the sea via stream 1404. Demineralization unit 1020 also receives condensate from steam turbine generator 1290 via stream 1292. A portion of the demineralized water is withdrawn from demineralization unit 1020 and sent as feed to electrolysis apparatus 1030 via stream 1022 and electricity 1440 is added as an input to the electrolysis apparatus 1030, wherein water is separated into hydrogen (H2) stream 1032 and oxygen (O2) stream 1034. In some embodiments, fresh water stream 1406 can supplement or replace stream 1036 as feed to electrolysis unit 1030.
A portion of the demineralized water is withdrawn from demineralization unit 1020 and sent as feed to the deaerator unit 1270 via stream 1024. Boiler feedwater is withdrawn from deaerator unit 1270 via stream 1272 and routed to the HS system 1200 to serve as a heat removal medium (boiler feedwater) for one or more process units in the HS system 1200. Stream 1272 is shown as a single boiler feedwater stream delivered to the HS system and returned from the HS system as one or more streams 1124 (in some cases 1124a high pressure steam and/or 1124b medium pressure steam) of steam returning from the HS system 1200 back to the RFCER system. In some embodiments, boiler feedwater stream 1272 and/or steam stream 1124 can each be a network of piping.
Oxygen (O2) is withdrawn from electrolysis apparatus 1030 and sent to the oxygen-fired heater (OFH) 1280 via stream 1034. Hydrogen (H2) stream 1032 is routed to hydrogen storage system (and optionally hydrogen compression system) 1040. The block in
Heat is removed from the electrolysis unit 1030 via stream 1036 to heat integration facilities 1295. Heat is supplied integration facilities 1295 from the steam turbine generator condensate stream 1298. Heat is supplied to desalination unit 1010 via stream 1296, DAC unit 1070 via stream 1297, and/or exported from the eFuels plant via stream 1018. Heat is transported by recirculation of one or more closed loop water streams to remove heat from processes generating heat and delivering heat to processes absorbing heat via water in streams 1036, 1298, 1296, 1297, and 1018. In other embodiments, such closed loops may circulate any convenient heat transfer fluid.
Carbon dioxide is sourced by importing from a source 1090 external to the eFuels plant, such as, but not limited to, generation by degradation of biomass, or onsite production by direct air capture 1070. Carbon dioxide is routed to carbon dioxide compression and storage 1080 via stream 1072. High pressure carbon dioxide is sent from CO2 compression and storage 1080 via stream 1082. The block in
Oxygen stream 1034 is fed to the combustion zone of the OFH 1280 along with a fuel stream 1126, comprising purge gas, off gas, or a combination thereof from the HS system 1200. Optionally, SLG from SLG storage 1210 is sent via stream 1214 as additional fuel to the combustion zone of the OFH 1280. Optionally, SLD from SLD storage 1211 is sent via stream 1215 as additional fuel to the combustion zone of the OFH 1280, as feed to anaerobic biodigester 1250, or a combination thereof. Combustion products comprising CO2 are withdrawn from the combustion zone of the OFH 1280 as stream 1282. Stream 1282 is then sent CO2 compression and storage for further processing consistent with the other CO2 sources.
Steam stream 1124 from the HS system 1200 is fed to the heating zone of the OFH 1280 where heat generated in the combustion zone is added to form superheated steam. High pressure superheated steam is delivered to steam turbine generator 1290 via stream 1284 to produce electricity 1294 for use by one or more process units in the RFCER system and/or the HS system 1200. Superheated medium pressure steam is delivered to the HS system 1200 via stream 1286 to supply heat to one or more process units in the HS system 1200.
Synthetic hydrocarbon product streams, SLG stream 1202, SLD stream 1204, SMD stream 1206, and SHD stream 1208, are withdrawn from the hydrocarbon synthesis system 1200. SLD stream 1204, SMD stream 1206, and SHD stream 1208 are sent to storage and/or distribution by shipping, trucking, and/or pipeline. SLG stream 1202 is sent to the hydrocarbon synthesis system 1200 via stream 1212 as feed to the RWGS unit and/or as fuel to the oxygen-fired heater 1280 via stream 1214.
Process wastewater stream 1242 is withdrawn from the hydrocarbon synthesis system 1200 via stream 1242 as feed to the anaerobic biodigester unit 1250. Gas stream 1254 is withdrawn from the anaerobic biodigester unit 1250 and sent to the hydrocarbon synthesis system 1200, primarily as feed to the RWGS unit. All or a portion of gas stream 1254 can be routed via stream 1255 as fuel to the OFH 1280. Treated wastewater stream 1252 is withdrawn from the anaerobic biodigester unit 1250 and sent as feed to the aerobic biodigester unit 1260. Stream 1243 is a bypass around anaerobic biodigester unit 1250 and only has flow when the anaerobic biodigester unit 1250 is out of service. Treated wastewater stream 1262 is withdrawn from the aerobic biodigester unit 1260 and sent as feed to the thermal desalination unit 1010 and/or to outfall 1264. In some embodiments, clean water is exported outside the eFuels plant 1000 via stream 1014.
In some embodiments, excess heat 1018 remains after heat exchange occurring in heat integration facilities 1295 and can be exported outside the eFuels plant.
Heat is added to the radiant coil 1602 within the firebox and correspondingly removed from the combustion products to produce superheated high pressure steam 1284 from high pressure steam 1124a from the HS system.
Heat is added to the convection coil 1612 within the convection section 1614 and correspondingly removed from the combustion products to produce superheated medium pressure steam 1286 from medium pressure steam 1124b from the HS system.
Further heat is removed from the combustion products (flue gas) by the condensing coil 1622 in the carbon dioxide recovery section 1624 in order to remove water 1628 from the carbon dioxide 1625. Carbon dioxide 1625 is sent to the carbon dioxide recovery unit and subsequently to storage and/or the HS system via line 1282, recycled to the OFH burners 1508 and/or the firebox in the radiant section 1604 to control combustion temperature, or a combination thereof.
In a first embodiment (normal mode 1), hydrocarbon feed to the OFH burners 1508 comprises SLD from SLD storage 1211 via line 1215, SLG from SLG storage 1210 via line 1214, and HS system purge gas and/or off gas 1126. The combined hydrocarbon fuel stream passes through knockout drum 1502 where water 1506 is removed. Dewatered hydrocarbon fuel 1504 is added to OFH burners 1508 along with oxygen 1034 as an oxidant and the resulting combustion produces combustion products and heat in the firebox in the radiant section 1604.
In a second embodiment (normal mode 2), hydrocarbon feed to the OFH burners 1508 comprises SLG from SLG storage 1210 via line 1214, and HS system purge gas and/or off gas 1126 (no SLD from SLD storage 1211 via line 1215). The combined hydrocarbon fuel stream passes through knockout drum 1502 where water 1506 is removed. Dewatered hydrocarbon fuel 1504 is added to OFH burners 1508 along with oxygen 1034 as an oxidant and the resulting combustion produces combustion products and heat in the firebox in the radiant section 1604.
In a third embodiment (normal mode 3), hydrocarbon feed to the OFH burners 1508 comprises SLD from SLD storage 1211 via line 1215, and HS system purge gas and/or off gas 1126 (no SLG from SLG storage 1210 via line 1214). The combined hydrocarbon fuel stream passes through knockout drum 1502 where water 1506 is removed. Dewatered hydrocarbon fuel 1504 is added to OFH burners 1508 along with oxygen 1034 as an oxidant and the resulting combustion produces combustion products and heat in the firebox in the radiant section 1604.
In a fourth embodiment (turndown mode), hydrocarbon feed to the OFH burners 1508 comprises SLD from SLD storage 1211 via line 1215 at minimum rates along with HS system purge gas and/or off gas 1126 (no SLG from SLG storage 1210 via line 1214). The combined hydrocarbon fuel stream passes through knockout drum 1502 where water 1506 is removed. Dewatered hydrocarbon fuel 1504 is added to OFH burners 1508 along with oxygen 1034 as an oxidant and the resulting combustion produces combustion products and heat in the firebox in the radiant section 1604.
In a fifth embodiment (startup mode), HS system purge gas and/or off gas 1126 are unavailable until the HS system has started. Hydrocarbon feed to the OFH burners 1508 comprises SLD from SLD storage 1211 via line 1215 and/or SLG from SLG storage 1210 via line 1214 until the HS system has started. The combined hydrocarbon fuel stream passes through knockout drum 1502 where water 1506 is removed. Dewatered hydrocarbon fuel 1504 is added to OFH burners 1508 along with oxygen 1034 as an oxidant and the resulting combustion produces combustion products and heat in the firebox in the radiant section 1604.
In a sixth embodiment (hot standby shutdown mode), HS system purge gas and/or off gas 1126 are shut down from steady state to zero. SLG from SLG storage 1210 via line 1214 is shut down until the HS system has restarted. Hydrocarbon feed to the OFH burners 1508 comprises SLD from SLD storage 1211 via line 1215 at minimum required to keep the OFH at temperature. The combined hydrocarbon fuel stream passes through knockout drum 1502 where water 1506 is removed. Dewatered hydrocarbon fuel 1504 is added to OFH burners 1508 along with oxygen 1034 as an oxidant and the resulting combustion produces combustion products and heat in the firebox in the radiant section 1604. Produced CO2 is vented and/or sent to CO2 storage.
In a sixth embodiment (cold shutdown mode), the OFH is run to minimum turndown. Then all of the HS system purge gas and/or off gas 1126, SLG from SLG storage 1210 via line 1214, and SLD from SLD storage 1211 via line 1215 are shut off from OFH and send to flare. Carbon dioxide recirculation continues to prevent air ingress.
Table 1 summarizes selected process parameters for various operating regimes of the eFuels plant 1000:
10804
10404
1Normalized to flow rate of CO2 imported in Example 1 in tonnes per hour and reported as parts by weight
2PM2.5, PM10, VOC, NOx, and SOx
3“Imported” includes imported from outside the eFuels plant or produced from DAC
4“Storage” is within box and not shown specifically in Figures
5“Other” is net electricity used in operating the includes imported from outside the eFuels plant or produced from DAC
Equipment, streams, and reference numbers are the same in
Electrolysis unit 1030 rates are reduced to the minimum rate required to produce oxygen to maintain operation of the oxygen-fired furnace via stream 1034. Reduced electrolysis unit rates reduce the flow of hydrogen in stream 1032, and hydrogen is withdrawn from storage via stream 1042 to satisfy the shortfall in hydrogen production due to the reduced electrolysis unit rates. CO2 from import and/or DAC production of CO2 is replaced by 100 parts CO2 from storage. A portion of SLG is withdrawn from storage via line 1212 to maintain balanced operation of the RWGS reactor and resulting production of SMD 1206. Electrolysis unit utility rates (heat, electricity, and water) are all increased. Flows in highlighted streams 1402 and 1012 are shut down along with the thermal desalination unit indicating a significant change from base case Example 1. Highlighted electricity 1440 to electrolysis unit 1030 and stream 1036 to heat integration 1295 indicate significant decrease versus base case Example 1.
Table 1 shows that for 100 parts CO2 consumed in the operation of the eFuels plant, eFuels plant production of SMD is maintained at 26.8 parts of SMD (e.g., jet fuel) and 4.8 parts of SLD with minimized seawater feed or CO2 imported or produced and with no CO2 or criteria pollutants emitted.
Highlighted streams 1402 and 1022 indicate an increase in seawater feed rate relative to base case Example 1. Highlighting of line 1212 indicates an increase in SLG withdrawn from storage to maintain balanced operation of the RWGS reactor and resulting production of SMD 1206. Highlighted stream 1036 indicates an increase heat exported from the electrolysis unit relative to base case Example 1.
Table 1 shows that for 98.7 parts CO2 consumed in the operation of the eFuels plant, 26.8 parts of SMD (e.g., jet fuel) and 4.7 parts of SLD are produced with no CO2 or criteria pollutants emitted.
Highlighted streams 1214, 1255, and 1282 indicate an increase in these rates relative to base case Example 1. Highlighting of line 1254, 1072, and 1212 indicate a decrease in these rates relative to base case Example 1.
Table 1 shows that for 100.3 parts CO2 consumed in the operation of the eFuels plant, 26.8 parts of SMD (e.g., jet fuel) and 3.9 parts SLD are produced with no CO2 or criteria pollutants emitted.
Highlighted streams 1402, 1296, and 1014 indicate an increase in these rates relative to base case Example 1.
Table 1 shows that for 100 parts CO2 consumed in the operation of the eFuels plant, 26.8 parts of SMD (e.g., jet fuel) and 4.7 parts of SLD are produced with no CO2 or criteria pollutants emitted.
Table 1 shows that for 100 parts CO2 consumed in the operation of the eFuels plant, 26.8 parts of SMD (e.g., jet fuel) and 4.7 parts of SLD are produced with no CO2 or criteria pollutants emitted.
Process units and streams highlighted with dashed lines in
Table 1 shows that for 104 parts CO2 consumed in the operation of the eFuels plant, 25.9 parts of SMD (e.g., jet fuel) and 4.7 parts of SLD. However, 7.705E-03 parts of CO2 and 1.932E-05 of criteria pollutants are emitted.
Table 1, above, shows that Examples 1-6 all produce more SMD than Example 7, while Examples 1-6 all have a lower feed rate of CO2 than Example 7.
Table 2, below, summarizes environmental and energy performance parameters for Examples 1-7.
Carbon efficiency, as used herein, means carbon content in products divided by carbon content in feed. Higher carbon efficiency means less carbon emissions from the plant (air or liquid), giving the products the lowest possible carbon intensity. Even with the broad range of operating scenarios in Examples 1-6 with the integrated RFCER system disclosed herein, carbon efficiency ranges from 94.7% to 98.9%. In contrast, Example 7 without the integrated RFCER system demonstrates a carbon efficiency of 91.3%
Electricity is a limited resource, and even more so for an electrical grid powered by renewable energy sources. Higher electrical efficiency translates to higher production rates at constant electrical load and increased operational flexibility when electrical load is more limited. Electrical efficiency, as used herein, means energy content in products divided by plant electrical power consumed in operation of the eFuels plant. At times, hydrogen is supplied to the HS system from the hydrogen storage system, the electrolysis unit can run at reduced rates for a limited time or even be shut down for a short time, giving a higher electrical efficiency for the time period of reduced rates or shutdown, such as is demonstrated by Example 2. At other times, hydrogen production is maximized to send excess hydrogen above HS system feed requirements to the hydrogen storage system, resulting in a lower electrical efficiency, such as is demonstrated in Example 3. The net effect of using H2 from storage during some time periods and filling the H2 storage during other periods results in average electrical efficiency approximately equivalent to the base case electrical efficiency of Example 1, wherein hydrogen production and hydrogen feed rate to the HS system are the same. Even with the broad range of operating scenarios in Examples 1-6, electrical energy efficiency ranges from 32.2% to 154.0%. In contrast, Example 7 demonstrates an electrical energy efficiency of 34.7%. However, this broad range of operating scenarios allows very different instantaneous hydrogen production rates (i.e., different electrolyzer rates and corresponding electrical loads) while maintaining stable operations of the HS system. Without wishing to be bound by any particular theory, it is believed that this stability aspect of the RFCER system actually provides an effective long-term electrical efficiency that more than offsets the slightly higher electrical energy efficiency shown for Example 7 (i.e., inability of the process of Example 7 to efficiently manage fluctuations in the electrical grid).
Total energy efficiency, as used herein, means the sum of energy in eFuels products plus energy exported from the eFuels plant in exported heat divided by the electrical load consumed in operation of the eFuels plant to produce such products and heat exports. Even with the broad range of operating scenarios in Examples 1-6, total energy efficiency ranges from 32.2% to 260.3%. In contrast, Example 1 demonstrates a total energy efficiency of 57.7%, whereas Example 7 shows a total energy efficiency of 34.7%. This demonstrates a significant improvement in energy efficiency for the process described here when compared to the eFuels plant without the integrated RFCER system.
Carbon intensity is a measure of the CO2 emitted over the product lifecycle (i.e., total SLG, SLD, SMD, and SHD exported from the eFuels plant). A high carbon intensity means the product lifecycle is increasing CO2 in atmosphere. A zero carbon intensity means the product lifecycle is not adding or reducing CO2 in atmosphere. A negative carbon intensity means the product is reducing atmospheric CO2. Even with the broad range of operating scenarios in Examples 1-6, product carbon intensity in CO2 consumed in the eFuels plant per tonne of synthetic hydrocarbon product ranges from 0 CO2/t to 0.17 CO2/t. In contrast, Example 7 demonstrates a product carbon intensity of 0.30 CO2/t. Furthermore, Example 7 lacks the operating flexibility as shown by Examples 1-6. Therefore, the flow diagram of Example 7 does not have the ability to respond to fluctuations in power from the electrical grid without causing at least alteration of, and in some cases interruption of, the operation and production rates of the HS system.
1CO2 emitted per tonne of eFuels products (combined production of SLG, SLD, SMD, and SHD exported from the eFuels plant) over the eFuel lifecycle
In summary, the process of Example 1 reduces the electrical efficiency by 1.7% when compared to the process of Example 7, an eFuels plant without the RFCER system (i.e., 34.1/34.7=98.3%). However, the process of Example 1 increases total energy efficiency by 166% compared to the process of Example 7 (i.e., 57.7/34.7=166%), and improves (reduces) carbon intensity by 77% at the same time (i.e., 0.07/0.30=23%). Additionally, the use of seawater significantly reduces freshwater consumption/competition as described in Example 7. The process disclosed herein also reduces the pollutant emissions to the atmosphere. Overall, the process disclosed herein provides more efficient use of natural resources and minimizes environmental impact for the production and use of sustainable liquid hydrocarbons.
The scope of the present application is not intended to be limited to the particular embodiments of the processes, means, methods, and/or steps described in the specification. The particular embodiments disclosed above are illustrative only, as the process and system may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Although the present invention and its advantages have been described in detail, it should be understood that various changes, substitutions and alterations can be made herein without departing from the spirit and scope of the invention as defined by the appended claims.
For the sake of brevity, only certain ranges are explicitly disclosed herein. However, in addition to recited ranges, any lower limit may be combined with any upper limit to recite a range not explicitly recited, as well as, ranges from any lower limit may be combined with any other lower limit to recite a range not explicitly recited, in the same way, ranges from any upper limit may be combined with any other upper limit to recite a range not explicitly recited. Additionally, within a range includes every point or individual value between its end points even though not explicitly recited. Thus, every point or individual value may serve as its own lower or upper limit combined with any other point or individual value or any other lower or upper limit, to recite a range not explicitly recited.
All patents, test procedures, and other documents cited in this application are fully incorporated herein by reference for all jurisdictions in which such incorporation is permitted. In the event of conflict between one or more of the incorporated patents or publications and the present disclosure, the present specification, including definitions, controls.
This application is a continuation-in-part of U.S. patent application Ser. No. 18/203,472, filed on May 30, 2023, entitled “PRODUCTION OF SYNTHETIC HYDROCARBONS,” the entirety of which is incorporated herein by reference. This application claims the benefit of and priority to the above-referenced application under 35 U.S.C. § 120.
| Number | Date | Country | |
|---|---|---|---|
| Parent | 18203472 | May 2023 | US |
| Child | 18964301 | US |
