System and method for retrofitting a brownfield facility

Abstract

The present invention modernizes abandoned or underutilized petrochemical facilities for the production of jet fuel, diesel, naphtha, drilling fuel, and wax. It utilizes converted amine systems and PRISM units in brownfield situations to clean incoming syngas and achieve the optimal H2:CO ratio for conversion. This retrofit and repurposing introduces novel heat transfer elements into the Fischer-Tropsch (FT) reactor and employs proprietary FT catalysts to produce GTL products. It also adds a unique FT analyzer to monitor the hydrocarbon stream and assist in production, and a Coriolis flowmeter to accurately measure liquid wax flow without being affected by wax plugging or vibration. Feedstocks include a variety of sources such as natural gas, biomass, and the like.

Description

Cross-reference to related applications

[0001] This application claims the benefit of U.S. Provisional Application 63 / 538,061, filed September 12, 2023, and U.S. Non-Provisional Application 18 / 593,764, filed March 1, 2024, both entitled “Systems and Methods for Modifying Brownfield Equipment,” the entire contents of which are incorporated herein by reference. Technical Field

[0002] This invention relates to energy production and the retrofitting of brownfield equipment to improve efficiency and reduce environmental impact. Background Technology

[0003] In the field of biodegradable fuel production, there are generally two types of commercial facilities: brownfield facilities and greenfield facilities. Greenfield facilities are newly built facilities that typically offer the advantages of incorporating the latest technologies and efficiencies. However, building greenfield facilities requires significant capital expenditure, making them a costly fuel production option.

[0004] On the other hand, brownfield facilities are previously used, idle, or underutilized industrial sites. These stranded assets include stranded gas fields and / or mothballed petrochemical facilities, representing untapped resources often left idle due to various economic or logistical constraints. These assets are particularly prevalent in the methanol and ammonia petrochemical industries. While these assets may be available, their potential contribution to energy production and environmental sustainability is largely overlooked due to a range of challenges inherent in brownfield facilities, especially when it comes to modernization and retrofitting to meet modern energy production demands. To date, no one has successfully retrofitted brownfield facilities to produce biodegradable fuels and products (including, but not limited to, commercial quantities of jet fuel, diesel, naphtha drilling mud, liquefied petroleum gas (LPG), and 2 waxes) while meeting modern environmental standards, as converting these sites into efficient fuel production facilities is technically challenging and costly. Numerous attempts have been made to mitigate these problems, but with limited success. Currently available solutions have failed to deliver meaningful improvements, typically only resulting in slight increases in fuel production. Nevertheless, they inevitably increase costs and raise concerns about economic viability due to long payback periods.

[0005] Meanwhile, industries that are difficult to reduce emissions, such as aviation, heavy industry, and shipping, are seeing a growing demand for clean, biodegradable products. These industries are significant contributors to greenhouse gas (GHG) emissions and typically rely on fossil fuels. However, there are currently no suitable solutions on the market that are both environmentally friendly and commercially viable.

[0006] Furthermore, the energy sector faces the problem of gas combustion, a practice that not only wastes valuable resources but also leads to GHG emissions. Current solutions do not reduce gas combustion, which is crucial for both economic efficiency and environmental protection. Summary of the Invention

[0007] This invention provides a method for retrofitting abandoned or inefficient production facilities, including petrochemical, methanol, and ammonia plants, to produce clean, biodegradable fuels and products, including but not limited to jet fuel, diesel, naphtha drilling mud, liquefied petroleum gas (LPG), and waxes. This is achieved by integrating various retrofitting systems, including amine systems, PRISM units, thermocouples, and retrofitted Fischer-Tropsch (FT) reactors, configured in a novel manner.

[0008] An amine adjustment system is used in brownfield environments to remove acid gases from natural gas. This system works in conjunction with other equipment systems to purify the syngas before it enters the PRISM unit. The PRISM unit is configured to achieve a specific hydrogen (H2) to carbon monoxide (CO) ratio, which is crucial for optimally converting the feed syngas into FT wax or synthetic crude oil. This invention is applicable to a variety of feedstocks, such as natural gas, biomass, renewable natural gas, hydrogen, municipal waste, and combustion or stagnation gases.

[0009] The FT reactors are equipped with specially designed heat transfer elements, commissioned specifically for retrofitted ammonia and methanol plants. These reactors utilize unique FT catalysts for producing gas-to-liquid (GTL) products. Furthermore, FT analyzers are incorporated to provide real-time analysis of key hydrocarbon streams, facilitating adjustments to maximize yield. This retrofit will contribute to improved system efficiency and maximize the lifespan of various components, particularly the catalyst within the FT reactors.

[0010] The invention also includes dedicated flow meters designed to prevent wax blockage caused by processes. These flow meters eliminate vibrations and gaseous media in the piping, allowing for accurate measurement of liquid wax flow. This helps maintain flow throughout the system and reduces the likelihood of wax hardening and damaging the system.

[0011] This invention also includes carbon / gas capture, energy capture, and water recovery systems throughout the equipment to help improve the environmental impact of retrofitted equipment. Carbon / gas capture can be used to release less CO2 and CO into the environment, and to capture and produce H2 with a purity higher than that typically produced by non-dedicated equipment. Energy capture can be carried out in the equipment's flue and heat recovery zone to heat water to generate steam for use in other areas of the equipment or to drive turbines to generate energy used in the rest of the equipment. Finally, the water recovery system can recover water that is typically wasted in less efficient equipment.

[0012] By incorporating these elements, the present invention provides a method for revitalizing abandoned or inefficient fuel production equipment. It introduces a cost-effective approach to the production of jet fuel, diesel naphtha, drilling fluids, and waxes, and is compatible with existing fuel transportation methods.

[0013] In one embodiment of the invention, the apparatus may include: a carbon dioxide removal system comprising at least one of an amine system and an amine gas analyzer; a steam methane reformer comprising a carbon dioxide pump connected to at least one output of the carbon dioxide removal system; a hydrogen removal system comprising a PRISM separator and at least one of a demister and a PRISM gas analyzer; a Fischer-Tropsch (FT) reactor comprising a buffer wax tank, a GTL wax catalyst, multiple separator cylinders, an FT heating unit, and at least one of the following: multiple FT thermocouples, multiple FT analyzers, a Katie spring assembly, a catalyst regeneration unit, multiple heat transfer elements, and multiple capillaries; and a control and safety system comprising at least one of a safety instrumented system (SIS), an analyzer interface, and a flare system.

[0014] In other embodiments of the invention, the fuel production equipment is at least one of the following: an ammonia plant, a methanol plant, and a petrochemical plant in a brownfield environment. The invention may further include a feed processing system for obtaining raw materials. Additionally, the feed processing system may include a feed gas analyzer configured to analyze the sulfur content in the feed material. The feed processing system may include piping and a pre-reformer for redirecting fresh naphtha feed from at least one output of the fuel production equipment. In one embodiment of the invention, the steam methane reformer may further include an induced draft fan and an forced draft fan, as well as a flue duct adjusted to recover heat from the gas passing through the flue duct and convert the heat to drive a turbine in the equipment. In one embodiment of the invention, the invention may further include a syngas compression and heat recovery system, which includes a process condensate stripping system. Additionally, an amine gas analyzer is configured to analyze carbon dioxide escape. In one embodiment of the invention, a PRISM gas analyzer is configured to analyze the ratio of hydrogen to carbon monoxide leaving a hydrogen removal system. In one embodiment of the invention, the PRISM separator can produce hydrogen with a purity of at least 96%. In one embodiment of the invention, the buffer wax tank further includes multiple steam coils. In one embodiment of the invention, the FT thermocouple includes multiple forked members placed within a pipe, the forks intersecting at a central axis within the pipe and extending into the interior of the pipe wall. In one embodiment of the invention, the FT analyzer includes at least one of an analyzer at the input end of the FT system, an analyzer at the output end, and an analyzer on the recirculation feed. In one embodiment of the invention, the GTL wax catalyst is an FT catalyst. In one embodiment of the invention, the separator assembly includes a first baffle assembly, a second baffle assembly, and a demister pad assembly. In one embodiment of the invention, the separator assembly induces laminar flow in the GTL wax produced by the FT reactor. In one embodiment of the invention, the apparatus further includes a hydrocracker and stripper system, the hydrocracker and stripper system including at least one of the following: a hydrocracker thermocouple assembly, a hydrogen replenishment compressor, a hydrocracker heating unit, a hydrocracker flow meter, and a hydrocracker gas analyzer. Furthermore, the hydrocracker flow meter includes a Coriolis flow meter. In one embodiment of the invention, the apparatus further includes a fractionation system comprising at least one of a fractionation tower and a storage component assembly. In one embodiment of the invention, the flare system includes a separator and piping capable of steam purging the flare. In one embodiment of the invention, the apparatus further includes an effluent control system comprising at least one of a bioreactor and a rainwater tank. In one embodiment of the invention, the bioreactor includes at least one of a pH controller, a bacteria controller, aeration, ultraviolet light, and a filtration component.In one embodiment of the invention, the SIS includes a computer-readable medium comprising a causal matrix set for controlling the device in the event of a failure.

[0015] In one embodiment of the invention, the apparatus further includes a syngas compression section, wherein the output of the steam methane reformer is connected to the input of the syngas compression section, and the output of the syngas compression section is connected to the input of a carbon dioxide removal system. Additionally, at least one output of the carbon dioxide removal system is connected to a hydrogen removal system. Furthermore, the apparatus includes a hydrocracking and stripping system, wherein at least one output of the hydrogen removal system is connected to the input of an FT reactor, and at least one output of the hydrogen removal system is connected to the hydrocracking and stripping system. Additionally, the apparatus includes a fractionation system, wherein at least one output of the FT reactor and at least one output of the hydrocracking and stripping system are connected to at least one input of the fractionation system. Attached Figure Description

[0016] The accompanying drawings illustrate several embodiments and, together with the specification, serve to explain the principles of the invention according to these embodiments. Those skilled in the art will understand that the specific arrangements shown in the drawings are merely exemplary and should not be construed as limiting the scope of the invention or the claims in any way.

[0017] Figure 1 The design of a GTL wax device according to an embodiment of the present invention is shown.

[0018] Figure 2 The design of the feeding section within the GTL wax device according to an embodiment of the present invention is shown.

[0019] Figure 3 The design of the steam methane reforming section within the GTL wax apparatus according to an embodiment of the present invention is shown.

[0020] Figure 4 The design of the synthesis gas and heat recovery section within the GTL wax apparatus according to an embodiment of the present invention is shown.

[0021] Figure 5 The design of the carbon dioxide removal section within the GTL wax device according to an embodiment of the present invention is shown.

[0022] Figure 6 The design of the hydrogen removal section within the GTL wax device according to an embodiment of the present invention is shown.

[0023] Figure 7 The design of the FT reactor section within the GTL wax apparatus according to an embodiment of the present invention is shown.

[0024] Figure 8The design of the hydrocracker and stripper sections within the GTL wax apparatus according to an embodiment of the present invention is shown.

[0025] Figure 9 The design of the fractionation system section within the GTL wax apparatus according to an embodiment of the present invention is shown.

[0026] Figure 10 The design of the control system within the GTL wax device according to an embodiment of the present invention is shown.

[0027] Figure 11 The design of a liquid-liquid separator within a GTL wax device according to an embodiment of the present invention is shown.

[0028] Figure 12 The design of a product separator within a GTL wax apparatus according to an embodiment of the present invention is shown.

[0029] Figure 13 A method for converting brownfield equipment into GTL wax equipment according to an embodiment of the present invention is shown. Detailed Implementation

[0030] This invention relates to a method for modifying brownfield equipment. The invention is described in conjunction with the various elements herein. However, it should be noted that although the various elements of the apparatus of the invention are described separately below, these elements are not necessarily separate. Various embodiments may be related to each other and may be separated from a single module or mold. Various different ways of forming the inventive apparatus according to the disclosure herein may vary without departing from the scope of the invention.

[0031] Generally, one or more different embodiments may be described in this application. Furthermore, various alternative arrangements may be described for the one or more embodiments described herein; it should be understood that these are presented for illustrative purposes only and are not limited to the embodiments contained herein or the claims presented in any way. As will be apparent from this disclosure, one or more arrangements may be broadly applicable to many embodiments. In general, the arrangements are described in sufficient detail to enable those skilled in the art to implement one or more embodiments, and it should be understood that other arrangements may be used, and structural changes may be made without departing from the scope of the embodiments. Specific features of one or more embodiments described herein may be described with reference to one or more specific embodiments or drawings that form part of this disclosure, wherein specific arrangements of one or more aspects are shown by way of example. However, it should be understood that such features are not limited to use in conjunction with the one or more specific embodiments or drawings described herein. This disclosure is neither a textual description of all arrangements of one or more embodiments nor a list of features of one or more embodiments that must be present in all arrangements.

[0032] The section headings and the title of this patent application provided in this patent application are for convenience only and should not be construed as limiting this disclosure in any way.

[0033] Unless otherwise expressly specified, interconnected devices and components do not need to be continuously connected to each other. Furthermore, interconnected devices and components may be directly or indirectly connected via one or more connection means or intermediate links.

[0034] The description of an aspect having multiple interconnected components does not imply that all of these components are necessary. Instead, various optional components may be described to illustrate various possible implementations and to provide a more comprehensive description of one or more implementations. Similarly, although process steps, method steps, etc., may be described in sequential order, such processes and methods are generally configured to operate in an alternating order unless explicitly stated otherwise. In other words, the arbitrary order or sequence of steps that may be described in this patent application does not itself imply a requirement to perform the steps in that order. The steps of the described process may be performed in any actual order. Furthermore, although described or implied to be non-simultaneous (e.g., because one step is described after another), some steps may be performed simultaneously. Moreover, the illustration of a process by way of description in the accompanying drawings does not imply that the illustrated process does not include other variations and modifications thereof, nor does it imply that the illustrated process or any of its steps are necessary for one or more implementations, nor does it imply that the illustrated process is preferred. Furthermore, each aspect is generally described once for each step, but this does not imply that they must occur once, or that they can only occur once each time the process or method is implemented or performed. In some implementations or situations, some steps may be omitted, or in a given aspect or situation, some steps may be performed multiple times.

[0035] When this document describes a single device or article of manufacture, it is obvious that multiple devices or articles of manufacture may be used in place of the single device or article of manufacture. Similarly, when this document describes multiple devices or articles of manufacture, it is obvious that a single device or article of manufacture may be used in place of multiple devices or articles of manufacture.

[0036] Alternatively, the function or feature of the device may be embodied by one or more other devices that are not explicitly described as having such function or feature. Therefore, other embodiments do not need to include the device itself.

[0037] For clarity, the technologies and institutions described or referenced herein will sometimes be described in the singular. However, it should be understood that, unless otherwise stated, a particular implementation may include multiple iterations of the technology or multiple instantiations of the institution. As will be understood by those skilled in the art, alternating implementations are included within the scope of various implementations, wherein, for example, depending on the functionality involved, functions may be performed differently from the order shown or discussed, including substantially in parallel or in the reverse order.

[0038] system

[0039] The device of the present invention comprises the following elements as shown below. These elements, individually or in combination, provide the aforementioned beneficial effects.

[0040] Figure 1A modified brownfield plant, designated 10, is depicted, having been adapted according to the steps of the present invention. Brownfield plant 10 comprises multiple sections or systems, each playing a specific function throughout the process. These sections are: feed processing section 100, steam methane reformer section 200, syngas compression section 300, carbon dioxide removal section 400, hydrogen removal section 500, Fischer-Tropsch (FT) reactor section 600, hydrocracking / stripping section 700, product fractionation section 800, and control system 900. Each of these sections / systems will be referenced... Figure 1-10 Further description. In addition, Figure 11 and Figure 12 The components of section 600 of the FT reactor are depicted. Figure 13 A method for modifying and storing brownfield equipment to achieve the objectives set forth in this invention is shown.

[0041] In one embodiment, brownfield facility 10 was originally a sequestered or poorly performing facility designed to process feedstock into liquid energy. Types of facilities that can be converted into brownfield facility 10 include, but are not limited to, methanol production facilities and ammonia production facilities.

[0042] The feedstocks that can be processed by brownfield facility 10 are diverse, including natural sources (such as natural gas) and bio-based sources (such as biomass, renewable natural gas, hydrogen, municipal waste, and combustion or residual gases). Liquid energy sources that can be produced by brownfield facility 10 include, for example, jet fuel, liquefied petroleum gas (LPG), diesel, and naphtha. Because of its ability to process a variety of feedstocks and produce a variety of liquid energy sources, brownfield facility 10 operates as a feedstock-independent facility and is also known as an XTL facility.

[0043] Feed processing 100

[0044] Figure 2 The feed processing section (labeled 100) is shown as serving to pretreat or clean gases generated from various feedstocks. Specifically, feed processing section 100 is configured to remove organic and inorganic sulfides from the feed gas. To achieve this, feed processing section 100 may include at least one reactor and a superheater. Modifications to this section may include the addition of a pre-reforming unit 105, an analyzer 110, and a naphtha fresh feed 115. In one embodiment of the invention, the outlet of feed processing section 100 may be connected to the inlet of a steam methane reformer 200.

[0045] In one embodiment related to retrofitting brownfield equipment, a pre-reformer 105 is added to the feed processing section 100. The pre-reformer 105 is designed to crack heavy hydrocarbons in the feed gas before it enters the steam methane reformer 200. Specifically, the pre-reformer 105 cracks ethane, butane, and propane that may be present in the incoming gas stream, leaving primarily methane to be supplied to the steam methane reformer. Without the pre-reformer 105, the steam methane reformer 200 may be overloaded due to the presence of heavy hydrocarbons; however, this can be managed by adjusting the feed rate to the unit.

[0046] Analyzer 110 is integrated into the system to monitor the gas composition in the output section. Analyzer 110 may include at least one sensor capable of detecting sulfur content and observing gas purity. Alternative types of analyzers may include different sensor technologies capable of performing similar measurements.

[0047] The naphtha fresh feed pump 115 can be used to redirect the naphtha gas slip stream from the storage tank to the feed processing section 100. This may increase the reformer's charge level as the naphtha arrives and is cracked or atomized. This, in turn, helps reduce the facility's gas consumption.

[0048] Steam methane reformer 200

[0049] See Figure 3 The steam methane reforming section (designated 200) functions to crack the incoming feed gas into its components (i.e., carbon monoxide (CO), carbon dioxide (CO2), and hydrogen (H2)). To facilitate this chemical conversion, the steam methane reforming section 200 may include various components such as heat exchangers, tubular reformers (radiant chambers), multiple reformer fans, a flue stack, and steam superheater convection coils. During retrofitting, heat capture elements may be added to the flue. These steam coils are used to generate steam to drive a turbine, providing energy to the device 10. Alternatively, if heat transfer coils are not used, electricity must be generated and supplied to the device by other means known in the art. A CO2 compressor 205 and retrofitted fans 210a and 210b may be added to the system. In one embodiment of the invention, the outlet of the steam methane reformer 200 may be connected to the input of a syngas compression and heat recovery system 300.

[0050] In operation, the feed gas entering the steam methane reformer section 200 undergoes a series of chemical reactions facilitated by the aforementioned components. A heat exchanger preheats the feed gas before it enters the tubular reformer, where the primary reforming reaction takes place. The chimney serves as an outlet for the combustion gases from the furnace, while the steam superheater raises the temperature of the steam used in the reforming process, as well as the temperature of other steam generated from excess heat in the flue gas. A second heat exchanger can be used for heat recovery or other thermal management purposes.

[0051] The gas exiting the steam methane reforming section 200 is characterized by its high temperature and low pressure conditions. Specifically, the gas can be heated to 1600 degrees Fahrenheit and subjected to a pressure of 180 psi. Furthermore, the gas leaving this section is humid, indicating the presence of moisture, which will undergo further treatment for use in subsequent sections of the equipment.

[0052] Another modification involves adding or converting a CO2 compressor, designated 205. In one embodiment, CO2 compressor 205 plays a primary role. It transfers CO2 from the amine system to the input of reformer 200. This adjustment in the feed gas composition is designed to promote chemical reactions that produce larger amounts of carbon monoxide (CO) and hydrogen, which is crucial for Fischer-Tropsch (FT) reactors. Reinjecting CO2 into the reformer front end allows the water shift reaction to maintain a higher percentage of CO in the gaseous form, which is advantageous for FT reactors.

[0053] For brownfield installations without an existing CO2 compressor, the method involves retrofitting an available natural gas compressor to function as a CO2 compressor 205. This is particularly useful for installations that already have a natural gas compressor that was originally designed to compress incoming gas to higher pressures, but not for that purpose. By converting an existing natural gas compressor to a CO2 compressor, the installation requires no additional investment in a new compressor.

[0054] The modified fan assemblies 210a and 210b can be used to ensure efficiency within the steam methane reformer 200. The modified steam methane reformer 200 will handle higher flow rates than the original brownfield unit 10. The forced draft fan 210a will be used to introduce more air into the steam methane reformer 200. The induced draft fan 210b will be used to draw more air into the flue gas to maintain negative pressure within the furnace. In one embodiment of the invention, this modification results in a 25% increase in capacity.

[0055] Syngas Compression & Heat Recovery System 300

[0056] See Figure 4The syngas compression section 300 serves multiple functions, including converting wet reformed gas from the steam methane reformer section 200 into dry syngas. Additionally, this section captures heat for use in other areas of the brownfield plant 10. To achieve these functions, the syngas compression section 300 may include a high-pressure separator, one or more heat exchangers, a process condensate stripping unit 305, and a compressor. In one embodiment of the invention, the outlet of the syngas compression system 300 may be connected to the inlet of the carbon dioxide removal section 400.

[0057] The wet reformed gas first passes through several high-pressure separators, which separate the gas from any entrained liquids. The gas then moves through heat exchangers used to dry the gas and capture heat. The captured heat is reused to preheat other gas streams or boiler feedwater streams, thereby optimizing energy use within the plant. The ability to cool the gas stream and separate liquids occurs multiple times until the gas cools to ambient temperature. This section may require modifications, such as adding to or retrofitting existing heat exchangers in brownfield plant 10, to efficiently perform these functions.

[0058] After leaving the heat exchanger, the gas is directed to a compressor, which is arguably the largest compressor in the facility and specifically designed to process syngas. The compressor increases the gas pressure from 180 PSI to 950 PSI. This high pressure is necessary for subsequent sections of the facility, including the amine system, the PRISM unit, and the Fischer-Tropsch (FT) reactor, all of which operate more efficiently at higher pressures.

[0059] Process condensate stripping (PCS) section 305 can be used to remove water from the gas before it enters the FT reactor 600, which can help reduce harmful air pollutants. PCS section 305 may include a column and associated condenser for stripping using air or steam-water generated in the FT reactor 600. This process can strip carbonic acid from the condensate and restore the condensate's pH to 7. In one embodiment of the invention, this can save 25-30% of the water consumed in the conversion process.

[0060] The term "syngas" is used to describe the gas at this stage, to distinguish it from the "reformed gas" that initially enters this section. Reformed gas is considered "wet" due to the presence of entrained liquids. However, after passing through a high-pressure separator and heat exchanger, these liquids are removed, and the gas is referred to as "dry" syngas. The main components of this dry syngas are carbon monoxide (CO), hydrogen (H2), and carbon dioxide (CO2).

[0061] CO2 removal system 400

[0062] See Figure 5The carbon dioxide removal section 400 is used to remove CO2 and H2S (commonly referred to as "acid gases") from the natural gas feed. This is achieved through a chemical reaction in a contact tower 405 (also known as an absorber). This tower utilizes an aqueous solution of a weak base (particularly an alkanolamine) to form soluble salts (e.g., amine carbamates or amine hydrosulfides). The removed CO2 is then directed to a CO2 compressor 205 for further processing. The gas leaving this section consists primarily of hydrogen and carbon monoxide. In one embodiment of the invention, the outlet of the carbon dioxide removal section 400 may be connected to the inlet of a hydrogen removal system 500.

[0063] To facilitate these processes, the carbon dioxide removal section 400 may include various components such as separators, scrubber coolers, contactor scrubber pumps, and scrubber buffer tanks. An amine contactor 405, a separator / scrubber 410, an amine regeneration unit 415, and an analyzer 420 may be added to or modified into the system.

[0064] Amine contactor 405 is used to absorb CO2 and H2S from a natural gas stream. Contactor 405 may contain monoethanolamine (MEA), methyldiethanolamine (MDEA), or diethanolamine (DEA) as the absorbent. The design of amine contactor 405 can be varied, utilizing trays or packing to achieve the desired separation efficiency. A demister can also be incorporated to minimize amine solvent loss.

[0065] Separator / washer 410 removes droplets and impurities from the gas stream. These droplets can be water, hydrocarbons, or other contaminants that can affect the performance of downstream equipment or the purity of the methane gas. The separator uses gravity to separate the liquid from the gas stream, and the liquid then exits the separator through a vapor outlet. Separator / washer 410 may contain a chemical solvent, such as an aqueous amine solution, which selectively captures CO2 molecules from the gas stream.

[0066] The amine regeneration unit 415 is used to regenerate the amine solution by vaporizing the absorbed CO2 and returning the amine to the system, thereby creating a closed-loop operation.

[0067] Analyzer 420 measures CO2 escape at the outlet of CO2 removal system 400. Analyzer 420 may be a gas sensor of suitable sensitivity known to those skilled in the art. The measurement is the percentage of unremoved CO2. In one embodiment of the invention, this level is 0.6 mol%.

[0068] Hydrogen removal section 500

[0069] See Figure 6The hydrogen removal system 500 is used to regulate the hydrogen content in the syngas stream. In one embodiment, the system is designed to achieve an H2:CO ratio of 2.03, which is particularly important for GTL (Gas-Tropsch) equipment used to optimally convert the feed syngas into Fischer-Tropsch (FT) wax or synthetic crude oil. To achieve this, the hydrogen removal section 500 may include various components such as a demister 505, a feed heater, and a PRISM separator 510. Furthermore, the system may be modified to include an analyzer 515 for monitoring the gas composition at different stages. In one embodiment of the invention, the outlet of the hydrogen removal system 500 may be connected to the inlet of the Fischer-Tropsch (FT) reactor section 600.

[0070] Demister 505 is designed to remove liquid particles from the gas feed, ensuring the syngas remains dry. This is crucial for extending the life of the PRISM membrane. In this invention, demister 505 may consist of a filter and a container. Gas passes through the filter, which captures liquid particles, allowing only dry gas to proceed. Alternative designs for demister 505 may include different types of filters or separation mechanisms.

[0071] PRISM separator 510 is used to remove hydrogen from syngas. In this embodiment, PRISM separator 510 may consist of thousands of hollow fibers acting as molecular filters. These fibers separate the compressed gas into its individual elements, effectively removing some hydrogen from the mixture. Alternative mechanisms for hydrogen separation may include other types of molecular sieve or membrane technologies. The hydrogen removed in this system is reused as a fuel source for heaters and boilers, and is fed into a hydrocracking section to assist in the cracking of heavy waxes.

[0072] Analyzer 515 is integrated into the system to monitor the gas composition of the output stage. Analyzer 515 may include at least one sensor capable of detecting H2 and CO levels and observing their ratios. Alternative types of analyzers may include different sensor technologies capable of performing similar measurements.

[0073] FT reactor 600

[0074] See Figure 7The Fischer-Tropsch (FT) reactor section 600 is used to convert gaseous feed into GTL wax. The FT reactor section 600 may incorporate fixed-bed technology and may require modifications including the addition of thermocouples 605, heat transfer elements, analyzers 610a, b, and c, a GTL buffer wax tank 615, an FT catalyst 620, a Katie spring 625, a catalyst regeneration unit 630, separator cylinders 635a, b, and c, and a process condensate stripping section 640. Alternative bed designs may use slurry beds. In one embodiment of the invention, the outlet of the FT reactor 600 may be connected to at least one of the hydrocracker / stripper section 700 and the inlet of the fractionation system 800.

[0075] Thermocouples and heat transfer elements 605 are designed for stable heat removal and temperature measurement within the reactor tubes. Compared to a standard of approximately 35, this invention deploys over 250 thermocouples in each reactor 600. The heat transfer elements 605 in this invention may include multiple forks (three or four in one embodiment) that form a group of walls that meet in the middle of the tube and contact the outer wall of the tube, subdividing the circular cross-section into multiple lumens. Fewer forks can be used for smaller diameter tubes, and more for larger diameter tubes. Alternative designs may include fewer or different types of heat transfer elements.

[0076] In one implementation, various analyzers are strategically positioned at various points in the process flow, specifically at the inlet, outlet, and recirculation flow of the Fischer-Tropsch (FT) reactor 600. These analyzers are designed to continuously monitor the composition of the gas stream, focusing on the hydrogen-to-carbon monoxide ratio. These analyzers provide real-time data for process adjustments.

[0077] In one embodiment, an inlet analyzer 610a may be placed at the inlet of reactor 600. The inlet analyzer 610a measures the composition of the fresh feed gas injected into the system. This allows for immediate adjustment to maintain the desired hydrogen to carbon monoxide ratio. The primary function of the inlet analyzer 610a is to ensure that the feed gas maintains a specific molar ratio of 2 moles of hydrogen to 1 mole of carbon monoxide. The data collected by these analyzers is transmitted to the control system 900 via the analyzer and / or compressor interface 940, which can adjust the composition of the feed gas if a deviation from the desired ratio is detected.

[0078] In another embodiment, an outlet analyzer 610b may be placed at the outlet of reactor 600 to measure the composition of the reaction gases, thereby providing information about the achieved level of conversion. More specifically, the outlet analyzer 610b is located at the outlet point of the FT reactor 600 (where the reaction gases are released). These analyzers 610b measure the composition of the outlet gas stream to determine the achieved level of conversion. Specifically, the outlet analyzer 610b assesses the concentrations of residual hydrogen and carbon monoxide to measure reaction efficiency. Data from the outlet analyzer 610b is used to adjust operating parameters, such as flow rate or temperature, to optimize the conversion in subsequent cycles.

[0079] The third analyzer 610c is located at the point where the recirculated stream, consisting of unreacted gas, is reintroduced into the inlet of the FT reactor 600. This is crucial because this is where the fresh feed gas mixes with the recirculated stream. Continuous monitoring at this point ensures that the mixed stream maintains the composition ratio required for optimal conversion. More specifically, the recirculated stream analyzer 610c is located at the point where the unreacted gas is reintroduced into the inlet of the FT reactor 600. These analyzers 610c monitor the composition of the recirculated gas stream, focusing on the concentrations of hydrogen and carbon monoxide. The control system 900 uses this data via the analyzer and / or compressor interface 940 to adjust the composition of the mixed stream, ensuring it matches the molar ratio required for optimal conversion.

[0080] A buffer wax pot 615 is used to keep wax in a molten state. The wax is maintained at a temperature greater than 212 degrees Fahrenheit to prevent solidification and potential blockage and damage to the system. The buffer wax pot 615 of this invention may include a container capable of maintaining wax movement and a steam coil to keep the wax molten. Alternatives to the buffer wax pot 615 include, but are not limited to, containers that utilize other heating methods to keep wax in a molten state.

[0081] FT catalyst 620 is used to convert feed gas into FT wax or synthetic crude oil. In this embodiment, the catalyst may be held in a tube within a fixed bed. In another embodiment, FT catalyst 620 may be a TI-8 catalyst. Alternative catalyst designs may include different types of catalytic materials or structures.

[0082] Katie springs 625 hold catalyst 620 inside the tube during operation. These springs are shaped to hold the catalyst at the bottom of the tube and allow for easy removal when the catalyst is replaced every 4-5 years. Alternative designs may include different types of holding mechanisms.

[0083] Regeneration unit 630 is designed to extend the lifetime of catalyst 620. It may consist of a stacked reactor with a moving bed of catalyst. The regenerated catalyst is reinjected into the top of the first reactor to complete the cycle. In one embodiment, regeneration unit 630 for catalyst 620 is used to restore catalyst 620 to its expected start-up lifetime. Doing so helps maintain peak catalyst productivity and high reactivity. Regeneration unit 630 for catalyst 620 in this invention may include a pipe assembly to hold catalyst 620 in a fixed position. A flow can then be introduced through a hydrogen-rich pipe to contact catalyst 620. The feed is then heated to the reaction temperature in a charge heater and sent to the first reactor section. Since the primary reforming reaction is endothermic, the charge is reheated to the desired reaction temperature using an inter-reactor heater (loop exchanger) before being introduced into the next reactor. The effluent from the reactor exchanges heat with the combined feed, is cooled, and is separated into vapor and liquid products in a separator. Alternative designs may include different types of regeneration mechanisms known to those skilled in the art. The regeneration unit may require H2 of 99.9% purity. This level of purity is achieved through the use of a PSA (Pressure Oscillating Adsorber) and H2 extracted from the feed by the dehydrogenation section 500. The regeneration unit 630 can utilize the PSA to produce pure hydrogen as the final product when regeneration is not required.

[0084] Separator cylinders 635a, b, and c are used to separate wax into different grades: heavy wax, medium wax, and light wax. The first-stage hot product separator 635a separates heavy wax from other grades of wax. The hot product liquid separator 635b separates medium wax. The cold product separator 635c separates light wax from the feed. Separator cylinders 635a, b, and c in this invention may include a series of perforated tubes. Alternatives to separator cylinders 635a, b, and c include, but are not limited to, using fewer separator cylinders. Alternative designs may include different numbers or types of separator cylinders.

[0085] In one embodiment, the separation unit 640 includes a perforated conduit 642, a first baffle assembly in a first cylinder 644, a second baffle assembly in a second cylinder 646, and a demister pad 648. Adding the perforated conduit 642 to the fractionation unit or separation unit 640 allows for the slowing of the incoming mixture flow, providing the necessary time for improved separation to occur downstream of the baffles 644, 646, and / or the demister pad 648. In one embodiment, this is achieved through a custom-designed perforation, calibrated to generate specific flow resistance. The perforations act as flow limiters, creating a pressure drop that results in laminar flow conditions as the mixture flows out of the conduit and into the container. In other embodiments, the perforated conduit may comprise a series of strategically placed perforations along its length and circumference. These perforations have specific diameters and spacing to ensure uniform flow distribution. In one embodiment, the conduit is made of a corrosion-resistant material suitable for high-pressure and high-temperature environments, ensuring its durability and long-term performance. By combining these specific design features and functions, the perforated conduit of this invention provides a robust, effective, and efficient solution for initial dispensing and flow control in the complex task of separating different grades of GTL wax and water. This component is particularly important for brownfield facilities retrofitted for fuel production, where precise control and effective separation are crucial.

[0086] Adding a first baffle assembly 644 to the first cylinder enables the modified brownfield separation unit to separate heavy wax from the mixed stream. The first baffle assembly 644 can be specifically designed to facilitate the separation of heavy GTL wax from the mixed stream of light and medium wax with water. According to various embodiments, the first baffle assembly 644 can be strategically positioned within the first cylinder, downstream of the perforated conduit 642, and can be custom-designed with specific geometries, including specific angles, dimensions, and surface treatments, to maximize the efficiency of heavy wax separation. In one embodiment, the first baffle assembly 644 induces laminar flow conditions within the first cylinder, allowing heavy wax to float and be effectively separated from other components based on density differences. The baffle 644 achieves this by creating a region of reduced flow velocity, which in turn provides the necessary residence time for the heavy wax to separate and float above the water and lighter wax. Once the heavy wax reaches a predetermined level, it flows past the baffle 644 and is directed for further processing, such as hydrocracking. This precise control of the separation process is crucial for guiding the heavy wax to its intended downstream processing unit, thereby improving the overall efficiency and operational integrity of the equipment. In one embodiment, plate 644 is made of a material that is both corrosion-resistant and able to withstand the high pressure and high temperature conditions often encountered in brownfield facilities converted for fuel production.

[0087] The second baffle assembly 646 may comprise an existing knuckle drum in the modified separation unit or a new knuckle drum, either of which is also referred to hereinafter as the second drum. In the second drum, a similar process occurs to further separate the medium and light waxes. In some embodiments, the second baffle assembly 646 may even be installed in the first drum. According to various embodiments, the second baffle assembly 646 may be designed with specific geometries (including angles and dimensions) to facilitate the separation of the medium and light GTL waxes from the remaining mixed stream. The materials chosen for constructing these baffles are corrosion-resistant and capable of withstanding high pressure and high temperature conditions. The function of the second baffle assembly 646 is to create a region of reduced flow rate within the second drum. This reduced flow rate provides the residence time required for the medium and light waxes to separate based on their density. Once separation occurs, the medium and light waxes are directed to their respective downstream processing units, such as fractionation towers. The second baffle assembly 646 works in conjunction with the first baffle assembly 644 in the first drum to provide a two-stage separation process, improving the overall performance of the separation unit. By incorporating these design features, the second baffle assembly 646 in the second cylinder provides an effective mechanism for the separation of medium GTL wax and light GTL wax. This component is used in brownfield equipment retrofitted for fuel production, where precise separation and guidance of the material flow are essential for equipment operation.

[0088] In one embodiment, a demister pad 648 (which may be located at the end of separation unit 640) further aids the separation process by capturing any remaining droplets in the gas phase. In one embodiment, the demister pad 648 is mounted inside and / or outside a second cylinder to ensure that any entrained gas is also separated from the liquid wax. In one embodiment, the demister pad 648 is made of a mesh material designed to capture droplets from the gas phase. The mesh is selected based on its ability to withstand the chemical composition of the mixed flow and the high pressure and high temperature conditions frequently encountered during the separation process. The size and density of the mesh are designed to maximize the surface area for droplet capture while minimizing flow resistance. In operation, the demister pad 648 is used to capture any remaining droplets that may be present in the gas phase after the separation process facilitated by baffles 644, 646. The pad 648 effectively improves the purity of the separated gas by removing these droplets. The liquid captured by the demister pad 648 is then discharged and conveyed to the appropriate downstream processing unit. The defogging pad 648 is designed to work in conjunction with the perforated pipe 642 and baffle assemblies 644, 646 in the first and second cylinders to facilitate a comprehensive separation process.

[0089] In one embodiment, capillary transmitters 649 are used to measure level, pressure, and temperature within separation unit 640. In one embodiment, these transmitters 649 have a diaphragm mechanism and are connected to separation unit 640 via capillary tubes. The tubes 649 are filled with fluid that transmits pressure changes to the diaphragm, which in turn generates an electrical signal corresponding to the measured parameters. The materials used to construct the capillary tubes 649 and the diaphragm are selected based on their chemical resistance and suitability for high-pressure and high-temperature conditions. During operation, the capillary transmitters 649 provide measurements without allowing the medium (whether wax or water) to directly contact the sensor. This design prevents clogging and ensures measurement accuracy. The electrical signal generated by the diaphragm is then converted into readings of level, pressure, and temperature, which are used for process control and monitoring. These transmitters 649 are integrated into the overall control system of separation unit 640 and work in conjunction with perforated pipes 642, baffles 644, 646, and a demister pad 648 to facilitate the separation process.

[0090] Heat transfer element 650 is used to maintain the wax temperature above 212 degrees Fahrenheit. Heat transfer element 650 may include additional steam tracing added to brownfield unit 10 to capture heat loss or waste from other sections and guide it back to hydrocracker / stripper section 700. Alternative designs may include different types of heat maintenance systems.

[0091] Hydrocracker / Stripper System 700

[0092] See Figure 8 The hydrocracker / stripper section 700 performs multiple functions within the brownfield plant 10. This section may include a stripper reflux tank, a stripper reflux pump, a reactor, an HCU heater, a flash tank, an effluent feed, a stripper, and a stripper feed preheater. Modifications to this section may involve adding thermocouples 705, stripper towers 710, hydrogen replenishment and recirculation compressors 715, heat transfer elements 720, flow meters 725, heaters 730, and analyzers 735. In one embodiment of the invention, the outlet of the hydrocracker / stripper section 700 may be connected to the inlet of the fractionation system 800.

[0093] Thermocouple 705 is designed to measure the temperature at multiple levels in the hydrocracking reactor column 700. In one embodiment of the invention, thermocouple 705 is located at at least eight levels in the column to measure the temperature of the catalyst at each level. This additional measurement and control capability allows the control system 900 to better adapt to system variations to maintain efficiency.

[0094] Stripper column 710 is used to separate components in a feed using a steam stream. Specifically, it can break down heavy waxes into medium and light waxes. The stripper column 710 of this invention may include a column capable of holding the heavy waxes in a liquid state and allowing steam to pass through the column. Alternative designs may include different types of separation mechanisms.

[0095] The hydrogen supply compressor 715 introduces H2 into the hydrocracker / stripper section 700. It may include a compressor that extracts H2 from the hydrogen removal section 500. Alternative designs may include different types of hydrogen supply mechanisms.

[0096] A heat transfer element 720 and a heater 730 are added to increase the temperature of the wax entering the hydrocracking section 700. The heat transfer element 720 may include a boiler or other heating elements known in the art. The heater may include a steam tracing heater or other heat sources known in the art.

[0097] The Flow Meter 725 provides high-precision flow and density measurements of wax flowing through a system. It functions as a high-precision mass flow meter, directly measuring the mass flow rate of fluids in closed pipes. Utilizing multivariable digital processing technology, it enhances signal filtering, significantly improving the sensitivity and accuracy of signal measurements, accelerating system response time, and making measurements more reliable. The Flow Meter 725 offers mass flow rate measurement accuracy of 0.1% to 0.2%, and density measurement resolution of 0.002 to 0.02 g / cm³. 3 Furthermore, the temperature measurement error is less than 0.5 degrees Celsius. In one embodiment of the invention, the flow meter 725 can be a Coriolis flow meter. These special flow meters will not be clogged by the produced wax. The flow meter 725 eliminates vibrations and gaseous media in the pipeline to strictly record the flow rate of liquid wax for measurement accuracy.

[0098] Analyzer 735 is integrated into system 700 to monitor the gas composition of the output stage. Analyzer 735 may include at least one sensor capable of detecting sulfur content and observing gas purity. Alternative types of analyzers may include different sensor technologies capable of performing similar measurements.

[0099] Fractionation system 800

[0100] Figure 9 A fractionation system 800 is shown. In one embodiment, it may include a fractionation column 810 and a storage unit 820.

[0101] In one embodiment, fractionation column 810 comprises two main columns, which differ from those in existing methanol and ammonia plants due to their unique internal components and additional containers. The first column is used for stripping diesel fuel, while the second column is designed to separate lighter hydrocarbons. In one embodiment, the first column operates as a conventional distillation column, utilizing the temperature gradient on the trays to facilitate proper separation of components. At the bottom of this column, heavy wax accumulates. In the intermediate section, a extraction point is established for diesel fuel, and at the top, another extraction point is designated for hydrocarbons (e.g., naphtha and liquefied petroleum gas (LPG)). Both diesel fuel and naphtha are then directed to smaller secondary columns for further purification before entering the final product stage. The heavy wax collected at the bottom of the first column is not discarded but is directed to a second reactor (referred to herein as a hydrocracker) for further processing. In one embodiment, the hydrocracker cracks the wax a second time before finally returning it to the column for further purification. This ensures that all components in the system are utilized efficiently.

[0102] In one embodiment, storage component 820 includes multiple transfer pumps, day tanks, and a main storage tank. Some equipment may not initially have these tanks and may need to be added during retrofitting. These tanks are capable of storing and maintaining, to specifications, jet fuel, diesel, naphtha drilling mud, LPG, and wax produced by the retrofitted equipment 10. The piping arrangement of the tanks allows for product isolation and testing before being transferred to the main storage tank. In another embodiment of the invention, storage component 820 may include fewer tanks, and the final product may be piped to a third party responsible for the main product storage.

[0103] Control System 900

[0104] Figure 10 An embodiment of the control system 900 is shown. The control system incorporates various analyzers and electronic components to monitor the modified equipment 10 and control various systems and / or sub-components.

[0105] In one embodiment, the control system 900 includes an analyzer and / or compressor interface 940. The analyzer and / or compressor interface 940 is integrated with two compressors: one for circulating gas through the reactor, and the other for injecting fresh feed gas. The analyzer and / or compressor interface 940 interfaces with analyzers throughout the plant and works in conjunction with the compressors to ensure the gas composition remains within specified parameter ranges. If the analyzer detects that some gases have not reacted as expected, the control system 900 allows the unreacted gases to be recirculated to pass through the reactor again. This feature enables the process to achieve maximum conversion efficiency by utilizing all available reactants.

[0106] In one embodiment, the control system 900 may further include a retrofit control system and / or an SIS system 920 to improve safety and operational efficiency. As described above, the present invention provides a method for retrofitting brownfield equipment for fuel production by incorporating a safety instrumented system (SIS). Unlike generic SIS or emergency stop systems (ESD) used in other equipment, the SIS in this invention is specifically designed and configured for the unique operational requirements of the brownfield equipment being retrofitted.

[0107] In one implementation, the SIS 920 serves as an automated control system encompassing various protective mechanisms throughout the facility. It is designed to safely shut down equipment without operator intervention in the event of operational anomalies or emergencies. The system can also isolate and protect specific areas or systems within the facility if it detects something is amiss or requires immediate attention. In one implementation, the SIS is programmed with a set of predefined safety parameters and logical sequences tailored to the specific operational requirements of the brownfield equipment. It continuously monitors various data points, such as temperature, pressure, and flow rate, via a network of sensors and transmitters. If any of these parameters deviates from a set safety margin, the SIS 920 triggers an automatic response to correct the deviation or safely shut down the affected system. The SIS 920 may include a causal matrix group for controlling the equipment in the event of a failure.

[0108] According to one embodiment of the invention, the SIS 920 may include I / O cards (input / output cards) 925. These modules are integrated into the SIS 920 to facilitate data transmission. The I / O cards 925 are designed to work with specific types of transmitters that feed information back to the control system 900. In one embodiment of the invention, the I / O cards 925 are high-speed data acquisition cards designed to interface with the device's existing control system. They are equipped with multiple channels to accommodate various analog and digital signals. Each I / O card 925 is housed in a fire-resistant housing and is certified for use in hazardous environments.

[0109] In addition, the SIS system 920 may include a dedicated transmitter 930 for sending data to the I / O card 925. In one embodiment, the transmitter 930 converts physical parameters (such as temperature and pressure) into electrical signals. These signals are then sent to the I / O card 925 via shielded cables to minimize electromagnetic interference. Each transmitter 930 is calibrated to ensure accuracy and is capable of self-diagnostics to alert the SIS 920 in case of a fault.

[0110] Optionally, the SIS system 920 also includes a distributed control system (DCS) 935, which is integrated with the SIS 920 to provide a comprehensive control solution for the device. In one implementation, the DCS 935 serves as a central hub for data aggregation and processing. The DCS 935 may be equipped with redundant processors and power supplies to ensure uninterrupted operation. The DCS 935 can be programmed to perform complex logical operations based on data received from the I / O card 925 and transmitter 930, thereby enabling real-time decision-making.

[0111] The modified flare system 950 can be used during emergency releases to recover any liquids that can be drained from the system to relieve pressure. The modified flare system 950 may include additional separators and piping capable of steam purging the flare. This process involves applying 175 psi of steam to steam-purge the flare and remove deposits, ensuring no product deposits remain within the flare.

[0112] An effluent control system 960 is used to ensure that effluent introduced into the environment from device 10 is within control limits. This minimizes the environmental impact of the modified device 10. The effluent control system 960 may include a bioreactor comprising at least one of a pH controller, a bacteria controller, aeration, ultraviolet light, and filtration components. The effluent control system 960 may include a rainwater tank. The rainwater tank can channel, store, and treat any surface runoff from device 10. Alternatively, the effluent control system 960 may also include carbon capture components to minimize the release of CO and CO2. Any unreacted gases produced by device 10 are recovered and used as fuel for heaters and furnaces.

[0113] Liquid-liquid separator

[0114] Figure 11 The internal structure of a liquid-liquid separator built within an FT reactor 600 according to an embodiment of the present invention is shown. Figure 11 The separator may represent at least one of separator cylinders 635a, 635b, and 635c. The separator may include a straight feed pipe 2050, a turbulent isolation plate 2100, a liquid-liquid coalescing medium 2150, and a weir 2200.

[0115] Product Separator

[0116] Figure 12 The internal structure of a product separator found within an FT reactor 600 according to an embodiment of the present invention is shown. The product separator may include a demister with a liquid downcomer 3050 and a vane inlet device 3100.

[0117] Methods for retrofitting brownfield equipment

[0118] Figure 13 A method for retrofitting brownfield plant 10 is illustrated. The steps include obtaining fuel production equipment 1000, retrofitting feed handling 1050, retrofitting steam / methane reformer 1100, retrofitting the heat exchanger in syngas compression system 1150, amine addition system 1200, PRISM addition system 1250, retrofitting Fischer-Tropsch (FT) reactor 1300, retrofitting hydrocracker / stripper 1350, retrofitting product fractionation section 1400, and retrofitting control system and SIS 1450. Depending on the configuration of the obtained brownfield plant, each of the above steps may not be necessary.

[0119] Obtaining fuel production equipment 1000 may include the following steps: locating the fuel production equipment and modifying it. The equipment can utilize various raw materials, including but not limited to natural gas, biomass, renewable natural gas, hydrogen, municipal waste, and combustion or residual gases. In one embodiment of the invention, the fuel production equipment may be a poorly performing or abandoned device. Obtaining the equipment can be achieved through many methods known in the art, and in one embodiment of the invention, the equipment is purchased.

[0120] Retrofitting the feed treatment 1050 may include steps to improve the feed treatment efficiency of the equipment. A pre-reformer 105 may be added to remove ethane, butane, and propane, leaving primarily methane in the feed. The feed treatment section may also be retrofitted or have superheaters and reactors added. A carbon dioxide compressor may be added to the inlet of the feed treatment section 100 of the equipment. The carbon dioxide compressor reintroduces carbon dioxide into the feed, leading to the front end of the steam methane reformer. The carbon dioxide compressor may be converted from an existing natural gas compressor present in the equipment prior to the retrofit. Retrofitting the feed treatment 1050 may include adding or retrofitting an analyzer 110 to the feed treatment and pairing it with the control system.

[0121] Retrofitting the steam / methane reformer 1100 may include steps of modifying an existing steam methane reformer present in the equipment. The modification may include at least one of the following: adding or modifying a fan present in the flue, or improving heat recovery in the flue by adding additional coils for heat capture. The fan may be modified by increasing airflow capacity to improve efficiency within the system. Heat recovery within the steam methane reformer may be used to provide heat to the rest of the equipment or to drive a turbine for energy generation within the equipment.

[0122] Modifying the heat exchanger in the syngas compression system 1150 may include modifying a cylinder within an existing syngas compression system. This modification can result in the removal of a greater amount of water from the system. The cylinder can better capture heat from the gas passing through the equipment section and produce dry gas, as well as use the captured heat for the rest of the equipment.

[0123] Adding an amine system 1200 may include adding or modifying an existing amine system for carbon dioxide removal. This modification may include adding an analyzer. In some embodiments of the invention, the carbon dioxide removal system may not be present in the equipment; therefore, the amine system will be added as a new system rather than as a modification of an existing amine system. Adding an amine system may include the following steps: adding or modifying a separator, a scrubber cooler, a contactor scrubber pump, a scrubber buffer tank, an amine contactor, a separation tank / scrubber, an amine regeneration unit, and an analyzer.

[0124] Adding a PRISM system 1250 may include the step of adding a hydrogen removal system 500. The device may not include a hydrogen removal system, therefore one needs to be added. The PRISM system is used to pass gas through and remove excess hydrogen to redirect it to the hydrocracking / stripping system 700 present in the device. Adding a PRISM system may also include adding an analyzer that can measure the hydrogen-to-carbon monoxide ratio in the system. Adding a PRISM system 1250 may also include the step of adding a demister to the section to reduce liquid particulate matter within the system. Adding a PRISM separator may include adding a high-efficiency separator membrane that can produce hydrogen with 96% purity.

[0125] Modifying the Fischer-Tropsch (FT) reactor 1300 may include the steps of modifying the existing FT reactor 600 in the apparatus. These steps may include: adding a Katie spring 625 to the reactor 600; adding analyzers 610a, b, and c to the reactor 600; adding a capillary tube 649; a heating system 650; and adding a suitable FT reactor. Modification of an existing FT reactor may include at least one of the following: adding or replacing thermocouples and heat exchangers; modifying a buffer wax tank; changing the catalyst to a GTL wax catalyst; and modifying the separation unit 640. Adding thermocouples 605 can significantly increase the number of thermocouples in the system and improve the design of the thermocouples. Analyzers 610a, b, and c may be modified or added to ensure that the gases detected within the FT reactor 600 are in appropriate ratios and connected to a control system to maintain these ratios. A buffer wax tank may be added in the steps to keep the FTL wax in a liquid state. Modification of the FT catalyst may include adding a GTL wax catalyst to the system. A Katie spring 625 may be added to hold the catalyst in the appropriate position within the FT reactor 600. A regeneration unit 630 can be added to the equipment to maintain the FT catalyst 620 under effective conditions. A separator cylinder comprising a series of baffles 644, 646, a demister pad 648, and a capillary transmitter 649 can be added to separate light, medium, and heavy waxes and guide the flow to appropriate locations within the equipment. A suitable heating unit 650 can be added or modified to keep the wax in a molten state.

[0126] Retrofitting the hydrocracker / stripper 1350 may include at least one of the following steps: adding a hydrogen make-up compressor 715 and a heater 730, and retrofitting existing thermocouples 705, flow meters 725, and analyzers 735 in the unit. Adding the hydrogen make-up compressor 715 includes connecting it between the outlet of the PRISM system and the hydrocracker / stripper 700 to improve efficiency within the unit. When retrofitting the hydrocracker / stripper 1350 to handle GTL wax without clogging, a dedicated flow meter 725 may be added. Retrofitting the hydrocracker / stripper 1350 may include adding a heat transfer element 720 to improve the movement of GTL wax in the pipes within the unit. If a stripper tower 710 is not present in the unit, it may need to be added.

[0127] Modifying the product fractionation section 1400 may include at least one of the following steps: adding or modifying the fractionation tower 810, and modifying the storage component 820 present in the equipment. If a fractionation tower is not present in the equipment, it is added in the step of modifying the product fractionation section 1400. Modification of the fractionation tower 810 may include steps to improve the ability to separate GTL wax. In one embodiment, the method includes modifying the separation unit. Some brownfield equipment includes separation units, but these conventional separation units are very simple because conventional methanol and / or ammonia equipment only separates two material streams (methanol and water). The modification method of the present invention updates the internal structure of the fractionation section or separation unit to address the unique challenges of separating different grades of gas-to-liquid (GTL) wax and water when modifying brownfield equipment to produce fuel. The modification method incorporates several innovative features that improve its performance compared to conventional separation systems: including but not limited to perforated pipe 642, a first baffle assembly 644 in the first cylinder, a second baffle assembly 646 in the second cylinder, a demister pad 648, and / or a capillary actuator 649. In a broader sense, the updated fractionation section or separation unit receives a mixed flow that first enters a perforated conduit and then is uniformly distributed in a horizontal container. The perforated conduit 642 also slows the mixture and induces laminar flow conditions. The mixture then encounters a first set of baffles 644 in the first drum, which separates the heavy wax from the other materials. The material then encounters a second set of baffles 646, which separates the medium and light waxes from the remaining components, with water settling at the bottom and different grades of wax floating above. A demister pad 648 may also be installed in this secondary drum or another part of the separation unit to ensure complete separation. These updated internal components separate the components into their respective streams for further processing. For example, heavy wax is directed to a hydrocracker 700, while medium and light waxes are sent to a fractionation column 810 for purification. The separated water is used to generate steam, reducing the need for an external water source. Modifications to the storage components in the equipment may include steps such as ensuring the piping is properly heated to keep the wax in a liquid state and modifying the storage tanks according to the rate at which the final product is removed from the equipment.

[0128] Retrofitting the control system and SIS 1450 may include at least one of the following steps: retrofitting the SIS system 920, the analyzer interface, the flare system, and the environmental controller. Retrofitting the environmental controller may include at least one of the following: adding a bacteria controller, aeration, ultraviolet light, filtration components, and retrofitting the pH controller. Retrofitting the SIS system 920 may include: creating multiple decision matrices for operating the equipment under normal and abnormal conditions. Retrofitting the analyzer interface 940 may include: adding additional interfaces and coupling them to additional analyzers present in the equipment. Retrofitting the flare system may include adding piping that allows for steam purging of the flare to prevent wax buildup.

[0129] Other precautions

[0130] As used herein, any reference to "one embodiment" or "implementation" indicates that a particular element, feature, structure, or characteristic described in connection with an embodiment is included in at least one embodiment. The phrase "in one embodiment" appearing throughout the specification does not necessarily refer to the same embodiment.

[0131] Some implementations may use the terms "coupled" and "connected" and their derivatives for description. For example, some implementations may use the term "coupled" to indicate that two or more elements are in direct physical or electrical contact. However, the term "coupled" may also mean that two or more elements are not in direct contact with each other, but still cooperate or interact with each other. Implementations are not limited to this context.

[0132] As used herein, the terms “comprising,” “including,” “including,” “having,” “possessing,” or any other variations are intended to cover non-exclusive inclusion. For example, a process, method, article, or apparatus that includes a list of elements is not necessarily limited to those elements, but may include other elements not expressly listed or inherent to such process, method, article, or apparatus. Furthermore, unless expressly stated otherwise, “or” means inclusive or rather, not exclusive. For example, conditions A or B satisfy any of the following: A is true (or exists) and B is false (or does not exist); A is false (or does not exist) and B is true (or exists); and both A and B are true (or exist).

[0133] Furthermore, the terms "a" or "an" are used to describe elements and components of the embodiments described herein. This is merely for convenience and to give the general meaning of the invention. This description should be understood to include one or at least one, and the singular includes the plural, unless it is obvious that it has a different meaning.

[0134] Upon reading this disclosure, those skilled in the art will understand further alternative structures and functional designs for the system and interactive message creation process provided by the principles disclosed herein. Therefore, while specific embodiments and applications have been shown and described, it should be understood that the disclosed embodiments are not limited to the precise structures and components disclosed herein. Various apparent modifications, variations, and alterations may be made to the setup, operation, and details of the methods and apparatus disclosed herein without departing from the spirit and scope defined in the appended claims.

Claims

1. A fuel production apparatus, comprising: A carbon dioxide removal system, wherein the carbon dioxide removal system includes at least one of an amine system and an amine gas analyzer; A steam methane reformer, the steam methane reformer including a carbon dioxide pump connected to at least one output from a carbon dioxide removal system; A hydrogen removal system, the hydrogen removal system comprising a PRISM separator, and at least one of a demister and a PRISM gas analyzer; Fischer-Tropsch (FT) reactor, the FT reactor comprising a buffer wax tank, a GTL wax catalyst, multiple separator cylinders, an FT heating unit and at least one of the following: multiple FT thermocouples, multiple FT analyzers, a Katie spring assembly, a catalyst regeneration unit, multiple heat transfer elements and multiple capillaries; as well as A control and safety system, the control and safety system including at least one of a safety instrumented system (SIS), an analyzer interface, and a flare system.

2. The fuel production equipment according to claim 1, wherein, The fuel production equipment is at least one of the following: an ammonia plant, a methanol plant, and a petrochemical plant in a brownfield environment.

3. The fuel production equipment according to claim 1, wherein, The fuel production equipment also includes a feed processing system for obtaining raw materials.

4. The fuel production equipment according to claim 3, wherein, The feed processing system includes a feed gas analyzer configured to analyze the sulfur content in the feedstock.

5. The fuel production equipment according to claim 3, wherein, The feed handling system includes a pipeline for redirecting fresh naphtha feed from at least one output of the fuel production equipment.

6. The fuel production equipment according to claim 3, wherein, The feed processing system includes a pre-reformer.

7. The fuel production equipment according to claim 1, wherein, The steam methane reformer also includes an induced draft fan and an expelled draft fan.

8. The fuel production equipment according to claim 7, wherein, The steam methane reformer also includes a flue that is configured to recover heat from the gas passing through it and convert that heat to drive a turbine in the unit.

9. The fuel production equipment according to claim 1, wherein, The fuel production equipment also includes a syngas compression and heat recovery system, which includes a process condensate stripping system.

10. The fuel production equipment according to claim 1, wherein, The amine analyzer is configured to analyze carbon dioxide escape.

11. The fuel production equipment according to claim 1, wherein, The PRISM gas analyzer is configured to analyze the ratio of hydrogen to carbon monoxide leaving the hydrogen removal system.

12. The fuel production equipment according to claim 1, wherein, The PRISM separator can produce hydrogen with a purity of at least 96%.

13. The fuel production equipment according to claim 1, wherein, The buffer wax tank also includes multiple steam coils.

14. The fuel production equipment according to claim 1, wherein, The FT thermocouple includes a plurality of forked structures placed inside a pipe, the forks intersecting at a central axis within the pipe and extending into the interior of the pipe wall.

15. The fuel production equipment according to claim 1, wherein, The FT analyzer includes at least one of the analyzer at the input end, the analyzer at the output end, and the analyzer on the recycle feed in the FT system.

16. The fuel production equipment according to claim 1, wherein, The GTL wax catalyst is an FT catalyst.

17. The fuel production equipment according to claim 1, wherein, The separator cylinder assembly includes a first baffle assembly, a second baffle assembly, and a demister pad assembly.

18. The fuel production equipment according to claim 17, wherein, The separator cylinders induce laminar flow in the GTL wax produced by the FT reactor.

19. The fuel production equipment according to claim 1, wherein, The fuel production equipment also includes a hydrocracker and stripper system, which includes at least one of the following: a hydrocracker thermocouple assembly, a hydrogen replenishment compressor, a hydrocracker heating unit, a hydrocracker flow meter, and a hydrocracker gas analyzer.

20. The fuel production equipment according to claim 19, wherein, The hydrocracker flow meter includes a Coriolis flow meter.

21. The fuel production equipment according to claim 1, wherein, The fuel production equipment also includes a fractionation system, which includes at least one of a fractionation tower and a storage component group.

22. The fuel production equipment according to claim 1, wherein, The flare system includes a liquid separator and piping capable of steam purging the flare.

23. The fuel production equipment according to claim 1, wherein, The fuel production equipment also includes an effluent control system, which includes at least one of a bioreactor and a rainwater tank.

24. The fuel production equipment according to claim 23, wherein, The bioreactor includes at least one of a pH controller, a bacteria controller, an aeration unit, an ultraviolet light source, and a filtration unit.

25. The fuel production equipment according to claim 1, wherein, The SIS includes a computer-readable medium comprising a causal matrix set for controlling the device in the event of a failure.

26. The fuel production equipment according to claim 1, wherein, The fuel production equipment also includes a feed processing system, wherein the output of the feed processing system is connected to the input of the steam methane reformer; The fuel production equipment also includes a syngas compression section, wherein the output of the steam methane reformer is connected to the input of the syngas compression section, and the output of the syngas compression section is connected to the input of the carbon dioxide removal system. At least one output terminal of the carbon dioxide removal system is connected to the hydrogen removal system; The fuel production equipment also includes a hydrocracking and stripping system, wherein at least one output of the hydrogen removal system is connected to the input of the FT reactor, and at least one output of the hydrogen removal system is connected to the hydrocracking and stripping system; and The fuel production equipment also includes a fractionation system, wherein at least one output of the FT reactor and at least one output of the hydrocracker and stripper system are connected to at least one input of the fractionation system.

27. A method for retrofitting brownfield equipment, comprising the following steps: Obtain fuel production equipment, wherein the fuel production equipment may be an ammonia or methanol production facility in a brownfield environment, or a petrochemical facility; The feed handling system is modified by adding at least one of a pre-reformer, an analyzer, and fresh naphtha feed. The steam methane reformer was modified by replacing it with a CO2 compressor, improving heat capture in the flue, and modifying the fan. Modify the heat exchanger in the syngas compression system; Adding or modifying amine systems for syngas compression and heat recovery; Add a PRISM system to adjust the ratio of H2 and CO; The Fischer-Tropsch (FT) reactor was modified by adding thermocouples, heat transfer elements, analyzers, and modifying the buffer wax tank, catalyst, regeneration unit, separation unit, and heating unit. The hydrocracker / stripper was modified by adding thermocouples, altering the stripper tower, adding a hydrogen supplement compressor, adding a heater, modifying a dedicated flow meter, and adding an improved analyzer. The product fractionation system was modified by updating internal components to enhance its ability to separate different grades of gas-to-liquid (GTL) wax and water; and The control system and safety instrumented system (SIS) are upgraded by modifying the communication capabilities between the analyzer and the control system, modifying the flare system, and providing a modified effluent control system.

Images