阅读说明：本技术 用于碳捕获与封存的制氢设备用合成气分离方法 (Synthesis gas separation method for hydrogen production equipment for carbon capture and sequestration ) 是由 塞尔盖·维克托罗夫·阿尔卡达克斯基 努沙德·昆麻 齐亚德·塔雷克·艾哈迈德 于 2020-04-05 设计创作，主要内容包括：利用合成气组分的水溶性差异对合成气进行气体分离的方法和系统,该方法包括由烃燃料源产生包含氢气和二氧化碳的产物气体；通过使比氢气更易溶于水的组分溶解在水中,从而从产物气体中分离出氢气,以产生氢气产物流和副产物流；将副产物流注入含有镁铁质岩石的储层中；以及使副产物流的组分与镁铁质岩石的组分发生原位反应,以使副产物流的组分沉淀并封存在储层中。(Methods and systems for gas separation of syngas utilizing water solubility differences of syngas components, the methods comprising producing a product gas comprising hydrogen and carbon dioxide from a hydrocarbon fuel source; separating hydrogen from the product gas by dissolving in water a component more soluble in water than hydrogen to produce a hydrogen product stream and a byproduct stream; injecting the byproduct stream into a reservoir containing mafic rock; and reacting components of the byproduct stream in situ with components of the mafic rock to precipitate and sequester the components of the byproduct stream in the reservoir.)

1. A process for gas separation of syngas by exploiting differences in water solubility of the components of the syngas, the process comprising the steps of:

producing a product gas comprising hydrogen and carbon dioxide from a hydrocarbon fuel source;

separating hydrogen from the product gas by dissolving in water a component more soluble in water than hydrogen to produce a hydrogen product stream and a byproduct stream;

injecting the byproduct stream into a reservoir containing mafic rock; and

reacting components of the byproduct stream in situ with components of the mafic rock to precipitate and sequester components of the byproduct stream in the reservoir.

2. The method of claim 1, wherein the separating step comprises using at least one vertical scrubber having countercurrent flow of product gas and water, the product gas flowing at 20 ℃.

3. The method of claim 2, wherein the CO is generated by reacting CO₂And H₂S is dissolved in a counter-current of water, thereby dissolving at least 50% of the CO₂And 95% of H₂S is removed from the product gas and separated from the hydrogen product stream.

4. The process according to any one of claims 1 to 3, wherein the separating step comprises using at least two series-connected vertical scrubbing columns having countercurrent flows of product gas and water.

5. The method of any one of claims 1 to 4, wherein the mafic rock comprises basalt.

6. The method of any one of claims 1 to 5, wherein the byproduct stream is further treated to inject CO prior to the step of injecting the byproduct stream into the reservoir₂Separating and purifying from other components to increase CO for injection into the byproduct stream in the reservoir₂And (4) concentration.

7. The method of any one of claims 1 to 6, further comprising CO to be used in the byproduct stream injected into the reservoir₂And (4) a liquefaction step.

8. The method of any one of claims 1 to 7, further comprising the step of reacting the separated hydrogen with nitrogen to form compressed liquid ammonia.

9. The method of claim 8, further comprising the step of transporting the compressed liquid ammonia and reconverting the compressed liquid ammonia to hydrogen and nitrogen by electrolysis to use hydrogen as a hydrogen fuel source.

10. The method of any one of claims 1 to 9, wherein the step of generating a product gas comprises steam reforming or partial oxidation.

11. The process of any one of claims 1 to 10, wherein the step of reacting in situ components of the byproduct stream with components of the mafic rock produces a precipitate selected from the group consisting of calcium carbonate, magnesium carbonate, iron carbonate, and combinations thereof.

12. The method of any one of claims 1 to 11, wherein the reservoir is between 250m and 2,200m below the surface of the earth and between 30 ℃ and 325 ℃.

13. The method of any one of claims 1 to 11, wherein the reservoir is between 350m and 1,500m below the surface of the earth and below 325 ℃.

14. A system for gas separation of syngas utilizing water solubility differences of components of syngas, the system comprising:

a hydrogen-producing unit having a hydrocarbon fuel inlet, the hydrogen-producing unit being capable of producing a product gas comprising hydrogen and carbon dioxide from a hydrocarbon fuel;

a hydrogen separation unit capable of separating hydrogen from the product gas by dissolving in water a component more soluble in water than hydrogen to produce a hydrogen product stream and a byproduct stream; and

an injection well capable of injecting the byproduct stream into a reservoir containing mafic rock to react components of the byproduct stream with components of the mafic rock in situ, thereby precipitating and sequestering components of the byproduct stream in the reservoir.

15. The system of claim 14, wherein the hydrogen separation unit comprises at least one vertical scrubber having countercurrent flow of product gas and water, the product gas flowing at 20 ℃.

16. The system of claim 15, wherein the CO is caused to pass through one scrubber in a single pass₂And H₂S is dissolved in a counter-current of water, thereby dissolving at least 50% of the CO₂And 95% of H₂S is removed from the product gas and separated from the hydrogen product stream.

17. The system of any one of claims 14 to 16, wherein the hydrogen separation unit comprises at least two series-connected countercurrent vertical scrubbing columns with product gas and water.

18. The system of any one of claims 14 to 17, wherein the mafic rock comprises basalt.

19. The system of any one of claims 14 to 18, further comprising a byproduct treatment unit to treat the byproduct stream to convert CO₂Separating and purifying from other components and increasing CO of the byproduct stream for injection into the reservoir₂And (4) concentration.

20. The system of any one of claims 14 to 19, further comprising a compressor to liquefy CO in the byproduct stream for injection into the reservoir₂。

21. The system of any one of claims 14 to 20, further comprising a reaction unit to react the separated hydrogen with nitrogen to form compressed liquid ammonia.

22. The system of claim 21, further comprising a transport unit to transport the compressed liquid ammonia and to convert the compressed liquid ammonia again to hydrogen and nitrogen by an electrolytic process to use hydrogen as a hydrogen fuel source.

23. The system of any one of claims 14 to 22, wherein the hydrogen production unit comprises a steam reformer or a partial oxidation reactor.

24. A system according to any one of claims 14 to 23, wherein components of the produced byproduct stream react in situ with components of the mafic rock to precipitate a product selected from the group consisting of calcium carbonate, magnesium carbonate, iron carbonate, and combinations thereof.

25. The system of any one of claims 14 to 24, wherein the reservoir is between 250m and 2,200m below the surface of the earth and between 30 ℃ and 325 ℃.

26. The system of any one of claims 14 to 24, wherein the reservoir is between 350m and 1,500m below the surface and below 325 ℃.

Technical Field

Embodiments of the present disclosure relate to the synergistic production of hydrogen and carbon capture. In particular, embodiments of the present disclosure relate to the production of hydrogen from fossil fuels by water-based syngas separation, and carbon capture via mafic rocks (e.g., basalt).

Background

Hydrogen or H₂Is an environmentally friendly fuel that has the potential to replace hydrocarbon fuels that emit greenhouse gases. For example, hydrogen can be used to power a fuel cell. Almost all of the H currently produced₂(more than about 95%) are from hydrocarbons and mainly from natural gas. Waste CO discharged to the atmosphere₂(one ton of H per production₂With about 7 to 12 tons of CO₂) Partially cancel H₂The "clean fuel" advantage of (1). To lighten H₂The attendant carbon footprint, has proposed an economically impractical system for H₂Method and system for capturing CO-produced CO₂Compression into liquids and injection into deep (greater than about 800 to 850 meters below ground) sedimentary rock reservoirs is combined in a process known as carbon capture and sequestration ("CCS"). However, conventional CCS significantly increases the already high energy consumption of H production₂The cost of the process, making this combined technology impractical under current market and regulatory conditions.

For the previously proposed hydrocarbons to produce H₂With CO₂E.g. CO in depleted hydrocarbon-bearing reservoirs or saline groundwater aquifers₂CCS of (2), increased with CO₂Purification, compression, transportation andhigh costs associated with injection. Numerous energy consuming steps are employed to ensure the high purity CO required to meet conventional CCS requirements₂(greater than about 98 mol%). Moreover, H is adsorbed due to standard pressure swing adsorption ("PSA")₂-CO₂Separation techniques by themselves do not provide sufficient CO quality and purity for CCS production₂Thus, further purification is required involving acid gas absorbing agents, such as Selexol^TM(for heavy and solid hydrocarbons) and Methyldiethanolamine (MDEA).

CO in conventional CCS₂Safe and economical transport, as well as injection and long term sequestration of CO all depend on₂Compression to a supercritical (liquid) state also adds significantly to the cost. Thus, underground CO₂The sequestration reservoir must be located at least about 850 meters vertically below the surface to ensure sufficient pressure for the CO to survive₂Remain in the liquid state, thereby increasing the cost of injection and disposal wells.

Due to CO in conventional CCS₂Will remain in the liquid state and/or in the compressed gas state for hundreds or thousands of years, thus requiring complex long-term monitoring procedures to ensure that the CO will be delivered₂Is truly confined in a given CCS reservoir and does not migrate to overburden aquifers or the earth's surface.

Disclosure of Invention

The present disclosure provides for efficient separation of H from syngas during hydrogen production from a hydrocarbonated petroleum fuel₂And with little greenhouse gas emissions. In some embodiments, the first step of the process is the simultaneous production of H from gaseous, liquid or solid hydrocarbons₂And waste or by-product CO₂(e.g., natural gas steam reforming). Simultaneous production of H from hydrocarbons₂And CO₂This can be done by a variety of processes. In a second step, H is separated based on the difference in gas-water solubility using a water-based separation technique₂With other gaseous components (e.g. CO)₂And H₂S) separating. In the third step of the process, a by-product component (e.g., CO) will be used₂And H₂S) injecting saturated water into reactive mafic or ultramafic rock, CO₂And/or other exhaust gases inThe reactive mafic or ultramafic rock is permanently fixed as a precipitated carbonate mineral.

The term mafic rock broadly describes silicate mineral rocks or igneous rocks rich in magnesium and iron. Mafic minerals may be darker in color, while the mafic minerals that form the rock include olivine, pyroxene, amphibole, and biotite. Examples of mafic rocks include basalt, diabase, and pyroxene, and examples of ultramafic rocks include dunite, olivine, and pyroxene. Chemically, mafic and ultramafic rocks can be rich in iron, magnesium, and calcium.

The carbon capture and sequestration ("CCS") systems and methods of the present invention are versatile and can also enable CO from other sources such as refining, power generation, and desalination₂Economically and permanently fixed in basalt, for example. In embodiments of the systems and methods described herein, CO is produced by passing syngas through a reaction vessel (e.g., scrubber) having water₂And acid gas dissolved in water, which may be permanently sequestered in basalt, in some embodiments, with no or no further separation, purification, or compression. Separated H₂The product can be further processed as needed and ultimately shipped for use as a fuel product. In embodiments of the systems and methods, the generated hydrogen gas can be reversibly converted to ammonia for safe storage and transport in smaller volumes.

To improve the cooperative H system₂And CO₂Efficiency of removal, System H₂Prior to an alternative CCS process in which CO is introduced₂Injecting into a natural geological host (geological sink) consisting of reactive basalt and ultramafic rock, in which natural geological host CO is present₂React rapidly to form stable mineral phases, such as precipitated carbonates. Carbon sequestration ("CSB") in basalt consumes significantly less energy than other CCS systems and processes, advantageously for acid gas impurities (i.e., H)₂S) has high tolerance, does not require deep wells, e.g., 850m deep or deeper, and does not require long term reservoir monitoring。

CO in basalt and ultramafic rocks compared to conventional CCS₂Sequestration is unique in that it relies to some extent on rapid progress of CO sequestration₂Chemical reactions for conversion of gases to solids, rather than relying on CO over time₂Physical sealing of itself. Economic estimates indicate that the system and method of the present disclosure captures one metric ton of CO compared to conventional CCS₂Is much lower in cost.

In some embodiments, the CO is added to the mixture₂Injecting CO into the reservoir containing basalt before or during the period₂The gas is dissolved in water, which avoids the need to include compressing and maintaining CO₂Some difficulties including the liquid state. By introducing CO₂Dissolved in the aqueous phase, helps to avoid drilling deep disposal wells at depths greater than about 850m below the surface as required by conventional CCS. In other words, sufficient amount of CO is allowed₂The pressure required to remain dissolved in the water is much lower and for embodiments of the present disclosure, the injection zone may be as shallow as 350 meters vertically below the surface.

Introducing CO₂Fast fixation to stable solid carbonate minerals, not only ensuring permanent removal of CO from the environment₂And eliminates the need for complex monitoring procedures required on the conventional CCS site. The pairs of the present technology present up to about 40 mol% of a compound such as H₂The extreme tolerance of other water-soluble exhaust gases like S, which can be like CO, also has an important influence on the efficiency₂As such, they rapidly and substantially completely mineralize basalt and ultramafic rock.

CSB does not require expensive and energy consuming steps to produce H from₂CO produced in the process₂And sulfur/H removal from other gases₂S impurities. Another important advantage is the interaction with liquid CO₂(liquid CO)₂Lower density than reservoir water and therefore buoyant) is enriched in CO₂The water of (a) is denser than the ambient groundwater. Thus, when CO rich injection is performed₂Will sink into the reservoir rather than move upward, which in some embodiments eliminates the need for a crown rock, andcrown rock is an extremely important geological feature of all conventional CCS reservoirs. In embodiments of the present disclosure, CO is injected and sequestered in basalt and mafic rock₂There is no effect on the quality of the groundwater present in those rocks. This is particularly important when these aquifers are used to supply drinking water or water for other purposes.

Accordingly, disclosed herein is a process for gas separation of syngas utilizing water solubility differences of syngas components, the process comprising producing a product gas comprising hydrogen and carbon dioxide from a hydrocarbon fuel source; separating hydrogen from the product gas by dissolving in water a component more soluble in water than hydrogen to produce a hydrogen product stream and a byproduct stream; injecting the byproduct stream into a reservoir containing mafic rock; and reacting components of the byproduct stream in situ with components of the mafic rock to precipitate and sequester the components of the byproduct stream in the reservoir. In some embodiments, the separating step comprises using at least one vertical scrubber having countercurrent flow of product gas and water, the product gas flowing at about 20 ℃. In other embodiments, by reacting CO₂And H₂S is dissolved in a counter-current of water such that at least about 50% of the CO is present₂And about 95% H₂S is removed from the product gas and separated from the hydrogen product stream.

In still other embodiments, the separating step comprises using at least two series-connected vertical scrubbing columns having countercurrent flows of product gas and water. In some embodiments, the mafic rock comprises basalt. In some other embodiments, the byproduct stream is further treated to inject CO prior to the step of injecting the byproduct stream into the reservoir₂Separated from other components and purified to increase CO for injection into byproduct streams in the reservoir₂And (4) concentration. Other embodiments of the method include using the CO in the byproduct stream for injection into the reservoir₂And (4) a liquefaction step. Certain embodiments include the step of reacting the separated hydrogen with nitrogen to form compressed liquid ammonia.

In other embodiments of the method, a step of transporting the compressed liquid ammonia, and a step of reconverting the compressed liquid ammonia to hydrogen and nitrogen by electrolysis to use the hydrogen as a source of hydrogen fuel are included. In some embodiments, the step of generating the product gas comprises steam reforming or partial oxidation. Other embodiments include the step of reacting in situ components of the byproduct stream with components of the mafic rock to precipitate a product selected from the group consisting of calcium carbonate, magnesium carbonate, iron carbonate, and combinations thereof. In still other embodiments, the reservoir is between about 250m and about 700m, or between about 400m and about 500m, and between about 150 ℃ and about 280 ℃, or lower, below the surface of the earth. Suitable temperatures in the reservoir may be as low as about 30 ℃. In other embodiments, the reservoir is between about 700m and about 2,200m below the surface of the earth and below about 325 ℃.

Further disclosed herein is a system for gas separation of syngas utilizing water solubility differences of syngas components, the system comprising: a hydrogen-producing unit having a hydrocarbon fuel inlet, the hydrogen-producing unit being capable of producing a product gas comprising hydrogen and carbon dioxide from a hydrocarbon fuel; a hydrogen separation unit capable of separating hydrogen from the product gas by dissolving in water a component more soluble in water than hydrogen to produce a hydrogen product stream and a byproduct stream; and an injection well capable of injecting the byproduct stream into a reservoir containing mafic rock such that components of the byproduct stream react in situ with components of the mafic rock, thereby precipitating and sequestering components of the byproduct stream in the reservoir.

In some embodiments of the system, the hydrogen separation unit comprises at least one vertical scrubber having countercurrent flow of product gas and water, the product gas flowing at about 20 ℃. In some embodiments, the CO is passed through one scrubber in a single pass₂And H₂S is dissolved in a counter-current of water, thereby dissolving at least about 50% of the CO₂And about 95% H₂S is removed from the product gas and separated from the hydrogen product stream. In still other embodiments, the hydrogen separation unit comprises at least two series-connected vertical scrubbing columns having countercurrent flows of product gas and water. In some embodiments of the system, the mafic rock comprises basalt.

Some embodiments include a byproduct treatment unit to treat the byproduct stream to convert CO₂Separated and purified from other components and increasing CO for injection of byproduct streams in the reservoir₂And (4) concentration. Other embodiments include a compressor to liquefy CO in a byproduct stream for injection into a reservoir₂. Other embodiments include a reaction unit to react the separated hydrogen with nitrogen to form compressed liquid ammonia. In certain embodiments of the system, a transport unit is included to transport the compressed liquid ammonia and to convert the compressed liquid ammonia to hydrogen and nitrogen again by electrolysis to use the hydrogen as a hydrogen fuel source.

In other embodiments, the hydrogen production unit comprises a steam reformer or a partial oxidation reactor. In some embodiments, components of the produced byproduct stream react in situ with components of the mafic rock to precipitate a product selected from the group consisting of calcium carbonate, magnesium carbonate, iron carbonate, and combinations thereof. In still other embodiments, the reservoir is between about 250m and about 700m, or between about 400m and about 500m, and between about 150 ℃ and about 280 ℃, or lower, below the surface of the earth. Suitable temperatures in the reservoir may be as low as about 30 ℃. In other embodiments, the reservoir is between about 700m and about 2,200m below the surface of the earth and below about 325 ℃.

Drawings

These and other features, aspects, and advantages of the present disclosure will become better understood with regard to the following description, claims, and accompanying drawings. It is to be noted, however, that the appended drawings illustrate only several embodiments of this disclosure and are therefore not to be considered limiting of its scope, for the disclosure may admit to other equally effective embodiments.

FIG. 1 shows a process for simultaneous H production₂Based on H₂Water soluble separation and CO₂Schematic flow diagram of an exemplary embodiment of a sequestration system for hydrocarbon production of H₂And almost zero greenhouse gas emissions.

Detailed Description

Accordingly, by reference to the accompanying drawings which form a part hereofIllustrative embodiments, a more particular description of embodiments of the present disclosure briefly summarized above may be had so that it may be understood in more detail that will become apparent for the efficient separation of H from syngas in a process for producing hydrogen from a hydrocarbonaceous petroleum fuel₂And with little greenhouse gas emissions, features and advantages of embodiments of the systems and methods, and other ways of providing features and advantages. It is to be noted, however, that the appended drawings illustrate only various embodiments of this disclosure and are therefore not to be considered limiting of its scope, for the disclosure may admit to other effective embodiments.

Production of H from hydrocarbons by using techniques such as steam reforming or partial oxidation/gasification₂Comprises three steps. In steam reforming, in H₂Heating a hydrocarbon (e.g., methane) in the presence of O (steam) and a catalyst to release hydrogen (H)₂) Carbon monoxide (CO), small amount of carbon dioxide (CO)₂) And/or other impurities, as shown in equations 1 and 2:

and/or

The raw syngas is then treated to remove sulfur compounds and/or further purified. The crude synthesis gas is then contacted with H according to equation 3₂O vapor is reacted in the presence of a catalyst to produce H₂And CO₂Thereby making H₂The yield is maximized:

CO+H₂O→CO₂+H₂equation 3

This is known as the water gas shift reaction and the product is therefore known as "shifted" syngas. In partial oxidation, the hydrocarbon is mixed with a small amount (non-stoichiometric) of oxygen (O) according to equation 4₂) Reacting to produce hydrogen from H₂And CO:

CH₄+1/2O₂→CO+2H₂equation 4

The raw synthesis gas also contains a small amount of CO₂And/or nitrogen (N)₂If air is used instead of pure O₂If so). The raw synthesis gas is then purified and brought to H by the reaction of equation 3₂The content is maximized. Table 1 lists the composition of an exemplary shifted syngas produced by two processes (steam reforming and partial oxidation):

TABLE 1 composition of exemplary shifted syngas from steam reforming or partial oxidation.

Components	H2	CO	CO2	N2	O2	Ar	H2S	H2O	Others
										Mol.％	40.9	1	29.8	2.4	0	0.4	0.01	25.4	0.11

After the water gas shift, H is usually reacted by using adsorption, absorption and/or membrane filtration₂With CO₂And other impurities, thereby purifying H₂. Membrane technology has been developed but has not been widely used on an industrial scale. One exemplary method is pressure swing adsorption ("PSA"), which utilizes the pressure-dependent selective adsorption characteristics of materials such as activated carbon, silica, and zeolites. In the PSA process, with H₂Separated waste or by-product CO₂And other impurities are subsequently vented to the atmosphere. Unfortunately, if a conventional CCS scheme is to be used for sequestration of CO₂Then the CO must be further purified₂And compressed into a liquid (supercritical) state for transport and injection into deep reservoirs. In this context, however, both steps may be avoided (or significantly simplified) when CSB is instead employed.

PSA is energy intensive and increases the yield of final substantially pure H₂Cost and complexity of the product. In the systems and methods of the present disclosure, PSA or other conventional H₂The syngas separation system can be reduced in size, or completely replaced by a surprisingly and unexpectedly effective technique that utilizes H₂And CO₂(and/or other acid gases) are significantly different from each other in water solubility. In embodiments of the present disclosure, the syngas produced after the water gas shift is cooled to about 20 ℃ and injected into the bottom of a vertical pressurized vessel (e.g., scrubber) where the dispersed gas is fed with the gas from the top of the vessel and dispersed throughoutThe water streams in the vessel interact and intimately mix. To maximize the contact between the dispersed gas and water, the column is filled with packing or has channels that form highly tortuous paths. Thus, CO₂

(and/or other water-soluble gases) are dissolved in water, and H₂(and/or other insoluble gases) accumulate at the top of the vessel for collection and/or further processing/purification.

Conventional CCS relies primarily on physical processes, such as the separation of single-phase liquid CO₂Injected and sequestered in non-reactive rock reservoirs (e.g. sandstone, limestone), while CSB relies on CO₂Natural chemical reactions with mafic and ultramafic rocks occur to precipitate solid carbonates. The reaction comprises the following steps: as shown in equations 5 to 7, first, CO₂Dissolved into water (with CO at the surface)₂Either water of gas or water present in situ in the mafic rock reservoir, or both) and reacts with water to form weak carbonic acid:

according to equation 8, the acidified water dissolves the Ca, Fe and Mg rich silicate phases (minerals and/or volcanic glasses), which causes the release of divalent metal ions in the solution:

(Mg,Fe,Ca)₂SiO₄+4H⁺→2(Mg,Fe,Ca)²⁺+2H₂O+SiO_2(aq)equation 8

CO formed during the reaction shown in equation 7₃ ^2-Reacting with divalent metal cation to make carbonic acidThe salt mineral precipitates as shown in equation 9:

(Ca,Mg,Fe)²⁺+CO₃ ^2-→(Ca,Mg,Fe)CO₃equation 9

Geochemical reaction-transport models show that mineral phases, such as calcite, siderite and magnesite, will remain stable under normal underground conditions and therefore can safely remove CO from the atmosphere₂For hundreds of thousands to millions of years. Other carbonate minerals include iron dolomite Ca [ Fe, Mg, Mn](CO3)₂. In addition, CSB is selective for other water-soluble acid gas impurities (e.g., H)₂S, which can also mineralize to sulfides) have a very high tolerance. This advantageous quality not only further simplifies the process, but also eliminates the need to produce H from the exit₂The gas mixture of the process is required to remove these impurities and at the same time to sequester all other H capable of forming a stable mineral phase by reaction with basalt/ferrierite₂O soluble gaseous contaminants.

CO of CSB in Water₂Dissolution may be achieved by any of the following means: a) introducing CO₂And water is injected into the tubing and annulus of the injection well, respectively, and allowed to mix at a depth of about 350m or more in the wellbore before entering the reservoir; or b) dissolving CO in a pressurized vessel at the surface₂And water, and then injecting the solution into a basalt/ultramafic rock reservoir. The former method is generally applicable to pure CO₂And/or CO₂In admixture with other water-soluble acid gases, the latter process being used to efficiently convert CO₂(and other water-soluble gases) are separated from insoluble or slightly soluble impurities and can therefore be used to treat complex flue gas mixtures (e.g., shifted syngas).

Due to CO₂There are certain thermodynamic limitations to the dissolution in water, so these two processes sequester 1 ton of CO per sequestration₂All require about 27 tons of H₂And O. In areas where water supply is in short supply, supercritical (liquid) CO can be injected into basalt or ultramafic rock₂To perform CSB; however, since it is necessary to compress CO₂Liquefaction, and this therefore increases energy requirements.

With respect to H produced₂Conventionally, H₂Storage and transport in liquid form at temperatures of about-253 c, which requires special double-walled insulated containers and/or continuous refrigeration. However, by H₂To liquid ammonia (NH)₃) Is reversibly chemically converted so that H₂Can be stored and transported at low pressure and ambient temperature with a greatly reduced volume. H₂To NH₃Is inherently safer and more advantageous, particularly when large quantities of H are to be stored and transported₂In the case of (1).

Due to CSB to CO₂Impurities in the stream (e.g. H)₂S and other gases) and thus CO-rich from other sources such as refining, power generation, and desalination₂Can be added to the main waste stream after limited treatment or separately injected into the reactive rock for permanent fixation and disposal.

For permanent fixation of CO in basalt and ultramafic rocks using CSB₂While producing H from hydrocarbons₂Its unexpected and surprising advantages include a significant reduction in the expected energy usage and cost, due to: since there is no need to compress and liquefy CO₂So that the energy consumption is lower and the well cost is lower; due to the fact that to CO₂The tolerance of impurities in the stream is high and therefore the operational complexity is low; by precipitation as a solid, with removal of H in the reservoir₂S and CO₂(ii) a Reservoir crown rocks are not required; and does not require complex long-term monitoring procedures. While in the surface or wellbore, CO₂When dissolved in water, CO does not need to be dissolved₂Liquefying, if CO is to be separated₂CO can be injected into underground as supercritical fluid₂And (4) liquefying.

FIG. 1 shows a process for simultaneous H production₂、H₂Separation and CO₂Schematic flow diagram of an exemplary embodiment of a system for sequestration of H from hydrocarbons₂With almost zero greenhouse gas emissions. In system 100, hydrocarbon inlet 102 provides a hydrocarbon source, such as natural gas, to hydrogen production system 104. Hydrogen production system 104 may include steam reforming or partial oxidation, and water gas shiftThe metathesis reaction is, for example, as shown in equations 1 to 4. The generated gas exits via outlet 106 and enters separation unit 108. The separation unit 108 is capable of separating hydrogen from CO₂And other by-products (e.g., acid gases).

PSA is energy intensive and increases the yield of final substantially pure H₂Cost and complexity of the product. In the systems and methods of the present disclosure, PSA or other conventional H₂The syngas separation system can be reduced in size, or completely replaced by a surprisingly and unexpectedly effective technique that utilizes H₂And CO₂(and/or other acid gases) are significantly different from each other in water solubility. In fig. 1, the syngas produced in the hydrogen production system 104 after the water gas shift is cooled to about 20 ℃ and injected into the bottom of the separation unit 108 via outlet 106. Separation unit 108 comprises at least one vertical pressurized vessel, such as a scrubber, in which dispersed gas interacts and intimately mixes with a water stream fed as stream 107 from the top of the vessel. To maximize dispersion gas (including H)₂、CO₂And acid gases, e.g. H₂S) contact with water, the column being filled with packing or having channels forming highly tortuous paths. Thus, CO₂(and/or other water-soluble gases) are dissolved in water, and H₂(and/or other insoluble gases) accumulate at the top of the separation unit 108 for collection and/or further processing/purification in outlet stream 118.

One purpose of the scrubber is to promote CO₂And other acid gases (e.g. H)₂S) efficient mass transfer from the gas phase to the liquid phase. This is achieved by filling with media of high specific surface area (e.g. media of high specific surface area) which are specifically optimized for this purposeOr Lantec) And/or by a low profile, bottom up, path air bubble column design. By promoting the entire fillingThe continuous formation of droplets in the bed provides maximum surface contact between the gas and the scrubbing liquid (e.g., water), resulting in high scrubbing efficiency and minimizing the depth of the packing.

Suitable residence times in the scrubber may be between about 5 seconds and about 120 seconds, depending on the composition and flow pattern of the syngas. The temperature may be in the range of about 2 ℃ to about 55 ℃ at a pressure in the range of about 1 atmosphere to about 6 atmospheres. Obtained H₂The purity ranges from about 50 mol% to 99.9 mol%, depending on the operating conditions and the composition of the syngas. Embodiments of the separation unit comprising at least one scrubber may be CO in all gas phases₂Operating in the concentration range, one variable that can be affected and adjusted is the amount of water required, which also depends on the operating pressure and temperature.

Water soluble CO₂And additional water-soluble gas (e.g., acid gas) is mixed with water from stream 107 and exits separation unit 108 via outlet 110, and may optionally proceed to further CO₂Purification and liquefaction unit 112, but is not required. The water may be supplied through a water supply well, and in some embodiments, may be supplied through water in a basalt reservoir and ultimately recycled back into the same basalt reservoir and the water contains CO₂And H₂S dissolves the components. In some embodiments using a single scrubber, between about 40% and about 60%, or between about 50% and about 70% of the CO is recovered from the syngas in separation unit 108₂And between about 90% and 100% or between about 97% and 100% H₂S, these CO₂And H₂S mixes with water from stream 107 and proceeds through outlet 110. In some embodiments, the separation unit 108 may have 1 scrub column, but in other embodiments, the separation unit 108 may have more than 1 scrub column operating in parallel or in series.

In the presence of further CO₂In the case of purification and liquefaction unit 112, the liquefied CO will be₂Basalt formation 116 is injected through injection well 114 to form solid precipitated metal carbonate according to equations 5 through 9.In the absence of optional further CO₂In the case of purification and liquefaction unit 112, CO₂And other gases such as acid gases exit the separation unit 108 via outlet 110 and directly into the basalt formation 116 via injection well 114, thereby forming solid precipitated metal carbonates according to equations 5 through 9. CO 2₂May be mixed with water in gaseous form at the surface, or in situ in the basalt formation 116 in gaseous form, or both. Solid carbonate nodules form in the caverns and veins of basalt around the injection well and extend outwardly from the injection well.

The rate of basalt dissolution and mineral carbonation reactions may increase with increasing temperature, so higher temperature basalt reservoirs may be advantageous, while deep reservoirs beyond about 850m are not required, as high pressures are not required for CO₂Maintained in a pressurized or liquid state. Exemplary suitable reservoir temperatures are about 185 ℃, or, for example, between about 150 ℃ and about 280 ℃, or lower. As explained, the CO injected₂By itself, or CO₂And other gases, with water near an injection well (e.g., injection well 114). The acidic fluid near injection well 114 remains unsaturated with respect to basalt minerals and volcanic glass.

The unsaturation and acidity cause basalt dissolution of the host rock near injection wells (e.g., injection well 114). After heat exchange and sufficient dissolution of the bulk basalt to neutralize the sour water and saturate the carbonate and sulfur minerals in the formation water, mineralization occurs primarily at a distance away from the injection well (which enables continuous CO injection in reservoirs such as basalt formation 116₂)。

The hydrogen exits the separation unit 108 in an outlet stream 118 and travels to a reaction unit 120 where the hydrogen reacts with nitrogen to form ammonia (NH) in the reaction unit 120₃). In some embodiments, at H₂Before proceeding to a reaction unit such as reaction unit 120, according to the pair H₂If required, carrying out other H₂Purification techniques such as PSA, adsorption or membrane separation. Ammonia exits at outlet 122Reaction unit 120, thereby reacting H₂By NH₃In a smaller volume. Reaction unit 120 may include a pressurized multi-stage ammonia production system (PMAPS) to produce ammonia in a pressurized liquid phase. Pressurized liquid NH₃Can be transported by pressurized tanker and, where hydrogen is required, by using NH₃Electrolytic cell, NH₃Can be reversibly converted into N again₂And H₂。

The singular forms "a", "an" and "the" include plural referents unless the context clearly dictates otherwise.

The term "about" when used in reference to a value or range refers to a value that includes plus or minus 5% of the value or range given.

In the drawings and specification, there have been disclosed embodiments of the systems and methods of the present disclosure for the efficient separation of H from syngas in a process for producing hydrogen from a hydrocarbonaceous petroleum fuel₂With little greenhouse gas emissions, and although specific terms are employed, they are used in a descriptive sense only and not for purposes of limitation. Embodiments of the present disclosure have been described in considerable detail with particular reference to these illustrated embodiments. It will, however, be evident that various modifications and changes may be made within the spirit and scope of the disclosure as described in the foregoing specification, and such modifications and changes are considered to be equivalents of the present disclosure and are part of the present disclosure.