WO2022177781A1 - Procédé pour réduire les demandes d'énergie et d'eau de lavage du co2 à partir de gaz résiduaires pauvres en co2 - Google Patents
Procédé pour réduire les demandes d'énergie et d'eau de lavage du co2 à partir de gaz résiduaires pauvres en co2 Download PDFInfo
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- WO2022177781A1 WO2022177781A1 PCT/US2022/015723 US2022015723W WO2022177781A1 WO 2022177781 A1 WO2022177781 A1 WO 2022177781A1 US 2022015723 W US2022015723 W US 2022015723W WO 2022177781 A1 WO2022177781 A1 WO 2022177781A1
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- stream
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- byproduct stream
- water
- carbon dioxide
- Prior art date
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- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 title claims abstract description 82
- 238000000034 method Methods 0.000 title claims abstract description 61
- 239000002912 waste gas Substances 0.000 title claims abstract description 22
- 238000005201 scrubbing Methods 0.000 title description 13
- 239000006227 byproduct Substances 0.000 claims abstract description 74
- CURLTUGMZLYLDI-UHFFFAOYSA-N Carbon dioxide Chemical compound O=C=O CURLTUGMZLYLDI-UHFFFAOYSA-N 0.000 claims abstract description 68
- 229910002092 carbon dioxide Inorganic materials 0.000 claims abstract description 46
- 239000011435 rock Substances 0.000 claims abstract description 45
- 239000001569 carbon dioxide Substances 0.000 claims abstract description 28
- 239000005431 greenhouse gas Substances 0.000 claims abstract description 14
- 238000011065 in-situ storage Methods 0.000 claims abstract description 13
- 239000007789 gas Substances 0.000 claims description 60
- 238000004519 manufacturing process Methods 0.000 claims description 37
- 238000002347 injection Methods 0.000 claims description 30
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- HZAXFHJVJLSVMW-UHFFFAOYSA-N 2-Aminoethan-1-ol Chemical compound NCCO HZAXFHJVJLSVMW-UHFFFAOYSA-N 0.000 claims description 9
- 239000012621 metal-organic framework Substances 0.000 claims description 9
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- BPQQTUXANYXVAA-UHFFFAOYSA-N Orthosilicate Chemical compound [O-][Si]([O-])([O-])[O-] BPQQTUXANYXVAA-UHFFFAOYSA-N 0.000 claims description 2
- 239000001257 hydrogen Substances 0.000 description 35
- 229910052739 hydrogen Inorganic materials 0.000 description 35
- UFHFLCQGNIYNRP-UHFFFAOYSA-N Hydrogen Chemical compound [H][H] UFHFLCQGNIYNRP-UHFFFAOYSA-N 0.000 description 34
- QGZKDVFQNNGYKY-UHFFFAOYSA-N Ammonia Chemical compound N QGZKDVFQNNGYKY-UHFFFAOYSA-N 0.000 description 26
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- RWSOTUBLDIXVET-UHFFFAOYSA-N Dihydrogen sulfide Chemical compound S RWSOTUBLDIXVET-UHFFFAOYSA-N 0.000 description 19
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- 239000000203 mixture Substances 0.000 description 18
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 description 16
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- 238000006243 chemical reaction Methods 0.000 description 13
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- RAHZWNYVWXNFOC-UHFFFAOYSA-N Sulphur dioxide Chemical compound O=S=O RAHZWNYVWXNFOC-UHFFFAOYSA-N 0.000 description 12
- 239000012535 impurity Substances 0.000 description 11
- 239000007787 solid Substances 0.000 description 11
- XEEYBQQBJWHFJM-UHFFFAOYSA-N Iron Chemical compound [Fe] XEEYBQQBJWHFJM-UHFFFAOYSA-N 0.000 description 10
- 229910052799 carbon Inorganic materials 0.000 description 10
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 description 10
- 229910052500 inorganic mineral Inorganic materials 0.000 description 9
- 239000011707 mineral Substances 0.000 description 9
- 235000010755 mineral Nutrition 0.000 description 9
- 229910002091 carbon monoxide Inorganic materials 0.000 description 8
- 229910052742 iron Inorganic materials 0.000 description 8
- 239000011777 magnesium Substances 0.000 description 8
- 229910052749 magnesium Inorganic materials 0.000 description 8
- 229910052757 nitrogen Inorganic materials 0.000 description 8
- 230000009919 sequestration Effects 0.000 description 8
- 230000015572 biosynthetic process Effects 0.000 description 7
- 239000011575 calcium Substances 0.000 description 7
- 229910000069 nitrogen hydride Inorganic materials 0.000 description 7
- 238000000746 purification Methods 0.000 description 7
- MWUXSHHQAYIFBG-UHFFFAOYSA-N Nitric oxide Chemical compound O=[N] MWUXSHHQAYIFBG-UHFFFAOYSA-N 0.000 description 6
- 230000008901 benefit Effects 0.000 description 6
- 229910052791 calcium Inorganic materials 0.000 description 6
- 238000005516 engineering process Methods 0.000 description 6
- 229910021529 ammonia Inorganic materials 0.000 description 5
- 150000004649 carbonic acid derivatives Chemical class 0.000 description 5
- 239000012071 phase Substances 0.000 description 5
- 239000004820 Pressure-sensitive adhesive Substances 0.000 description 4
- VTYYLEPIZMXCLO-UHFFFAOYSA-L calcium carbonate Substances [Ca+2].[O-]C([O-])=O VTYYLEPIZMXCLO-UHFFFAOYSA-L 0.000 description 4
- 229910001748 carbonate mineral Inorganic materials 0.000 description 4
- 239000003546 flue gas Substances 0.000 description 4
- 239000012530 fluid Substances 0.000 description 4
- 230000007774 longterm Effects 0.000 description 4
- 229910052751 metal Inorganic materials 0.000 description 4
- 239000002184 metal Substances 0.000 description 4
- 238000012544 monitoring process Methods 0.000 description 4
- BVKZGUZCCUSVTD-UHFFFAOYSA-L Carbonate Chemical compound [O-]C([O-])=O BVKZGUZCCUSVTD-UHFFFAOYSA-L 0.000 description 3
- MWRWFPQBGSZWNV-UHFFFAOYSA-N Dinitrosopentamethylenetetramine Chemical compound C1N2CN(N=O)CN1CN(N=O)C2 MWRWFPQBGSZWNV-UHFFFAOYSA-N 0.000 description 3
- VYPSYNLAJGMNEJ-UHFFFAOYSA-N Silicium dioxide Chemical compound O=[Si]=O VYPSYNLAJGMNEJ-UHFFFAOYSA-N 0.000 description 3
- NINIDFKCEFEMDL-UHFFFAOYSA-N Sulfur Chemical compound [S] NINIDFKCEFEMDL-UHFFFAOYSA-N 0.000 description 3
- 230000002378 acidificating effect Effects 0.000 description 3
- 238000007906 compression Methods 0.000 description 3
- 230000006835 compression Effects 0.000 description 3
- 239000003673 groundwater Substances 0.000 description 3
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- ZLNQQNXFFQJAID-UHFFFAOYSA-L magnesium carbonate Chemical class [Mg+2].[O-]C([O-])=O ZLNQQNXFFQJAID-UHFFFAOYSA-L 0.000 description 3
- 239000001095 magnesium carbonate Substances 0.000 description 3
- 239000003345 natural gas Substances 0.000 description 3
- 238000005086 pumping Methods 0.000 description 3
- 230000002195 synergetic effect Effects 0.000 description 3
- FYYHWMGAXLPEAU-UHFFFAOYSA-N Magnesium Chemical compound [Mg] FYYHWMGAXLPEAU-UHFFFAOYSA-N 0.000 description 2
- 235000010216 calcium carbonate Nutrition 0.000 description 2
- BVKZGUZCCUSVTD-UHFFFAOYSA-N carbonic acid Chemical compound OC(O)=O BVKZGUZCCUSVTD-UHFFFAOYSA-N 0.000 description 2
- 239000003054 catalyst Substances 0.000 description 2
- 238000005868 electrolysis reaction Methods 0.000 description 2
- RAQDACVRFCEPDA-UHFFFAOYSA-L ferrous carbonate Chemical class [Fe+2].[O-]C([O-])=O RAQDACVRFCEPDA-UHFFFAOYSA-L 0.000 description 2
- 239000002803 fossil fuel Substances 0.000 description 2
- 239000013505 freshwater Substances 0.000 description 2
- 238000002309 gasification Methods 0.000 description 2
- 235000011160 magnesium carbonates Nutrition 0.000 description 2
- CRVGTESFCCXCTH-UHFFFAOYSA-N methyl diethanolamine Chemical compound OCCN(C)CCO CRVGTESFCCXCTH-UHFFFAOYSA-N 0.000 description 2
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- 230000002441 reversible effect Effects 0.000 description 2
- 229910052717 sulfur Inorganic materials 0.000 description 2
- 239000011593 sulfur Substances 0.000 description 2
- 239000005335 volcanic glass Substances 0.000 description 2
- 229910021532 Calcite Inorganic materials 0.000 description 1
- OYPRJOBELJOOCE-UHFFFAOYSA-N Calcium Chemical compound [Ca] OYPRJOBELJOOCE-UHFFFAOYSA-N 0.000 description 1
- 235000019738 Limestone Nutrition 0.000 description 1
- FAPWRFPIFSIZLT-UHFFFAOYSA-M Sodium chloride Chemical compound [Na+].[Cl-] FAPWRFPIFSIZLT-UHFFFAOYSA-M 0.000 description 1
- UCKMPCXJQFINFW-UHFFFAOYSA-N Sulphide Chemical compound [S-2] UCKMPCXJQFINFW-UHFFFAOYSA-N 0.000 description 1
- 239000005864 Sulphur Substances 0.000 description 1
- 230000035508 accumulation Effects 0.000 description 1
- 238000009825 accumulation Methods 0.000 description 1
- 230000000274 adsorptive effect Effects 0.000 description 1
- 229910052612 amphibole Inorganic materials 0.000 description 1
- 229910000512 ankerite Inorganic materials 0.000 description 1
- 239000008346 aqueous phase Substances 0.000 description 1
- QVGXLLKOCUKJST-UHFFFAOYSA-N atomic oxygen Chemical compound [O] QVGXLLKOCUKJST-UHFFFAOYSA-N 0.000 description 1
- 230000033558 biomineral tissue development Effects 0.000 description 1
- 229910052626 biotite Inorganic materials 0.000 description 1
- 238000004364 calculation method Methods 0.000 description 1
- VTVVPPOHYJJIJR-UHFFFAOYSA-N carbon dioxide;hydrate Chemical compound O.O=C=O VTVVPPOHYJJIJR-UHFFFAOYSA-N 0.000 description 1
- 150000001768 cations Chemical class 0.000 description 1
- 239000003153 chemical reaction reagent Substances 0.000 description 1
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- 230000001419 dependent effect Effects 0.000 description 1
- 238000011978 dissolution method Methods 0.000 description 1
- 238000005553 drilling Methods 0.000 description 1
- 239000003651 drinking water Substances 0.000 description 1
- 235000020188 drinking water Nutrition 0.000 description 1
- 238000005265 energy consumption Methods 0.000 description 1
- 239000008398 formation water Substances 0.000 description 1
- 150000002431 hydrogen Chemical class 0.000 description 1
- 229910052909 inorganic silicate Inorganic materials 0.000 description 1
- 239000006028 limestone Substances 0.000 description 1
- 239000007791 liquid phase Substances 0.000 description 1
- 229910000021 magnesium carbonate Inorganic materials 0.000 description 1
- 235000014380 magnesium carbonate Nutrition 0.000 description 1
- 229910052748 manganese Inorganic materials 0.000 description 1
- 239000011572 manganese Substances 0.000 description 1
- 239000000463 material Substances 0.000 description 1
- 230000007246 mechanism Effects 0.000 description 1
- 238000005374 membrane filtration Methods 0.000 description 1
- 229910021645 metal ion Inorganic materials 0.000 description 1
- 239000010450 olivine Substances 0.000 description 1
- 229910052609 olivine Inorganic materials 0.000 description 1
- 239000001301 oxygen Substances 0.000 description 1
- 229910052760 oxygen Inorganic materials 0.000 description 1
- 239000002244 precipitate Substances 0.000 description 1
- 229910052611 pyroxene Inorganic materials 0.000 description 1
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- 230000001105 regulatory effect Effects 0.000 description 1
- 238000009877 rendering Methods 0.000 description 1
- 229910021646 siderite Inorganic materials 0.000 description 1
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- 239000000377 silicon dioxide Substances 0.000 description 1
- 239000011780 sodium chloride Substances 0.000 description 1
- 150000004763 sulfides Chemical class 0.000 description 1
- 150000003464 sulfur compounds Chemical class 0.000 description 1
- 210000003462 vein Anatomy 0.000 description 1
- 239000008215 water for injection Substances 0.000 description 1
- 230000003442 weekly effect Effects 0.000 description 1
- 239000010457 zeolite Substances 0.000 description 1
Classifications
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/34—Chemical or biological purification of waste gases
- B01D53/46—Removing components of defined structure
- B01D53/62—Carbon oxides
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/02—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by adsorption, e.g. preparative gas chromatography
- B01D53/04—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by adsorption, e.g. preparative gas chromatography with stationary adsorbents
- B01D53/047—Pressure swing adsorption
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
- B01D53/1456—Removing acid components
- B01D53/1475—Removing carbon dioxide
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
- E21B41/005—Waste disposal systems
- E21B41/0057—Disposal of a fluid by injection into a subterranean formation
- E21B41/0064—Carbon dioxide sequestration
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2251/00—Reactants
- B01D2251/60—Inorganic bases or salts
- B01D2251/602—Oxides
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
- B01D2252/10—Inorganic absorbents
- B01D2252/103—Water
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
- B01D2252/20—Organic absorbents
- B01D2252/204—Amines
- B01D2252/20421—Primary amines
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
- B01D2252/20—Organic absorbents
- B01D2252/204—Amines
- B01D2252/20478—Alkanolamines
- B01D2252/20484—Alkanolamines with one hydroxyl group
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2253/00—Adsorbents used in seperation treatment of gases and vapours
- B01D2253/20—Organic adsorbents
- B01D2253/204—Metal organic frameworks (MOF's)
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2256/00—Main component in the product gas stream after treatment
- B01D2256/16—Hydrogen
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2257/00—Components to be removed
- B01D2257/30—Sulfur compounds
- B01D2257/302—Sulfur oxides
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2257/00—Components to be removed
- B01D2257/30—Sulfur compounds
- B01D2257/304—Hydrogen sulfide
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2257/00—Components to be removed
- B01D2257/50—Carbon oxides
- B01D2257/504—Carbon dioxide
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2258/00—Sources of waste gases
- B01D2258/02—Other waste gases
- B01D2258/0233—Other waste gases from cement factories
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2258/00—Sources of waste gases
- B01D2258/02—Other waste gases
- B01D2258/025—Other waste gases from metallurgy plants
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/22—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by diffusion
- B01D53/229—Integrated processes (Diffusion and at least one other process, e.g. adsorption, absorption)
Definitions
- Embodiments of the disclosure relate to carbon capture from various CO2 emission sources, including those lean in carbon dioxide, such as may be produced at a power generation facility, as well as those rich in carbon dioxide, such as may result during hydrogen production.
- Embodiments of the disclosure relate to synergistic hydrogen production and carbon capture.
- embodiments of the disclosure relate to hydrogen production from fossil fuels with substantially no greenhouse gas emissions due to carbon capture via mafic rock, for example basalts.
- embodiments of the disclosure relate to carbon dioxide capture via mafic rock, for example basalts.
- Hydrogen or 3 ⁇ 4 is an environmentally-friendly fuel which has the potential to replace greenhouse gas emitting hydrocarbon fuels.
- hydrogen can be used to power fuel cells.
- economically-impractical methods and systems have been proposed for 3 ⁇ 4 production combined with capturing, compressing to a liquid, and injecting co- produced CO2 into deep (greater than about 850 m underground) sedimentary rock reservoirs in a process known as carbon capture and storage (“CCS”).
- CCS carbon capture and storage
- conventional CCS adds significant cost to an already highly-energy-consuming 3 ⁇ 4 production process, thus rendering the combined technology unfeasible under current market and regulatory conditions.
- WO2020/234464 describes a process of obtaining very pure CO 2 and/or H 2 S, pressurizing the CO 2 and/or H 2 S, pumping the pressurized CO 2 and/or H 2 S and pressurized water downhole, dissolving the pressurized CO 2 and/or H 2 S and pressurized water within the wellbore, and trapping the mixture in the formation.
- pressurized gases and water are pumped downhole before being brought into contact with each other, such processes assume that all the gases are dissolved in the water. Indeed, in a relatively short time period, i.e., less than a couple of years, all of the CO 2 is dissolved and trapped in the formation.
- the process of separating and purification of the CO 2 prior to injection is very costly.
- the present disclosure presents systems and methods for efficient carbon capture.
- embodiments relate to production of hydrogen from hydrocarbon fossil fuels with little to no greenhouse gas emissions.
- the first step of the method is co-production of 3 ⁇ 4 and waste or byproduct CO 2 from gaseous, liquid, or solid hydrocarbons (for example steam reforming of natural gas).
- the co-production of 3 ⁇ 4 and CO 2 from hydrocarbons can be accomplished in various processes.
- CO 2 is injected into reactive mafic or ultramafic rocks, where CO 2 and/or other waste gases are permanently immobilized as precipitated carbonate minerals.
- mafic generally describes a silicate mineral or igneous rock that is rich in magnesium and iron.
- Mafic minerals can be dark in color, and rock-forming mafic minerals include olivine, pyroxene, amphibole, and biotite. Mafic rocks include basalt, diabase, and gabbro. Chemically, mafic rocks can be enriched in iron, magnesium, and calcium.
- produced hydrogen can be converted reversibly to ammonia for safe storage and transportation in a reduced volume.
- CCS carbon capture and storage
- 3 ⁇ 4 production occurs preceding an alternative CCS process in which CO 2 is injected into natural geological sinks comprised of reactive basaltic and ultramafic lithologies, where it rapidly reacts to form stable mineral phases, such as precipitated carbonates.
- Carbon storage in basalts (“CSB”) consumes significantly less energy than other CCS systems and processes, has advantageously high tolerance to acid gas impurities (i.e., H 2 S), does not require deep wells, such as those 850 m deep or deeper, and does not require long term reservoir monitoring.
- Rapid immobilization of CO 2 as solid, stable carbonate minerals not only ensures permanent removal of CO 2 from the environment, but also precludes the need for sophisticated monitoring programs needed at conventional CCS sites.
- CSB negates the need for expensive and energy consuming steps to remove sulfur/H 2 S impurities from CO 2 and other gases produced during 3 ⁇ 4 production.
- Another important advantage is that in contrast to liquid CO 2 , which is less dense than reservoir water and thus buoyant, CCk-rich water has higher density than ambient groundwater. Consequently, when injected CCk-rich water will sink in the reservoir rather than move upwards, which eliminates the need of a caprock - a critically important geological feature of all conventional CCS reservoirs.
- injection and storage of CO 2 in basalts and mafics has no impact on the quality of groundwater residing in those lithologies. This is particularly important when such aquifers are used to supply drinking water or water for other purposes.
- a method for producing hydrogen substantially without greenhouse gas emissions including producing a product gas comprising hydrogen and carbon dioxide from a hydrocarbon fuel source; separating hydrogen from the product gas to create a hydrogen product stream and a byproduct stream; injecting the byproduct stream into a reservoir containing mafic rock; and allowing components of the byproduct stream to react in situ with components of the mafic rock to precipitate and store components of the byproduct stream in the reservoir.
- the mafic rock comprises basaltic rock.
- the byproduct stream before the step of injecting the byproduct stream into the reservoir, is further treated to separate and purify CO2 from other components to increase CO2 concentration of the byproduct stream for injection into the reservoir.
- the method further comprise the step of liquefying CO2 in the byproduct stream for injection into the reservoir.
- the method includes the step of mixing the byproduct stream with water, the byproduct stream comprising H2S.
- the method includes the step of reacting the separated hydrogen with nitrogen to form compressed liquid ammonia.
- Still other embodiments include the steps of transporting the compressed liquid ammonia and returning the compressed liquid ammonia to hydrogen and nitrogen via electrolysis for use of hydrogen as a hydrogen fuel source.
- the step of producing a product gas includes steam reforming or partial oxidation.
- the step of allowing components of the byproduct stream to react in situ with components of the mafic rock to precipitate produces precipitates selected from the group consisting of: calcium carbonates, magnesium carbonates, iron carbonates, and combinations thereof.
- the reservoir is between about 250 m and about 500 m below the surface and is between about 150 °C and about 280 °C, or less. In other embodiments, the reservoir is between about 350 m and about 1,500 m below the surface and is less than about 325 °C.
- a system for producing hydrogen substantially without greenhouse gas emissions including a hydrogen production unit with a hydrocarbon fuel inlet operable to produce a product gas comprising hydrogen and carbon dioxide from hydrocarbon fuel; a hydrogen separation unit operable to separate hydrogen from the product gas to create a hydrogen product stream and a byproduct stream; and an injection well operable to inject the byproduct stream into a reservoir containing mafic rock to allow components of the byproduct stream to react in situ with components of the mafic rock to precipitate and store components of the byproduct stream in the reservoir.
- the mafic rock comprises basaltic rock.
- the system includes a byproduct treatment unit to treat the byproduct stream to separate and purify CO2 from other components and to increase CO2 concentration of the byproduct stream for injection into the reservoir.
- the system includes a compressor to liquefy CO2 in the byproduct stream for injection into the reservoir.
- the system includes a mixing unit to mix the byproduct stream with water, the byproduct stream comprising H2S.
- the system includes a reaction unit to react the separated hydrogen with nitrogen to form compressed liquid ammonia.
- the system includes a transportation unit to transport the compressed liquid ammonia and return the compressed liquid ammonia to hydrogen and nitrogen via electrolysis for use of hydrogen as a hydrogen fuel source.
- the hydrogen production unit includes a steam reformer or partial oxidation reactor.
- components of the produced byproduct stream react in situ with components of the mafic rock to precipitate products selected from the group consisting of: calcium carbonates, magnesium carbonates, iron carbonates, and combinations thereof.
- the reservoir is between about 250 m and about 500 m below the surface and is between about 150 °C and about 280 °C. Still in other embodiments, the reservoir is between about 350 m and about 1,500 m below the surface and is less than about 325 °C.
- a method for reducing greenhouse gas emissions including producing a waste gas stream comprising between 0 and 40 vol%, inclusive, carbon dioxide, pre-concentrating the waste gas stream to increase a concentration of carbon dioxide, producing a concentrated byproduct stream comprising 40 vol% to 75 vol% carbon dioxide, dissolving carbon dioxide contained in the concentrated byproduct stream in water, producing a dissolved byproduct stream and an undissolved byproduct stream, injecting the dissolved byproduct stream or a portion thereof into a reservoir containing mafic rock, and allowing components of the dissolved byproduct stream to react in situ with components of the mafic or ultramafic rocks to precipitate and store components of the byproduct stream in the reservoir.
- a system for reducing greenhouse gas emissions including a facility configured to produce a waste gas stream comprising from 0 vol% to 40 vol% carbon dioxide, inclusive, a pre-concentrator configured for increasing a concentration of carbon dioxide in the waste gas stream, producing a concentrated byproduct stream, a water dissolution system configured for dissolving the carbon dioxide in water, producing a dissolved byproduct stream and an undissolved byproduct stream, and an injection well operable to inject the dissolved byproduct stream into a reservoir containing mafic rock to allow components of the concentrated byproduct stream to react in situ with components of the mafic or ultramafic rocks to precipitate and store components of the byproduct stream in the reservoir.
- a method for sequestering CO 2 including producing a product gas comprising carbon dioxide and one or more selected from the group consisting of H 2 S, SO 2 , Ar, and N 2 from a hydrocarbon fuel source, pre-concentrating the product gas in a pre-concentrator to increase a concentration of carbon dioxide from less than 20 vol% to above 40 vol%, producing a concentrated byproduct stream, dissolving the concentrated byproduct stream in water, producing a dissolved byproduct stream comprising water, CO 2 , and any dissolved H 2 S and/or SO 2 ; and injecting the dissolved byproduct stream into a reservoir containing mafic or ultramafic rocks, and allowing the CO 2 and any H 2 S and SO 2 to react in situ with components of the mafic rock to precipitate and store components of the byproduct stream in the reservoir.
- FIG. 1 shows a schematic flow chart for an example embodiment of a system for simultaneous FE production, FE transport, and CO2 sequestration for producing FE from hydrocarbons with near zero greenhouse gas emissions.
- FIG. 2 shows a schematic flow chart for an example embodiment of a CO2 sequestration using a pre-concentrator.
- hydrocarbons for example methane
- H2O steam reforming
- hydrocarbons for example methane
- catalysts to release raw syngas consisting of hydrogen (FE), carbon monoxide (CO), small amounts of carbon dioxide (CO2), and/or other impurities as shown in Equations 1 and 2:
- This raw syngas also contains minor amounts of C0 2 and/or nitrogen (N 2 , if air was used instead of pure 0 2 ).
- N 2 if air was used instead of pure 0 2 .
- the raw syngas is then purified, and its H 2 content maximized by the reaction of Equation 3.
- Table 1 The composition of an example shifted syngas produced by both processes (steam reforming and partial oxidation) is presented in Table 1:
- H 2 is purified by separation from C0 2 and other impurities by processes that employ adsorption, absorption, and/or membrane filtration.
- One example process is Pressure Swing Adsorption (“PSA”), which uses pressure- dependent selective adsorption properties of materials such as activated carbon, silica, and zeolites. Waste or byproduct C0 2 and other impurities separated from H 2 during PSA are then vented to the atmosphere.
- PSA Pressure Swing Adsorption
- Waste or byproduct C0 2 and other impurities separated from H 2 during PSA are then vented to the atmosphere.
- a conventional CCS scheme were to be used to sequester C0 2 , then the C0 2 must be purified further and compressed to a liquid (supercritical) state for transportation and injection in a deep reservoir. Both steps, however, are avoided (or simplified significantly) here when CSB is applied instead.
- CSB While conventional CCS relies predominantly on physical processes such as the injection and storage of single phase liquid C0 2 in non-reactive rock reservoirs (e.g., sandstone, limestone), CSB relies on the naturally occurring chemical reactions between C0 2 and mafic and ultramafic rocks to precipitate solid carbonates. Reactions include the following: first CO2 dissolves in and reacts with water (either or both water supplied with CO2 gas at the surface or water present in situ in a mafic reservoir) to form a week carbonic acid as shown in Equations 5-7:
- Acidified water dissolves Ca, Fe, and Mg-rich silicate phases (minerals and/or volcanic glass) which results in the release of divalent metal ions in solution according to Equation 8:
- Geochemical reaction-transport modeling demonstrates that mineral phases (for example calcite, siderite, and magnesite) will remain stable under prevailing subsurface conditions, hence safely removing CO2 from the atmosphere for hundreds of thousands to millions of years.
- Other carbonate minerals include ankerite Ca[Fe, Mg, Mn](C0 3 ) 2 .
- CSB has extreme tolerance for other water soluble acid gas impurities (e.g. H2S, which is also mineralized as sulphides).
- Such an advantageous quality not only simplifies the process further, eliminating the need to remove those impurities from a gas mixture exiting an 3 ⁇ 4 production process, but it also allows for simultaneous sequestering of all other H2O soluble gas contaminants capable of forming stable mineral phases by reacting with basalts/ultramafics.
- CO2 dissolution in water for CSB can be achieved by either: a) separately injecting CO2 and water in the tubing and annular space of injector wells and allowing these to mix at or below about a 350 m depth in the wellbore prior to entering the reservoir; or b) dissolving CO2 and water at the surface in a pressurized vessel and then injecting the solution in a basalt/ultramafic reservoir. While the first method generally applies to pure CO2 and/or a mixture of CO2 and other water soluble acid gases, the latter method is used to effectively separate CO2 (and other water soluble gases) from insoluble or weekly soluble impurities, and can therefore be used to process complex flue gas mixtures (e.g. shifted syngas).
- complex flue gas mixtures e.g. shifted syngas
- CSB may be done by injecting supercritical (liquid) CO2 in basalts or ultramafics; however, this would increase energy demands due to the need for liquefying CO2 via compression.
- Table 1 quantity of fresh water (in tons) needed to dissolve one ton of CO2 at 25°C as a function of the pressure and fraction (%vol) of CO2 in the gas mixture.
- Water demand will increase significantly if CO2 is to be scrubbed from complex waste gas mixtures. This is because CO2 solubility in water is proportional to its partial pressure (or concentration) in the mixture. For example, given the same pressure and temperature conditions (i.e. 35 bar and 25°C) the amount of water required to scrub one ton of CO2 from a N2-CO2 mixture containing 40 vol% CO2 will be 47.3 tons.
- the quantity of water needed to scrub one ton of CO2 will be 189.3 tons or greater. Therefore, the water and/or energy demands for scrubbing CO2 from CCF-lean gas mixtures is high and potentially limiting to the applicability of CSB in such cases. While conditions of 35 bar and 25 °C are noted above, other scrubbing conditions may also be used, and may vary depending upon the feed gas composition. For example, pressure and temperature can be as high as that which CO2 will turn supercritical.
- 3 ⁇ 4 is stored and transported as a liquid at a temperature of about -253 °C, which requires special double-walled isolated vessels and/or constant refrigeration.
- NH3 liquid ammonia
- reversible chemical conversion of 3 ⁇ 4 into liquid ammonia (NH3) allows storage and transportation of 3 ⁇ 4 at low pressure and ambient temperatures, at greatly reduced volumes.
- the reversible 3 ⁇ 4 to NH3 storage and transport method is inherently safer and advantageous, in particular where large volumes of 3 ⁇ 4 are to be stored and transported.
- CCF-rich tail gases from other sources such as refining, power production, and desalinization could, after limited treatment, be either added to the principal waste stream or independently injected into reactive lithologies for permanent immobilization and disposal.
- Unexpected and surprising advantages of simultaneously producing 3 ⁇ 4 from hydrocarbons while using CSB for permanent CO2 immobilization in basalts and ultramafics include significantly lower predicted energy usage and cost due to: lower energy consumption and lower well costs because there is no requirement to compress and liquefy the CCF; lower complexity of operations due to high tolerance to impurities in the CO2 stream; simultaneous removal of H2S along with CO2 in the reservoirs via precipitation as solids; no need for a reservoir caprock; and no need for sophisticated long-term monitoring programs. There is no need to liquefy CO2 when it is dissolved in water either at the surface or in the wellbore, but it would be liquefied if directly injected in the subsurface as supercritical fluid.
- FIG. 1 shows a schematic flow chart for an example embodiment of a system for simultaneous H2 production, 3 ⁇ 4 transport, and CO2 sequestration for producing 3 ⁇ 4 from hydrocarbons with near zero greenhouse gas emissions.
- a hydrocarbon inlet 102 provides a hydrocarbon source, for example natural gas, to a hydrogen production system 104.
- Hydrogen production system 104 might include steam reforming or partial oxidation, and water- gas shift reactions, for example as described in Equations 1-4.
- Production gases exit via outlet 106 to a separation unit 108.
- Separation unit 108 is operable to separate hydrogen from CO2 and other byproducts, and can include for example one or more absorption units, adsorption units, membrane separation units, or any suitable separation technology for separating 3 ⁇ 4 from CO2 and other product gases, such as for example acid gases.
- CO2 purification and liquidification unit 112 can optionally proceed to a further CO2 purification and liquidification unit 112, but need not to.
- further CO2 purification and liquidification unit 112 liquefied CO2 is injected into basaltic formation 116 via injection well 114 to form solid precipitated metal carbonates per Equations 5-9.
- CO2 and additional gases such as acid gases exit separation unit 108 via outlet 110 and proceed directly into basaltic formation 116 via injection well 114 to form solid precipitated metal carbonates per Equations 5-9.
- CO2 can be mixed with water as a gas at the surface or in situ in basaltic formation 116, or both. Solid carbonate nodules form in vugs and veins in basalt around injection wells and extending outwardly from the injection wells.
- Rates of basalt dissolution and mineral carbonation reactions can increase with increasing temperature, and thus higher temperature basaltic reservoirs may be advantageous, while deep reservoirs beyond about 350 m are not required because high pressures are not required to keep CO2 in a pressurized or liquid state.
- An example suitable reservoir temperature is about 185 °C, or for example between about 150 °C and about 280 °C.
- injected CO2 either by itself or with other gases, creates an acidic environment with water near the injection well, such as injection well 114. Near injection well 114, the acidic fluids remain undersaturated with respect to basaltic minerals and volcanic glass.
- Reaction unit 120 can include a pressurized multistage ammonia production system (PMAPS) to produce ammonia in a pressurized liquid phase.
- PMAPS pressurized multistage ammonia production system
- Pressurized liquid NH 3 can be transported by a pressurized tanker truck, and using an NH 3 electrolyzer, NH 3 can be reversibly returned to N 2 and 3 ⁇ 4 wherever hydrogen is required.
- CO2 may be effectively and efficiently sequestered from other various product and waste streams, including CC -lean streams from facility is selected from the group consisting of a power production facility, a desalination plant, a refinery, a chemical production plant, an ore smelting plant, a cement production plant, a logging plant, a landfill, a fertilizer production plant, and other industrial facilities, among others.
- the CCk-lean stream may have other gas components which may also be handled by the process and system of one or more embodiments disclosed herein.
- the CC -lean stream may have N2, Ar, SO2, H2S, or other inert gases or acid gases.
- Inert gases may ultimately be vented to atmosphere while CO2 and other acid gases may ultimately be sequestered.
- the CC -lean streams that may be processed according to embodiments herein may have a CO2 concentration of less than 40 vol%.
- Embodiments herein may also effectively sequester CO2 from very lean streams, such as a flue gas or other waste streams having, for example, from 4 vol% to 12 vol% CO2.
- embodiments herein may be used to initially enhance the CO2 concentration of the waste stream and then effectively dissolve the CO2 and other acid gases in water, and providing the mixture of CO2 and water for injection into a well.
- the CO2 concentration of the CCk-lean stream may be less than 5,7, 10, 15, 20, 25 or 30 vol % before pre-concentration, and may be concentrated to above 35, 40, 45, 50, 55, 60, or 70 vol %, where any lower limit may be combined with any appropriate upper limit. While waste streams may have a broad range of CO2 concentrations, the CSB has been found to effective where the waste stream is initially pre-concentrated to a CO2 concentration above 35, 40, or 45 vol %.
- gas streams having higher initial concentrations than those listed above may be pre-concentrated according to embodiments herein, such as where there is a positive net economic impact, such as in reduction of water usage, energy usage, and/or capital or operating expenses (CAPEX and OPEX, respectively) for the facility.
- a positive net economic impact such as in reduction of water usage, energy usage, and/or capital or operating expenses (CAPEX and OPEX, respectively) for the facility.
- Embodiments herein may result in a concentrated CO2 stream having a CO2 concentration of greater than 40 vol%, as noted above, including high purity CO2 streams, such as greater than 90 vol%, for example.
- Some embodiments herein may provide a concentrated CO2 stream having a moderate purity of CO2, , such as less than 85 vol%, less than 80 vol%, less than 75 vol% or less than 70 vol%. It has been found that effective sequestration may be achieved through pre-conditioning to fit a wide range of C02 concentrations, depending on water and energy availability, as well CAPEX and OPEX of the facility.
- the ability to process lower purity CO 2 streams according to embodiments herein may provide significant advantages in processing options, costs, and other conventional factors, especially as compared to other carbon sequestration processes that require greater than 99 vol% CO 2 to be cost effective.
- CSB as described herein can apply to other processes and may be implemented at any industrial facility (e.g., power plants, refineries, water desalination plants, cement plants, smelters, etc.) where CSB can be utilized to reduce/eliminate the facilities’ CO 2 (and H 2 S) emissions, even in facilities where the CO 2 concentration in the waste byproduct stream is low and conventional sequestration by CSB is not practical. This is conditional upon the proximity of said facilities to accumulations of reactive rocks, such a basalt, of sufficient volume, thickness, and water saturation volume, to allow the use of CSB for CO 2 sequestration.
- any industrial facility e.g., power plants, refineries, water desalination plants, cement plants, smelters, etc.
- CSB can be utilized to reduce/eliminate the facilities’ CO 2 (and H 2 S) emissions, even in facilities where the CO 2 concentration in the waste byproduct stream is low and conventional sequestration by CSB is not practical. This is conditional upon the proximity of said facilities
- CO 2 (acid gas) pre concentration step it is envisioned to apply a separate CO 2 (acid gas) pre concentration step.
- the purpose of this step is to increase CO 2 concentrations to the medium-high ranges, rather than to the near 100 vol% CO 2 concentrations required for conventional CCS.
- the CO 2 water scrubbing mechanism may also be intended to sequester acid sulphur gases (e.g., H 2 S), the CO 2 concentration method does not need to remove such impurities.
- This step can employ any conventional method or technology for pre-concentrating CO 2 , such as, but not limited to, absorption based methods using monoethanolamine (MEA) solutions, adsorption based methods such as Pressure Swing Adsorption (PSA), metal-organic framework (MOF), membrane gas separation, and chemical looping combustion, among other.
- MAA monoethanolamine
- PSA Pressure Swing Adsorption
- MOF metal-organic framework
- membrane gas separation membrane gas separation
- chemical looping combustion among other.
- multiple of the same unit may be used in series, multiple different units may be used in series, and parallel pre-concentrating steps may be used.
- two PSAs may be used in series, with two series of PSAs being used in parallel.
- two PSAs may be used with an MEA, MOF, membrane gas separation, or chemical looping combustion unit either before, after, or in between the PSAs.
- Such processes may increase the CO2 concentration by removing one or more of water vapor, nitrogen, nitrogen oxide, CO, etc.
- processes may increase the CO2 and FFS concentration by removing one or more of water vapor, nitrogen, nitrogen oxide, CO, etc.
- CO2 concentration from 7-10 vol % can be achieved by introducing a CO2 (or a CO2 and FbS) concentration unit to the water scrubbing process at a CSB facility.
- This may reduce the scrubbing facility’s operational costs (OPEX) by reducing the volume of waste gas to be processed, the volume of water needed to dissolve/scrub CO2 and consequently the energy needed for pumping and compressing both the water and the gas. That in turn may also reduce capital expenditure costs (CAPEX) by reducing the size of the scrubber facility, the diameter of the delivery pipeline(s) as well as the number of disposal wells needed.
- OPEX operational costs
- CAPEX capital expenditure costs
- FIG. 2 shows a schematic of the system disclosed herein in which a CO2 pre concentrator is used to prepare a CO2 stream for water scrubbing and disposal in reactive rocks.
- the CO2 stream may be a CCk-lean waste gas stream from a power production facility, a desalination plant, a refinery, a chemical production plant, an ore smelting plant, a cement production plant, a logging plant, a landfill, a fertilizer production plant, or other industrial facilities.
- a CCk-lean stream 200 from any suitable source may be fed to the CO2 pre-concentrator 202, which may produce a concentrated CO2 stream 204 and an insoluble gas stream 218a.
- the concentrated CO2 stream may then be fed to a compressor 206 to increase the pressure of the concentrated CO2 stream, producing a pressurized CO2 stream 208.
- the concentrated CO2 stream 208 may then be fed to a CO2 scrubbing unit, where the gases are contacted with water to dissolve the CO2.
- CO2 scrubbing unit 210 may also be operable to separate N2, Ar, and other insoluble or inert gases from CO2 and other acid gases, such as hydrogen sulfide (H2S) and/or sulfur dioxide (SO2), while dissolving CO2 and other acid gases, such as H2S, in water.
- a water inlet 212 is fed to a water pump 214 with the pressurized water 216 being used as the scrubbing medium.
- the insoluble gases (or undissolved byproducts) are collected in outlet 218b, and may be sent to further purification, utilization, vented to atmosphere, or a combination thereof, as necessary.
- CO2 and additional gases, such as acid gases, are dissolved in the water and exit scrubbing unit 210 via outlet 220.
- the CC -water mixture may then be fed to a pump 222 and injected via flow line 224 into basaltic formation 226, such as through an injection well, to form solid precipitated metal carbonates per Equations 5-9.
- Solid carbonate or sulfide nodules form in basalt around injection wells and extend outwardly from the injection wells.
- embodiments herein may provide for the efficient sequestration of carbon from both CCh-lean waste streams and synergistic hydrogen production.
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