Method for reducing energy and water demands of scrubbing CO.SUB.2 .from CO.SUB.2.-lean waste gases

Abstract

Methods and systems for reducing greenhouse gas emissions, including producing a waste gas stream comprising form greater than 0 vol % to less than 20 vol %, inclusive, carbon dioxide, pre-concentrating the waste gas stream to increase a concentration of carbon dioxide, producing a concentrated byproduct stream comprising more than 40 vol %, 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 rock to precipitate and store components of the byproduct stream in the reservoir.

Claims

1. A method for reducing greenhouse gas emissions, the method comprising the steps of: producing a waste gas stream comprising from greater than 0 vol % to less than 20 vol % carbon dioxide; pre-concentrating the waste gas stream to increase a concentration of carbon dioxide, producing a concentrated byproduct stream comprising more than 40 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 or ultramafic rock; and allowing components of the dissolved byproduct stream to react in situ with components of the mafic rock to precipitate and store components of the byproduct stream in the reservoir.

2. The method according to claim 1, wherein the waste gas stream comprises from 4 vol % to 12 vol % carbon dioxide.

3. The method according to claim 1, where the mafic rock comprises basaltic rock.

4. The method according to claim 1, where the step of pre-concentrating comprises one or more selected from the group consisting of monoethanolamine (MEA) solution absorption, pressure swing adsorption (PSA), metal-organic framework (MOF), membrane gas separation, and chemical looping combustion.

5. The method according to claim 4, wherein the step of pre-concentrating increases the CO.sub.2 concentration from less than 40 vol % to a concentration of 40 vol % to 75 vol %.

6. The method according to claim 5, wherein the step of pre-concentrating increases the CO.sub.2 concentration from less than 20 vol % to a concentration of 40 vol % to 70 vol %.

7. The method according to claim 1, wherein the waste gas stream additionally comprises one or more of H.sub.2S, SO.sub.2, Ar, and N.sub.2.

8. The method according to claim 7, wherein the dissolving step further comprises dissolving SO.sub.2 and/or H.sub.2S in the water, the Ar and/or N.sub.2 from the waste stream being recovered with the undissolved byproduct stream.

9. The method according to claim 1, where the step of producing a waste gas stream includes steam reforming or partial oxidation.

10. The method according to claim 1, where the reservoir is between about 250 m and about 500 m below the surface and is between about 150° C. and about 280° C.

11. The method according to claim 1, where the reservoir is between about 350 m and about 1,500 m below the surface and is less than about 325° C.

12. A method for sequestering CO.sub.2, the method comprising the steps of: producing a product gas comprising carbon dioxide and one or more selected from the group consisting of H.sub.2S, SO.sub.2, Ar, and N.sub.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.sub.2, and any dissolved H.sub.2S and/or SO.sub.2; injecting the dissolved byproduct stream into a reservoir containing mafic or ultramafic rock; and allowing the CO.sub.2 and any H.sub.2S and SO.sub.2 to react in situ with components of the mafic rock to precipitate and store components of the byproduct stream in the reservoir.

13. The method according to claim 12, further comprising collecting any Ar and N.sub.2 from an overhead outlet of the pre-concentrator.

14. The method according to claim 12, where the step of pre-concentrating comprises one or more selected from the group consisting of monoethanolamine (MEA) solution absorption, pressure swing adsorption (PSA), metal-organic framework (MOF), membrane gas separation, and chemical looping combustion.

Description

BRIEF DESCRIPTION OF DRAWINGS

(1) These and other features, aspects, and advantages of the present disclosure will become better understood with regard to the following descriptions, claims, and accompanying drawings. It is to be noted, however, that the drawings illustrate only several embodiments of the disclosure and are therefore not to be considered limiting of the disclosure's scope as it can admit to other equally effective embodiments.

(2) FIG. 1 shows a schematic flow chart for an example embodiment of a system for simultaneous H.sub.2 production, H.sub.2 transport, and CO.sub.2 sequestration for producing H.sub.2 from hydrocarbons with near zero greenhouse gas emissions.

(3) FIG. 2 shows a schematic flow chart for an example embodiment of a CO.sub.2 sequestration using a pre-concentrator.

DETAILED DESCRIPTION

(4) So that the manner in which the features and advantages of the embodiments of systems and methods of H.sub.2 production from hydrocarbons with near zero greenhouse gas emissions, as well as others, which will become apparent, may be understood in more detail, a more particular description of the embodiments of the present disclosure briefly summarized previously may be had by reference to the embodiments thereof, which are illustrated in the appended drawings, which form a part of this specification. It is to be noted, however, that the drawings illustrate only various embodiments of the disclosure and are therefore not to be considered limiting of the present disclosure's scope, as it may include other effective embodiments as well.

(5) The production of H.sub.2 from hydrocarbons using technologies such as steam-reforming or partial oxidation/gasification includes three steps. In steam reforming, hydrocarbons, for example methane, are heated in the presence of H.sub.2O (steam) and catalysts to release raw syngas consisting of hydrogen (H.sub.2), carbon monoxide (CO), small amounts of carbon dioxide (CO.sub.2), and/or other impurities as shown in Equations 1 and 2:
CH.sub.4+H.sub.2O.Math.CO+3H.sub.2  Eq. 1
and/or
C.sub.nH.sub.m+nH.sub.2O.Math.nCO+(n+0.5 m)H.sub.2  Eq. 2

(6) The raw syngas is then treated to remove sulfur compounds and/or purified further. H.sub.2 yield is then maximized by reacting the raw syngas with H.sub.2O steam in the presence of catalyst to produce H.sub.2 and CO.sub.2 according to Equation 3:
CO+H.sub.2O.fwdarw.CO.sub.2+H.sub.2  Eq. 3

(7) This is known as a water-gas shift reaction, hence the product is called “shifted” syngas. In partial oxidation, hydrocarbons are reacted with small (non-stoichiometric) amounts of oxygen (O.sub.2) to produce raw syngas consisting of H.sub.2 and CO according to Equation 4:
CH.sub.4+½O.sub.2.fwdarw.CO+2H.sub.2  Eq. 4

(8) This raw syngas also contains minor amounts of CO.sub.2 and/or nitrogen (N.sub.2, if air was used instead of pure O.sub.2). The raw syngas is then purified, and its H.sub.2 content maximized by the reaction of Equation 3. The composition of an example shifted syngas produced by both processes (steam reforming and partial oxidation) is presented in Table 1:

(9) TABLE-US-00001 TABLE 1 Example shifted syngas composition from steam reforming or partial oxidation. Component H.sub.2 CO CO.sub.2 N.sub.2 O.sub.2 Ar H.sub.2S H.sub.2O Other Mol % 40.9 1 29.8 2.4 0 0.4 0.01 25.4 0.11

(10) Following water-gas shift, H.sub.2 is purified by separation from CO.sub.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 CO.sub.2 and other impurities separated from H.sub.2 during PSA are then vented to the atmosphere. Unfortunately, if a conventional CCS scheme were to be used to sequester CO.sub.2, then the CO.sub.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.

(11) While conventional CCS relies predominantly on physical processes such as the injection and storage of single phase liquid CO.sub.2 in non-reactive rock reservoirs (e.g., sandstone, limestone), CSB relies on the naturally occurring chemical reactions between CO.sub.2 and mafic and ultramafic rocks to precipitate solid carbonates. Reactions include the following: first CO.sub.2 dissolves in and reacts with water (either or both water supplied with CO.sub.2 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:
CO.sub.2+H.sub.2O.Math.H.sub.2CO.sub.3(aq)  Eq. 5
H.sub.2CO.sub.3.Math.HCO.sub.3.sup.−+H.sup.+  Eq. 6
HCO.sub.3.sup.−.Math.CO.sub.3.sup.2−+H.sup.+  Eq. 7

(12) 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:
(Mg,Fe,Ca).sub.2SiO.sub.4+4H.sup.+.fwdarw.2(Mg,Fe,Ca).sup.2++2H.sub.2O+SiO.sub.2(aq)  Eq. 8

(13) CO.sub.3.sup.2− formed during the reaction shown in Equation 7 reacts with the divalent metal cations leading to the precipitation of carbonate minerals as shown in Equation 9:
(Ca,Mg,Fe).sup.2++CO.sub.3.sup.2−.fwdarw.(Ca,Mg,Fe)CO.sub.3  Eq. 9

(14) Geochemical reaction-transport modeling demonstrates that mineral phases (for example calcite, siderite, and magnesite) will remain stable under prevailing subsurface conditions, hence safely removing CO.sub.2 from the atmosphere for hundreds of thousands to millions of years. Other carbonate minerals include ankerite Ca[Fe, Mg, Mn](CO.sub.3).sub.2. In addition, CSB has extreme tolerance for other water soluble acid gas impurities (e.g. H.sub.2S, 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 H.sub.2 production process, but it also allows for simultaneous sequestering of all other H.sub.2O soluble gas contaminants capable of forming stable mineral phases by reacting with basalts/ultramafics.

(15) CO.sub.2 dissolution in water for CSB can be achieved by either: a) separately injecting CO.sub.2 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 CO.sub.2 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 CO.sub.2 and/or a mixture of CO.sub.2 and other water soluble acid gases, the latter method is used to effectively separate CO.sub.2 (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).

(16) Due to certain thermodynamic constraints of CO.sub.2 dissolution in water, both methods require about 27 tons of H.sub.2O per 1 ton of CO.sub.2 sequestered. In areas where water is in short supply, CSB may be done by injecting supercritical (liquid) CO.sub.2 in basalts or ultramafics; however, this would increase energy demands due to the need for liquefying CO.sub.2 via compression.

(17) The solubility of CO.sub.2 and other waste gases in water is proportional to their fraction in waste gas mixtures. As a result, water scrubbing of CO.sub.2 from CO.sub.2-lean mixtures, such as those found in stack emissions from power generation plants, desalination plants, cement plants, etc., can render CSB less cost effective. A thermodynamic calculation shows that, at optimal conditions (i.e., 100 vol % CO.sub.2 and freshwater as a carrier fluid), the amount of water needed to dissolve one ton of pure CO.sub.2 at a pressure of 35 bar and a temperature of 25° C. is 19 tons (see Table 1).

(18) TABLE-US-00002 TABLE 1 quantity of fresh water (in tons) needed to dissolve one ton of CO.sub.2 at 25° C. as a function of the pressure and fraction (% vol) of CO.sub.2 in the gas mixture. CO.sub.2 Content of gas (mol percent or approximately volume percent) Pressure, bar 100 80 60 40 20 10 5 2 331.3 414.1 552.2 828.2 1656.5 3313.0 6626.0 5 132.5 165.6 220.9 331.3 662.6 1325.2 2650.4 10 66.3 82.8 110.4 165.6 331.3 662.6 1325.2 15 44.2 55.2 73.6 110.4 220.9 441.7 883.5 20 33.1 41.4 55.2 82.8 165.6 331.3 662.6 25 26.5 33.1 44.2 66.3 132.5 265.0 530.1 30 22.1 27.6 36.8 55.2 110.4 220.9 441.7 35 18.9 23.7 31.6 47.3 94.7 189.3 378.6 40 16.6 20.7 27.6 41.4 82.8 165.6 331.3 45 14.7 18.4 24.5 36.8 73.6 147.2 294.5 50 13.3 16.6 22.1 33.1 66.3 132.5 265.0

(19) Water demand, however, will increase significantly if CO.sub.2 is to be scrubbed from complex waste gas mixtures. This is because CO.sub.2 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 CO.sub.2 from a N.sub.2—CO.sub.2 mixture containing 40 vol % CO.sub.2 will be 47.3 tons. If the CO.sub.2 concentration in the mixture drops to 10 vol % however, which is the typical CO.sub.2 content of a flue gas stream from a conventional power plant, the quantity of water needed to scrub one ton of CO.sub.2 will be 189.3 tons or greater. Therefore, the water and/or energy demands for scrubbing CO.sub.2 from CO.sub.2-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 CO.sub.2 will turn supercritical.

(20) With respect to the produced H.sub.2, conventionally H.sub.2 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. However, reversible chemical conversion of H.sub.2 into liquid ammonia (NH.sub.3) allows storage and transportation of H.sub.2 at low pressure and ambient temperatures, at greatly reduced volumes. The reversible H.sub.2 to NH.sub.3 storage and transport method is inherently safer and advantageous, in particular where large volumes of H.sub.2 are to be stored and transported.

(21) Due to high tolerance of CSB to impurities in the CO.sub.2 stream (such as H.sub.2S and other gases), CO.sub.2-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.

(22) Unexpected and surprising advantages of simultaneously producing H.sub.2 from hydrocarbons while using CSB for permanent CO.sub.2 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 CO.sub.2; lower complexity of operations due to high tolerance to impurities in the CO.sub.2 stream; simultaneous removal of H.sub.2S along with CO.sub.2 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 CO.sub.2 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.

(23) FIG. 1 shows a schematic flow chart for an example embodiment of a system for simultaneous H.sub.2 production, H.sub.2 transport, and CO.sub.2 sequestration for producing H.sub.2 from hydrocarbons with near zero greenhouse gas emissions. In system 100, 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 CO.sub.2 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 H.sub.2 from CO.sub.2 and other product gases, such as for example acid gases.

(24) CO.sub.2 and additional gases, such as acid gases, exit separation unit 108 via outlet 110 and can optionally proceed to a further CO.sub.2 purification and liquidification unit 112, but need not to. In the case of further CO.sub.2 purification and liquidification unit 112, liquefied CO.sub.2 is injected into basaltic formation 116 via injection well 114 to form solid precipitated metal carbonates per Equations 5-9. Without optional further CO.sub.2 purification and liquidification unit 112, CO.sub.2 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. CO.sub.2 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.

(25) 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 CO.sub.2 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. As explained, injected CO.sub.2, 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.

(26) Undersaturation and acidity leads to dissolution of host rock basalts in the vicinity of injection wells, such as injection well 114. Mineralization then mostly occurs at a distance away from the injection well (which allows continuous injection of CO.sub.2 in a reservoir such as basaltic formation 116), after heat exchange and sufficient dissolution of host basaltic rock neutralizes the acidic water and saturates the formation water with respect to carbonate and sulfur minerals.

(27) Hydrogen exits separation unit 108 at outlet stream 118 to proceed to reaction unit 120 where hydrogen is reacted with nitrogen to form ammonia (NH.sub.3). Ammonia exits reaction unit 120 at outlet 122 for reduced volume transport of H.sub.2 as NH.sub.3. Reaction unit 120 can include a pressurized multistage ammonia production system (PMAPS) to produce ammonia in a pressurized liquid phase. Pressurized liquid NH.sub.3 can be transported by a pressurized tanker truck, and using an NH.sub.3 electrolyzer, NH.sub.3 can be reversibly returned to N.sub.2 and H.sub.2 wherever hydrogen is required.

(28) The above was found to be effective for processes that produce H.sub.2 and have a high concentrations of CO.sub.2 in the byproduct streams (40 vol %+), such as may be produced via gasification and other processes noted. The processing of the hydrogen-containing streams in adsorptive and other processes focused on recovering the hydrogen permits CSB of the CO.sub.2 byproduct, as described in various embodiments above.

(29) However, it has also been found that CO.sub.2 may be effectively and efficiently sequestered from other various product and waste streams, including CO.sub.2-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. In some embodiments, the CO.sub.2-lean stream may have other gas components which may also be handled by the process and system of one or more embodiments disclosed herein. For example, the CO.sub.2-lean stream may have N.sub.2, Ar, SO.sub.2, H.sub.2S, or other inert gases or acid gases. Inert gases may ultimately be vented to atmosphere while CO.sub.2 and other acid gases may ultimately be sequestered. The CO.sub.2-lean streams that may be processed according to embodiments herein may have a CO.sub.2 concentration of less than 40 vol %. Embodiments herein may also effectively sequester CO.sub.2 from very lean streams, such as a flue gas or other waste streams having, for example, from 4 vol % to 12 vol % CO.sub.2. While it is not routine, arguably not even contemplated in the art to sequester CO.sub.2 from such lean streams, by using water solubility trapping for storage in basalts or other reactive rocks, embodiments herein may be used to initially enhance the CO.sub.2 concentration of the waste stream and then effectively dissolve the CO.sub.2 and other acid gases in water, and providing the mixture of CO.sub.2 and water for injection into a well.

(30) The CO.sub.2 concentration of the CO.sub.2-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 CO.sub.2 concentrations, the CSB has been found to effective where the waste stream is initially pre-concentrated to a CO.sub.2 concentration above 35, 40, or 45 vol %. Additionally, 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.

(31) Embodiments herein may result in a concentrated CO.sub.2 stream having a CO.sub.2 concentration of greater than 40 vol %, as noted above, including high purity CO.sub.2 streams, such as greater than 90 vol %, for example. Some embodiments herein may provide a concentrated CO.sub.2 stream having a moderate purity of CO.sub.2, 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 CO.sub.2 concentrations, depending on water and energy availability, as well CAPEX and OPEX of the facility. The ability to process lower purity CO.sub.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.sub.2 to be cost effective.

(32) Since the relationship between the CO.sub.2 partial pressure and its solubility in water is non-linear, a relatively moderate increase of the concentration of CO.sub.2 in the flue gas can improve significantly the cost effectiveness of the CSB dissolution method by significantly reducing water demand. For example, an increase of the concentration of CO.sub.2 from 10 to 40 vol % will reduce the quantity of water needed by a factor of 4, and if CO.sub.2 concentration is increased to 60 vol %, water demand will drop to about one sixth of the volume needed to trap CO.sub.2 from a 10 vol % mixture. This significant reduction of fluid volume will not only reduce the demand of energy for pumping and compression but also the number of disposal wells.

(33) Accordingly, it is further envisioned that 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.sub.2 (and H.sub.2S) emissions, even in facilities where the CO.sub.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.sub.2 sequestration.

(34) In such embodiments, it is envisioned to apply a separate CO.sub.2 (acid gas) pre-concentration step. The purpose of this step is to increase CO.sub.2 concentrations to the medium-high ranges, rather than to the near 100 vol % CO.sub.2 concentrations required for conventional CCS. Because the CO.sub.2 water scrubbing mechanism may also be intended to sequester acid sulphur gases (e.g., H.sub.2S), the CO.sub.2 concentration method does not need to remove such impurities. This step can employ any conventional method or technology for pre-concentrating CO.sub.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. Further, 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. For example, two PSAs may be used in series, with two series of PSAs being used in parallel. Additionally, 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.

(35) Such processes may increase the CO.sub.2 concentration by removing one or more of water vapor, nitrogen, nitrogen oxide, CO, etc. In other embodiments, such processes may increase the CO.sub.2 and H.sub.2S concentration by removing one or more of water vapor, nitrogen, nitrogen oxide, CO, etc.

(36) The increase in CO.sub.2 concentration from 7-10 vol %, as would typically be found in low concentration byproduct streams, to above 40 vol % can be achieved by introducing a CO.sub.2 (or a CO.sub.2 and H.sub.2S) 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 CO.sub.2 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.

(37) FIG. 2 shows a schematic of the system disclosed herein in which a CO.sub.2 pre-concentrator is used to prepare a CO.sub.2 stream for water scrubbing and disposal in reactive rocks. The CO.sub.2 stream may be a CO.sub.2-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 CO.sub.2-lean stream 200 from any suitable source may be fed to the CO.sub.2 pre-concentrator 202, which may produce a concentrated CO.sub.2 stream 204 and an insoluble gas stream 218a. The concentrated CO.sub.2 stream may then be fed to a compressor 206 to increase the pressure of the concentrated CO.sub.2 stream, producing a pressurized CO.sub.2 stream 208. The concentrated CO.sub.2 stream 208 may then be fed to a CO.sub.2 scrubbing unit, where the gases are contacted with water to dissolve the CO.sub.2. CO.sub.2 scrubbing unit 210 may also be operable to separate N.sub.2, Ar, and other insoluble or inert gases from CO.sub.2 and other acid gases, such as hydrogen sulfide (H.sub.2S) and/or sulfur dioxide (SO.sub.2), while dissolving CO.sub.2 and other acid gases, such as H.sub.2S, 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.

(38) CO.sub.2 and additional gases, such as acid gases, are dissolved in the water and exit scrubbing unit 210 via outlet 220. The CO.sub.2-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.

(39) As described above, embodiments herein may provide for the efficient sequestration of carbon from both CO.sub.2-lean waste streams and synergistic hydrogen production.

(40) The singular forms “a,” “an,” and “the” include plural referents, unless the context clearly dictates otherwise.

(41) In the drawings and specification, there have been disclosed embodiments of systems and methods for reducing or eliminating greenhouse gas emissions, and although specific terms are employed, the terms are used in a descriptive sense only and not for purposes of limitation. The embodiments of the present disclosure have been described in considerable detail with specific reference to these illustrated embodiments. It will be apparent, however, that various modifications and changes can be made within the spirit and scope of the disclosure as described in the foregoing specification, and such modifications and changes are to be considered equivalents and part of this disclosure.