Abstract
This present invention describes methods and systems for integrating liquid-phase, electrochemical and chemical processes into power generation, petrochemical, metal, cement and other industrial process plants, in such a manner as to capture and recycle all input carbon into cost-competitive hydrogen, oxygen and hydrocarbons. These integrated systems will recover internally generated losses in chemical potential (AG Gibbs Free or Available Energy) as well as waste heat (ΔH—Enthalpy), and sometimes electricity, to assist in driving these electrochemical and chemical processes, which will increase the total useful output of the process plants, thereby increasing thermal, carbon and economic efficiency.
Claims
1-50. (canceled)
51. A system integrating a fossil-fueled power plant with: i) a post-combustion, carbon dioxide capture subsystem that carbonizes an acidic, basic or buffer, liquid electrolyte solution; ii) a decarbonizing subsystem that regenerates the carbonized electrolyte solution; iii) a thermal management subsystem that integrates the power plant waste heat and/or external heat sources with the thermal needs of the other subsystems; iv) a power management subsystem that integrates and optimizes all internal electrical needs with external supplies and loads; and, v) a control system to manage all of the above listed subsystems and respond to varying internal and external demands, interruptions and events.
52. The system according to claim 51, wherein the carbon dioxide capture subsystem captures carbon dioxide in one stage of carbonate to bicarbonate.
53. The system according to claim 51, wherein the carbon dioxide capture subsystem carbon captures carbon dioxide in two stages, the first stage capturing 50% in hydroxide to carbonate and the second capturing the remainder in the newly formed carbonate to bicarbonate.
54. The system according to claim 51, wherein the decarbonizing subsystem is a thermal decarbonization subsystem using steam to regenerate the bicarbonate to carbonate and carbon dioxide, which can be vented, collected, sold and/or sequestered.
55. The system according to claim 51, wherein the decarbonizing subsystem is an electrochemical cell using electrical and/or thermal input to strip the bicarbonate of oxygen at one electrode and hydrocarbons and/or oxygenated hydrocarbons at the other.
56. The system according to claim 51, wherein the decarbonizing subsystem is an electrochemical cell using electrical and/or thermal input to strip the bicarbonate of oxygen at one electrode and hydrocarbons and/or oxygenated hydrocarbons at the other.
57. A system integrating a fossil-fueled or supplied industrial process plant (i.e, steel, aluminum, cement, paper, fertilizer, petrochemical, hydrogen, etc.) with: i) a post-combustion, or use, carbon dioxide capture subsystem that carbonizes an acidic, basic or buffer, liquid electrolyte solution; ii) a decarbonizing subsystem that regenerates the carbonized electrolyte solution; iii) a thermal management subsystem that integrates the power plant waste heat and/or external heat sources with the thermal needs of the other subsystems; iv) a power management subsystem that integrates and optimizes all internal electrical needs with external supplies and loads; and, v) a control system to manage all of the above listed subsystems and respond to varying internal and external demands, interruptions and events.
58. The system according to claim 57, wherein the carbon dioxide capture subsystem captures carbon dioxide in one stage of carbonate to bicarbonate.
59. The system according to claim 57, wherein the carbon dioxide capture subsystem captures carbon dioxide in two stages, the first stage capturing 50% in hydroxide to carbonate and the second capturing the remainder in the newly formed carbonate to bicarbonate.
60. The system according to claim 57, wherein the decarbonizing subsystem is a thermal decarbonization subsystem using steam to regenerate the bicarbonate to carbonate and carbon dioxide, which can be vented, collected, sold and/or sequestered.
61. The system according to claim 57, wherein the decarbonizing subsystem is an electrochemical cell using electrical and/or thermal input to strip the bicarbonate of oxygen at one electrode and hydrocarbons and/or oxygenated hydrocarbons at the other.
62. The system according to claim 57, wherein the decarbonizing subsystem is an electrochemical cell using electrical and/or thermal input to strip the bicarbonate of oxygen at one electrode and hydrocarbons and/or oxygenated hydrocarbons at the other.
Description
BRIEF DESCRIPTION OF THE DRAWINGS
[0058] FIG. 1 shows the Ground State of carbon is not carbon dioxide (CO.sub.2) but carbonate (CO.sub.3). It also shows that a significant amount of recoverable energy is still available from CO.sub.2.
[0059] FIG. 2 displays the energy content of various carbon based fuels and feedstocks on both the Carnot scale (left) and the Gibbs scale (right).
[0060] FIG. 3 shows a Grimes Free Energy process that is driven by both thermal energy and electrical energy. The necessary inputs are an oxidizable reactant A, a Reducible Reactant B, an ionically conductive electrolyte and some form of work. Under proper conditions these will produce the Desired Synthesis Product C and a By-Product D.
[0061] FIG. 4 is a Table showing a range of oxidizable reactants, reducible reactants, ionically conductive electrolytes, work, power and delta G inputs, electron transfer materials, desired synthesis products and by-products that can be processed by the redox reactor of FIG. 3. The lower portion of the table shows examples of how methane (CH.sub.4) can be synthesized from an input of methanol (CH.sub.3OH) and that the reverse synthesis of methanol can be synthesized from an input of methane.
[0062] FIG. 5 shows how the ECR integrates features from the two current commercial hydrogen production technologies Steam Methane Reforming (SMR>95%), a thermochemical process, and Electrolysis, an electrochemical process.
[0063] FIG. 6 shows examples of the flows of two electrochemical devices: the upper reactor is an electrochemical reformer (ECR) that accepts methanol and water and heat and/or electricity and outputs hydrogen gas as the desired product and carbon dioxide as the by-product, assuming thermal stripping or operating at electrolyte saturation. The lower reactor is a carbon capture and re-use (CCR) device that accepts carbon dioxide, water, heat and electricity and outputs methanol (CH.sub.3OH) as the desired product and oxygen as the by-product.
[0064] FIG. 7 compares the efficiency and complexity of producing hydrogen via steam methane reforming (SMR) with hydrogen production via electrochemical reforming (ECR) of methanol.
[0065] FIG. 8 is a simplified diagram of a system that integrates an electrochemical reformer, which converts methanol, water and electrolyte to hydrogen and carbonized electrolyte with a fixed-bed, decarbonizing stripper that thermally regenerates the carbonized electrolyte using steam to remove the excess carbon as CO.sub.2.
[0066] FIG. 9 is a simplified diagram of a system that integrates an electrochemical reformer, which converts methanol, water and electrolyte to hydrogen and carbonized electrolyte with a planar, electrochemical, decarbonizing stripper that uses electricity and heat to regenerate the carbonized electrolyte by producing hydrocarbons at one electrode and oxygen at the other with both by products being exported.
[0067] FIG. 10 is similar to the systems shown in FIGS. 9 and 8 except carbon dioxide is the input and the outputs are oxygen and hydrocarbons (CH.sub.2)).
[0068] FIG. 11 shows the basic inputs and outputs of a fossil-fueled power plant.
[0069] FIG. 12 shows a more nearly complete method of calculating overall efficiency of electricity generation from one ton of coal that includes both the heat of combustion and Gibbs Free Energy.
[0070] FIG. 13 shows a simplified diagram of the 3G&S process for post combustion carbon capture and re-use to eliminate emissions and improve thermal efficiency. Fossil fuels can still be used to generate electricity without exhausting CO.sub.2 to the atmosphere.
[0071] FIG. 14 shows a simplified diagram of a fossil-fueled power plant integrated with a post-combustion CO.sub.2 capture carbonizer subsystem and a CCR decarbonizer producing hydrocarbons and oxygen for export.
[0072] FIG. 15 shows the efficiency calculation per ton of coal in a coal-fired power plant integrated with a post-combustion CO.sub.2 capture carbonizer subsystem and a CCR decarbonizer producing hydrocarbons and oxygen for export.
[0073] FIG. 16 shows a simplified diagram of a fossil-fueled power plant integrated with a post-combustion CO.sub.2 capture carbonizer subsystem and a CCR decarbonizer producing hydrocarbons and oxygen that are recycled to the plant input. The system also includes a steam stripper of CO.sub.2 for the carbon from portion of the total fuel use that is still externally imported.
[0074] FIG. 17 shows the basic energy flows for a 400 MW natural gas-fired combined-cycle power plant (NGCC).
[0075] FIG. 18 shows the basic mass flows for a 400 MW natural gas-fired combined-cycle power plant (NGCC).
[0076] FIG. 19 shows the basic energy flows of a 400 MW NGCC power plant integrated with post-combustion CCR producing hexane for export.
[0077] FIG. 20 shows the basic mass flows of a 400 Mw NGCC power plant integrated with post-combustion CCR producing hexane for export and oxygen for internal consumption.
[0078] FIG. 21 shows the basic energy flows of a 400 MW NGCC power plant integrated with post-combustion CCR producing methane to be recycled for internal use.
[0079] FIG. 22 shows the basic mass flows of a 400 MW NGCC power plant integrated with post-combustion CCR producing methane and oxygen to be recycled for internal consumption.
[0080] FIG. 23 shows the basic energy flows of a 400 MW NGCC power plant integrated with pre-combustion carbon capture using an ECR, which produces hydrogen in sufficient quantities to supply the power plant. The carbonized electrolyte from the ECR is fed to a CCR producing methane to be recycled for internal use in the ECR.
[0081] FIG. 24 shows the basic mass flows of a 400 MW NGCC power plant integrated with pre-combustion carbon capture using an ECR, which produces hydrogen in sufficient quantities to supply the power plant. The carbonized electrolyte from the ECR is fed to a CCR producing methane to be recycled for internal use in the ECR with the oxygen produced fed into the power plant.
[0082] FIG. 25 shows the basic energy flows of a 400 MW NGCC power plant integrated with post-combustion CCR producing methanol for export and oxygen to be recycled for internal consumption.
[0083] FIG. 26 shows the basic mass flows of a 400 MW NGCC power plant integrated with post-combustion CCR producing methanol for export and oxygen to be recycled for internal consumption.
[0084] FIG. 27 shows a simplified diagram showing the material flows in a NGCC power plant with multi-pass ECR/CCR subsystems integrated to capture and reuse higher percentages of the initial fossil carbon than the single-pass systems shown above.
[0085] FIG. 28 compares the efficiency, yield and Carbon Intensity numbers of SMR hydrogen produced from liquefied natural gas versus ECR hydrogen made from remotely produced methanol.
[0086] FIG. 29 compares the efficiency, yield and Carbon Intensity numbers of SMR hydrogen produced from liquefied natural gas versus ECR hydrogen made from remotely produced biogas-methanol.
[0087] FIG. 30 shows the increase in yield created by using ECR hydrogen to generate electricity versus combusting the biogas directly.
[0088] FIG. 31 shows the increase in hydrogen delivered from a primary renewable electrical source by a physically separated CCR/ECR combination versus liquefied hydrogen.
[0089] FIG. 32 shows the increase in yield enabled by the same CCR/ECR configuration compared to ammonia as a Liquid Organic Hydrogen Carrier with both being driven by remote, renewable electrons.
[0090] FIG. 33 shows the potential energy density of an integrated ECR/CCR system being put on-board a fuel cell vehicle to provide hydrogen for transportation, assuming water recovery from the fuel cell
[0091] FIG. 34 shows the detailed energy input and output from one ton of carbon dioxide converted by a CCR into hexane.
[0092] FIG. 35 shows the detailed energy input and output from one ton of methane converted by a CCR into hydrogen.
DETAILED DESCRIPTION OF THE INVENTION
[0093] The present invention describes the underlying technologies and methods of integrating them into novel configurations that will improve the thermal, carbon and economic efficiency of power generation and other industrial process plants. The key elements of the integrated systems are the ability to recover and reuse what is currently called “waste” heat (ΔH—enthalpy) and the more critical ability to recover and reuse the exothermic change in chemical potential (ΔG—Gibbs Free or Available Energy).
[0094] FIG. 1 shows both forms of energy recoverable from a carbon atom. The top step shows the 400 kJ per mole of ΔH available from the combustion of carbon to its final combustion by product, carbon dioxide. This is the generally accepted view of carbon utility and all current Carnot efficiency ratings are calculated by dividing the total recoverable energy out of a system (electricity, heat, etc.) by this figure. However, carbon dioxide is not the ground state of carbon, carbonate minerals are. The lower step shows the range of values of the chemical potential available, ΔG. This figure varies depending on what metal the carbon attaches itself to when it exothermically forms its carbonate mineral (a naturally occurring process called weathering). Carnot said that temperature is the ultimate limitation on efficiency but his thinking was incomplete in that he didn't include the effect of changes in chemical potential. This is the ultimate limit of efficiency, on which temperature depends.
[0095] FIG. 2 shows the the energy content of a wide range of compounds with the ΔH Carnot scale on the left and the ΔG Gibbs scale on the right. Here CO.sub.2 is at zero on the Carnot scale while it still has about 200 kJ available on the Gibbs scale. On the ΔG scale, even some minerals still have useful amounts of energy available (see sodium bicarbonate or Atka Seltzer).
[0096] In order to benefit from this available energy a Free Energy Driven Process is needed. FIG. 3 shows a simplified schematic of such a process, where Oxidizable Reactant A and Reducible Reactant B are combined in a reactor with an Ionically Conductive Electrolyte, which can be acidic, neutral or basic, an electron transfer material, and some form of power or work is added (heat, electricity, or other form of ΔG). This will create Desired Synthesis Product C along with By-Product D, which can be captured in the solution or extracted from the reactor. FIG. 4 shows a matrix with a partial list of these reactants, electrolytes, forms of work, electron transfer materials, products and by-products. Desired systems would design the process to make by-product D salable as well as Product C. This would change the overall efficiency calculation from;
[00004]
to,
[00005]
[0097] FIG. 5 shows an embodiment of this principle in a basic comparison of the Grimes liquid-phase ECR to the two commercially available methods of hydrogen generation used today, Steam Methane Reforming (SMR) and water electrolysis. The ECR combines the best features of each system thereby making up for the deficiencies in each. The SMR is missing an ionically conductive electrolyte and a conductive catalyst. The electrolyser is missing an oxidizable reactant. A comparison of the effect these omission is shown in the Table 2 below.
TABLE-US-00002 TABLE 2 Thermodynamic Comparison ΔG ΔH ΔG ΔH temp Kcal Kcal Kcal Kcal cell system PROCESS fuel ° C. per mole fuel per mole fuel per mole H.sub.2 per mole H.sub.2 voltage efficiency CENTRALIZED NATURAL GAS Steam Reforming CH.sub.4 850 −38.77 40.40 −9.69 10.10 — 85% CENTRALIZED & DISTRIBUTED Electrolysis.sup.2 H.sub.2O + e.sup.− 75 54.76 67.94 54.76 67.94 1.95 65% DISTRIBUTED NATURAL GAS Steam Reforming.sup.1 CH.sub.4 800 −35.31 42.00 −8.80 10.50 — 65% HT Reforming.sup.1 CH.sub.4 700 −27.88 45.17 −6.97 11.29 — 55% Autothermal Reforming.sup.1 CH.sub.4 850 −24.07 46.74 −6.02 11.69 — 55% Partial Oxidation.sup.1 CH.sub.4 600 −93.04 −11.36 −23.26 −2.84 — 50% Electrochemical Reforming (t).sup.3 CH.sub.4 400 −1.89 29.95 −0.47 7.49 — 87% Electrochemical Reforming (e).sup.2 CH.sub.4 26 17.77 34.80 4.44 8.70 0.09 85% DISTRIBUTED METHANOL Steam Reforming.sup.1 CH.sub.3OH 280 −18.03 25.95 −6.01 8.65 — 65% Electrochemical Reforming (t).sup.3 CH.sub.3OH 200 −17.71 2.87 −5.90 0.96 — 87% Electrochemical Reforming (e).sup.2 CH.sub.3OH 75 −11.77 6.20 −3.92 2.07 0.04 85% CENTRALIZED & DISTRIBUTED Carbonate ECR (t).sup.3 C 200 −19.68 −2.51 −9.64 −1.28 — 87% Carbonate ECR (e).sup.2 C 50 −13.51 1.38 −6.75 0.69 0.04 78% .sup.1system efficiency calculations include heat input, gas separation and compression .sup.2electrolysis and electrically driven ECR system efficiencies and CC energy penalty are based on the use of renewable electricity sources .sup.3system efficiency is calculated assuming the use of internal heat
[0098] Here you can see that the lack of an oxidizable reactant increases the energy required to create a mole of hydrogen from water to 67.94 kJ. An SMR can deliver the same mole of hydrogen for an energy cost of 10.10 kJ but the temperature has risen from 75 to 800 C. An ECR can deliver the mole of hydrogen from methane thermally at half the temperature (400 C) and with a reduction in energy consumption to 7.49 kJ. If electricity is used to drive the ECR, the energy consumption will rise to 8.70 kJ but the temperature will drop to 25 C. However, since the process can be fed liquid as well as gaseous inputs, if methanol is used as the oxidizable reactant, the mole of hydrogen will cost only 0.96 kJ at a temperature of 200 C. This coupled with the fact that the ECR evolves hydrogen at a pressure slightly higher than the fuel/water/electrolyte mixture, which eliminates the need for gas-phase hydrogen compression, offers significant commercial advantage. FIG. 6 shows the basic diagram of a methanol ECR with a thermal CO.sub.2 stripper regenerating the carbonized electrolyte and a Carbon Capture & Reuse (CCR) cell that is capturing CO.sub.2 and producing methanol and oxygen as the product and by-product.
[0099] Another key advantage of the ECR is shown in FIG. 7, which compares the simplicity of the ECR to the complexity of an SMR. A typical SMR starts with a boiler that injects steam into the steam reforming reactor, which creates a syngas stream of hydrogen and carbon monoxide. This is fed into a high-temperature, water-gas shift reactor that converts a portion of the CO to CO.sub.2. The output of this reaction is then fed into a low-temperature, water-gas shift reactor that completes this process. The output mixture of H.sub.2 and CO.sub.2, now called reformate, is then fed to a pressure swing absorption system that separates the hydrogen from the carbon dioxide. In this step about 20-30% of the product hydrogen is lost. Finally, the pure hydrogen is fed into a compressor for use, storage and/or transport.
[0100] By comparison, the ECR is a single reactor, operating at a lower temperature, that is fed the fuel/water/electrolyte mixture and evolves hydrogen at purities above 99%. This can be further cleaned at little expense and by compressing the input liquid to the desired output pressure, mechanical compression of the product gas is eliminated. The efficiency calculation was originally done by a major US oil company based on their experience with large-scale SMR and their funded lab work.
[0101] The flows of the initial embodiment of the ECR, called the Carbonizer, are shown in FIG. 8. This shows a continuous flow, heated, catalytic reactor that receives the input fuel and water and mixes it with an alkaline electrolyte. The input carbon will be converted to carbonate or bicarbonate, while gaseous hydrogen will be released.
CH.sub.4+3H.sub.2O+Na.sub.2CO.sub.3=>4H.sub.2+2NaHCO.sub.3 (11)
[0102] This step will reduce the pH of the electrolyte and at this point the carbon is effectively sequestered permanently. This carbonized electrolyte could be disposed of either in mines or in the ocean. Being basic, it would actually counteract the damaging acidification of the ocean that is being caused by Climate Change. However, since the cost of replacing the electrolyte is commercially unattractive, in this embodiment, a simple steam stripper, called the Decarbonizer, is used to regenerate the electrolyte back to its original condition and recycle back into the front end of the process.
2NaHCO.sub.3+H.sub.2O=>Na.sub.2CO.sub.3+CO.sub.2 (12)
[0103] FIGS. 9 shows the flows of a methane fed ECR Carbonizer, producing hydrogen, mated with an electrically driven CCR Decarbonizer, that produces oxygen and hydrocarbons. (For this description CH.sub.2 is shorthand of any hydrocarbon unless otherwise noted. The chain length of the output hydrocarbon would be determined by catalyst selection and operating parameters.). FIG. 10 shows a similar system but instead of fuel the ECR is fed CO.sub.2. In this configuration, no hydrogen is produced. The Carbonizer acts as a capture system and feeds the carbonized electrolyte to the CCR to recycle the carbon as salable hydrocarbons and oxygen. Unlike many other carbon capture approaches, this will create additional income and increase overall system efficiency as opposed to being a financial and energy burden.
[0104] In order to properly understand the full effect of this invention, a clear understanding must be established regarding the definition of efficiency. FIG. 11 shows the typical configuration of a thermal power plant. Fuel and air are combusted in a boiler with the resultant steam being used to drive a turbine and generator. The boiler exhaust is scrubbed and vented to the atmosphere with ash collection and disposal. The spent steam is condensed with the water recycled and the waste heat is externally rejected. The efficiency of this plant is calculated by dividing the energy value of the electricity out by the energy value of the input fuel.
[0105] FIG. 12 shows an example of a more thorough calculation of this plant's efficiency based on the input of one ton of coal. The traditional calculation would divide the useful energy value of the electrical output (2,319 kWh(e)=7.91 MMBTU=8,345 MJ) by the heat of combustion (ΔH) of the coal input (20.61 MMBTU=21,744 MJ), yielding a thermal efficiency of 38.4%. However, this ignores the chemical potential (ΔH) of the 2,102 kg of CO.sub.2 produced by the combustion process (12.33 MMBTU=13,008 MJ) giving the electrons produced a Carbon Intensity Number (CI#) of 252 grams CO.sub.2/MJ. If this chemical potential is added to the calculation, while the output remains the same, the total input, ΔH plus ΔG, increases to 32.94 MMBTU or 34,752 MJ. This would reduce the overall efficiency of the plant to 24%.
[0106] Since CO.sub.2 is the end product of combustion, it has always been ignored in efficiency calculation although CO.sub.3, or carbonate, is the actual ground state. This oversight, and the assumptions that i) it was immaterial, and, ii) the atmosphere was an infinite sink, allowed an industrial civilization to be built with no concern for its effect. Unfortunately, it has crept up on the world in the form of Climate Change.
[0107] FIG. 13 shows a Grimes alternative to this old worldview. The top steps 1 through 5 show a typical fossil-fueled power plant but with the CO.sub.2 and waste heat captured in an ECR Carbonizer. Since all carbon emissions are captured, the CI# of the electrical output is zero. The lower section shows two options. The more cost-efficient configuration would be the use of an ECR/CCR combination to make hydrocarbons for export (#8). In the second, the carbon could be sequestered as bicarbonate, which would require the addition of fresh carbonate electrolyte, at a cost. Path #6 shows the option of using additional fossil fuel input to create hydrogen that could be used to reduce the bicarbonate without electrical input, while Path #7 shows that biomass fuels (biogas, sugar, bio-methanol, etc.) can be used for this step and also drive the CI# of the hydrocarbon output to zero.
[0108] FIG. 14 shows the integration of a pre-combustion carbon capture embodiment of this invention into the same fossil-fueled power plant as shown in FIG. 11. It shows another key element of this invention, an Integrated Thermal Management Subsystem that captures the various temperatures of waste heat and matches them to the thermal requirements of the ECR Carbonizer and CCR Decarbonizer. For simplicity's sake, the simpler Power Management Subsystem is not shown.
[0109] In this embodiment, the first goal will be to design the system to recover and use all of the waste heat generated by the power plant. The second will be to minimize the electrical input required for the CCR Decarbonizing step. As FIG. 13 shows, additional hydrocarbon input can be fed directly into the ECR Carbonizing subsystem and the product hydrogen used to reduce the bicarbonate back to hydroxide. Since electricity is the primary plant output, minimal parasitic consumption is desirable. However, in this Figure the ECR Carbonizer is fed post-combustion CO.sub.2 and both the product hydrocarbons and oxygen from the CCR Decarbonizer are exported.
[0110] FIG. 15 shows the effect of this invention on the overall plant efficiency. The same total ΔH plus ΔG energy input (32.94 MMBTU or 34,752 MJ) produces only 93% of the prior electrical output, due to increased parasitic needs, but the invention adds an additional 24.27 MMBTU or 25,605 MJ of fuel to the output. This increases the total output to 31.62 MMBTU or 33,359 MJ, which yields an overall efficiency of 96%. If the hydrocarbons are exported for use elsewhere, the CI3 of the electricity is zero, while the CI# for the liquid fuel would be 82 grams CO.sub.2/MJ as opposed to ˜100 for petroleum based diesel.
[0111] A final key feature of this invention is the fact that that oxygen it produces could be blended with input air to reduce nitrogen emissions and, depending on the fuel could enable 100% oxygen combustion eliminating them entirely. In the case of a fuel cell power plant, hydrogen/oxygen operation would also increase efficiency and longevity.
[0112] FIG. 16 shows another embodiment of the post-combustion configuration where the hydrocarbons and oxygen produced are recycled into the plant input. It incorporates a steam stripper to regenerate the carbonized electrolyte and therefore would produce CO.sub.2. However this will reduce the need for imported energy and increase overall system efficiency while reducing the carbon intensity proportionally.
[0113] FIGS. 17 & 18 quantify the energy and mass flows for a typical 400 MW natural gas combined cycle (NGCC)power plant. Using ΔH calculations alone, the overall efficiency is 10,721,227GJ of electricity out divided by 20,204,423 GJ of natural gas in, or 53%. If the 5,604,842 GJ of ΔG is added to the input, the total grows to 25,809,265 GJ, which reduces the overall efficiency to 42%. Since the plant emits 979,398 tons of carbon dioxide per year, the CI# is 91 grams CO.sub.2/MJ
[0114] FIGS. 19 & 20 quantify the effect of integrating the invention into the same plant with the CCR Decarbonizer producing hexane (C.sub.6H.sub.14) for export but with the oxygen recycled back into the plant input. Although this increases the salable output by 144% (15,427,391 GJ of hexane versus 10,721,227 GJ of electricity), to calculate overall efficiency, the total output of 26,148,618 GJ has to be divided by the total ΔH plus ΔG input of 27,043,890 GJ(20,204,403 GJ of ΔH from natural gas and 6,839,487 GJ of ΔG from the CCR). Therefore the theoretical system efficiency could increase to almost 97%. Looking at the history of electrolysis, an analogous process, the real-world performance should be significantly lower but still offer a major increase in efficiency over today's common practices.
[0115] FIGS. 21 & 22 show the energy and mass flows for the same plant with the post-combustion ECR/CCR combination producing methane and oxygen, both of which are recycled back into the plant input. The most notable effect of this embodiment is that the amount of natural gas needed per year shrinks from 20,204,423 GJ to 12,869,913 GJ, a reduction of 7,34,510 GJ, or 36%. This reduces the total ΔH plus ΔG input to 19,597,892 GJ(212,869,813 GJ of ΔH from natural gas and 6,728,079 GJ of ΔG from the CCR). Since the electrical output remains the same 10,721,227 GJ, the overall efficiency climbs to 55%.
[0116] The energy and mass flows for a pre-combustion carbon capture embodiment of this invention are shown in FIGS. 23 & 24. In FIG. 23 6,505,475 ΔH GJ of input natural gas is fed directly into the ECR Carbonizer, which will produce the 20,204,423 ΔH GJ of hydrogen needed to deliver the 10,721,227 ΔH GJ of electricity from the combined cycle turbines. An additional 3,707,537 ΔH GJ of methane will be fed to the ECR/Carbonizer from the CCR Decarbonizer. The additional ΔG flows are the change of chemical potential in the ECR, which adds 17,478,144 ΔG GJ and the export of 496,395 tons of CO.sub.2 (see FIG. 24) containing an additional 4,435,920 ΔG GJ of Available Energy. Therefore the total ΔH plus ΔG input equals 23,983,619 GJ. Divided into the combined ΔH plus ΔG outputs of 15,157,147 GJ this yield an overall system efficiency of 63%. Since air will still be needed nitrogen oxide emissions will be reduced and reduction in fossil natural gas input will reduce the CI# per MJ of electricity will drop to 46, a 49% reduction. In other embodiments of this invention, additional stages could be added in sequence to drive the CI# closer to zero.
[0117] FIGS. 25 & 26 show the energy and mass flows for a similar size pre-combustion carbon capture embodiment configured for recycling of oxygen but export of CCR produced hydrocarbons, in this case methanol. In FIG. 25, the total ΔH plus ΔG input adds up to 36,598,601 GJ (14,799,444 GJ of ΔH from natural gas and 21,799,157 GJ of ΔG from the changes in chemical potential). Dividing this into the total ΔH plus ΔG output of 30,525,822 GJ (12,819,446 GJ of ΔH from the methanol, 10,721,227 GJ of ΔH from the electricity and 6,985,149 GJ of ΔG Available Energy left in the CO.sub.2 emissions), yields an overall efficiency of 83%. FIG. 26 shows that this configuration will release 779,296 tons of CO.sub.2. If all of these emissions are allocated to the exported methanol the CI# for that use would be 57, while the CI# for the electricity would drop to zero. If the methanol is used by the same entity that owns the power plant the average of the CI# for the total salable energy out would be 31. In both cases a significant reductions.
[0118] All of the previous Figures show systems with only a single-pass of capture, which doesn't capture or convert 100% of the input carbon. FIG. 27 shows a simplified diagram of a post-combustion, multi-pass configuration that can be used to reduce the net carbon emissions at a Natural Gas Combined Cycle Power Plant (NGCC). In this embodiment, the CCR Decarbonizer can use either electrons or hydrogen to reduce the carbonized electrolyte, which will require additional energy input to maintain constant electricity out. In this example, additional natural gas is used to produce hydrogen in post-combustion capture subsystems. Since the processes are easily scalable, as many multiple stages can be added as are needed to lower the net emissions as much as the customer wants. What final remnant remains can be easily disposed as solid carbonates, with the cost being spread across a much larger output. An example of this effect is shown in Table 3.
TABLE-US-00003 TABLE 3 Post-Combustion Multi-Pass Trend 400 MW NGCC Plant Total Energy In Electricity Out Electric CI # Fuel Fuel CI # Total Energy Out Total CI # Total Efficiency configuration GJ GJ g CO.sub.2/MJ BOED g CO.sub.2/MJ GJ g CO.sub.2/MJ % today (bought fuel) 35,980,205 10,721,227 106 7,479 74 24,919,431 88 69.26% single-pass 35,357,740 10,721,227 62 7,479 74 24,919,431 69 70.48% double -pass 45,847,987 10,721,227 40 13,088 74 35,568,085 54 77.58% triple-pass 56,463,686 10,721,227 18 18,764 74 46,344,084 61 82.08%
[0119] This Table summarizes the model of a post-combustion system integrated with a 400 MW NGCC Power Plant. The top row shows, i) the total energy input, ii) electrical output and CI# for the power generated by such a plant, iii) the amount and CI# of the same amount of fuel that would be produced by a single-pass ECR/CCR system, 7,479 BOED (barrels of oil equivalent per day), iv) the total energy out and CI# and, v) the total efficiency of electricity and fuel production. The second row shows that a single-pass system would reduce the total energy input slightly and increase the total efficiency as well. However, the total CI# would drop from 88 to 69. The next row down shows the effect of a double pass embodiment, which increases the amount of energy in by about 30% but amount of fuel available to sell increases by almost 75%. Assuming the CI# of the fuel stays constant, the CI# of the electricity to less than 40% of the existing plant with the average down by 27%. Adding a third-pass increases the energy in but continues to reduce the electrical and overall CI# while increasing total efficiency as well. Additional passes could be added until the CI# drops as close to zero as desired.
[0120] The economic benefits of this invention also become clear. A 400 MW NGCC plant might gross $125/MWh or $1.2M/day. Wholesale diesel prices today are about $60/barrel. Therefore a single-pass system would add $0.45M, a double pass $0.79M/day and a triple-pass $1.13/day. Projected capital and operating costs show significantly increased net earnings from these integrated systems as well.
[0121] Another advantage of this invention is the competitive advantage it offers over other methods of generating hydrogen. FIG. 28 compares the net hydrogen output of an SMR, produced from pipeline natural gas, to ECR hydrogen made from methanol produced from the same natural gas. From an energy standpoint the ECR will consume 35% less natural gas per kg of hydrogen produced. However, this does not quantify the benefit of being able to store and transport the hydrogen as methanol and the fact that the carbon capture is inherent in the process , as opposed to being an add-on, with increased cost and decreased efficiency, as is the case of the SMR.
[0122] FIG. 29 shows the effect when the distance between the initial natural gas and hydrogen consumption is increased. The top section factors in the energy losses associated with liquefaction, transport and re-gasification. with these factors added, the net benefit increases to a 41% reduction in energy cost per kg of hydrogen produced.
[0123] FIG. 30 show another application where the ECR benefits is apparent. In this case, biogas is the primary energy input and electricity is the end product. If the biogas is used directly, the net output per metric ton in is 2,117 kWh. If the same amount of biogas is fed into an ECR and the hydrogen is used to produce electricity at the same efficiency, the net output will increase to 2,743 kWh. This represents a 30% increase in output per unit of energy in and the carbon is captured pre-combustion with no additional cost or energy penalty.
[0124] If you add the CCR to the ECR, the embodiment shown in FIG. 31 offers a competitive advantage over conventional transport of liquefied, electrolytic hydrogen. If we electrically drive a CCR Decarbonizer at a source of electricity (wind, solar, hydro, off-peak, etc.), this can be stored as a reduced electrolyte and hydrocarbon liquid. These two species can be stored for later use or transported and then recombined in an ECR to produce hydrogen at the point of need. The net effect, in comparison to conventional liquefied hydrogen transport is an increase to 500% of the total amount of available energy.
[0125] Similarly, FIG. 32 shows a comparison of the net hydrogen deliverable from 1 MWh of electricity using ammonia as the hydrogen carrier or the CCR/ECR combination. Again, the the total amount delivered is 5× the amount available from Ammonia.
[0126] These facts lead to an interesting conclusion shown in FIG. 33. Here the gravimetric and volumetric energy density of various on-board hydrogen storage systems are show. At the bottom left are the compressed tank systems currently used in vehicles and their targets for improvement. About the middle are methanol, ethanol and hydrogen from ethanol using an ECR. (In this analysis, the water needed for the reaction is recovered from the fuel cell using the hydrogen.). Obviously, all of the ECR hydrogen configuration are significantly better than compressed or liquid systems. Oddly enough, if wax (C.sub.20H.sub.42+) is used in the ECR, the overall energy density is higher than diesel. This, plus the fact that this can be ambient pressure and temperature addresses one of the major issues preventing hydrogen from becoming the dominant transport fuel.
[0127] This ECR/CCR technology can also be added to systems at an energy and financial profit. FIG. 34 shows the fuel yield from one ton of capture CO.sub.2. Based on the previously mentioned wholesale price of $60/BOED, this ton of carbon dioxide will create $200 of revenue. This will more than offset the capital and operating cost needed to install and operate such a system. These technologies make atmospheric carbon emissions an asset as opposed to a liability.
[0128] FIG. 35 shows a similar analysis of the useful output available form one ton of methane. Based on today's prices, that methane would cost about $150. At todays prices at a refinery, tis would sell for about $750. and at a fueling station, it would be worth over $2,000. This is evidence of the potential economic benefits this invention offers.
[0129] Although the examples given have related to power plants, the same principals can be applied to a wide range of other industrial process plants. Virtually all processes use electricity and/or heat, which generally creates CO.sub.2 emissions, or the process itself uses carbon electrodes, as in the case of electrically driven steel and aluminum production, which are consumed and emitted as additional CO.sub.2. This invention can capture and recycle these emissions for these and other process plants just as easily offering the same increases in thermal, carbon and economic efficiency.
[0130] All documents, including patents, described herein are incorporated by reference herein, including any priority documents and/or testing procedures. The principles, preferred embodiments, and modes of operation of the present invention have been described in the foregoing specification. Although the invention herein has been described with reference to particular embodiments, it is to be understood that these embodiments are merely illustrative of the principles and applications of the present invention. It is therefore to be understood that numerous modifications may be made to the illustrative embodiments and that other arrangements may be devised without departing from the spirit and scope of the present invention as defined by the appended claims.
