Integrated chemical looping combustion system and method for power generation and carbon dioxide capture

Abstract

A chemical looping combustion (CLC) based power generation, particularly using liquid fuel, ensures substantially complete fuel combustion and provides electrical efficiency without exposing metal oxide based oxygen carrier to high temperature redox process. An integrated fuel gasification (reforming)-CLC-followed by power generation model is provided involving (i) a gasification island, (ii) CLC island, (iii) heat recovery unit, and (iv) power generation system. To improve electrical efficiency, a fraction of the gasified fuel may be directly fed, or bypass the CLC, to a combustor upstream of one or more gas turbines. This splitting approach ensures higher temperature (efficiency) in the gas turbine inlet. The inert mass ratio, air flow rate to the oxidation reactor, and pressure of the system may be tailored to affect the performance of the integrated CLC system and process.

Claims

1. An integrated system, comprising: a gasification subsystem comprising (a-i) a fuel heater suitable for heating a liquid fuel stream, (a-ii) a gasifier located downstream of, and fluidly connected to, the fuel heater, the gasifier being configured to gasify the liquid fuel stream with an oxygen-rich stream to form a syngas stream, and (a-iii) a gas splitter located downstream of, and fluidly connected to, the gasifier, the gas splitter being configured to split the syngas stream into a first syngas substream and a second syngas substream; a chemical looping combustion (CLC) subsystem comprising (b-i) a reducer located downstream of, and fluidly connected to, the gas splitter, the reducer being configured to oxidize the first syngas substream in the presence of an oxygen carrier to form a CO.sub.2/H.sub.2O stream, the oxygen carrier being reduced to a reduced oxygen carrier, and (b-ii) an oxidizer located downstream of, and fluidly connected to, a first solid-gas separator, the oxidizer being configured to oxidize the reduced oxygen carrier in the presence of an oxygen-containing stream to regenerate the oxygen carrier; a power generation subsystem comprising (c-i) a combustor located downstream of, and fluidly connected to, the gas splitter and the oxidizer, the combustor combusting the second syngas substream in the presence of the oxygen-containing stream to form an exhaust stream, and (c-ii) a first gas turbine located downstream of, and fluidly connected to, the combustor for generating gas turbine shaft work with the exhaust stream; a heat recovery-steam generation (HRSG) subsystem comprising (d-i) a first heat exchanger located downstream of, and fluidly connected to, the reducer, the first heat exchanger being configured to form steam by heating a water stream with the CO.sub.2/H.sub.2O stream.

2. The system of claim 1, wherein the CLC subsystem further comprises (b-iii) a first solid-gas separator located downstream of, and fluidly connected to, the reducer, the first solid-gas separator being configured to separate the CO.sub.2/H.sub.2O stream from the reduced oxygen carrier, wherein the first heat exchanger is located downstream of, and fluidly connected to, the first solid-gas separator.

3. The system of claim 1, wherein the CLC subsystem further comprises (b-iv) a second solid-gas separator located downstream of, and fluidly connected to, the oxidizer, the second solid-gas separator being configured to separate the oxygen-containing stream from the oxygen carrier, wherein the combustor is located downstream of, and fluidly connected to, the second solid-gas separator.

4. The system of claim 2, wherein the CLC subsystem further comprises (b-iv) a second solid-gas separator located downstream of, and fluidly connected to, the oxidizer, the second solid-gas separator being configured to separate the oxygen-containing stream from the oxygen carrier, wherein the combustor is located downstream of, and fluidly connected to, the second solid-gas separator.

5. The system of claim 1, wherein the power generation subsystem further comprises (c-iii) a first steam turbine located downstream of, and fluidly connected to, the first heat exchanger, wherein the first steam turbine is configured to generate steam turbine shaft work with the steam.

6. The system of claim 1, wherein the HRSG subsystem further comprises (d-ii) a second heat exchanger located downstream of, and fluidly connected to, the reducer and the first heat exchanger, wherein the second heat exchanger is configured to form steam at no higher temperature than the first heat exchanger by heating a water stream with the CO.sub.2/H.sub.2O stream.

7. The system of claim 6, wherein the power generation subsystem further comprises (c-iv) a second steam turbine located downstream of, and fluidly connected to, the second heat exchanger, wherein the second steam turbine operates at no higher pressure than the first steam turbine, and wherein the second steam turbine is configured to generate steam turbine shaft work with the steam.

8. The system of claim 6, wherein the HRSG subsystem further comprises (d-iii) a third heat exchanger located downstream of, and fluidly connected to, the reducer and the first and second heat exchangers, wherein the third heat exchanger is configured to form steam at no higher temperature than the second heat exchanger by heating a water stream with the CO.sub.2/H.sub.2O stream.

9. The system of claim 8, wherein the power generation subsystem further comprises (c-v) a third steam turbine located downstream of, and fluidly connected to, the third heat exchanger, wherein the third steam turbine operates at no higher pressure than the second steam turbine, and wherein the third steam turbine is configured to generate steam turbine shaft work with the steam.

10. The system of claim 8, wherein the heat exchangers are arranged in series.

11. The system of claim 7, wherein the steam turbines are arranged in series.

12. The system of claim 1, further comprising: a condenser located downstream of, and fluidly connected to, the first heat exchanger, the condenser condensing the CO.sub.2/H.sub.2O stream to form a condensate and a CO.sub.2 stream; and a gas compressor located downstream of, and fluidly connected to, the condenser, the gas compressor being configured to compress the CO.sub.2 stream, wherein CO.sub.2 is present in the CO.sub.2 stream at a volume concentration of at least 75 vol % relative to the total volume of the CO.sub.2 stream.

13. The system of claim 8, further comprising: two or more condensers located downstream of, and fluidly connected to, the first heat exchanger, the condensers condensing the CO.sub.2/H.sub.2O stream to form a condensate and a CO.sub.2 stream; and a gas compressor located downstream of, and fluidly connected to, each of the condensers, wherein the gas compressors are configured to compress the CO.sub.2 stream, wherein CO.sub.2 is present in the CO.sub.2 stream at a volume concentration of at least 75 vol % relative to the total volume of the CO.sub.2 stream.

14. The system of claim 1, wherein the oxygen carrier comprises iron oxide, nickel oxide, manganese oxide, copper oxide, cobalt oxide, or a mixture of two more of any of these, and/or wherein the oxygen carrier is supported on a substantially inert material comprising aluminum oxide, silica, a silicate, a zeolite, sepiolite, titanium oxide, zirconium oxide, or a mixture of two or more of any of these.

15. The system of claim 1, wherein the oxygen carrier comprises iron (III) oxide supported on alumina, with a mass ratio of the alumina to the oxygen carrier in a range of from 0.25 to 0.75.

16. The system of claim 1, configured such that a molar ratio of the second syngas substream to the syngas stream is in a range of from 0.001 to 0.25.

17. The system of claim 1, wherein the fuel heater is further suitable for heating and delivering a solid fuel stream.

18. The system of claim 1, further comprising a water-gas shift reactor stage downstream of the gas splitter and/or a pressure swing absorber.

19. A method of generating power using the integrated system of claim 1, the method comprising: delivering the liquid fuel stream to the fuel heater to form a heated fuel stream; delivering the heated fuel stream to the gasifier to form the syngas stream in the presence of the oxygen-rich stream; splitting the syngas stream to the first syngas substream and the second syngas substream with the gas splitter, and delivering the first syngas substream to the reducer while concurrently delivering the second syngas stream to the combustor; oxidizing the first syngas stream with the reducer in the presence of the oxygen carrier to form the CO.sub.2/H.sub.2O stream, wherein the oxygen carrier is reduced to the reduced oxygen carrier; optionally separating the CO.sub.2/H.sub.2O stream from the reduced oxygen carrier with the first solid-gas separator, before delivering the reduced oxygen carrier to the oxidizer; oxidizing the reduced oxygen carrier with the oxidizer in the presence of the oxygen-containing stream to regenerate the oxygen carrier; optionally separating the oxygen-containing stream from the oxygen carrier with a second solid-gas separator, before delivering the oxygen carrier to the oxidizer while concurrently delivering the oxygen-containing stream to the combustor; combusting the second syngas stream in the presence of the oxygen-containing stream to form the exhaust stream; and delivering the exhaust stream to the first gas turbine to generate power.

20. The method of claim 19, wherein the oxygen carrier is iron (III) oxide supported on alumina, with a mass ratio of the alumina to the oxygen carrier in a range of from 0.25 to 0.75, and wherein a molar ratio of the second syngas substream to the syngas stream is 0.01 to 0.25.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) A more complete appreciation of the invention and many of the attendant advantages thereof will be readily obtained as the same becomes better understood by reference to the following detailed description when considered in connection with the accompanying drawings, wherein:

(2) FIG. 1 shows a schematic plant layout and process flow diagram of a combined chemical looping process within the scope of the present invention;

(3) FIG. 2 shows an inventive process and the effect of the equivalence ratio on the product distribution of the producer gas;

(4) FIG. 3 shows an inventive process and the effect of the amount of the air supply on the efficiency of the combined CLC process at various inert ratios;

(5) FIG. 4 shows the effect of the pressure on the efficiency of the combined CLC process at different air supply ratios;

(6) FIG. 5 shows an inventive process and the effect of the pressure on the power generated from the gas turbines and heat recovery-steam generators at different air supply ratios;

(7) FIG. 6 shows an inventive process and the effect of the air supply ratio on the efficiency of the integrated CLC process at different split ratios of the producer gas;

(8) FIG. 7 shows an inventive process and the effect of the air supply ratio on the specific CO.sub.2 emission at different split ratios of the producer gas; and

(9) FIG. 8 shows the gasification and CLC subsystems of the schematic plant layout of FIG. 1.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

(10) Aspects of the invention provide integrated systems, comprising a gasification subsystem, a chemical looping combustion (CLC) subsystem, a power generation subsystem, and a heat recovery-steam generation (HRSG) subsystem, and particularly comprising a gas splitter located downstream of, and fluidly connected to, a gasifier, which gas splitter is configured to split the syngas stream (primarily H.sub.2 and CO) from the gasifier into a first syngas substream and a second syngas substream, wherein one or both of these substreams are (directly) sent to separate stages in the CLC process. The first substream may be sent to a reducer/reduction reactor, while the second substream is fed directly to a combustor/combustion reactor, one or preferably both, prior to any turbines, particularly without any intervening reactive or separative components between the splitter and the reducer and/or combustor. The splitter may be configured to separate out particular components of the gasification product, i.e., syngas, stream, but preferably, the splitter merely divides the gasification product stream.

(11) Inventive gasification subsystems may comprise (a-i) one or more fuel heaters, (a-ii) one or more gasifiers, and/or (a-iii) one or more gas splitters, generally connected in series.

(12) Useful fuel heaters within the scope of the invention are preferably configured to handle, i.e., suitable for heating, a liquid fuel stream. Such liquid fuels may include any petroleum or mineral oils, oil sands, oil shales, crude oils, tars, tar sands, sour oils, asphalts, waxes, tallows, napthas, lubricating oils, and the like, but may also include lighter fuels, such as petroleum ethers, gasoline, gas oils, aromatics, paraffins, naphthenes, kerosenes, fuel oils, diesels, or the like. Useful fuel heaters may alternatively, or additionally to liquids, be configured to heat and deliver solid fuels, including, for example, coal, lignite, petroleum coke, polyaromatic hydrocarbons (PACs), and the like. Useful fuel heaters may alternatively, or additionally to liquids and/or solids, be configured to heat and deliver gases, such as methane, natural gas, propane, butane(s), C1-C4 gases, liquefied petroleum gas, or the like.

(13) Within the scope of the invention, gasifiers are generally located downstream of, and fluidly connected to, the fuel heater, as well as the gas splitter. Useful gasifiers are generally configured to gasify the liquid fuel stream with an oxygen-rich stream to form a syngas stream, though the gasification may be conducted on solid or gaseous sources, or even on any combination of these. The gasification preferably occurs with less than 10, 5, 2.5, 1, 0.5, 0.1, 0.001 wt. % metal oxide particles, or even in the absence of metal oxide particles, though exclusion metal oxide particles is not necessary for useful results.

(14) Gas splitters useful within the invention are generally located downstream of, and fluidly connected to, the gasifier, alongside being further downstream of any fuel heater(s). The gas splitter should be suitable to split, i.e., divide, the syngas stream from the gasification reactor(s) into at least a first syngas substream and a second syngas substream. These substreams are preferably of substantially the same composition relative to one another, though the compositions are not required to be identical and it is possible to remove undesired components from, or enrich desired components, of one or both of the substreams. Gas splitters useful in the invention are distinct from gas-solid separators, or other stream component separators conventional in the art, and instead function to divide a stream volumetrically, i.e., as a percent of the full composition stream, such as 5 vol. % of a full composition syngas stream into one substream and 95 vol. % of a full composition syngas stream into a second substream. Useful splitting or split ratios may be in a range of 0 to 25, 2.5 to 20, 5 to 17.5, or 7.5 to 15 mol. % to, e.g., the substream headed to the combustor, and a remainder to the other substream. Further useful upper endpoints for the substream to the combustor could be 50 mol. %, 40, 33.3, 30, 27.5, 22.5, 16.6, 12.5, 10, 7.5, 5, or 2.5 mol. %, based on the moles of gas from the gasification subsystem or “island,” while further useful lower endpoints for the substream to the combustor could be 0.1, 0.25, 0.5, 1, 2, 3, 4, 6, 10, 12.5, or 15 mol. %.

(15) In addition to the gasification subsystem in any arrangement discussed above, a chemical looping combustion (CLC) subsystem within the scope of the invention may comprise (b-i) at least one reducer/reduction reactor located downstream of, and fluidly connected to, the gas splitter, the reducer being configured to oxidize the first syngas substream in the presence of an oxygen carrier to form a CO.sub.2/H.sub.2O stream, the oxygen carrier being reduced to a reduced oxygen carrier, (b-ii) optionally, at least one first solid-gas separator located downstream of, and fluidly connected to, the reducer, the first solid-gas separator being configured to separate the CO.sub.2/H.sub.2O stream from the reduced oxygen carrier, (b-iii) at least one oxidizer/oxidation reactor located downstream of, and fluidly connected to, the first solid-gas separator, the oxidizer being configured to oxidize the reduced oxygen carrier in the presence of an oxygen-containing stream to regenerate the oxygen carrier, and (b-iv) optionally, at least one second solid-gas separator located downstream of, and fluidly connected to, the oxidizer, the second solid-gas separator being configured to separate the oxygen-containing stream from the oxygen carrier.

(16) Feeding the CLC subsystem will generally be air, which is usually fed into the oxidizer via one or more compressors. In addition to this, the air fed into the oxidizer is preferably enriched in oxygen (O.sub.2) concentration, i.e., at least 80, 85, 90, 92.5, 95, 97.5, 99, or 99.9 wt. % O.sub.2. The air and/or oxygen stream may even be substantially pure oxygen, i.e., having triple or double digit ppm amounts of contaminants or less. The air may be preprocessed in a pressure swing adsorption unit to modify the gas composition, though purified gases are also commercially available.

(17) Useful oxygen carriers herein could be any oxidized metal(s) or mineral(s) which can be circulated between generally two (or more) interconnected reactors or reactor spaces. The oxygen carrier(s) may comprise iron oxide, nickel oxide, manganese oxide, copper oxide, cobalt oxide, mineral(s) such as ilmenite, or a mixture of two more of any of these, which may include multi-metal oxides (such as bimetallic oxides) or mixtures of single-metal oxides. In addition, the oxygen carrier may supported on a substantially inert material comprising an alumina, silica, silicates, (non-reactive) zeolites, sepiolite, titanium oxide, zirconium oxide, and similar substantially inert materials, or mixture of two or more of any of these. Preferred supports may include aluminum and/or silicon oxides, which may include multi-metal oxides or mixtures of single-metal oxides, particularly alumina. Exemplary oxygen carriers could be Fe.sub.2O.sub.3—Fe.sub.3O.sub.4, CuO, Co—Ni. The oxygen carrier may preferably comprise iron (III) oxide, preferably supported on alumina. The mass ratio of the support to the oxygen carrier, in such an arrangement, may preferably be a range of from 0.25 to 0.75, 0.3 to 0.7, 0.35 to 0.65, 0.4 to 0.6, or 0.45. The molar ratio of the second syngas substream to the syngas stream—streaming from the gasification—is in a range of from 0.01 to 0.25, 0.025 to 0.2, 0.033 to 0.175, 0.05 to 0.15, 0.067 to 0.133, or 0.075 to 0.125.

(18) The oxygen carrier in its oxide form should be suitable to provide oxygen needed for the combustion of fuel in the reduction reactor(s) and produce reduced metal (oxide), steam, and CO.sub.2. The oxygen carrier-assisted reaction typically follows Equation 1, below:
(2j+k)M.sub.xO.sub.y+C.sub.jH.sub.2k.fwdarw.(2.sub.j+.sub.k)M.sub.xO.sub.y-1+kH.sub.2O+jCO.sub.2  (Eq. 1),
which is a modified form of the idealized gasification reaction following Equation 2, below;
C.sub.xH.sub.y+x/2O.sub.2.Math.xCO+y/2H.sub.2  (Eq. 2),
augmented by an idealized oxidation of the oxygen carrier following Equation 3, below:
M.sub.xO.sub.y-1+½O.sub.2.fwdarw.M.sub.xO.sub.y  (Eq. 3)
Reduction schemes for an exemplary oxygen carrier are as set forth in Equations 4 and 5, along with enthalpic balances, below:
3Fe.sub.2O.sub.3+CO.Math.CO.sub.2+2Fe.sub.3O.sub.4 ΔH.sub.298.sup.0=−871 MJ/kmol  (Eq. 4)
3Fe.sub.2O.sub.3+H.sub.2.Math.H.sub.2O+2Fe.sub.3O.sub.4ΔH.sub.298.sup.0=−830 MJ/kmol  (Eq. 5)
and the oxidation reaction, with enthalpic balance is in Equation 6, as follows:
4Fe.sub.3O.sub.4+O.sub.2.Math.6 Fe.sub.2O.sub.3ΔH.sub.298.sup.0=−943 MJ/kmol  (Eq. 6).

(19) In addition to the gasification and/or CLC subsystem in any arrangement discussed above, a power generation subsystem within the scope of the invention may comprise (c-i) at least one combustor located downstream of, and fluidly connected to, the gas splitter and the oxidizer, the combustor combusting the second syngas substream in the presence of the oxygen-containing stream to form an exhaust stream, (c-ii) at least a first gas turbine located downstream of, and fluidly connected to, the combustor for generating gas turbine shaft work with the exhaust stream, (c-iii) optionally, a first, second, and/or third steam turbine located downstream of, and fluidly connected to, the first heat exchanger, the first steam turbine being configured to generate steam turbine shaft work with the steam.

(20) The second steam turbine may be located downstream of, and fluidly connected to, the second heat exchanger. The second steam turbine may operate at the same or a lower pressure than the first steam turbine. The second steam turbine may be configured to generate steam turbine shaft work with the steam.

(21) The third steam turbine may be located downstream of, and fluidly connected to, the third heat exchanger. The third steam turbine may operate at the same or a lower pressure than the second steam turbine. The third steam turbine may be configured to generate steam turbine shaft work with the steam.

(22) The steam turbines may be arranged in series, though there may be dual (or additional) steam turbines arranged in parallel, and there may be a mixture of series and parallel steam turbines, or all steam turbines may be in parallel or in series.

(23) In addition to the gasification, CLC, and/or power generation subsystem in any arrangement discussed above, a heat recovery-steam generation (HRSG) subsystem within the scope of the invention may comprise (d-i) a first heat exchanger located downstream of, and fluidly connected to, the reducer, the first heat exchanger being configured to form steam by heating a water stream with the CO.sub.2/H.sub.2O stream, (d-ii) optionally, a second heat exchanger located downstream of, and fluidly connected to, the reducer and the first heat exchanger, the second heat exchanger being configured to form steam at no higher temperature than the first heat exchanger by heating a water stream with the CO.sub.2/H.sub.2O stream, and (d-iii) optionally, a third heat exchanger located downstream of, and fluidly connected to, the reducer and the first and second heat exchangers, the third heat exchanger being configured to form steam at no higher temperature than the second heat exchanger by heating a water stream with the CO.sub.2/H.sub.2O stream.

(24) The heat exchangers may be arranged in series, though there may be dual (or additional) heat exchangers arranged in parallel, and there may be a mixture of series and parallel heat exchangers, or all heat exchangers may be in parallel or in series.

(25) Integrated systems, i.e., plant arrangements, according to the invention may further comprise one or more condensers located downstream of, and fluidly connected to, the first, second, third, and/or further heat exchangers, the condensers being configured to condense the CO.sub.2/H.sub.2O stream to form a condensate and a CO.sub.2 stream. The integrated systems may further comprise one or more gas compressors located downstream of, and fluidly connected to, the one or more condensers. These gas compressors are generally configured to compress the CO.sub.2 stream, while the CO.sub.2 is present in the CO.sub.2 stream(s) at a volume concentration of at least 75, 80, 85, 90, 95, 96, 97, 97.5, 98, 99, 99.5, or 99 vol. % relative to the total volume of the CO.sub.2 stream. The CO.sub.2 may be captured according to any method known, including those disclosed by Yan, each Hoteit reference, Guillou, Spallina, Li, Nazir, Xiang, Consonni, which are incorporated by reference herein.

(26) In addition to, or separate from the above, systems within the invention may further comprise one or more water-gas shift reactor stage downstream of the gas splitter and gasifier. Systems within the invention may further comprise one or more pressure swing absorbers, i.e., prior to the air compressor upstream of the oxidizer, or after the gasification, depending upon the contents of the gases in question.

(27) Aspects of the invention provide method of generating power, optionally using an integrated system according to any combination of the features described herein. Inventive methods will generally involve a splitting of the gasification product, i.e., syngas, into at least two similar or identically composed syngas substreams. Methods within the invention will generally comprise: delivering a hydrocarbon fuel—particularly liquid hydrocarbon—stream to a fuel heater to form a heated fuel stream; delivering the heated fuel stream to a gasifier to form a syngas stream in the presence of an oxygen-rich stream; splitting the syngas stream to a first syngas substream and a second syngas substream with a gas splitter, and delivering the first syngas substream to a reducer while concurrently delivering the second syngas stream to a combustor; oxidizing the first syngas stream with the reducer in the presence of an oxygen carrier to form a CO.sub.2/H.sub.2O stream, wherein the oxygen carrier is reduced to a reduced oxygen carrier; optionally separating the CO.sub.2/H.sub.2O stream from the reduced oxygen carrier with a first solid-gas separator, before delivering the reduced oxygen carrier to an oxidizer; oxidizing the reduced oxygen carrier with the oxidizer in the presence of the oxygen-containing stream to regenerate the oxygen carrier; optionally separating the oxygen-containing stream from the oxygen carrier with the second solid-gas separator, before delivering the oxygen carrier to the oxidizer while concurrently delivering the oxygen-containing stream to the combustor; combusting the second syngas stream in the presence of the oxygen-containing stream to form an exhaust stream; and delivering the exhaust stream to a gas turbine to generate power.

(28) An important aspect of integrated CLCs within the scope of the invention is electricity production. Thus, performance of plants and process according to the invention can be measured in terms of net electrical efficiency. The net electrical efficiency is the ratio of the total energy produced by the power generation system to sum of the energy in the fuel oil and the energy required for any oxygen purification of the air fed into the oxidizer. Producing one ton of 95% purity O.sub.2 from air requires 305 kW. The energy balance for the system modelled herein is in Equation 7 below:

(29) $\begin{array}{cc}{\eta }_e=\frac{E_e-\left(E_{\mathrm{oxy}}+E_{C1}+E_{C2}+E_{C3}+E_{\mathrm{Aux}}\right)}{m_{\mathrm{fuel}}.Math.{\mathrm{LHV}}_{\mathrm{fuel}}},& \left(\mathrm{Eq}.7\right)\end{array}$
wherein, η.sub.e is the net electrical efficiency, E.sub.e is the total energy produced by the power generation system, m.sub.fuel is the mass flow rate of the fuel oil, and LHV.sub.fuel is the low heating value of the fuel oil. E.sub.oxy and E.sub.aux respectively represent the energy consumed for oxygen production and auxiliaries, while E.sub.C1, E.sub.C2, and E.sub.C3 are the energy consumed for air compressor (CMP), CO.sub.2 compressor 1.sup.st stage (C-1), and CO.sub.2 compressor 2.sup.nd stage (C-2), respectively. According to this calculation, higher net electrical efficiency indicates better performance of a combined CLC process as modelled. Similar calculus may be applied to augmented plant designs with fewer or more stages.

(30) A further relevant facet of performance evaluation may be CO.sub.2 emissions relative to the producer gas directly fed into the combustion (CMB) and released to the atmosphere after heat recovery. The specific CO.sub.2 emission is defined as the amount of CO.sub.2 emitted to the atmosphere per the amount of the energy produced from the power generation system. Equation 8, below, sets forth the evaluation of specific CO.sub.2 emission as follows:

(31) $\begin{array}{cc}{\mathrm{EM}}_{{\mathrm{CO}}_2}=\frac{m_{{\mathrm{CO}}_2}}{E_e},& \left(\mathrm{Eq}.8\right)\end{array}$
wherein EM.sub.CO2 is the specific CO.sub.2 emission and m.sub.CO2 is the amount of CO.sub.2 emitted to the atmosphere, Fe again being the total energy produced by the power generation system.

(32) The experiment in this application (Example) can be compared for accuracy with the data set forth in Consonni (Comp. Ex), which discussed in the Background section. The comparative data is set forth in Table 1, below.

(33) TABLE-US-00001 TABLE 1 OX products RED products Components Comp. Ex. Example Comp. Ex. Example Solids Mass flow, kg/s 2507 2507 2470 2470 Temperature, ° C. 1050 999 986.2 997 Reduced iron, % wt 0 43.6% 43.9% Oxidized iron, % wt 50.8% 50.7%  6.5%  6.1% Inert material, % wt 49.2% 49.3% 50.0% 50.0% Gases Mass flow, kg/s 474.8 437.7 47.2 47.4 Temperature, ° C. 1050 999 986.2 997 N.sub.2, % mol 82.70%  84.99%  1.09% 1.07% O.sub.2, % mol 15.18%  15.01%  0.00% 0.00% Ar, % mol 0.98% 0.00% 0.00% 0.00% H.sub.2O, % mol 1.11% 0.00% 65.25%  65.17%  CO.sub.2, % mol 0.03% 0.00% 33.64%  33.75%  Items Comp. Ex. Example Power output, MW Gas turbine 111.1 118.7 Steam turbine 98.6 48.7 CO.sub.2 compressor, MW −4.8 −5.2 Auxiliaries −3.3 −2.5 Net power output 201.6 159.8 Natural gas fuel input, MW.sub.LHV 467.1 467.1 Net efficiency 43.2% 34.2%

(34) Certain parameters have been determined to influence the results of the process or plant operation, including the actual to stoichiometric ratio of air supply (AS ratio), the mass ratio of the inert material (e.g., Al.sub.2O.sub.3) to the mass of the oxygen carrier (e.g., Fe.sub.3O.sub.4), the reaction pressure, and the producer gas split ratio (SP ratio) representing moles producer gas, i.e., syngas, directly flowing to the combustor (CMB) for per mole of producer gas from the gasification. These parameters are discussed below in relation to the drawings.

(35) Referring now to the drawings, wherein like reference numerals designate identical or corresponding parts throughout the several views.

(36) In reference to FIG. 1, an embodiment of the integrated CLC process comprises four main units/groups: (i) a gasification island, (ii) chemical looping combustion island, (iii) heat recovery and (iv) power generation system. In this example, fuel oil, referred to as a liquid fuel stream (1) may be heated in the fuel heater (FH) prior to the gasifier (G) and then the heated fuel oil (3) is sent to the gasifier. Further sources of carbon, e.g., methane, natural gas, light hydrocarbons, coal, tar(s), or the like may be used. The analysis report of the fuel oil is given in Table 2. In other stream, the oxygen with 95% purity, referred to as an oxygen-rich stream (5) is also fed to the gasifier (G) from the air purification process. In the presence of the oxygen as a gasifying agent, the fuel oil may be converted into gaseous products, such as H.sub.2, CO, CO.sub.2, and CH.sub.4, and some amount of coke.

(37) TABLE-US-00002 TABLE 2 Parameter Value Mass fraction Carbon 86.6 Hydrogen 13.7 Nitrogen <0.1 Sulfur 0.05 Lower heating value, MJ/kg 43.00

(38) The coke formed during gasification is preferably homogenously fluidized along with the gaseous products. The gasifier products, referred to as a syngas stream (4) are then directed to the gas splitter (SPL) to divide the gasifier into two streams: a stream to the reduction reactor (RED) (6a), referred to as a first syngas substream, and a stream to the combustor (CMB) (6b) referred to as a second syngas substream. A useful function, optionally the main function, of the combustor (CMB) is to enhance the temperature of the flue gas prior to the gas turbine (GT). In the combustor (CMB), the gasifier products, including CO and H.sub.2, and optionally further gas(es), react with the excess oxygen from the oxidation reactor (OX).

(39) In the oxidation reactor (OX), the oxygen, which may be present as a component of the air (8) referred to as an oxygen-containing stream, reacts with the magnetite (Fe.sub.3O.sub.4) from the reduction reactor (RED), and produces the hematite (Fe.sub.2O.sub.3) as the oxygen carrier. Air in the oxidation reactor (OX) may be supplied from the atmosphere using compressor (CMP) (7). Practically, the oxygen carrier is hosted or supported on a support, such as alumina (Al.sub.2O.sub.3), silica (SiO.sub.2), zeolite, glass, or some other at least substantially inert material.

(40) The products from the oxidation reactor (OX) (9), referred to as the oxygen carrier, i.e., in this example, hematite on alumina, excess oxygen, and nitrogen, are then circulated to the second gas-solid separator (SEP.sub.2) to separate the solid product (10), i.e., hematite in this example, and the gaseous products (11) i.e., O.sub.2 and N.sub.2. The hematite can flow to the reduction reactor (RED) while the gaseous products may be directed to the CMB to combust with the second syngas substream (6b) to form an exhaust stream (15) in the gas turbine (GT) to generate mechanical work. The mechanical work may be further converted to the electricity by generating gas turbine shaft work with the exhaust stream.

(41) The flue gas from the gas turbine (GT) (16) may flow to the atmosphere or cycle back through the steam generation system (30), i.e., high pressure (HP) (30c), medium pressure (MP) (30b), and low pressure (LP) (30a) steam generators (SG), with each of which one or more steam turbines (ST-1, ST-2, ST-3) may be associated. Exhaust from the GT outlet (16) enters a high pressure steam generator (HP SG) where the exhaust gets converted to HP steam (17) or moves to the medium pressure steam generator (MP SG) (18), which then gets converted to medium pressure steam (22) or moves to the low pressure steam generator (LP SG) (23), which can then get converted into low pressure steam (26) or may flow to the atmosphere (27) or cycle back through the steam generation system (30). The HP (17), MP (22), and LP (26) steam each enter the ST-1, ST-2, and ST-3 respectively, generating power. The exhaust from ST-1 (21), ST-2 (25), and ST-3 (29) cycles back through the steam generation system (30) at the high (30c), medium (30b), or low (30a) pressures through at least one heat exchanger (HE). In the reduction reactor (RED), the gasifier products from the gas splitter (SPL) (6a) may react with the hematite, and yield CO.sub.2, H.sub.2O and magnetite (Fe.sub.3O.sub.4). The products from the reduction reactor (RED) (12) may be sent to the cyclone (CYC) referred to as the first solid gas separator (SEP.sub.1) to separate the gaseous products (13), i.e., CO.sub.2 and H.sub.2O referred to as the CO.sub.2/H.sub.2O stream, from the solid product (14), referred to as the reduced oxygen carrier, i.e., magnetite (Fe.sub.3O.sub.4) in this case. The magnetite may be sent to the oxidation reactor (RED) for regeneration while the gaseous products are sent to the steam generation system. The gaseous products from the RED (13) enters the series of steam generators each containing a water stream, where in the HP SG it heats the water stream (37) to make HP steam (17) or moves to the MP SG (20), where the water stream gets converted to medium pressure steam (22) or moves to the LP SG (24), where the water stream gets converted into low pressure steam (26) or the gaseous products from the RED are then cooled eventually stored as CO.sub.2 (28).

(42) From the steam generation system the gaseous products are then cooled to 30° C. (28) and the condensed water is separated in the condenser (CND) (32). The dry gaseous products (31) are then compressed using two stages intercooler gas compressor (C-1 (33) and C-2 (34, 35)) to 85 bar before storage (36). The gaseous products from the reduction reactor (RED) (13) contain high purity of CO.sub.2 (96-98%). Therefore, in this integrated CLC process, the CO.sub.2 is stored as a valuable product instead of being emitted to the atmosphere. It is worth noticing that the gasification reaction occurs in the gasifier (G), while both the oxidation reaction and reduction reactions involved in the oxidation reactor (OX) and reduction reactor (RED), respectively.

(43) An integrated CLC process as depicted in FIG. 1 is modeled with the Gibbs minimization approach using ASPEN PLUS® software. In ASPEN PLUS® software, carbon, hematite, magnetite and alumina are treated as solid compounds. The fuel oil and the gaseous products are considered respectively as the nonconventional and mixed component using the MIXCINC® stream class. The Peng-Robinson thermodynamic package is used for physical properties in the simulations presented in the drawings. The Peng-Robinson Equation of State (EOS) is considered suitable for predicting hydrocarbons and light gases, e.g., N.sub.2, CO, H.sub.2, etc., as well as their mixtures. The following four assumptions were made to simplify the model. First, N.sub.2 and alumina were treated as inert materials. Second, the effect of pressure drop, mass transfer, and thermo-fluid-dynamic were treated as negligible. Third, the reactors, i.e., the gasifier (G, in the drawings), the oxidation reactor (OX, in the drawings), the reduction reactor (RED, in the drawings) and the combustor (CMB) were treated as run at equilibrium. Fourth, an adiabatic system and single properties of the fuel were used. Table 3 presents the operating conditions of the combined CLC process in FIG. 1 as modelled.

(44) TABLE-US-00003 TABLE 3 Air supply 25° C., 1 atm  Fuel oil supply 25° C., 10 atm Oxygen supply 25° C., 10 atm Compressor air leakage 0.8% of inlet flow rate Compressor polytropic efficiency 90% Turbine isentropic efficiency 93% Approach temperature 25° C. Steam generation pressure level 1.8 bar, 18.4 bar, 78.2 bar Condensor pressure 0.05 bar Generator efficiency 99% CO.sub.2 compressor isentropic efficiency 85% CO.sub.2 compressor mechanical efficiency 96% CO.sub.2 compressor electrical efficiency 96% CO.sub.2 storage 30° C., 85 bar

(45) The thermodynamic modelling of gasification can be conducted using Gibbs minimization approach. A heated fuel oil with the mass flow rate of 50,000 kg/h from the fuel heater (FH) is fed to the gasifier (G). Suitable mass flow rates, can for example, be in the range of 1,000,000 to 60, 500,000 to 600, 250,000 to 6,000, 125,000 to 10,000, 100,000 to 15,000, or 75,000 to 20,000 kg/h. The heated fuel oil is converted into gaseous products in the gasifier (G). As modelled herein, the R.sub.Yield and the R.sub.Gibbs reactors are used to simulate the gasifier since the fuel oil is considered nonconventional and requires conversion into its constituent element in the R.sub.Yield prior to the R.sub.Gibbs reactor. In the R.sub.Gibbs reactor, i.e., the modelled gasifier (G), the fuel oil reacts with the oxygen, and it produces the gaseous products, sometimes called producer gas, primarily comprising H.sub.2 and CO.

(46) FIG. 2 discloses model functions of the equivalence ratio for the gasification process using the layout in FIG. 1. The oxygen equivalence ratio can be an important parameter in the gasification. The equivalence ratio is defined as the ratio of actual oxygen to biomass weight ratio per stoichiometric oxygen to biomass weight ratio. The product distribution varies significantly with the increase of the oxygen equivalence ratio as shown in FIG. 2. High quality producer gas, i.e., low carbon formation and high concentration of H.sub.2 and CO, can result from an oxygen equivalence ratio of 0.32, while optimum oxygen equivalence ratios in gasification may be in a range of from 0.26 to 0.43, 0.27 to 0.42, 0.28 to 0.40, 0.29 to 0.38, 0.30 to 0.36, or 0.31 to 0.34. An oxygen equivalence ratio of 0.32 and adiabatic conditions are assumed in the models herein. The high purity O.sub.2 (95% O.sub.2, 5% N.sub.2) is injected to the gasifier (G) as the gasifying agent. Higher gasification temperature generally provides higher conversion of the fuel.

(47) The oxidation reactor (OX) and the reduction reactor (RED) can be modelled using an R.sub.Gibbs reactor. A 20% excess of oxygen carrier materials (in this case, Fe.sub.2O.sub.3—Fe.sub.3O.sub.4) is circulated in the CLC to accomplish complete oxidation of the producer gas since incomplete conversion of hematite was experimentally observed at stoichiometric condition.

(48) The heat recovery system exemplified in the modelling utilizes the exhaust of gas turbine generator (GT) and the gaseous product of reduction reactor (RED) to generate steam. The heat recovery system includes three steam generators, such as high pressure steam generator (HP-SG, 78.2 bar), medium pressure steam generator (MP-SG, 18.4 bar), and low pressure steam generator (LP-SG, 1.8 bar). Acceptable pressure ranges will of course vary based upon the equipment used, but exemplary ranges for the high pressure components could be in a range of from 150 to 50, 125 to 60, 100 to 65, or 90 to 70 bar. Likewise, exemplary ranges for the medium pressure components could be in a range of from 50 to 10, 40 to 12, 30 to 14, or 20 to 16 bar, and the exemplary ranges for the low pressure components could be in a range of from 10 to 1, 7.5 to 1.1, 5 to 1.2, 5 to 1.25, 2.5 to 1.4, or 2 to 1.5 bar. The temperature of the exhaust after heat recovery in the model is around 142° C. The exhaust may be in any temperature range, depending on the fluid driving the final turbine stage(s), e.g., 200 to 40, 180 to 50, 175 to 60, or 150 to 80° C., though the ubiquity of water as a turbine driving fluid will generally require a exhaust temperature above 100° C.

(49) The power generation subsystem or “island,” as modelled, comprises one gas turbine generator (GT) and three steam turbine generators, high pressure (ST-1), intermediate pressure (ST-2) and low pressure (ST-3), though there may be additional gas turbine generators and/or steam turbines within the scope of the invention. The gas turbine generator ordinarily generates power using hot gases/fluids from the oxidation reactor (OX), though the heating may be direct or indirect. The hot gases from the gas turbine (GT) outlet may be used to generate steam at three different pressures (in the example, 78.2 bar, 18.4 bar, and 1.8 bar) in the heat recovery system along with the hot gases from the reduction reactor (RED), or other fluids heated directly or indirectly elsewhere in the process. The steam may be fed to the steam turbine generators to generate power.

(50) The effect of the air supply ratio and the inert ratio on the performance of the combined CLC process is modeled in FIG. 3. The actual to stoichiometric ratio of air supply (AS ratio) refers to moles of the actual air entering the process per stoichiometric moles of air necessary for complete combustion of the fuel. FIG. 3 shows that by varying the flow rate of air supply while keeping a constant flow rate of the fuel at various inert ratios. The inert ratio (IN ratio) is defined as the mass ratio of the inert material (e.g., Al.sub.2O.sub.3—exemplified herein, SiO.sub.2, ZrO.sub.2, etc.) to the mass of the oxygen carrier (i.e., Fe.sub.3O.sub.4—exemplified herein).

(51) FIG. 3 illustrates that the efficiency of CLC processes within the scope of the invention significantly increases when the air supply ratio is augmented. For instance, at the inert ratio of 0.7, the efficiency increases from 23% to 47% when the air supply ratio is increased from 5 to 9. The efficiency increase may be caused by increased air supply enhancing the energy generation in the power generation subsystem, counteracting a slightly increased energy consumption by the air compressor, CO.sub.2 compressors, and auxiliaries.

(52) FIG. 3 also shows that the air supply ratio can effect the efficiency of the combined CLC process at varied inert ratios, i.e., ratios of the support mass to oxygen carrier mass. Higher inert ratios generally have a minor effect on the efficiency of the combined CLC process at low air supply ratios, while the effect is significant on the efficiency at high air supply ratios. A negative effect can be observed when the actual to stoichiometric ratio of air supply is lower than a certain value. For instance, at an air supply ratio of 5, the efficiency of the process depicted in FIG. 1 decreases from 24.31% to 23.85% when the inert ratio is increased from 0.3 to 0.7. A similar trend may occur using natural gas as the fuel and iron as the oxygen carrier. On the other hand, when the air supply ratio is 9 the efficiency of the integrated CLC process modelled, increases from 42% to 47% if the inert ratio is increased from 0.3 to 0.7.

(53) It is believed that the inert material brings about this positive effect on efficiency by storing thermal energy. In other words, the inert material preserves the temperature of the CLC subsystem/island and consequently maintains the temperature of the thermodynamic cycle of the gas turbine. In addition, higher inert fractions promote higher fractions of the fuel heating value in the heat recovery system, particularly in heat recovery steam generators. The amount of the working fluid also has an effect on the performance of the gas turbine. When the air supply is limited, the role of the inert material is limited due to the insufficient amount of working fluid available to transfer the thermal energy from the CLC subsystem/island to the power generation subsystem/island. On the other hand, the presence of the inert material may contribute a positive effect if a sufficient air supply is injected to the CLC process.

(54) FIG. 4 illustrates how an increase in the compression ratio, i.e., the pressure in the process, can negatively impact the efficiency of the process. At an air supply ratio of 7, the efficiency decreases from 37% to 31% as the compression ratio increases from 8 to 16 bar abs. Higher compression ratios of air, CO.sub.2, and/or heavy oil, result in increased energy consumption. Thus, the total energy generated from the process decreases with increases in the compression ratio as reflected in FIGS. 4 and 5. A similar tendency is observable at an air supply ratio of 6 and 5. Efficiencies of integrated CLC processes may continuously decrease when pressure is elevated, for example, from 5 bar to 25 bar abs. At the same pressure, however, higher efficiencies of combined CLC process are observed as the air supply ratio is augmented, particularly, increased. This due to higher air supply ratios increasing the amount of the working fluid, which results in the increase of the turbine work.

(55) Power generation of the gas turbine declines if the compression ratio is increased from 8 bar to 16 bar abs as shown in FIG. 5. At the AS ratio of 7, the power generation of the gas turbine mitigates from 182 MW to 170 MW as the pressure increases from 8 bar to 16 bar abs. This is mainly due to air leakage and mechanical issues in the compressors and turbines. Thus, the higher pressures intensify the effect of the losses on the performance of the compressor and turbine. Under certain circumstances integrated CLC processes (cooling, heating, and power generation) can exhibit the highest power generation at 10 bar abs.

(56) FIG. 5 illustrates the influence of pressure to the power generation of the steam turbines. Power generation of the steam turbines declines with increased pressure. For instance, 74 MW of power can be generated at an air supply ratio of 7 and 8 bar abs pressure. However, power generation may decrease to 47 MW at a pressure of 16 bar abs with the same air supply ratio. The HRSG may generate energy from both the exhaust gas from the gas turbine (GT) and the flue gas from the oxidation reactor (OX). The flue gas from the oxidation reactor (OX) is influenced by the quality of the producer gas, i.e., syngas, from the gasification. The producer gas quality, in terms of the heating value—reflecting the composition of the combustible gases (CO and H.sub.2), declines when the pressure is increased.

(57) FIG. 6 illustrates that the efficiency of the integrated CLC process can increase by increasing the split ratio. The splitting or split ratio of the producer gas refers to the moles of producer gas directly flowing to the combustor (CMB) per mole of the producer gas from the gasification. For instance, at an air supply ratio of 9, the efficiency of the combined CLC process in the model increases from 46% to 55% as the split ratio is increased from 0 to 0.15. This result can be explained by noting that splitting the producer gas to the combustor (CMB) allows the temperature of the gas entering the gas turbine (GT) to be higher than the temperature of the CLC subsystem. In other words, the gas turbine (GT) may have the capability to fully extract the energy from the split producer gas and thus operate independently from the CLC subsystem.

(58) A useful feature of the integrated CLC process can be to minimize CO.sub.2 emissions. Accordingly, increased process efficiency can be balanced against the CO.sub.2 emitted to the atmosphere. From a CO.sub.2 emissions standpoint, the performance of integrated CLC processes and plants can be described in terms of the specific CO.sub.2 emission. Specific CO.sub.2 emission refers to the mass of the CO.sub.2 emitted to the atmosphere per the quantity of the energy generated from the process.

(59) FIG. 7 illustrates that a higher split ratio can have an adverse effect on CO.sub.2 emission. For instance, at the air supply ratio of 9, the specific CO.sub.2 emission increases from 0 to 0.073 kg CO.sub.2/kW when the split ratio is increased from 0 to 0.15. Direct injection of the producer gas to the combustor (CMB) and release of CO.sub.2 to the atmosphere may explain this effect. Injecting the natural gas to the combustor can likewise produce higher specific CO.sub.2 emission. FIG. 7 shows that increased air supply ratio can mitigate the specific CO.sub.2 emission if the producer gas is split to the combustor (CMB). For example, at a split ratio of 0.15, the modelled specific CO.sub.2 emission declines from 0.102 kg/CO.sub.2 to 0.073 kg/CO.sub.2 as the air supply ratio increases from 6 to 9. A higher increase in power generation than the increase in the CO.sub.2 emission, as the air supply ratio increases, can explain this phenomenon.

(60) Thus, at higher air supply ratios, higher inert ratios can have a positive effect on the efficiency, e.g., as modelled, 47% at air supply ratio of 9 and inert ratio of 0.7. However, increasing the pressure can adversely affect the performance of the integrated CLC process. For example, a efficiency decline from 37% to 31% is observed in the model when the pressure is increased from 8 to 16 bar abs. Increasing the split ratio of the producer gas into the combustor (CMB) can also have a positive effect on the overall efficiency, e.g., 55% at air supply ratio of 9 and inert ratio of 0.7, though a negative effect is observed on specific CO.sub.2 emission, i.e., 0.073 kg CO.sub.2/kW at the same air supply ratio of 9 and inert ratio of 0.7.

(61) Obviously, numerous modifications and variations of the present invention are possible in light of the above teachings. It is therefore to be understood that within the scope of the appended claims, the invention may be practiced otherwise than as specifically described herein.

REFERENCE SYMBOLS

(62) 1-36 streams FH fuel heater G gasifier SPL gas splitter CMP compressor OX oxidation reactor RED reduction reactor SEP gas-solid separator CMB combustor GT gas turbine HP high pressure MP medium pressure LP low pressure SG steam generator ST-1 first steam turbine ST-2 second steam turbine ST-3 third steam turbine CND condenser C-1 first stage intercooler gas compressor C-2 second stage intercooler gas compressor