METHOD FOR CARBON CAPTURE IN A GAS TURBINE BASED POWER PLANT WITH A CARBON CAPTURE SYSTEM

Abstract

Disclosed herein is a system comprising a compressor in mechanical communication with a turbine; the compressor being operative to produce compressed air; a premixer; the premixer being operative to mix a fuel with the compressed air; a carbonator being located downstream of the premixer; the carbonator being operative to receive a mixture of carbon dioxide and syngas and to convert a metal oxide into a metal carbonate by reacting it with the carbon dioxide; a calciner; the calciner being operative to receive the metal carbonate from the carbonator; and to dissociate carbon dioxide from the metal carbonate; and a combustor; the combustor being located downstream of the carbonator; where the combustor is operative to combust syngas received from the carbonator.

Description

TECHNICAL FIELD

This disclosure relates to a method for carbon capture in a gas turbine based power plant with a carbon capture system.

BACKGROUND

The combustion of a fuel, such as coal, oil, peat, waste, natural gas, and the like, in a combustion plant such as a power plant, generates a hot process gas stream known as a flue gas stream. In general, the flue gas stream contains particulates and gaseous contaminants such as carbon dioxide (CO₂). The negative environmental effects of releasing carbon dioxide to the atmosphere have been recognized, and have resulted in the development of processes adapted for removing or reducing the amount of carbon dioxide from the flue gas streams.

There are three approaches to capturing carbon dioxide. One approach involves pre-combustion where the fuel is decarbonized prior to the main combustion phase in the power plant. This method has several drawbacks. These involve the loss of energy during the pre-combustion phase and the high auxiliary energy consumption of the air separation unit.

Another approach involves oxy-combustion where an oxygen rich stream is used in the combustion instead of air and the flue gas resulting from combustion contains a high percentage of carbon dioxide, which is easier to separate from the flue gases.

Yet another approach comprises post combustion where the carbon dioxide is removed from the flue gas after combustion. This method involves removing the carbon dioxide from the flue gas stream using a chilled ammonia process or an amine solvent removal process. This method has several drawbacks—notably that the low carbon dioxide concentration in the flue gas stream necessitates a large effort to capture the carbon dioxide. In the amine solvent capture process, the energy losses due to the regeneration of solvent to free the carbon dioxide reduce the amount of energy generated and increases the cost of energy generated.

Each of these methods has certain drawbacks. It is therefore desirable to devise a method for carbon capture that overcomes some of these drawbacks

SUMMARY

Disclosed herein is a system comprising a compressor in mechanical communication with a turbine; the compressor being operative to produce compressed air; a premixer; the premixer being operative to mix a fuel with the compressed air; a carbonator being located downstream of the premixer; the carbonator being operative to receive a mixture of carbon dioxide and syngas and to convert a metal oxide into a metal carbonate by reacting it with the carbon dioxide; a calciner; the calciner being operative to receive the metal carbonate from the carbonator; and to dissociate carbon dioxide from the metal carbonate; and a combustor; the combustor being located downstream of the carbonator; where the combustor is operative to combust syngas received from the carbonator.

Disclosed herein is a method comprising discharging a mixture of compressed air and fuel to a partial oxidation chamber; partially oxidizing the fuel to produce syngas and carbon dioxide; reacting a metal oxide with the carbon dioxide in a carbonator to produce a metal carbonate; calcining the metal carbonate in a calciner to produce carbon dioxide and the metal oxide; recycling the metal oxide to the carbonator from the calciner; sequestering the carbon dioxide; and combusting the syngas in a combustor to generate steam.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 is a depiction of an exemplary system that captures carbon dioxide in a dry process prior to combustion; and

FIG. 2 is a graph showing the higher pressure in the carbonator than in the calciner.

DETAILED DESCRIPTION

Disclosed herein is a system and a method that facilitates carbon capture in a facility where power is generated for public consumption (e.g., electricity) or for use in another manufacturing industry (e.g., manufacturing of glass, cement, and the like). The system advantageously comprises using carbonate looping to facilitate pre-combustion carbon dioxide capture. The system advantageously combines carbonate looping with the use of a syngas stream that is generated without the use of an energy intensive air separation unit. In an exemplary embodiment, a carbonaceous combustible fluid (fuel) is first reformed into syngas in a water shift reactor. Carbon dioxide produced as a byproduct in the water gas shift reactor is then charged to a carbonate looping process where it is reacted with a metal oxide to produce a metal carbonate. The metal carbonate is then reduced in a calciner back to the metal oxide. Carbon dioxide released from the metal oxide in the calciner is captured and sequestered or used for another purpose without being released to the atmosphere. The syngas is then combusted in a combustor to produce steam. Steam generated in the combustor in used in a turbine to generate electricity. This approach reduces the energy penalty associated with the use of wet chemistry post-combustion capture or the use of pre-combustion capture.

This system is advantageous in that the relatively high carbon dioxide concentration in the syngas stream lends itself to more efficient capture. In addition, carbon dioxide is removed from the process using dry chemistry thus eliminating the costs associated with wet chemistry such as those costs associated recovering ammonia in a chilled ammonia process or with a solvent recovery process when an amine solvent is used to capture carbon dioxide.

The FIG. 1 displays a system 100 for facilitating capture of carbon dioxide. The system 100 comprises a compressor 102. A premixer 104, a partial oxidation chamber 106, a water shift reactor 108, a carbonator 110 and a calciner 112 are located successively downstream of the compressor 102 and are in fluid communication with one another and with the compressor 102. A combustor 120 lies downstream of the carbonator 110 and is in fluid communication with it. The combustor 120 receives hydrogen from the calciner 112 and combusts it to generate steam. The combustor 120 can be a single combustor or a reheat combustor type. The steam generated in the combustor 120 is discharged to a turbine 122 where it is used to generate electrical energy by driving an electrical motor M or a generator G. The turbine 122 is coaxially mounted with the compressor 102 and is in mechanical communication with it. A heat recovery steam generator 124 lies downstream of the turbine 122.

With reference now once again to the FIG. 1, the compressor 102 is operative to compress air prior to discharging it to a premixer 104 where it is premixed with a carbonaceous combustible fluid (fuel). The air is compressed in the compressor to a pressure of about 10 to about 40 kilograms per square centimeters. The compressed air stream 103 emanating from the compressor 102 is about 300 to about 700° C.

A fuel is introduced into the premixer 104 where it is mixed with air. The fuel may comprise any carbonaceous combustible fluid. Examples of fuel are methane (also referred to as natural gas), ethane, propane, ethylene, acetylene, gasoline, diesel, liquefied coal, and the like. An exemplary fuel for used in the system 100 is natural gas.

The air-fuel stream 105 containing a sub-stoichiometric mixture of air and fuel in a weight ratio of about 4 to about 20 is then discharged to the partial oxidation (PDX) chamber 106 at a pressure of about 9 to about 40 kilograms per square centimeters and a temperature of about 400 to about 1200° C.

Partial oxidation (PDX) of the sub-stoichiometric fuel-air mixture occurs in the partial oxidation chamber 106, creating a hydrogen-rich syngas. The reaction occurring in the partial oxidation chamber is as follows:

CH₄+½O₂ - - - >CO+2H₂

Some carbon dioxide and water vapor is also formed during the reaction. The mixture of carbon monoxide and hydrogen 107 from the partial oxidation chamber 106 is then discharged to the water shift reactor 108, where additional carbon monoxide is transformed into carbon dioxide. In the water shift reactor 108, steam is injected to react with the carbon monoxide to transform it to carbon dioxide. In one embodiment, the partial oxidation chamber 106 may be designed such that the steam reforming i.e., the steam reforming using water generated during the partial oxidation automatically occurs neat the exit of the reactor thereby obviating the need for steam injection into the water shift reactor 108.

CO+H₂O - - - >CO₂+H₂

The hydrogen along with the carbon dioxide from the water shift reactor 108 is then discharged into the carbonator 110 via stream 109. In the carbonator 110, a metal oxide reacts with the carbon dioxide present in the syngas to form a metal carbonate. The metal carbonate is then directed to a calciner 112 via stream 111. The hydrogen left in the carbonator is discharged to a combustor 120 where it undergoes combustion with oxygen present in compressed air received from the compressor.

In the calciner 112, the metal carbonate is decomposed to form the metal oxide and carbon dioxide. The metal oxide is returned to the carbonator by stream 113 via a heat exchanger 126, where it is cooled down to the temperature used in the carbonator 110. Suitable metal oxides for use in the carbonator are alkaline earth metal oxides and alkali metal oxides. An exemplary metal oxide is calcium oxide. When the metal oxide is calcium oxide, the calcium oxide reacts with carbon dioxide to form calcium carbonate as seen in the equation below.

CaO+CO₂ - - - >CaCO₃

In one embodiment, in one exemplary method of operating the carbonator 110, the stream 109 comprising hydrogen and carbon dioxide is discharged into the carbonator 110. The process parameters of the process chain described herein depends upon the type of the combustor and the gas turbine, namely on the pressure and temperature of the compressed air from the compressor to the partial oxidation chamber. It is desirable to maintain the hydrogen and carbon dioxide produced in the water gas shift reactor 108 at a suitable pressure for the injection into the combustor 120. For this reason, the pressure in the carbonator 110 is about 16 kilograms per square centimeter to about 34 kilograms per square centimeter while the temperature is about 600 to about 1200° C. depending upon the application.

In one embodiment, when natural gas is used as the fuel, the temperature in the carbonator 110 is about 650 to about 700° C., specifically about 650° C. At this temperature, the calcium oxide reacts with the carbon dioxide to form calcium carbonate. The calcium carbonate is then discharged to the calciner 112, where additional fuel and oxygen are introduced to calcine the calcium carbonate at a temperature of about 875 to about 950° C., specifically about 900° C.

The solid particle stream of calcium carbonate is moved to the calciner 112 using the driving force of the pressure differential between the carbonator 110 and the calciner 112. In an exemplary embodiment, the process is controlled mainly by a drop in pressure between the carbonator and the calciner. The carbonator 110 generally operates at a higher pressure than the calciner 112. FIG. 2 shows the difference in pressure between the carbonation of calcium oxide in the carbonator and the calcination 110 of the calcium oxide in the calciner 112. At the temperature of the reaction respectively in the carbonator (923 degrees Kelvin) and the calciner (1073 degrees Kelvin) it can be seen that the pressure in the carbonator 110 is much higher than the pressure in the calciner 112. This pressure differential can be used to drive the transfer of material from the carbonator 110 to the calciner 112.

In addition, by conducting the reaction at a pressure of 10 kilograms per square centimeter and 40 kilograms per square centimeter between the upper curve (or FIG. 2) above which only calcium hydroxide is formed and the lower curve below which calcium oxide is formed, one can produce both calcium hydroxide and calcium oxide. By operating between the two curves, both calcium hydroxide and calcium oxide are produced. This is beneficial in that there is a continuous supply of fresh calcium oxide derived from the calcium hydroxide (as a result of the reaction shown above the upper curve). The calcium oxide thus does not undergo sintering over time and become poisoned. It continues to be freshly regenerated with a high surface area and can thus facilitate the absorption of carbon dioxide from the flue gas stream over extended periods of time.

This pressure differential is therefore beneficial to the lifecycle of the metal oxide/metal carbonate used in the method described herein. The reduced pressure reduces the effect of usage at such high temperatures on the structure and surface area of the calcium oxide and the calcium carbonate. The pressure differential prevents the reduction in surface area of the calcium oxide and the calcium carbonate. Retention of surface area helps retain the contact area between the carbon dioxide gas and the calcium oxide, which helps maintain the amount of carbon dioxide absorbed by a unit weight of the calcium oxide. In addition, the formation of calcium hydroxide in the carbonator has a positive influence on the reactivity lifetime of the metal oxide and the kinetics of the cycling process.

Optionally the energy due to this pressure drop may be recovered for use in another device (e.g., an expander for fluids). In one embodiment, a specific throttling device (not shown) may be used to control the flow of calcium carbonate to the calciner 112. In another embodiment, the solid particles are moved from the calciner 112 to the carbonator 110 using a pump (not shown).

The reaction in the carbonator 110 is highly exothermic and generates a lot of heat. In order to maintain the temperature of the carbonator so that the reaction to absorb carbon dioxide can be effectively controlled, the additional heat generated by the exotherm is optionally recovered in a heat exchanger 116 and used for generating additional steam that is used in heat recovery steam generator 124 or used to preheat the fuel and oxygen used for the calcination process (in the calciner 112) thereby reducing the amount of fuel and oxygen used for the process of calcination.

This method is advantageous in that it does not require the use an air separation unit (ASU). In comparative processes where the capture of carbon dioxide is not driven by a fuel that includes syngas, the calcium carbonate is converted to calcium oxide by means of a highly endothermic reaction that uses a significant fuel input that would have to be oxidized by oxygen rather than air, thereby necessitating the use of an air separation unit which complicates the whole system and increases auxiliary power consumption.

The carbon dioxide stream 117 generated in the calciner 112 is then discharged to the cooler 114. Since the carbon dioxide stream leaves the calciner 112 at an elevated temperature of about 875 to about 950° C., the heat recovered from the carbon dioxide stream 117 in the cooler 114 may also be used in the heat recovery steam generator 124 or used to preheat the fuel and oxygen used for the calcination process (in the calciner 112). The carbon dioxide stream 119 emanating from the cooler may optionally directed to a separation device 118 where carbon dioxide is separated from hydrogen. The recovered hydrogen may be used in other combustion processes. In one embodiment depicted in the FIG. 1, the recovered hydrogen may be combined with hydrogen generated in the carbonator 110 and sent to the combustor. The carbon dioxide stream (now devoid of hydrogen) may be sequestered after pressurization to the appropriate sequestration conditions.

As detailed above, the hydrogen stream 115 emanating from the carbonator 110 is then discharged to the combustor 120 for combustion. Steam is generated as a result of this combustion according to the equation

2H₂+O₂ - - - >2H₂O

Steam generated in the combustor 120 from the combustion of the syngas stream 115 may be used to drive the gas turbine 122. In one embodiment, additional natural gas may also be injected into the combustor 120 in case it is desirable for flame stability or for emissions control.

In one embodiment, in the event that the pressure developed in the compressor 102 is not enough to achieve the desired reaction kinetics as a result of the pressure variation between the carbonator 110 and the calciner 112, then optionally a temperature increase in the calciner 112 can be used to further control the process or to further optimize the global plant performance. The temperature in the calciner may be increased by an amount of 50 to about 400° C. from the operating temperature of about 875 to about 950° C.

In one embodiment, if it is desired to increase the temperature of the calciner 112, different types of alternative fuels can be used in the calciner (e.g., coal, natural gas, biomass). Additional oxygen is also added to the calciner 112 to facilitate combustion of the alternative fuels which then leads to an increase in the temperature in the calciner 112. The oxygen may be increased by an amount of about 5 to about 75 wt % over a process where there is no need to increase the temperature of the process because the pressure variation facilitates the desired reaction kinetics in the carbonator 110 and the calciner 112.

When oxygen and alternative fuels are used in the calciner 112, the calciner 112 may produce solid residues (e.g., ash mixed with calcium oxide fines in case it is fired with biomass or coal or CaO fines only when it is fired natural gas) that can be reused in other industrial applications such as in the manufacturing of cement.

In another embodiment, only additional oxygen can also be added independently to the calciner to oxidize hydrogen, methane or carbon monoxide that can enter the calciner 112 via the calcium carbonate particle streams that are discharged from the carbonator 110. The addition of oxygen also increases the temperature in the calciner 112 that improves the efficiency of the regeneration process in the calciner 112.

In another embodiment, the leaked hydrogen, methane and carbon monoxide from the carbonator 110 can be separated and possibly recovered downstream of the calcinator 112 via specific system, (e.g., non selective membrane) or directly at the carbon dioxide compression and treatment stage. The fuel recovered can then used in the combustor 120 during combustion.

The flue gas stream generated in the combustor 120 is directed to a heat recover steam generator 124 where heat recovered from the steam may be used in a wet steam cycle. The flue gases now devoid of carbon dioxide may be directed to a stack following the removal of nitrogen oxides, sulfur oxides, and the like.

The process parameters of the process chain described above depends upon the type of the combustor and the gas turbine, namely on the pressure and temperature of the extraction from air from the compressor to the partial oxidation chamber. It is desirable to maintain the syngas produced at a suitable pressure for the injection into the combustor. For this reason, the pressure in the carbonator 110 is about 16 kilograms per square centimeters to about 34 kilograms per square centimeters while the temperature is about 600 to about 1200° C. depending upon the application.

Although the present descriptions and diagrams depict various embodiments, the principles disclosed herein can be used in any method or process that includes dry chemistry. In particular, the method can be applied to any other system where carbon dioxide is captured from a gas phase bound to a solid material that operates in a similar cycling pattern and where the solid adsorbent or absorbent is preferably introduced into the cycle as a powder or as small particles. Powder or small particles offer the advantage of increasing contact area, which increases the gas to solid mass transfer rate and thus reduce the reaction time.

It will be understood that, although the terms “first,” “second,” “third” etc. may be used herein to describe various elements, components, regions, layers and/or sections, these elements, components, regions, layers and/or sections should not be limited by these terms. These terms are only used to distinguish one element, component, region, layer or section from another element, component, region, layer or section. Thus, “a first element,” “component,” “region,” “layer” or “section” discussed below could be termed a second element, component, region, layer or section without departing from the teachings herein.

The terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting. As used herein, the singular forms “a,” “an” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise. It will be further understood that the terms “comprises” and/or “comprising,” or “includes” and/or “including” when used in this specification, specify the presence of stated features, regions, integers, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, regions, integers, steps, operations, elements, components, and/or groups thereof.

Furthermore, relative terms, such as “lower” or “bottom” and “upper” or “top,” may be used herein to describe one element's relationship to another elements as illustrated in the Figures. It will be understood that relative terms are intended to encompass different orientations of the device in addition to the orientation depicted in the Figures. For example, if the device in one of the figures is turned over, elements described as being on the “lower” side of other elements would then be oriented on “upper” sides of the other elements. The exemplary term “lower,” can therefore, encompasses both an orientation of “lower” and “upper,” depending on the particular orientation of the figure. Similarly, if the device in one of the figures is turned over, elements described as “below” or “beneath” other elements would then be oriented “above” the other elements. The exemplary terms “below” or “beneath” can, therefore, encompass both an orientation of above and below.

Unless otherwise defined, all terms (including technical and scientific terms) used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this disclosure belongs. It will be further understood that terms, such as those defined in commonly used dictionaries, should be interpreted as having a meaning that is consistent with their meaning in the context of the relevant art and the present disclosure, and will not be interpreted in an idealized or overly formal sense unless expressly so defined herein.

Exemplary embodiments are described herein with reference to cross section illustrations that are schematic illustrations of idealized embodiments. As such, variations from the shapes of the illustrations as a result, for example, of manufacturing techniques and/or tolerances, are to be expected. Thus, embodiments described herein should not be construed as limited to the particular shapes of regions as illustrated herein but are to include deviations in shapes that result, for example, from manufacturing. For example, a region illustrated or described as flat may, typically, have rough and/or nonlinear features. Moreover, sharp angles that are illustrated may be rounded. Thus, the regions illustrated in the figures are schematic in nature and their shapes are not intended to illustrate the precise shape of a region and are not intended to limit the scope of the present claims.

The term and/or is used herein to mean both “and” as well as “or”. For example, “A and/or B” is construed to mean A, B or A and B.

The transition term “comprising” is inclusive of the transition terms “consisting essentially of” and “consisting of” and can be interchanged for “comprising”.

While this disclosure describes exemplary embodiments, it will be understood by those skilled in the art that various changes can be made and equivalents can be substituted for elements thereof without departing from the scope of the disclosed embodiments. In addition, many modifications can be made to adapt a particular situation or material to the teachings of this disclosure without departing from the essential scope thereof. Therefore, it is intended that this disclosure not be limited to the particular embodiment disclosed as the best mode contemplated for carrying out this disclosure.

Claims

1. A system comprising:

a compressor in mechanical communication with a turbine; the compressor being operative to produce compressed air;

a premixer; the premixer being operative to mix a fuel with the compressed air;

a carbonator being located downstream of the premixer; the carbonator being operative to receive a mixture of carbon dioxide and syngas and to convert a metal oxide into a metal carbonate by reacting it with the carbon dioxide;

a calciner; the calciner being operative to receive the metal carbonate from the carbonator; and to dissociate carbon dioxide from the metal carbonate; and

a combustor; the combustor being located downstream of the carbonator; where the combustor is operative to combust syngas received from the carbonator.

2. The system of claim 1, where the combustor produces steam that is discharged to the turbine.

3. The system of claim 1, where the carbon dioxide dissociated in the calciner is sequestered.

4. The system of claim 3, where the carbon dioxide is cooled prior to being sequestered.

5. The system of claim 2, where the steam is discharged to a heat recovery steam generator after being discharged from the turbine.

6. The system of claim 1, further comprising a partial oxidation chamber located downstream of the premixer; where the partial oxidation chamber is operative to partially oxidize the fuel received from the premixer to create syngas.

7. The system of claim 1, where the fuel comprises natural gas.

8. The system of claim 1, further comprising a water gas shift reactor disposed downstream of the premixer; the water gas shift reactor being operative to reform the syngas to carbon dioxide and hydrogen.

9. The system of claim 1, where partial oxidation of the fuel, reformation of fuel and the carbonation are all performed in the carbonator.

10. The system of claim 1, where partial oxidation of the fuel and the carbonation are all performed in the carbonator.

11. The system of claim 1, where reformation of fuel and the carbonation are all performed in the carbonator.

12. The system of claim 1, where a pressure in the carbonator is greater than a pressure in the calciner.

13. The system of claim 1, where a pressure in the carbonator is about 16 kilograms per square centimeter to about 34 kilograms per square centimeter and a temperature is about 600 to about 1200° C.

14. The system of claim 1, where flue gases devoid of carbon dioxide are discharged from a heat recovery generator to a stack.

15. A method comprising:

discharging a mixture of compressed air and fuel to a partial oxidation chamber;

partially oxidizing the fuel to produce syngas and carbon dioxide;

reacting a metal oxide with the carbon dioxide in a carbonator to produce a metal carbonate;

calcining the metal carbonate in a calciner to produce carbon dioxide and the metal oxide;

recycling the metal oxide to the carbonator from the calciner;

sequestering the carbon dioxide; and

combusting the syngas in a combustor to generate steam.

16. The method of claim 15, further comprising discharging the steam to a turbine.

17. The method of claim 15, further comprising cooling the carbon dioxide in a heat exchanger and using water from the heat exchanger in a heat recovery steam generator.

18. The method of claim 15, further comprising using steam to reform the syngas (CO+H2) in a water gas shift reactor into CO2+H2.

19. The method of claim 15, further comprising supplying the combustor with additional fuel.

20. The method of claim 15, where the fuel is natural gas.