Apparatus and process for separating CO2 from a flue gas

Abstract

An apparatus and a process for separating carbon dioxide from a flue gas of a coal burning power plant. The process includes compressing the flue gas to increase the pressure and temperature, and then passing the flue gas through a cryogenic heat exchanger that decreases the temperature even more prior to passing the cooled carbon dioxide through a turbine that decreases the temperature more and forms liquid and solid forms carbon dioxide. A carbon dioxide separator then separates the carbon dioxide from the flue gas, leaving both liquid and solids forms. A screw compressor compresses the solid carbon dioxide to produce only liquid carbon dioxide at a pressure suitable for sequestration. The liquid carbon dioxide is passed through the heat exchanger to cool the flue gas and to separate out any sulfur dioxide and water from the flue gas and to vaporize the liquid carbon dioxide prior to sequestration of the vapor carbon dioxide.

Description

GOVERNMENT LICENSE RIGHTS

None.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit to a Provisional Patent Application 61/178,737 filed on May 15, 2009 and entitled APPARATUS AND PROCESS FOR SEPARATING CO₂ FROM A FLUE GAS.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates generally to a coal or bio-mass burning power plant, and more specifically to process and apparatus for separating and sequestering CO₂ emissions.

2. Description of the Related Art Including Information Disclosed Under 37 CFR 1.97 and 1.98

In coal-based or bio-mass power generation, pulverized coal (PC) is bio-mass is the primary generating technology for combustion. PC combustion technology continues to undergo technological improvements that increase efficiency and reduce emissions. Carbon dioxide (CO₂) capture and sequestration in coal-based power generation is an important emerging option for managing carbon dioxide emissions while meeting growing electricity demand.

Most of the coal-based generating units in the US are between 25 and 55 years old with an average generating efficiency of about 33% and some of the newer generating units at about 36% efficiency. The fraction of the thermal energy in the fuel that ends up in the net electricity produced is the generating efficiency of the unit. Increased generating efficiency is important, since it translates directly into lower criteria pollutant emissions and lower carbon dioxide emissions per kW-hr of electricity generated.

FIG. 1 shows a prior art sub-critical pulverized coal unit without CO₂ capture. In a pulverized coal unit, the coal is ground to talcum-powder fineness, and injected through burners into the furnace with combustion air. The fine coal particles heat up rapidly, undergo pyrolysis and ignite. The bulk of the combustion air is then mixed into the flame to completely burn the coal char. The flue gas from the boiler passes through the flue gas clean-up units to remove particulates that include SO_x and NO_x. The flue gas exiting the clean-up section meets criteria pollutant permit requirements, typically contains 10-15% CO₂ and is essentially at atmospheric pressure.

FIG. 2 shows a prior art sub-critical pulverized coal unit with CO₂ capture. CO₂ capture with PC combustion generation involves CO₂ separation and recovery from the flue gas, at low concentration and low partial pressure. The processes for separation include chemical absorption with amines, such as monoethanolamine (MEA) or hindered amines, which is the commercial process of choice. Chemical absorption offers high capture efficiency and selectivity for air-blown units and can be used with sub-, super-, and ultra-supercritical generation for a sub-critical PC unit. The CO₂ is first captured from the flue gas stream by absorption into an amine solution in an absorption tower. The absorbed CO₂ must then be stripped from the amine solution via a temperature increase, regenerating the solution for recycle to the absorption tower. The recovered CO₂ is cooled, dried, and compressed to a supercritical fluid. It is then ready to be piped to storage.

CO₂ removal from the flue gas requires energy, primarily in the form of low-pressure steam for the regeneration of the amine solution. This reduces steam to the turbine and the net power output of the generating plant. Thus, to maintain constant net power generation the coal input must be increased, as well as the size of the boiler, the steam turbine/generator, and the equipment for flue gas clean-up. Absorption solutions that have high CO₂ binding energy are required by the low concentration of CO₂ in the flue gas, and the energy requirements for regeneration are high.

A sub-critical PC unit with CO₂ capture shown in FIG. 2 that produces 500 MWe net power requires a 37% increase in plant size and in coal feed rate compared to the non-capture unit of FIG. 1 with the same power output. The generating efficiency is reduced from 34.3% to 25.1%. The internal power requirement for CO₂ capture and recovery is equivalent to almost 130 MWe, most of which is in the form of the low-pressure steam required to recover the absorbed CO₂ from the amine solution. Compression of the CO₂ consumes 70 MWe. All associated equipment is also effectively 37% larger. The process technology added for the capture and recovery of CO₂ effectively removes most of the SO₂ and PM that are not removed earlier in the flue-gas train so that their emissions are now extremely low, an added benefit of CO₂ capture. The primary factors in efficiency reduction associated with addition of CO₂ capture are: the thermal energy required recover CO₂ from the amine solution reduces the efficiency by 5%; the energy required to compress the CO₂ from 0.1 MPa to about 15 MPa is the next largest factor, reducing the efficiency by 3.5%; and other energy requirements amount to less than 1%.

BRIEF SUMMARY OF THE INVENTION

A coal fired power plant and a process to remove CO₂ from the flue gas of a coal fired power plant. The flue gas from the power plant is compressed to increase the pressure and the temperature. The compressed flue gas is then cooled and passing the flue gas through a heat exchanger to separate out any H₂O and SO₂ from the flue gas. The cooled flue gas is then passed through a turbine that drives an electric generator where the flue gas is further cooled to produce liquid and solid CO₂, which is then passed through a separator that separates the liquid and solid CO₂ from the flue gas. The separated liquid and solid CO₂ is then passed into a screw compressor that liquefies the solid CO₂ to produce all liquid CO₂ which is then passed through the heat exchanger to cool the flue gas further. The flue gas with little CO₂ remaining is then passed through the heat exchanger and discharged to atmosphere. The compressed liquid CO₂ that passes

In another embodiment, the carbon dioxide separation occurs in a separate carbon dioxide separator unit located downstream from the turbine and upstream from the heat exchanger. In another embodiment, the carbon dioxide separator is also the heat exchanger. In another embodiment, a second heat exchanger is located between the compressor and the first heat exchanger to cool the compressed flue gas entering the first heat exchanger and heat the flue gas exiting from the first heat exchanger in which the flue gas is then used to drive a second turbine.

To prevent carbon dioxide ice from forming on the turbine, the turbine is heated by passing a heating fluid such as compressed air through the turbine or using electric heating elements.

BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS

FIG. 1 shows a diagram of a prior art sub-critical pulverized coal unit without CO₂ capture.

FIG. 2 shows a diagram of a prior art sub-critical pulverized coal unit with CO₂ capture

FIG. 3 shows a diagram cross section of a first embodiment of the CO₂ separation system of the present invention.

FIG. 4 shows a diagram cross section of a second embodiment of the CO₂ separation system of the present invention.

FIG. 5 shows a diagram cross section of a third embodiment of the CO₂ separation system of the present invention.

DETAILED DESCRIPTION OF THE INVENTION

The apparatus and process for separating the CO₂ from a flue gas of a coal burning power plant is shown in FIGS. 3 through 5. The embodiment of FIG. 3 shows a flue gas 11 from the coal burning power plant entering an ambient air fan cooler 12 that separates water from the flue gas at a rate of 55 kg/sec and then passes the remaining flue gas at 36 degrees C. into an air conditioning unit 13 that separates more water at a rate of 23 kg/sec. for this example, the flue gas flow rate is at 768 kg/s for an 81 MW power plant. The flue gas exiting the air conditioning unit is at 6 degrees C. and then enters a compressor 14 that discharges the remaining flue gas at a pressure ratio of 4 with a temperature of 153 degrees C. From the compressor 14, the flue gas enters an ambient air cooler 15 and exits at 36 degrees C. The flue gas then enters a heat exchanger 16 that is used to cool the flue gas and separate out H₂O and SO₂ and other contaminants from the flue gas 11. The heat exchangers used in the CO₂ separator process can be iron based with a Tanalum coating. The numbers described for amounts of material flow or temperatures can vary based on the size of the power plant and other factors. The numbers cites are for a power plant of the range of 81 MW.

The flue gas exiting the heat exchanger 16 at 160 degrees K (−113 C) and at 685 kg/sec flows into a turbine 17 that form liquid and solid CO₂ from the flue gas 11. The turbine 17 is used to drive an electric generator and produce electric power. As the flue gas 11 passes through the turbine 17, the temperature of the flue gas drops considerably. To prevent the CO₂ solid ice from sticking onto the turbine parts such as the blades and vanes, heat is added to the turbine such as by a compressed air (heated air due to the compression process) that is passed through the turbine components to heat up the parts so that the CO₂ ice will not stick to the turbine parts. Thus, the turbine 17 is heated instead of cooled as in the prior art gas turbine engines. The flue gas 11 then exits the turbine 17 at 160 degrees K and enters a CO₂ particle separator 18 and then flows into the heat exchanger 16 to receive heat from the first pass-through flue gas 11 that enters the heat exchanger 16 from the compressor 14. As the CO₂ turns to ice, it will stick to the turbine parts and walls. If the parts can be heated to above 220 degrees K, then the CO₂ will not stick to the parts. The compressed air used to heat the turbine parts can be compressed flue gas. The turbine parts can also be heated using electrical heating elements in which an electric current is passed through the parts to produce the required heat. The turbine 17 is also connected to an electric generator for the production of electrical energy.

The CO₂ from the CO₂ particle separator 18 is both in a solid and a liquid form and is converted into an all liquid form in a screw compressor 19 to 2200 psi and where the liquid CO₂ then flows through the heat exchanger 16 to draw heat from the first and second pass-through flue gas passages within the heat exchanger 16. The CO₂ that exits the heat exchanger 16 is at 2200 psi but in a vapor form and flows at a rate of 102 kg/sec and is ready to be discharged into a storage location for sequestration.

In the embodiment of FIG. 3, the first pass-through flue gas 11 from the compressor 14 is cooled by the passages of the second pass-thorough flue gas and the liquid CO₂ passage that then separates from the first pass-through flue gas the H₂O and SO₂ and other contaminants. The second pass-through flue gas 11 has passed through the CO₂ particle separator 18 and contains only around 10% of the CO₂ from the original flue gas flow which can then be discharged to the atmosphere. The screw compressor 19 liquefies the solid CO₂ and pressurizes the liquid CO₂ to a pressure required for sequestration. In the example of the first embodiment, the power plant size is around 81 Mw with a flue gas flow of around 768 kg/s. however, the present invention is not limited to this size and flow rate in order to separate out the CO₂ from the flue gas using the same process but at different flow rates.

A second embodiment shown in FIG. 4 is similar to that in the first embodiment of FIG. 3 but without the air conditioning unit 13 upstream of the compressor 14, and with the addition of a feedwater heater 21 in-between the compressor 14 outlet and the ambient air cooler 15 that is upstream of the heat exchanger 16. The feed-water heater 21 is used to heat water. As in the FIG. 1 embodiment, the liquid and solid CO₂ making turbine 17 is heated to prevent the ice from building up on the turbine parts such as the blades, vanes and inner shrouds. The heat exchanger 16 in the FIG. 4 embodiment works that same as in the FIG. 1 embodiment. Also, the screw compressor functions the same as in the FIG. 1 embodiment. The heat exchanger 16 separates the SO₂ and H₂O and other impurities from the first pass-through flue gas while cooling the first pass-through flue gas. The compressed liquid CO₂ from the screw compressor 19 draws heat away from both the first pass-through and second pass-through flue gas flows. The vaporized liquid CO₂ that exits the heat exchanger is at the required pressure for sequestration.

FIG. 5 shows a third embodiment similar to the FIG. 3 embodiment, but with all or part of the CO₂ being condensed in the heat exchanger 16. The CO₂ particle separator 18 located downstream from the turbine 17 can be used to separate CO₂ from the flue gas as well as using the heat exchanger 16 to separate CO₂ from the flue gas from the first pass-through flue gas. In the FIG. 5 embodiment, some or all (if the CO₂ separator 18 downstream of the turbine 17 is not used) of the CO₂ is separated from the first pass-through flue gas 11 as well as the SO₂ and H₂O and other impurities. The liquid and solid CO₂ separated in the first pass-through flue gas in the heat exchanger 16, along with the SO₂ and H₂O and other impurities, is all passed into the screw compressor 19 and pressurized to liquefy the solid CO₂ and to pressurize the liquid CO₂ to the required pressure for sequestration. The liquid CO₂ (with the SO₂ and H₂O and other impurities) is vaporized as they pass throw the heat exchanger and exits as a vapor but at the high pressure required for sequestration.

If the CO₂ particle separator 18 is used, any left-over solid and liquid CO2 from the first pass-through flue gas in the heat exchanger 16 is passed through the turbine 17 to form solid and liquid CO₂ is passed into the separator 18. The liquid and solid CO₂ from the separator 18 is then merged with the liquid and solid CO₂ from the heat exchanger 16 and passed into the screw compressor 19. The screw compressor then liquefies the solid CO₂ to form all liquid CO₂ with the required pressure for sequestration. The second pass-through flue gas 11 from the turbine 17 is then discharged out to atmosphere as relatively clean flue gas with only about 10% of the original CO₂ remaining. The pressurized and liquid CO₂ from the screw compressor 19 that is passed through the heat exchanger 16 includes the SO₂ and H₂O and other impurities as well as the CO₂ to be sequestered together. The CO₂ containing fluid exiting the heat exchanger is a vapor but still at the high pressure for sequestration.

In the FIG. 5 embodiment, the second pass-through flue gas 11 discharged from the heat exchanger 16 is passed through a second heat exchanger 22 that cools the flue gas before is passes into the heat exchanger 16 as the first pass-through flue gas. The second pass-through flue gas then exits the second heat exchanger 22 and enters of second turbine 23 where the pressure is decreased before being discharged to the atmosphere as relatively clean flue gas. The second turbine 23 is used to drive an electric generator for electric power production.

In each of the three embodiments for separating CO₂ from a flue gas described above, a cryogenic air separation process is used to separate most of the CO₂ as a liquid (or a gas) that can then be delivered to a storage system such as an in-ground sequestration apparatus. In the cryogenic process to separate the CO₂ from the flue gas, the flue gas is cooled to a low enough temperature so that the carbon dioxide will freeze out onto the walls of the heat exchanger air passages.

Claims

1. An apparatus to separate carbon dioxide from a flue gas of a power plant comprising:

a compressor to increase a pressure and a temperature of the flue gas;

an air cooler means located downstream from the compressor to cool the flue gas from the compressor;

a heat exchanger located downstream from the air cooler means to cool the flue gas exiting from the air cooler means and separate sulfur dioxide from the flue gas;

a turbine located downstream from the heat exchanger to form a liquid and a solid form of carbon dioxide from the flue gas;

a carbon dioxide separator means located downstream from the turbine to separate carbon dioxide from the flue gas from the turbine;

a screw compressor to liquefy the solid form of carbon dioxide from the carbon dioxide separator means and pass the liquid carbon dioxide through the heat exchanger to covert the liquid carbon dioxide into a vapor and cool the flue gas passing through the heat exchanger; and,

the flue gas from the carbon dioxide separator being passed through the heat exchanger to add heat to the liquid carbon dioxide from the screw compressor.

2. The apparatus to separate carbon dioxide from a flue gas of claim 1, and further comprising:

the air cooler means is an air cooler fan.

3. The apparatus to separate carbon dioxide from a flue gas of claim 1, and further comprising:

the air cooler means is a feed water heater with an air cooler fan located downstream from the feed water heater.

4. The apparatus to separate carbon dioxide from a flue gas of claim 1, and further comprising:

the air cooler means is a second heat exchanger that also heats up the flue gas from the first heat exchanger; and,

a second turbine to pass the flue gas from the first heat exchanger and drive an electric generator.

5. The apparatus to separate carbon dioxide from a flue gas of claim 1, and further comprising:

the carbon dioxide separator means includes a carbon dioxide separator located between the turbine and the heat exchanger.

6. The apparatus to separate carbon dioxide from a flue gas of claim 5, and further comprising:

the turbine located between the heat exchanger and the carbon dioxide separator means includes means to heat the turbine so that solid carbon dioxide does not form on the turbine.

7. The apparatus to separate carbon dioxide from a flue gas of claim 6, and further comprising:

the means to heat the turbine includes a passage formed within the turbine to pass a heated fluid.

8. The apparatus to separate carbon dioxide from a flue gas of claim 6, and further comprising:

the means to heat the turbine includes an electric heating element within the turbine.

9. The apparatus to separate carbon dioxide from a flue gas of claim 1, and further comprising:

the carbon dioxide separator means includes the heat exchanger with solid and liquid carbon dioxide from the heat exchanger passed into the screw compressor; and,

the liquid carbon dioxide from the screw compressor passed through the heat exchanger to convert the liquid carbon dioxide into a lapor.

10. The apparatus to separate carbon dioxide from a flue gas of claim 1, and further comprising:

the turbine located between the heat exchanger and the carbon dioxide separator drives an electric generator.

11. The apparatus to separate carbon dioxide from a flue gas of claim 1, and further comprising:

the heat exchanger is a cryogenic heat exchanger.

12. A process for separating carbon dioxide from a flue gas of a power plant, the process comprising the steps of:

increasing the pressure and the temperature of the flue gas;

cooling the flue gas without decreasing the pressure of the flue gas;

passing the flue gas through a heat exchanger to cool the flue gas and to separate water and sulfur dioxide from the flue gas;

passing the pressurized flue gas from the heat exchanger through a turbine to produce solid and liquid forms of carbon dioxide;

separating the solid and liquid forms of carbon dioxide from the flue gas;

increasing the pressure of the solid and liquid forms of carbon dioxide to eliminate the solid form of carbon dioxide and produce an all liquid form carbon dioxide and to a pressure suitable for sequestration of the carbon dioxide; and,

passing the pressurized and liquid form of carbon dioxide through the heat exchanger to cool the flue gas and convert the liquid carbon dioxide into a vapor.

13. The process for separating carbon dioxide of claim 12, and further comprising the step of:

heating the turbine to prevent carbon dioxide ice for forming within the turbine.

14. The process for separating carbon dioxide of claim 12, and further comprising the step of:

prior to passing the compressed flue gas through the first heat exchanger, passing the compressed flue gas through a second heat exchanger to heat the flue gas exiting from the first heat exchanger and drive a second turbine.

15. The process for separating carbon dioxide of claim 12, and further comprising the step of:

separating the solid and liquid forms of carbon dioxide from the flue gas exiting from the turbine and increasing the pressure of the solid and liquid forms of carbon dioxide to eliminate the solid carbon dioxide prior to passing the liquid carbon dioxide through the heat exchanger.

16. The process for separating carbon dioxide of claim 12, and further comprising the steps of:

separating the carbon dioxide from the flue gas in the heat exchanger to form a first flow of carbon dioxide and then in a second carbon dioxide separator after passing the flue gas through the turbine to form a second flow of carbon dioxide; and,

combining the two flows of carbon dioxide and pressurizing the carbon dioxide to form only liquid carbon dioxide to pass through the heat exchanger at a pressure suitable for sequestration.