WO2009003238A1

WO2009003238A1 - Improvements in the recovery of carbon dioxide

Info

Publication number: WO2009003238A1
Application number: PCT/AU2008/000977
Authority: WO
Inventors: Douglas James PALFREYMAN; Donald Ray Cummings
Original assignee: Dut Pty Ltd
Priority date: 2007-07-03
Filing date: 2008-07-03
Publication date: 2009-01-08

Abstract

A process for removing the carbon dioxide from a flue gas exiting from a fossil fuel combustion reaction, wherein the process includes the following steps: a. cooling the flue gas to below 50°C by directly contacting the flue gas with a counter current stream of liquid water; and, b. removing the carbon dioxide from the flue gas by directly contacting the flue gas with a scrubbing agent.

Description

IMPROVEMENTS IN THE RECOVERY OF CARBON DIOXIDE

The present invention relates to a process for removing carbon dioxide from a flue gas exiting from a fossil fuel combustion reaction.

Background of the Invention

Whilst it may be desirable for the purposes of reducing carbon dioxide emissions to physically remove carbon dioxide from the flue gases leaving existing coal-fired boilers and power plants, such an operation presents many problems and difficulties.

The flue gases often contain sulphur dioxide and trioxide with the latter readily producing sulphuric acid mist on cooling of the flue gas and the sulphur dioxide reacting with and destroying some of the known carbon dioxide scrubbing agents, particularly those based on alkali carbonates.

Other known scrubbing agents such as amines and the like react with oxygen contained in flue gases, degrading or destroying the scrubbing agents.

Low temperature scrubbing of the flue gas with solvents to remove carbon dioxide can be made very difficult due to the presence of large quantities of water vapour in the flue gases. In addition, there is the further major problem of producing the recovered carbon dioxide together with any impurities co-produced as pressurised liquid as required for ease of transport and compression for possible use, disposal or sequestration.

Current proposals for post capture of carbon dioxide from fossil fuel-fired power plants using amine-based scrubbing systems have the problem of oxygen promoted degradation of the amines. Sulphur oxides and nitrous oxides have also been found to react with and remove scrubbing agents such as carbonates and refrigerated ammonia

Existing processes for the post capture of carbon dioxide from existing coal-fired power plants are based on scrubbing operations being carried out at close to atmospheric pressure which has the consequent problems of requiring chemical reaction-based carbon dioxide removal solvents such as amines which have a high carbon dioxide carrying capacity at low pressure but which also require heat energy as a prime means for releasing the carbon dioxide. This also results designs for large boilers requiring very large scrubbing towers and connecting ducts and the problem of such units requiring large fans, gas stripping heaters and the like such that the parasitic load for such systems, which can be well in excess of 20% of the power rating of the boiler can result in a major reduction in available power which can be produced from the boiler when fitted with such a carbon dioxide removal system

Methanol is a solvent and therefore good scrubbing agent for carbon dioxide but if the methanol scrubbing is used to remove the carbon dioxide in the flue gas prior to it the flue gas being vented there is the problem of the possibility of methanol slippage into the vented flue gas.

A significant problem with possible Humidifed Air Turbine (HAT) cycles, including the Advanced Integrated Drying and Gasification (AIDG) cycle, is that it is not suited for use with standard commercial gas turbine systems in that the power which can be generated from the air When humidified can greatly exceed the rating of the expander stage and allied generator with this resulting in either having to significantly modify the turbine or the major problem of having to find an appropriate use for the surplus compressed air generated by the HAT-modified gas turbine..

Aqueous ammonia can also be used for removal of carbon dioxide from boiler flue gases but this system has some significant problems in that in order to minimise ammonia slippage, the amount of aqueous ammonia being circulated and the size of the scrubbing plant it is generally desirable to use chilled ammonia at temperatures about 0ºC and the use of heat exchangers and refrigeration plant to enable operation at such temperatures.

A further problem with ammonia is that it reacts with sulphur dioxide and nitrogen oxides requiring plant and equipment for the reactions and means to recover the resultant ammonium compound or compounds resulting from such reactions.

Accordingly the present invention seeks to provide a process which addresses at least some of the disadvantages of the current systems for the removal of carbon dioxide from fossil fuel combustion reactions.

Summary of the Invention

According to one aspect the present invention provides a process for removing the carbon dioxide from a flue gas exiting from a fossil fuel combustion reaction, wherein the process includes the following steps: a. cooling the flue gas to below 50ºC by directly contacting the flue gas with a counter current stream of liquid water; and, b. removing the carbon dioxide from the flue gas by directly contacting the flue gas with a scrubbing agent.

By contacting the flue gas directly with a counter current stream of liquid water, the water level in the flue gas as well as the temperature of the flue gas is greatly reduced.

According to one form the scrubbing agent is chosen from amines including aqueous monoethanol amine (MEA), diglycolamine (DGA), diethanolamine (DEA), diisopropanolamine (DIPA) and methyldiethanolamine (MDEA), methanol, and/or ammonia. According to a preferred form the scrubbing agent is chosen from methanol.

According to a further form, prior to step b. an alcohol having a higher volatility than water is added to the flue gas and the subsequent flue gas stream including the alcohol is further cooled by indirect heat exchange. In accordance with this form, the alcohol may be chosen from any alcohol with a higher volatility than water such as for example methanol or ethanol. In a preferred form, the alcohol is chosen from methanol. According to one form the flue gas stream including alcohol is further cooled by indirect heat exchange in a vertical reflux heat exchanger or a series of sequential heat exchangers. According to this form, liquid condensate is formed during the indirect heat exchange which includes water and alcohol. This condensate is removed from the flue gas stream as an outlet condensate stream from the indirect heat exchanger. In a preferred form, the liquid condensate is distilled to separate the alcohol from the water and recover the alcohol for recycling back into the process.

According to one form, step b. is carried out in a tray distillation column situated above the indirect heat exchanger wherein the flue gas including the alcohol passes from the indirect heat exchanger into the tray distillation column wherein the flue gas is directly contacted with the scrubbing agent.

According to another form, the flue gas is compressed in a compressor after step a. to between 5 and 30 atmospheres and preferably between 10 and 20 atmospheres.

According to a further form, the flue gas exiting step b. being stripped of carbon dioxide, is fed to a combustion stage and the resulting hot gas exiting the combustion stage is used to drive a hot gas expansion turbine whereby at least a part of the energy used to drive the compressor is provided by the hot gas expansion turbine.

According to one form, the scrubbing agent including the carbon dioxide that is exiting from step b. is stripped in a distillation column to remove the carbon dioxide and any other dissolved gases providing a bottom stream of stripped scrubbing agent and a top stream of gas including carbon dioxide. In one form, the top stream of gas passes to a refrigerated reflux condenser which produces a stream of liquid carbon dioxide and a remaining gas stream. According to a further form, the remaining gas stream is combined with the flue gas exiting step b., and is prefereably then used as the cooling medium in the indirect heat exchanger prior to step b.

According to a further form any sulphur trioxide is removed from the flue gas prior to step a. wherein the sulphur trioxide is removed by agglomeration in electrostatic precipitators, which optionally removes residual particulate matter, or the sulphur trioxide is removed by sulphuric acid de-misting devices including "Brink" mist eliminators.

According to a further form, sulphur dioxide is also removed from the flue gas, In a preferred form, the scrubbing agent is methanol and the sulphur dioxide is removed in step b together with the carbon dioxide after which the carbon dioxide and the sulphur dioxide are stripped from the methanol and sulphur dioxide mixture removed from the carbon dioxide mixture providing a substantially pure sulphur dioxide stream.

According to one form, additional compressed air and/or fuel or synthesis gas is added to the combustion stage. According to one form, the additional compressed air and/or fuel or synthesis gas is provided by an integrated gasification combined cycle (IGCC) system, or an Advanced Integrated Drying and Gasification (AIDQ) system. In a further form, part of the energy provided by the hot gas expansion turbine in an integrated gasification combined cycle (IGCC) system, or an Advanced Integrated Drying and Gasification (AIDG) system is used to drive the compressor.

According to a further form, any surplus energy provided by the hot gas expansion turbine is used to generate electricity. In a further form, surplus carbon dioxide is removed from the fuel or synthesis gas produced by the gasifier in the Advanced Integrated Drying and Gasification (AIDG) system.

According to a further form, flue gas exiting from the hot gas expansion turbine in the integrated gasification combined cycle (IGCC) system, or the Advanced Integrated Drying and Gasification (AIDG) system is added to the flue gas prior to step b. whereby carbon dioxide is also removed from the flue gas exiting the hot gas expansion turbine in the integrated gasification combined cycle (IGCC) system, or the Advanced Integrated Drying and Gasification (AIDG) system.

According to another form, the carbon dioxide removed by the process is then sequestered using carbon dioxide geo-sequestration techniques. According to this form, the carbon geo- sequestration techniques include: injection of the carbon dioxide into coal seam methane producing coal seams; or, injection of the carbon dioxide into depleted oil fields to enable carbon dioxide miscible flood-based enhanced recovery of oil from the partially depleted oil fields, whereby enhanced coal seam gas and/or oil recovery is accompanied with the geo-sequestration of carbon dioxide. According to One preferred form, power generation and crude oil production and refining carbon dioxide emissions are reduced and crude oil is recovered from depleted oil fields. According to another preferred form power generation emissions are reduced and recovery of coal seam methane is enhanced.

Brief Description of the Figures

The present invention will become better understood from the following detailed description of preferred but non-limiting embodiments thereof, described in connection with the accompanying figure, wherein:

Figures 1 is a process diagram in accordance with one embodiment of the present invention.

Detailed Description of the Figure and preferred embodiments of the Invention

An embodiment of the present invention will now be described with reference to Figure-1 wherein a pulverised coal-fired boiler 2 receives air from an air pre-heater 4 that has been driven by a forced draft air fan 6 and together with coal is combusted in the boiler 2 producing flue gas including carbon dioxide which exits via line 106 exchanging heat with the air pre-heater 4 and then passing to a bag filter 8 which removes much of the particulate matter included in the flue gas stream,

In this particular embodiment, the flue gas issuing from the coal-fired boiler includes carbon dioxide, sulphur trioxide, sulphur dioxide and water together with other gases.

After passing through the bag filter 8, the flue gas passes to a water wash tower 9 via line 109 where the flue gas is contacted with a water which cools the flue gas and reacts with sulphur trioxide present in the flue gas and forms sulphuric acid, some of which is removed as dilute sulphuric acid in the acidic water leaving the water wash tower 9 in pipeline 111 and part of the sulphur trioxide forms a mist of very small acid droplets which are difficult to separate.

The flue gas then passes on to an electrostatic precipitator 10 which is a means of agglomerating and separating acid mist and which also removes particulate matter in the flue gas stream and the resulting mixture of dilute sulphuric acid and paniculate matter is withdrawn via pipeline 113.

Now that the sulphur trioxide is removed the flue gas stream passes to an extraction fan Il which assists in drawing the flue gas through the bag filter 8, water wash tower 9 and electrostatic precipitator 10 and delivers it for further processing in the carbon dioxide post capture system which includes an initial indirect flue gas cooler 13 followed by packed water wash columns 12 and \6 and wash water circulating pumps 14 and 18.

The carbon dioxide post capture system further includes single pass vertical shell and tube heat exchangers 60 and 20 designed to operate in refluxing mode on' the tube side and a tray column 24 with refrigerant circulating in cooling tubes assemblies 26 which are fed from a refrigeration plant with the cooling tube assemblies being located in the distillation trays 24. Further refrigeration cooling coils 21 and 22 are also located at the top and bottom of the distillation trays and are connected to the same refrigeration plant that circulates through the cooling tube assemblies 26 of the distillation trays 24

After the scrubbing agent such as methanol is directly contacted with the flue gas passing through the distillation trays, a pump 28 pushes the methanol including carbon dioxide and to a heat exchange system 30 fitted with a separation vessel 32 to enable separation of gas liberated from the methanol being heated in 30. A distillation column 34 and a refrigerated reflux condenser 36 which in this example is a vertical tubular exchanger which enable carbon dioxide gas to be separated from condensing carbon dioxide and also incorporates a heating coil which may contain condensing refrigerant or other possible heating media to ensure substantial removal of light gases.

A re-boiler 38 can be heated by low pressure steam or heat exchange fluid which may for example come from steam in line 155.

A refrigerant plant 26 to provide refrigerant is shown and in one embodiment could constitute liquid propane from a propane-based refrigeration system.

A compressor 52 is mechanically coupled to an expander 56 such as a gas fired turbine which is in turn fed by a combustor 54. The exit gas from the expander 56 leaves via line 136 into a waste heat boiler which then produces steam exiting out of line 155. A power generator is coupled to the expander 56 to produce power from any excess energy produced by the expander 56 and not used by the compressor 52.

In this embodiment an stream of air is fed to the coal fired boiler 2 from fan 6 via 102 to pre-heater 4 and then via duct 104 to the coal fired boiler 2. Flue gas from the boiler passes via duct 106 to the air pre-heater 4 and then via duct 108 to the bag filter 8.

All or part of the flue gas leaving the bag filter 8 is withdrawn via duct 109 to the water wash 9 and then via duct 112 to the electrostatic precipitator 10 and then via duct 114 to fan 11.

Gas leaving 11 via 115 passes to cooler 13 and then via pipeline 113 to the compressor 52 in which it is compressed and leaves via pipeline 116 and is cooled in heat exchanger 15 before passing to wash column 12 for direct further water wash-based cooling where the flue gas is directly contacted with water before passing via pipeline 117 to the base of heat exchangers 60 and 20.

A mixture containing more than 5% methanol is injected into the flue gas stream via pipeline 121 before entering the base of heat exchanger 60. Here the methanol containing flue gas is cooled to low temperature and any condensing water and methanol is removed via pipeline 198 and the cooled gas from the heat exchanger 60 passes through a bubble cap or similar separating tray 19 before passing upward into heat exchanger 20 in which further methanol and water vapour is condensed and removed via pipeline 196. In heat exchangers 60 and 20 water is condensed preferentially to methanol such that the freezing point of condensate is lowered as the gas is cooled and ice or hydrate formation is avoided.

Condensed water leaving heat exchangers 60 and 20 via pipelines 196 and 198 is heated to remove methanol from the water before the water is discharged and the recovered methanol and water mixture containing at least 5% methanol is recycled for addition to the incoming compressed flue gas at line 121.

In the gas/liquid contacting trays 24 the flue gas is contacted counter-currently with refrigerated methanol entering via pipeline 140 and passing down the refrigerated gas/liquid contacting trays such that the greater part of the carbon dioxide and any sulphur dioxide in the entering flue gas is removed, via pipeline 142 as a mixture with refrigerated methanol which also contains some dissolved nitrogen.

The methanol with dissolved gases leaves the gas/liquid contacting trays 24 via pipeline 142 and passes to pump 28 and then via pipeline 150 to the first stage of the heat exchanger 30 in which the mixture is heated and separates into gas and liquid and leaves via pipeline 146 and enters separator 32 and returns to 30 via pipeline 150 and is further heated in 30 before passing via pipeline 152 to separation column 34. The separated gas which contains nitrogen separated from the methanol passes via pipeline 148 to the base of the gas/liquid contacting trays 24 where it is recombined with the flue gas.

Distillation column 34 strips carbon dioxide from the entering carbon dioxide containing methanol which then passes together with some methanol via pipeline 154 to the refrigerated reflux condenser 36 in which the carbon dioxide is cooled and further purified in a propane refrigerant cooled refluxing partial condenser 36 with separated carbon dioxide gas leaving via pipeline 160. Stripped methanol leaves 34 via pipeline 162 with part of the withdrawn liquid passing via pipeline 164 to the re-boiler 38 before returning as liquid and vapour to column 34 via pipeline 166.

Stripped methanol passes via pipeline 168 to heat exchanger 30 in which it is cooled before returning to the gas/liquid contacting trays 24 via pipeline 140.

Stripped flue gas leaves 24 via pipeline 122 to heat exchanger 20 in which it is heated and passes via pipeline 126 to heat exchanger 60 in which it is heated farther and leaves via pipeline 128 to wash column 16 in which it is heated and saturated by water entering in pipeline 118 and passes via pipeline 130 to heat exchanger 15 before passing to the conibustor 54. The heated water entering via pipeline 118 is cooled by counter-current contact with cool dry air.

The combustor 54 can have fuel gas added from pipeline 132 and additional compressed air is added via pipeline 133 to enable combustion with' the hot resultant products of combustion passing to the gas turbine expander 56 with the net power available after driving the compressor 52 being used to drive the generator 58 with the hot flue gases leaving 56 via line 136 being used to heafwater entering the waste heat boiler 57 via pipeline 153 and leaving as steam via pipeline 155 for use in heating re-boilers and the like in the post capture system with the exhaust gases which contain boiler flue gases, with a significantly lower carbon dioxide content, being discharged to atmosphere via duct or stack shown as line 138.

Not shown in the diagram is the recovery of water condensate containing methanol from pipelines 198 and 196 which would be heated and stripped of methanol by known means enabling the recycling of methanol via pipeline 121 and the discharge of water recovered from the boiler flue gas.

One further embodiment of the present invention is now described with reference to Figure- 1 in which 62 is a compressor, 66 is an expander, 68 is a generator, 64 is a gas turbine conibustor with 62, 64, 66 and 68 being components of a gas turbine. 76 is an air humidification system and 78 is an air separation unit. 80 is an AΪDG type gasitler as outlined in Australian patent AU 714670 and 82 is CO2 removal system.

70 is a recuperator system in which 72 is a heat exchange bundle or rack of heat exchanger tubes for pre-heating fuel gas and 74 is a heat exchange bundle or rack for pre-heating combustion air,

In this embodiment of the invention air passes to the gas turbine compressor 62 via pipeline 202 and compressed air leaves via line 204 with part of the air being side- streamed via pipeline 132 as the supplementary air for combustion in the gas turbine system made up of items 52, 54, 56 and 58, The remaining air then passes either via pipeline 210 to 76 or via pipeline 208 to 78 in which oxygen is removed from the air and transferred via pipeline 212 to the gasifier system 80.

The gasifier system can be fed with a pressurised coal and water slurry which via pipeline system 214 and dried by injection into hot ga$es leaving the coal gasifier with the coal gasification product gas now containing additional water vapour which passes to a particulates removal system which can consist of a water injected venturi scrubbing system before passing via pipeline 216 to 82 and the separated and dried coal then being fed as pressurised fine coal particles to the gasifier incorporated in 80, The ash and waste particulate matter produced in 80 is removed which is not shown in Figure-1.

In 82 the crude synthesis gas with its particulate matter removed and with an added water vapour content is first passed through to a sulphur tolerant shift reaction system and then cooled and can be removed by methanol washing with the. wash system integrated with the methanol wash system shown in Figure 1. Alternately the fuel gas can be used as gas turbine fuel and the flue gases mixed with flue gas from the cola fired boiler 2 with carbon dioxide being removed by the post capture system shown in Figure 1. By means of the present invention any alcohol or ammonia left in the flue gas after carbon dioxide removal would be decomposed and eliminated in the combustor allied in the associated gas turbine system.

Also, by means of the present invention nitric oxides in the treated flue gas can be substantially eliminated in the gas turbine combustor by means such as sequential reduction and oxidation combustion techniques or known post combustion treatment systems for exhaust gases from clean gas based combustion systems.

Furthermore, by means of the present invention water soluble mercury compounds in the flue gas will be removed in the water-wash stages and any residual elemental mercury will be largely eliminated in the low temperature treatment stages.

The present invention will now be further described in connection with Figure 1 and the following example Which is based on treating flue gas from a nominal 880 Megawatt gross output power plant made up of two parallel 440 Megawatt generating units. The plant operates under supercritical conditions and would have a net output of 840 Megawatts. It provides a flue gas flow of 494 kg/s per unit exiting at 141ºC and with a flue gas carbon dioxide concentration of 13.0% equating to 95 kg/s of carbon dioxide.

Table 1 below gives flow data relating to the flow lines in figure 1 where flow lines with subscript indicate there are two parallel steam plants with the flue being treated in a single process stream and being broken into two separate flows for the two separate turbines. The gross power used for gas processing would be 45 Megawatts resulting in a net power output from the site of 1093 Megawatts from the overall facility with the two gas turbines using supplementary natural gas for firing and having a gas based gross power efficiency of 29%.

In this example, the two flue gas streams would be combined and 80% of the carbon dioxide would be captured.

Finally, it can be understood that the inventive concept in any of its aspects can be incorporated in many different constructions so that generality of the preceding description is not superseded by the particularity of the attached drawings. Various alterations, modifications and/or additions may be incorporated into the various constructions and arrangements of parts without departing from the spirit or ambit of the present invention.

Claims

The Claims;

1. A process for removing the carbon dioxide from a flue gas exiting from a fossil fuel combustion reaction, wherein the process includes the following steps: a. cooling the flue gas to below 50ºC by directly contacting the flue gas with a counter current stream of liquid water; and, b. removing the carbon dioxide from the flue gas by directly contacting the flue gas with a scrubbing agent.

2. A process according to claim 1 wherein the scrubbing agent is chosen from amines including aqueous monoethanolamine (MEA), diglycolamine (DGA), diethanolamine (DEA), diisopropanolamine (DIPA) and methyldiethanolamine (MDEA), methanol, and/or ammonia.

3. A process according to claim 2 wherein the scrubbing agent is methanol.

4. A process according to any one of claims 1 to 3 wherein prior to step b. an alcohol having a higher volatility than water is added to the flue gas and the subsequent flue gas stream including the alcohol is further cooled by indirect heat exchange.

5. A process according to claim 4 wherein the alcohol is methanol.

6. A process according to claim 4 or claim 5 wherein the flue gas stream including alcohol is further cooled by indirect heat exchange in a vertical reflux heat exchanger or a series of sequential heat exchangers,

7. A process according to any one of claims 4 to 6 wherein liquid condensate formed during the indirect heat exchange and including water and alcohol is removed from the flue gas stream,

8. A process according to claim 7 wherein the liquid condensate removed from the flue gas stream is distilled to separate the alcohol from the water and recover the alcohol for recycling back into the process.

9. A process according to any one of claims 4 to 8 wherein step b. is carried out in a tray distillation column situated above the indirect heat exchanger wherein the flue gas including the alcohol passes from the indirect heat exchanger into the tray distillation column wherein the flue gas is directly contacted with the scrubbing agent,

10. A process according to any one of claims 1 to 9 wherein the flue gas is compressed in a compressor after step a, to between 5 and 30 atmospheres.

11. A process according to claim 10 wherein the flue gas is compressed to between 10 and 20 atmospheres.

12. A process according to claim 10 or 11 wherein the flue gas exiting step b. being stripped of carbon dioxide, is fed to a combustion stage and the resulting hot gas exiting the combustion stage is used to drive a hot gas expansion turbine whereby at least a part of the energy used to drive the compressor is provided by the hot gas expansion turbine.

13. A process according to any one of claims 1 to 12 wherein the scrubbing agent including the carbon dioxide that is exiting from step b, is stripped in a distillation column to remove the carbon dioxide and any other dissolved gases providing a bottom stream of stripped scrubbing agent and a top stream of gas including carbon dioxide.

14. A process according to claim 13 wherein the top stream of gas passes to a refrigerated reflux condenser which produces a stream of liquid carbon dioxide and a remaining gas stream.

15. A process according to claim 14 wherein the remaining gas stream is combined with the flue gas exiting step b..

16. A process according to any one of claims 1 to 15 wherein any sulphur trioxide is removed from the flue gas prior to step a. wherein the sulphur trioxide removed by agglomeration in electrostatic precipitators, which optionally removes residual particulate matter, or the sulphur trioxide is removed by sulphuric acid de-misting devices including "Brink" mist eliminators.

17. A process according to any one of claims 1 to 16 wherein sulphur dioxide is also removed from the flue gas.

18. A process according to claim 17 wherein the scrubbing agent is methanol and the sulphur dioxide is removed in step b together with the carbon dioxide after which the carbon dioxide and the sulphur dioxide are stripped from the methanol and sulphur dioxide mixture removed from the carbon dioxide mixture providing a substantially pure sulphur dioxide stream.

19. A process according to any one of claims 12 to 18 wherein additional compressed air and/or fuel or synthesis gas is added to the combustion stage.

20.. A process according to any one claim 19 wherein the additional compressed air and/or fuel or synthesis gas is provided by an integrated gasification combined cycle (IGCC) system, or an Advanced Integrated Drying and Gasification (AIDG) system.

21. A process according to any one of claims 12 to 20 wherein part of the energy provided by the hot gas expansion turbine in an integrated gasification combined cycle (IGCC) system, or an Advanced Integrated Drying and Gasification (AIDG) system is used to drive the compressor.

22. A process according to any one of claims 12 to 21 wherein any surplus energy provided by the hot gas expansion turbine is used to generate electricity.

23. A process according to any one of claims 20 to 22 wherein in which surplus carbon dioxide is removed from the fuel or synthesis gas produced by the gasifier in the

Advanced Integrated Drying and Gasification (AIDG) system.

24. A process according to any one of claims 20 to 23 wherein flue gas exiting from the hot gas expansion turbine in the integrated gasification combined cycle (IGCC) system, or the Advanced Integrated Drying and Gasification (AIDG) system is added to the flue gas prior to step b. whereby carbon dioxide is also removed from the flue gas exiting the hot gas expansion turbine in the integrated gasification combined cycle (IGCC) system, or the Advanced Integrated Drying and Gasification (AIDG) system.

25. A process according any one of claims 1 to 24 wherein the carbon dioxide removed by the process is then sequestered using carbon dioxide geo-sequestration techniques.

26. A process according to claim 25 wherein the carbon geo-sequestration techniques include: injection of the carbon dioxide into coal seam methane producing coal seams; or, injection of the carbon dioxide into depleted oil fields to enable carbon dioxide miscible flood-based enhanced recovery of oil from the partially depleted oil fields, whereby enhanced coal seam gas and/or oil recovery is accompanied with the geo-sequestration of carbon dioxide.

27. A process according to claim 26 wherein power generation and crude oil production and refining carbon dioxide emissions are reduced and crude oil is recovered from depleted oil fields.

28. A process according to claim 26 wherein power generation emissions are reduced and recovery of coal seam methane is enhanced.