Abstract:
A system and process is provided primarily for use in hot climates, using ammonia solution to remove carbon dioxide from desulphurised water-vapour-containing flue gases of a fossil fuel power plant, while outputting useful streams of water and fertiliser.

Description:
FIELD OF THE INVENTION 
       [0001]    The present invention relates to the field of climate protection technology, and in particular to improving the process of carbon capture in fossil fuel power plants using a system in which carbon dioxide is absorbed from the power plant&#39;s flue gases by an ammonia-based solution or slurry. 
       BACKGROUND OF THE INVENTION 
       [0002]    Fossil fuel power plants can be fitted with carbon dioxide (CO 2 ) capture equipment either when first built or as a retrofit. One technology that shows near-term promise for large-scale practical application comprises processes in which ammonia-rich solutions and slurries are used to absorb CO 2  from power station flue gases. 
         [0003]    For example, published International patent application no. WO 2006/022885 A1 (E. Gal) describes a process of the chilled ammonia type, in which downstream of conventional pollution control equipment, such as electrostatic precipitators and flue gas desulphurisers, the flue gases are cooled to well below ambient saturation temperature and subject to wet scrubbing with cold water to remove residual contaminants not removed by the conventional equipment. This is followed by passage of the cleaned flue gases through one or more CO 2  absorbers operating at about atmospheric pressure and at a low temperature in the range 0° C. to 20° C., where the gaseous CO 2  in the flue gases is reacted with an ammoniated solution. Cooling of the flue gas before passage through the CO 2  absorber reduces its moisture content and its volume, thereby increasing the CO 2  concentration and making its capture more efficient. Moreover, the relatively low scrubbing temperature in the absorber enhances mass transfer of CO 2  to the ammonia solution while reducing the ammonia&#39;s vapour pressure, so tending to prevent its evaporation into the flue gas stream. The CO 2 -rich ammonia solution from the absorber vessel is then pressurised and heated to release the absorbed CO 2  as a relatively clean pressurised CO 2  gas stream containing low concentrations of ammonia, the latter being recovered by a further cold scrubbing process. The ammonia solution is now CO 2 -lean, and is re-circulated for further CO 2  absorption duty. Meanwhile, the CO 2  gas stream can be cooled and further pressurised for storage and sequestration. The reader is referred to the above-mentioned patent publication for a more complete description of the process. 
         [0004]    Carbon capture processes are of course intended to slow down the onset of climate change caused by increased concentrations of greenhouse gases in the atmosphere. However, most climate specialists agree that some global warming is already occurring and will continue for several decades, at least. The results of global warming-driven climate change will include increased aridity in some regions of the world, with concomitant water shortages. Additionally, there will be an increased need for fertilisers to boost crop yields. 
       SUMMARY OF THE INVENTION 
       [0005]    Accordingly, the present invention provides a system that removes carbon dioxide from desuiphurised water-vapour-containing flue gases of a fossil fuel power plant, while outputting streams of fertiliser and water. The system comprises:
       (a) a first flue gas cooling stage, including water cooling means and a first flue gas cooler connected to receive cooled recirculated water from the water cooling means to cool the flue gases and thereby condense water therefrom;   (b) a second flue gas cooling stage, including coolant cooling means connected in a closed circuit to a second flue gas cooler, whereby the second flue gas cooler receives recirculated coolant from the coolant cooling means to further cool the flue gases and thereby condense further water therefrom;   (c) bleed means by which respective water streams at least equal to the amounts condensed from the first and second flue gas cooling stages are separately removed from the system for further use;   (d) a carbon dioxide absorbing stage that uses a recirculated ammonia-rich solution to absorb carbon dioxide from the cooled de-watered flue gases and output a stream of carbon dioxide depleted flue gas including entrained ammonia;   (e) a carbon dioxide regenerating stage that receives the carbon dioxide containing ammonia-rich solution from the carbon dioxide absorbing stage, outputs a stream of carbon dioxide including entrained ammonia by heating the ammonia-rich solution to liberate the absorbed carbon dioxide therefrom, and recirculates carbon-dioxide depleted ammonia-rich solution to the carbon dioxide absorbing stage;   (f) means removing the carbon dioxide stream from the system for long term storage;   (g) a sulphuric acid wash stage that receives the stream of carbon dioxide depleted flue gas from the carbon dioxide absorbing stage, removes ammonia therefrom by reaction of the ammonia with the sulphuric acid to produce concentrated ammonium sulphate solution, and outputs a stream of clean carbon dioxide depleted flue gas;   (h) bleed means by which a stream of the concentrated ammonium sulphate solution is removed from the system for further use; and   (i) means receiving the clean flue gas from the sulphuric acid wash stage and passing it to atmosphere.       
 
         [0015]    It may be necessary or desirable for a water wash stage to be located between the carbon dioxide absorbing stage and the sulphuric acid wash stage to recover an initial proportion of ammonia from the stream of carbon dioxide depleted flue gas, the recovered ammonia being recycled to the ammoniated solution in the carbon dioxide absorbing stage. A water wash stage may also be located after the carbon dioxide regenerating stage to recover ammonia from the stream of carbon dioxide before the carbon dioxide is removed from the system for long-term storage, the recovered ammonia being recycled to the ammoniated solution in the carbon dioxide regenerating stage. 
         [0016]    Preferably, the first flue gas cooler is a direct contact gas cooler. Advantageously, the recirculated water that has been heated by the flue gases in the first flue gas cooler is passed through a heat exchanger in the carbon dioxide regenerating stage, thereby to heat the carbon dioxide containing ammonia-rich solution and liberate the absorbed carbon dioxide therefrom. After passing through the carbon dioxide regenerating stage, the recirculated water is passed through the water cooling means in the first flue gas cooling stage. 
         [0017]    The water cooling means in the first flue gas cooling stage should cool the recirculated water by a method that does not result in loss of the recirculated water by evaporation. Thus, the water cooling means in the first flue gas cooling stage may be a heat exchanger that puts the recirculated water in a non-contact heat exchange relationship with either the clean flue gas stream output by the sulphuric acid wash stage before the clean flue gas stream is passed to atmosphere, or an environmental coolant, such as seawater or ambient air. For example, the water cooling means may be a dry cooling tower that uses the clean flue gas stream or ambient air to cool the recirculated water. As a further alternative, the water cooling means in the first flue gas cooling stage may be an absorption chiller that is energised by heat from the power plant and is operative to cool the recirculated water and reject the heat so gained to the environment. 
         [0018]    Putting the recirculated water in a non-contact heat exchange relationship with the clean flue gas stream before the latter is passed to atmosphere is particularly advantageous because it avoids heating of environmental coolants and because heating of the clean flue gas stream after the sulphuric acid wash stage will aid exhaust plume dispersal. 
         [0019]    Whereas the first flue gas cooler is preferably a direct contact gas cooler, the second flue gas cooler is a form of heat exchanger in which the coolant does not directly contact the flue gas stream. Hence, the second flue gas cooler may comprise an array of heat exchange coils through which the recirculated coolant is passed. 
         [0020]    The coolant cooling means in the second flue gas cooling stage may be a mechanical chiller in which the coolant is a refrigerant (such as ammonia, CO 2 , or Freon®) that is evaporated by heat exchange with the flue gases and condensed by heat exchange with an environmental coolant, such as seawater or ambient air. Alternatively, the coolant cooling means may be an absorption chiller that is energised by heat from the power plant and is operative to cool recirculated water or other coolant that has been heated by the flue gases and to reject the heat so gained to the environment. 
         [0021]    The invention also provides a process for removing carbon dioxide from desulphurised water-vapour-containing flue gases of a fossil fuel power plant. The process comprises the steps of
       (a) cooling the flue gases and condensing water therefrom in a first flue gas cooling stage;   (b) further cooling the flue gases and condensing further water therefrom in a second flue gas cooling stage;   (c) bleeding water separately from the first and second flue gas cooling stages in respective water streams whose flow rates are at least equivalent to the respective amounts condensed from the first and second flue gas cooling stages;   (d) absorbing carbon dioxide from the cooled de-watered flue gases in an ammonia-rich solution and outputting a stream of carbon dioxide depleted flue gas including entrained ammonia;   (e) heating the ammonia-rich solution and outputting a stream of liberated carbon dioxide including entrained ammonia;   (f) recirculating carbon-dioxide depleted ammonia-rich solution for use in further carbon dioxide absorption;   (g) removing the carbon dioxide stream from the process for long term storage;   (h) removing entrained ammonia from the stream of carbon dioxide depleted flue gas by scrubbing it in a sulphuric acid wash stage and outputting a stream of clean carbon dioxide depleted flue gas while simultaneously producing concentrated ammonium sulphate solution by combination of the ammonia with the sulphuric acid;   (i) bleeding a stream of the concentrated ammonium sulphate solution from the sulphuric acid wash stage for further use; and   (j) passing the clean flue gas to atmosphere.       
 
         [0032]    Preferably, the fossil fuel power plant is a gas turbine combined cycle power plant burning gasified coal or oil. 
         [0033]    Further aspects of the invention will be apparent from a perusal of the following description and claims. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWING 
         [0034]    Exemplary embodiments of the invention will now be described with reference to the accompanying  FIG. 1 , which is a flow diagram illustrating in simplified form a process for removing, inter alia, carbon dioxide from flue gases. 
       
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
       [0035]    A power plant burning natural gas produces a relatively clean flue gas stream, containing only about 2-3% CO 2 . On the other hand, a power plant burning fuels such as coal and oil, produces flue gases that contain (among other things) about 10-15% CO 2 . World-wide, the majority of power stations already built, or which are planned to be built in the near to mid-term, are coal-fired in some form or other. It will therefore be appreciated that reducing their CO 2  emissions has a very important role to play in reducing the impact of climate change. 
         [0036]    Although desulphurisation of power plant flue gases is not an object of the present invention, it is assumed at the left hand end of  FIG. 1  that the flue gas stream  10  requires desulphurisation. After passing through an electrostatic precipitator (if necessary, not shown), which removes any suspended particulates and sulphurous/sulphuric acid mist, flue gas  10  enters a desulphurisation process  12 . In the present case, a wet scrubbing process is assumed, in which crushed limestone (calcium carbonate)  13  is mixed with low quality water  14  (e.g., seawater) to produce a limestone slurry spray through which the flue gas  10  is passed. A reaction occurs in which sulphur dioxide in the flue gas is converted to calcium sulphite and carbon dioxide. The calcium sulphite is then oxidised to hydrated calcium sulphate (gypsum)  15 , which can be sold as a building material. 
         [0037]    The Wellman-Lord process is an alternative desulphurisation process that could be considered for use with the present invention. Firstly, the hot flue gases are scrubbed to remove ash, hydrogen chloride, hydrogen fluoride and sulphur trioxide. After cooling, the gases are sprayed with a saturated solution of sodium sulphite in an absorption tower. The sodium sulphite reacts with the sulphur dioxide to form a concentrated sodium bisulphite solution, which is passed to an evaporation system for regeneration, where it is broken down by a steam treatment to release the sodium sulphite for recycling. The released sulphur dioxide is converted to elemental sulphur, sulphuric acid or liquid sulphur dioxide. A main advantage of this process is that the sorbent is regenerated during the process and is continuously recycled. Furthermore, when used with a power plant that raises steam for power generation, the power plant may provide a source of steam for use in the process. 
         [0038]    A further alternative that could be considered for use with the present invention is to remove sulphur from coal during the burning process in the power plant. This can be done by using either pressurised fluidised bed combustors, or the Integrated Gasification Combined Cycle process. In this case, flue gas desulphurisation as shown in  FIG. 1  would be unnecessary. 
         [0039]    For the purposes of describing embodiments of the invention with reference to  FIG. 1 , it will be assumed that the flue gas  10 A, no matter how it has been desulphurised, originates from a gas turbine combined cycle (GTCC) power plant burning gasified coal or oil, and therefore contains about 10-15% CO 2 . In addition to CO 2  and other atmospheric gases, the desulphurised flue gas  10 A contains only residual contaminants and is water saturated with about 15-18% water at a temperature of 40-70° C., typically about 55° C. To purge the residual contaminants and cool the flue gas  10 A, it is passed through a first flue gas cooling stage comprising a direct contact gas cooler (DCC)  16 , where relatively cool water  18 A at about ambient temperature (say, 25° C.) is used to wash the flue gas in a counter-current flow, packed-bed vessel. Consequently, the flue gas is cooled to about ambient temperature and excess water condenses out. Assuming the flue gas stream  10 A is acceptably clean, the water in the DCC  16  (which is recirculated via the CO 2  regenerator  44 , as explained later), will also be acceptably clean. The condensed water mixes with the washing water  18 A to form a lightly contaminated water stream  18 B, which exits the DCC  16  at a temperature of about 52° C. The raised temperature of stream  18 B results from the combined effect of heat of condensation and heat transfer from the flue gas. Note that a stream of water  20 , at least equivalent to the amount of water condensed out of the flue gas  14 , is shown as being bled off the main stream  18 B at the outlet of the DCC  16 . After purification as necessary, e.g., in ion exchange resin or a solar still, the water  20  will be potable, or useable for industrial or agricultural purposes. 
         [0040]    It will be evident to the skilled person that after a period of operation of the DCC  16 , during which the water used therein has been continuously recirculated, impurities picked up from the flue gas  10 A will gradually accumulate in the recirculated water. It will therefore be necessary either continuously or periodically to replace some of the impure recirculating water with clean water. A convenient way to do this would be to bleed off in stream  20  an amount of water that is slightly in excess of the amount condensed out of the flue gas  14 , and to make up the resulting water deficit by continuous injection of a correspondingly small flow of clean water into the top of the DCC  16 . Such clean water would conveniently be the excess portion of the stream  20 , after purification. 
         [0041]    The initially cooled flue gas  10 B is next passed to a second cooling stage comprising a gas cooler  24 , which is a radiator type of heat exchanger, similar to the air inlet coolers used on gas turbine engines when the ambient air temperature is too high for efficient operation of the gas turbine. In this type of gas cooler, the coolant  26 A,  26 B passes through an array of heat exchange coils and there is no direct contact between the coolant and the gas stream  10 B. 
         [0042]    In the embodiment of the invention shown in  FIG. 1 , chiller  30  is a mechanical chiller. This mainly comprises a compressor that pumps a refrigerant, such as Freon®, ammonia, or carbon dioxide, around a closed circuit between gas cooler  24 , where the coolant removes heat from the flue gas by evaporation, and a means of heat rejection  28  comprising a condenser, the whole therefore acting as a heat pump. The condenser will condense the coolant by rejecting heat to an environmental coolant, such as seawater or ambient air. 
         [0043]    Alternatively, chiller  30  may be an absorption type of industrial chiller that is energised by heat from the power plant and acts to cool recirculated water or other coolant  26 B that has been heated by the flue gas stream  10 B. Again, heat gained by the absorption chiller from the heated coolant  26 B must be rejected to the environment at  28  through a heat exchanger whose form will depend on the type of coolant used in the gas cooler  24  and the nature of the environmental coolant to which heat is rejected. 
         [0044]    Using the above chiller arrangements, it is possible to cool the flue gas down to 5° C. in stream  10 C ready for entry to the CO 2  absorber  34  after energisation by the booster fan  36 . 
         [0045]    The flue gas  10 B, at a temperature of about 25° C. before entering the gas cooler  24 , still contains a substantial amount of water vapour. It is therefore necessary to further reduce the amount of water in the flue gas stream  10 B to a low level that will not affect the water balance in the CO 2  absorber/regenerator system  34 / 44 . This is achieved in the gas cooler  24 , because at 5° C., most of the water vapour in the flue gas  10 B condenses out for removal as water stream  32 . After little or no further treatment, water  32  will be potable, or useable for industrial or agricultural purposes. 
         [0046]    The relatively dry (0.8% water content), cooled and energised flue gases  10 D are passed through one or more CO 2  absorbers  34  operating at about atmospheric pressure, where the gaseous CO 2  in the flue gases is reacted with, and consequently absorbed by, an ammoniated solution or slurry. The CO 2 -depleted flue gas stream  10 E is passed for further processing before release to atmosphere, as described below. Meanwhile, the CO 2 -rich ammonia solution  40 A is pumped by pump  42  from the absorber vessel  34  to the CO 2  regeneration system  44 , where it is heated to release the absorbed CO 2  as a relatively clean pressurised CO 2  gas stream  45  containing low concentrations of ammonia. After passing through the regeneration system  44 , the CO 2 -lean ammonia solution  40 B is re-circulated to the CO 2  absorber  34  for further duty. Advantageously, but not essentially, the low concentrations of ammonia in the CO, gas stream  45  may be recovered by a water wash process in scrubber  46  and recycled to the regenerator  44 . Thereafter, the cleaned CO 2  gas stream  47  can be cooled and further pressurised for storage and sequestration (not shown). 
         [0047]    An advantageous aspect of the carbon capture system being described is the way in which at least some of the heat necessary to release the absorbed CO 2  from the ammoniated solution in the regeneration system  44  is supplied from the DCC  16 . As mentioned previously, the cooling water stream  18 B leaves the DCC  16  at a temperature of about 52° C. After the water  20  has been bled off, the remaining water stream  18 C is passed through a heat exchanger  22  in the regeneration system  44 , where it helps to liberate the CO 2  by heating the ammoniated solution. It may not be possible to supply all the heat that is required by the regeneration system  44  from the DCC  16 , in which case a supplementary heater (not shown) will be required in regeneration system  44 . After giving up a large proportion of its heat to the regeneration system, the water is now at about 35° C., and is recirculated to a dry cooling tower  48  as stream  18 D for cooling to ambient temperature again before being re-used in DCC  16 . 
         [0048]    A dry cooling tower  48  is used in the embodiment of  FIG. 1  because open cooling towers, which are normally used in power generation schemes, evaporate large amounts of water into the atmosphere. This would be undesirable in situations where water saving is important, and would tend to negate an object of this invention, which is to use power station flue gases to provide extra water in areas where it may be in short supply. 
         [0049]    Returning now to the path of the flue gases after leaving the CO 2  absorber  34 , the skilled person will realise that inevitably the flue gas stream  10 E will have been contaminated by ammonia in the CO 2  absorber  34 . In the embodiment of  FIG. 1 , this ammonia is removed in a two-stage process. Firstly, flue gas stream  10 E, containing about 5000 parts per million (ppm) of NH 3 , is passed through a water wash process in scrubber  48  to recover a large proportion of the ammonia, which is recycled to the absorber  34 . This reduces the ammonia concentration to about 200 ppm in the flue gas stream  10 F leaving scrubber  48 . Secondly, flue gas stream  10 F is passed through a sulphuric acid wash scrubber  50 , which reduces the ammonia concentration to about 2 ppm in the flue gas stream  10 G that leaves scrubber  50 . By this stage in the system, the flue gas stream  10 G has been sufficiently cleaned for release to atmosphere though a stack. 
         [0050]    The acid wash is a stand-alone process that continually recirculates a relatively small amount of sulphuric acid from the bottom of the scrubber  50  to the top via a pump  52 . In the scrubber, the sulphuric acid combines with the ammonia in the flue gases to form ammonium sulphate by the reaction 
         [0000]      H 2 SO 4 +2NH 3 =(NH 4 ) 2 SO 4 . 
         [0051]    Because the amount and concentration of sulphuric acid circulating in the scrubber is appropriately controlled, the ammonium sulphate solution at the bottom of the scrubber is quite highly concentrated, containing up to 30% or 40% ammonium sulphate. As shown, this is bled off in stream  54  and is suitable for use as a fertiliser after minimal further processing. The sulphuric acid is of course gradually consumed in the acid wash process, so it is necessary to continually inject further amounts of it into the scrubber  52  via a make-up line  56 . Loss of water by evaporation in scrubber  52  will be very low, because the flue gas  10 F at entry to the scrubber has a temperature of only about 5° C. Hence, the clean flue gas  10 G will also be at about 5° C., containing very little water vapour, and very little water make-up will be required to be injected into the scrubber  52  with the sulphuric acid. 
         [0052]    Loss of ammonia from the system due to inefficiencies in ammonia recovery and its use in production of ammonium sulphate must of course be compensated for by injection (not shown) of make-up ammonia into the CO 2  absorber/regenerator stage  34 / 44 . 
         [0053]    A process may be envisaged in which the ammonia entrained in the flue gases during their passage through the absorber is removed by the sulphuric acid scrubber  50  alone. In this case, greater amounts of ammonium sulphate solution would be produced, requiring proportionally greater amounts of sulphuric acid in the scrubber  50 , and increased sulphuric acid and ammonia make-up. 
         [0054]    As already noted, cooling towers (whether dry or open) can only cool a fluid down to ambient temperature or slightly above, since they depend upon atmospheric air to obtain a cooling effect. Hence, in hot climates, where air temperatures may regularly exceed 35° C., the water stream  18 D may be put into a heat exchange relationship with seawater, if it is locally available, rather than use a cooling tower. 
         [0055]    A further alternative to dry cooling tower  48  could be another absorption-type chiller, energised by heat from the power plant, to cool the water  18 D down to an acceptable temperature for use in the DCC  16 . Again, this requires rejection of heat to the environment. 
         [0056]    As an environmentally preferable alternative to the use of environmental coolants to cool water stream  18 D, a dry cooling tower  48 , or other suitable heat exchange arrangement, could be used to transfer heat from water stream  18 D at about 35° C., to the clean flue gas stream  10 G, which is initially at about 5° C., before the flue gas is exhausted to atmosphere. This is indicated on  FIG. 1  by the dashed leftward extension of the arrow  10 G. Such transfer of flue gas heat from an earlier stage in the process to the clean flue gas stream avoids the need to reject heat to environmental coolants such as seawater and enables more rapid dispersal of the clean flue gas in an exhaust plume. The plume may be invisible due to its low water vapour content. 
         [0057]    The following features of the above described process should be particularly noted. 
         [0058]    (a) The amount and purity of water that can be bled off from the process is maximised by
       using a GTCC power plant burning gasified coal (as opposed to other types of coal burning power plants) to ensure that the impurity content of the fuel gas stream  10  is minimised, so that after desulphurisation, the flue gas stream  10 A entering the DCC  16  is sufficiently clean to facilitate an acceptably clean water bleed  20 ;   avoiding the prior art expedient of feeding back excess water from DCC  16  to the desulphurisation process  12 —instead, lower-quality water such as seawater can be used in the desulphurisation process, thereby freeing relatively clean water for bleeding off in stream  20 ; and   using “zero evaporation” (no water loss) methods of cooling the water stream  18 A and coolant stream  26 A before their entry to the DCC  16  and the gas cooler  24 , respectively.       
 
         [0062]    (b) The invention maximises the amount of useful fertiliser product that is produced by the process. This is achieved by using the sulphuric acid wash  50  as a stand-alone stage at the end of the process, i.e., its only link with any previous stage or stages in the process is to receive flue gas stream  10 F from an earlier process stage, its recirculating acid wash being isolated from previous process stages. 
         [0063]    (c) The energy efficiency of the CO 2  removal process is increased and its environmental impact is reduced by:
       the use of heat from the DCC  16  in the CO 2  regenerator;   the use of the chilled clean flue gas  10 G to cool water before the water enters the DCC  16  and the corresponding heating of the clean flue gas to aid exhaust plume dispersal.       
 
         [0066]    The present invention has been described above purely by way of example, and modifications can be made within the scope of the invention as claimed. Thus, the breadth and scope of the present invention should not be limited by any of the above-described exemplary embodiments. Each feature disclosed in the specification, including the claims and drawings, may be replaced by alternative features serving the same, equivalent or similar purposes, unless expressly stated otherwise. 
         [0067]    Unless the context clearly requires otherwise, throughout the description and the claims, the words “comprise”, “comprising”, and the like, are to be construed in an inclusive as opposed to an exclusive or exhaustive sense; that is to say, in the sense of “including, but not limited to”.