Abstract:
A method for producing electrical power and capture CO 2 , where gaseous fuel and an oxygen containing gas are introduced into a gas turbine to produce electrical power and an exhaust gas, where the exhaust gas withdrawn from the gas turbine is cooled by production of steam in a boiler ( 20 ), and where cooled exhaust gas is introduced into a CO 2  capture plant for capturing CO 2  from the cooled exhaust gas leaving the boiler ( 20 ) by an absorption/desorption process, before the treated CO 2  lean exhaust gas is released into the surroundings and the captured CO 2  is exported from the plant, where the exhaust gas leaving the gas turbine has a pressure of 3 to 15 bara, and the exhaust gas is expanded to atmospheric pressure after leaving the CO 2  capture plant. A plant for carrying out the method is also described.

Description:
TECHNICAL FIELD 
       [0001]    The present invention relates to the field of CO 2  capture from CO 2  containing gases, such as exhaust gases from combustion of carbonaceous fuels. More specifically, the invention relates to improvements to a gas fired power combined cycle power plant including CO 2  capture having a higher electrical efficiency compared to earlier proposed solutions. 
       BACKGROUND ART 
       [0002]    The release of CO 2  from combustion of carbonaceous fuels, and most specifically fossil fuels is of great concern due to the greenhouse effect of CO 2  in the atmosphere. One approach to obtain reduction of CO 2  emission into the atmosphere is CO 2  capture from the exhaust gases from combustion of carbonaceous fuels and safe deposition of the captured CO 2 . The last decade or so a plurality of solutions for CO 2  capture have been suggested. 
         [0003]    The technologies proposed for CO 2  capture may be categorized in three main groups: 
         [0004]    1. CO 2  absorption—where exhaust gas is reversibly absorbed from the exhaust gas to leave a CO 2  lean exhaust gas and the absorbent is regenerated to give CO 2  that is treated further and deposited. 
         [0005]    2. Fuel conversion—where hydrocarbon fuels are converted (reformed) to hydrogen and CO 2 . CO 2  is separated from the hydrogen and deposited safely whereas the hydrogen is used as fuel. 
         [0006]    3. Oxyfuel—where the carbonaceous fuel is combusted in the presence of oxygen that has been separated from air. Substituting oxygen for air leaves an exhaust gas mainly comprising CO 2  and steam which may be separated by cooling and flashing. 
         [0007]    WO 2004/001301 A (SARGAS AS) 13 Dec. 2003, describes a plant where carbonaceous fuel is combusted under an elevated pressure, where the combustion gases are cooled inside the combustion chamber by generation of steam in steam tubes in the combustion chamber, and where CO 2  is separated from the combustion gas by absorption/desorption to give a lean combustion gas and CO 2  for deposition, and where the lean combustion gas thereafter is expanded over a gas turbine. 
         [0008]    WO 2006/107209 A (SARGAS AS) 12 Oct. 2006 describes a coal fired pressurized fluidized bed combustion plant including improvements in the fuel injection and exhaust gas pre-treatment, 
         [0009]    Combustion of the carbonaceous fuel under elevated pressure and cooling of the pressurized combustion gases from the combustion chamber reduces the volume of the flue gas, relative to similar amounts of flue gas at atmospheric pressure. Additionally, the elevated pressure and cooling of the combustion process makes a substantially stoichiometric combustion possible. A substantially stoichiometric combustion giving a residual content of oxygen of &lt;5% by volume, such as &lt;4% by volume or &lt;3% by volume, reduces the mass flow of air required for a specified power production. The elevated pressure in combination with the reduced mass flow of air results in a substantial reduction of the total volume of the exhaust gas to be treated. Additionally, this results in substantial increase in the concentration and partial pressure of CO 2  in the flue gas, greatly simplifying the apparatus and reducing the energy required to capture CO 2 . Furthermore, the low residual content of oxygen gives less oxygen in the CO 2  product, which is important for applications of the CO 2  such as for increased oil recovery from oil wells. 
         [0010]    WO 99/48709 A, (Norsk Hydro AS), 24 Aug. 2000, relates to a power plant comprising a main power and secondary power system. The main power system is a combined cycle power plant comprising a gas turbine and a steam turbine where steam is generated by cooling the exhaust gas leaving the gas turbine. The cooled and expanded exhaust gas is then introduced into the secondary power system where the exhaust gas is compressed and again cooled before the compressed exhaust gas is introduced into an amine based CO 2  capture plant where the exhaust gas is separated in a CO 2  stream that is exported from the plant, and a CO 2  depleted stream that is reheated before the gas is expanded over a turbine for generation of electrical power before the expanded CO 2  depleted exhaust gas is released into the surroundings. By recompressing the exhaust gas after leaving the combined cycle power plant, the volume of the exhaust gas to be treated is substantially reduced, although not to the degree obtainable by substantially stoichiometric combustion. Additionally, the partial pressure of CO 2  of the exhaust gas is increased, which again increases the efficiency of the CO 2  capture in the absorption unit of the CO 2  capture plant. 
         [0011]    The CO 2  capture process is an energy consuming process substantially reducing the overall efficiency of the power plant. Substantially effort has been made to reduce the energy, or heat loss, caused by the CO 2  capture process, as the energy loss is of great economical interest. This energy loss is an important bar for implementing CO 2  capture, and a reduction of the energy loss is therefore important for making CO 2  capture economically possible. 
       SUMMARY OF INVENTION 
       [0012]    According to a first aspect, the present invention relates to a method for producing electrical power and capture CO 2 , where gaseous fuel and an oxygen containing gas are introduced into a gas turbine to produce electrical power and an exhaust gas, where the exhaust gas withdrawn from the gas turbine is cooled by production of steam in a boiler, and where cooled exhaust gas is introduced into a CO 2  capture plant for capturing CO 2  from the cooled exhaust gas leaving the boiler by an absorption/desorption process, before the treated CO 2  lean exhaust gas is released into the surroundings and the captured CO 2  is exported from the plant, wherein the exhaust gas leaving the gas turbine has a pressure of 3 to 15 bars, that the exhaust gas is expanded to atmospheric pressure after leaving the CO2 capture plant. By partially expanding the exhaust gas in the gas turbine to a pressure from 3 to 15 bara, the volume of the exhaust gas is higher and the pressure is higher than in a plant operating at substantially atmospheric pressure, without the need for costly flue gas re-compression. The lower volume and higher pressure gives several advantages. The reduced volume of the gas reduces the size requirement for the carbon capture equipment. The higher pressure of the exhaust gas increases the partial pressure of CO 2  and increases the efficiency and speed of the absorption process and thus the CO 2  capture. The higher pressure also makes it possible, in an efficient way, to use hot potassium carbonate based absorbents. Hot potassium carbonate based absorbents are stable and non-volatile and therefore environmentally friendly/acceptable in contrast to the different amines or ammonium carbonate absorbents that are used have been proposed for carbon capture plants. 
         [0013]    The presently preferred pressure of the exhaust gas leaving the gas turbine is 6 to 12 bara. The pressure is a compromise between the preferred pressure for the carbon capture and the required expansion in the gas turbine to give power for the gas turbine compressor and a temperature of the expanded gas that may be cooled further in the boiler. 
         [0014]    According to one embodiment, NOx in the exhaust gas is removed or substantially reduced after the exhaust gas is leaving the boiler, and before introduction into an absorber in the CO 2  capture plant. Introduction of a unit for NOx removal/reduction both reduces the emission of NOx from the power plant as such, and avoids problems with NOx in the carbon capture part of the plant. 
         [0015]    According to another embodiment, the exhaust gas leaving the boiler is further cooled by heat exchanging against CO 2  lean exhaust gas leaving the absorber, and wherein the CO 2  lean exhaust gas thereafter is expanded over a turbine. The heat exchanging of the exhaust gas to be introduced into the absorber against the CO 2  lean exhaust gas leaving the absorber, reduces the temperature of the exhaust gas to be introduced into the absorber, which is an advantage for the absorption in the stripper. Additionally, heating of the lean exhaust gas to be expanded over the turbine for expansion of lean exhaust gas, adds energy to the gas to be expanded and thus the energy output from the turbine. 
         [0016]    According to a second aspect, the present invention relates to a combined cycle power plant with CO 2  capture, comprising a gas turbine, a boiler for cooling of the exhaust gas leaving the gas turbine by generation of steam in heat tubes, a steam turbine cycle to produce electric power from the steam generated in the boiler, and a CO 2  capture plant comprising an absorber adopted to bring an aqueous absorbent in countercurrent flow to the exhaust gas to give CO 2  lean exhaust gas and a CO 2  rich absorbent, an lean exhaust line for withdrawal of the lean exhaust gas from the absorber, a rich absorbent line for withdrawing rich absorbent from the absorber and introducing the rich absorbent into a stripper for regeneration of the absorbent, a CO 2  withdrawal line for withdrawal of a CO 2  rich stream from the stripper, and a lean absorbent line for withdrawing regenerated, or lean, absorbent from the stripper and introducing the lean absorbent into the absorber, wherein the gas turbine is configured for partial expansion of the exhaust gas to a pressure of 3 to 15 bara, and wherein a turbine for expanding the exhaust gas to atmospheric pressure is arranged downstream of the absorber for expanding of the exhaust gas after capture of the CO 2 . 
     
    
     
       BRIEF DESCRIPTION OF DRAWINGS 
         [0017]      FIG. 1  is a principle drawing of a first embodiment of gas fired power plant according to the present invention, 
           [0018]      FIG. 2  is a principle drawing of a second embodiment according to the present invention, 
           [0019]      FIG. 3  is principle drawing of a third embodiment according to the present invention, and 
           [0020]      FIG. 4  is a principle drawing of a fourth embodiment of the present invention. 
       
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
       [0021]      FIG. 1  is a representation illustrating the basic concept of the present invention. The illustrated plant comprises three main parts, a gas turbine  1 , a steam turbine unit  2 , and a CO 2  capture plant  3 . 
         [0022]    Air is introduced via an air line  10  into a compressor  11 ,  11 ′ with an intercooler  100  between the stages. The compressor may also be operated without intercooler  100 . Compressed air is led via a line  12  and mixed with gas, such as natural gas, that is introduced in a fuel line  14  into a combustion chamber  13  where the gas is combusted under an elevated pressure. Typically, the pressure in the combustion chamber is in the range above 20 bar absolute, hereinafter abbreviated bara. High pressure up to above 40 bara is preferred. The combustion gas is withdrawn through a compressed exhaust line  15  and is introduced into a turbine  16 , where the gas is partially expanded, from the pressure in the combustion chamber to a pressure of 3 to 15 bara, such as typically 6 to 12 bara. 
         [0023]    Expansion of the exhaust gas reduces the temperature of the exhaust gas, and the degree of expansion is a compromise between the necessity of driving the compressor  11 ,  11 ′ and reducing the temperature of the exhaust gas sufficiently for the downstream equipment, and the preferred high pressure in the CO 2  capture unit. Expanding the pressure from typically 42 bara 1250° C. to 8.4 bara gives an outlet temperature of about 830° C., which is suitable for further external cooling by the production of steam. In contrast, the expansion from lower pressure turbines, which operate at typically 26 bara, will give much higher outlet temperatures. As an example, expanding the pressure from typically 26 beta 1250° C. to 8.4 bara will reduce the temperature of the exhaust gas to about 940° C. which would greatly complicate the further cooling by production of steam in an external apparatus. 
         [0024]    The turbine  16  is connected to a generator  17  via an axle  18 , for generation of electrical power. For efficient CO 2  capture, the pressure at the outlet from turbine  16  should be as high as possible. This is achieved when the power from turbine  16  is just sufficient to drive compressor  11 . In this case, the power from generator  17  will be small or zero. In this case, generator  17  may be removed. The axle  18  is illustrated as one common axle for the compressor  11 , turbine  16  and generator  17 , but the skilled man will understand that special designs, not shown on the drawing, such as two axles, may be preferred to reduce the problem caused by imbalance at the axle due to the different flow in the compressor and turbine. Most commercially available gas turbines will not be able to handle this imbalance at the axle. The inventors have identified at least one specific gas turbine having the required properties and that may tackle such imbalance, namely LMS100 from GE Power Systems, Houston, USA. 
         [0025]    The exhaust gas is withdrawn from the turbine  16  in an expanded exhaust line  19  and introduced into a boiler  20  where the exhaust as is cooled by generation of steam in heat tubes  21  inside the pressure container of the boiler  20 . Exhaust line  19  may be a double pipe where the outer pipe is insulated and kept at a relatively low temperature such as 300 to 400° C., the annulus between the pipes is pressurized with a flowing gas such as air with a temperature of not more than 300 to 400° C., and the inner pipe is used for the hot exhaust gas. Boiler  20  may consist of a pressure container which is kept at a relatively low temperature, such as 300 to 400° C. for structural integrity, and an internal enclosure where the hot exhaust gas is brought in contact with the heat tubes  21 . The low temperature of the pressure shell may be achieved by flowing air or a cold gas between the pressure shell and the internal heat tube enclosure, and/or by cooling the internal heat tube enclosure with water. 
         [0026]    Steam is withdrawn from the boiler  20  though steam line  22 , and is introduced into a steam turbine  23 . The steam turbine  23  is connected to a second generator  24  for generation of electrical power. 
         [0027]    Expanded steam is withdrawn from the steam generator  23  via an expanded steam line  25  and is cooled in a cooler  26  to ascertain that the steam is condensed. A circulation pump  27  is provided to pump the condensed steam, or water, through a water line  28  and back to the heat tubes  21  in the boiler  20 . The skilled man will understand that preheating of the water, using waste heat or steam side draw from the steam turbine  23 , and re-heat of the steam after partial expansion in steam turbine  23  before final expansion, will increase the efficiency of this cycle. 
         [0028]    Partly expanded and partly cooled exhaust gas, at a temperature between 250 and 450° C. is withdrawn from the boiler through line  29 . 
         [0029]    Combustion of carbonaceous fuel in the presence of air generates NOx. Besides its environmental effects, NOx may also be detrimental to the CO 2  capture. A Selective Catalytic Reduction (SCR) unit  30  therefore arranged downstream of the boiler  20 . Urea or NH 3  is introduced into the SCR unit and reacted with NOx over a catalyst for removal of NOx according to known technology. The temperature in the SCR unit is preferably between 250 and 450° C. Preferred operation temperature for a SCR unit is about 350° C. The SCR unit may be combined with a catalyst to oxidize CO to CO2. 
         [0030]    Downstream of the SCR unit one or more heat exchangers, exhaust gas scrubbers and possibly filters are arranged. The first heat exchanger  40  is a flue gas cooling unit far cooling of the exhaust gas to below 250° C. The second illustrated coaling unit  41  is illustrated as a countercurrent scrubber, or combined direct contact cooler and polishing unit, which is the preferred cooler as it both cools and saturates the exhaust gas with water, and removes residual contaminants such as NOx and ammonia slip from the flue gas. 
         [0031]    Cooling water is introduced into the cooler  41  through recirculation pipe  42  into the cooler  41  above a contact zone  43  and brought in counter-current flow to exhaust gas that is introduced into the cooler  41  below the contact zone. Water is collected at the bottom of the cooler  41  and recycled through the recirculation pipe  42 . Recirculation pipe  42  may be routed via a heat exchanger to remove excess heat, such that the fluid flowing to the top of contact zone  43  is colder than at the bottom of the contact zone. Recirculation pipe  42  may alternatively be routed directly to the top of countercurrent scrubber  51 , where it is cooled by contact with relatively dry gas from CO 2  absorber column  45 , via line  49 . Cooling occurs because some water is vaporized into the relatively dry gas. Circulation pipe  52  is then routed to the top of countercurrent scrubber  43 . In this way, the flue gas temperature may be adjusted as required for the CO 2  absorber. 
         [0032]    Cooled exhaust gas is withdrawn from the cooler  41  through a cleaned exhaust gas line  44  and is introduced into the lower part of an absorber column  45  where the exhaust gas is brought in counter-current flow with an aqueous absorbent in one or more contact zone(s)  46  inside the absorber. The aqueous absorbent is introduced into the absorber above the upper contact zone through a lean absorbent line  47 . 
         [0033]    CO 2  in the exhaust gas is absorbed by the absorbent inside the absorber to give a CO 2  laden, or rich, absorbent that is withdrawn from the bottom of the absorber  45  through a rich absorbent line  48 . 
         [0034]    A lean exhaust gas, from which more than 50%, preferred more than 80%, of the CO 2  in the exhaust gas introduced into the absorber is removed, is withdrawn through a lean exhaust gas line  49 . 
         [0035]    The pressure in the absorber is slightly lower than the pressure in the boiler  20  due to a minor pressure drop in the SCR  30 , heat exchanger  40  and direct contact cooler  41  and the lines connecting them. Preferably, the pressure drop is as small as possible as it is preferred that the pressure in the absorber is as high as possible. The pressure drop from boiler  20  to the absorber  45  is therefore preferably less than 1 bar, and preferably less than 0.5 such as 0.2 to 0.3 bar. This corresponds to a pressure in the absorber from 4.5 to 14.8 bare. 
         [0036]    The combination of high pressure and high CO 2  content of the exhaust gas introduced into the absorber makes it possible to reduce the volume of the absorber at the same time as high efficiency CO 2  capture is obtained. Significantly, this also enables the use of industrially proven capture equipment, without scale-up, and the use of hot potassium carbonate absorbent which in contrast to organic absorbents does not degrade by reaction with residual exhaust gas oxygen. 
         [0037]    The aqueous absorbent used in the absorber may be an amine solution, an amino acid solution, an ammonium carbonate solution or, preferably, an oxygen tolerant hot aqueous potassium carbonate based solution. Preferably the hot aqueous potassium carbonate based solution comprises from 15 to 35% by weight of K 2 CO 3  dissolved in water. Appropriate additives may be used to increase reaction rates and to minimize corrosion. Potassium carbonate based absorbent, with inorganic additives, are preferred as absorbent due to zero volatility and excellent chemical stability, in particular in the CO2 absorber which treats flue gas with high partial pressure of oxygen. Oxygen will degrade alternative absorbents, such as virtually all organic aqueous solutions including amines, amino acids etc, at the concentrations and the temperatures of the absorber and desorber. Degradation of the absorbent will add several problems and cost elements to the operations of the plant, including additional cost of separating degraded absorbent form the bulk of the absorbent, replacing degraded absorbent and waste handling. Degradation of absorbent may also give gaseous degradation products that may be discharged together with the CO 2  depleted exhaust gas. Some of these emissions will be toxic and environmentally unacceptable. 
         [0038]    In hot potassium carbonate based systems CO 2  is absorbed according to the following overall reversible reaction: 
         [0000]      K 2 CO 3 +CO 2 +H 2 O&lt;--&gt;2 KHCO 3 −ΔH rl=− 32.29 kJ/mol CO2)  (1)
 
         [0039]    Lean exhaust gas is withdrawn at the top of the absorber  45  through a lean exhaust gas line  49  and is introduced into a washing section  50  where the lean exhaust gas is brought in countercurrent flow against washing water in a contact section  51 . Washing water is collected at the bottom of the washing section through a washing water recycle line  52  and is re-introduced into the washing section above the contact section  51 . Cooling in line  52  may condense water vapour from the exhaust gas, and thus preserve water. Alternatively, heating will vaporize water, increasing the heat capacity and volume of the lean exhaust gas, and thus increasing the power produced in expander  54 . Heating may be accomplished by introducing hot water from countercurrent scrubber  41  to the top of countercurrent scrubber  50 , by re-directing circulation line  42  to the top of countercurrent scrubber  50 , and returning the water to countercurrent scrubber  41  via line  52  which is then connected to the top of countercurrent scrubber  41 . Washed lean exhaust gas is withdrawn from the top of the washing section through a treated exhaust pipe  53 . 
         [0040]    The gas in the treated exhaust pipe  53  is introduced into the heat exchanger  40  where the treated exhaust gas is heated against the hot exhaust gas leaving the SCR  30 . 
         [0041]    The thus heated and treated exhaust gas is then introduced into a gas turbine  54  where the gas is expanded to produce electrical power in a generator  55 . Expanded gas is withdrawn through an expanded exhaust gas pipe  56  and is released into the atmosphere. The skilled person will understand that residual heat in the expanded gas may be used in the steam cycle such as pre-heating of boiler water in line  28 , for the production of additional steam to the steam turbine, or for heating water flowing to the top of countercurrent scrubber  50 . 
         [0042]    Rich absorbent, i.e. absorbent laden with CO 2  is collected at the bottom of the absorber  45  and is withdrawn there from through the rich absorbent pipe  48 , as described above. 
         [0043]    An oxygen reduction unit  73  is preferably arranged in the rich absorbent line  48  to remove or substantially reduce the oxygen content of the rich absorbent before introduction into stripping column  61 . The oxygen reduction unit is provided to reduce the oxygen content of the rich absorbent to avoid an oxygen content in the captured CO 2  that is too high for the intended use of the CO 2 . In most oil fields, CO 2  having a too high oxygen content will not be accepted for enhanced oil recovery (EOR), which at short term will be the most probable large scale use for captured CO 2 . 
         [0044]    The oxygen reduction unit may be a flash tank, where oxygen is removed from the rich absorbent by flashing over a pressure reduction valve  72 . More preferably, the oxygen reduction unit  73  is a stripping unit where oxygen is removed by means of a stripping gas, most preferably nitrogen, but other inert gases such as CO 2 , may also be used 
         [0045]    The pressure in the oxygen reduction unit  73  is lower than the pressure in the absorber  46  to release oxygen. The pressure in the oxygen removal unit is, however, higher than the partial pressure of CO 2  in the exhaust gas introduced into the absorber through line  44 , to avoid that a substantial part of the CO 2  in the rich absorbent is stripped of together with the oxygen. Typically, the pressure in the oxygen reduction unit is between 2 and 3 bara. The stripped of oxygen and any stripping gas is withdrawn through a stripper line  74  for further treatment. 
         [0046]    The rich absorbent leaving the oxygen removal unit  73  is thereafter flashed over a flash valve  60  to a pressure slightly above 1 bara, such as 1.2 bara, before being introduced into a stripping column  61 . 
         [0047]    One or more contact section(s)  62  is/are arranged in the stripping column  61 . The rich absorbent is introduced above the upper contact section of the stripper, and countercurrent to steam introduced below the lowest contact section. Low partial pressure of CO 2  in the stripper, which is the result of low pressure and dilution of CO 2  in the stripper, causes the equilibrium in the reaction (1) above to be shifted towards left and CO 2  to be released from the absorbent. 
         [0048]    Lean absorbent is collected at the bottom of the stripping column  61  and is withdrawn through a lean absorbent pipe  63 . The lean absorbent pipe  63  is split in two, a lean absorbent reboiler pipe  64  that is heated in a reboiler  66  to give steam that is introduced as stripping gas into the stripping column through a steam line  67 , and a lean absorbent recycle line  65  in which lean absorbent is recycled into the absorber  45 . 
         [0049]    A flash valve  68  followed by a flash tank  69  is provided in the lean absorbent recycle line  65  to flash the lean absorbent. The gaseous phase is withdrawn from the flash tank  69  by means of a compressor  70 . The compressed and thus heated gaseous phase is introduced into the stripping column  61  as additional stripping steam. The liquid phase in the stripping tank  69  is withdrawn and pumped by means of a pump  71  to boost the pressure thereof before the liquid phase is introduced into the absorber  45  via line  47  as lean absorbent. 
         [0050]    A washing section comprising a contact section  80  and a collector plate  81  arranged below the washing section is arranged at the top section of the stripping column  61 . Gas leaving the top of the (upper) contact section  62  flows through the collector plate and through the contact section  80  before being withdrawn through a CO 2  withdrawal pipe  82  at the top of the stripping column  61 . 
         [0051]    Washing and cooling water is introduced over the washing section  80  through a washing water line  83  and is caused to flow countercurrent to the upstreaming CO 2  and water vapour mixture from the contact section(s)  62  for removal of any absorbent or other impurities in the gas and for condensing water vapour, thus heating the water. The water is withdrawn from the collector plate  81  through a wash water return line  84 . A circulation pump  85  is provided in line  84  to boost the pressure and facilitate the flow of the heated water before it is flashed in a flash valve  86  and introduced into a flash tank  87  to be separated in a liquid phase and a gaseous phase. Increased energy content and higher temperature of the water in wash water line  84  will reduce the required power for compressor  90 . The wash water in line  84  may therefore be routed to utilize suitable low temperature waste heat after it exits collector plate  81 , but before it enters flash valve  86 . Such waste heat sources may include intercoolers used in the CO2 compressor train  95 , waste heat from intercooler  100  and waste heat from direct contact cooler  41 . 
         [0052]    The liquid phase in flash tank  87 , now cooled by the low pressure flash operation, is withdrawn through a circulation pump  88  and is re-circulated to the washing contact section  80 . The gaseous phase is withdrawn through a compressor  90  and thereafter optionally cooled in a cooler  91  and led through a steam line  92  and introduced as additional stripping steam together with the steam in line  67 . Together with steam from compressor  70 , this supplies most of the steam needed for the operation of the stripping column  61 , thus minimizing the duty of reboiler  66  and maximizing the overall system efficiency. 
         [0053]    CO 2  and residual steam are collected at the top of the stripping column through a CO 2  withdrawal pipe  82 . The steam and CO 2  in pipe  82  is cooled in a cooler  93  and introduced into a flash tank  94 . Water is collected in the bottom of the flash tank  94  and is introduced into the water return line  83  as washing water. A water balance pipe  95  may be provided to add or remove water to pipe  83 , to balance the circulating amount of water.  FIG. 1  shows a relatively simplified and schematic overview of the water balance in this system. In practice, maintaining water balance in the CO 2  system is very important and may be more complex. For example, appropriate amounts of the liquid from flash tank  94  may be routed directly to the top of contact sections  62  in stripping column  61 , to the top of contact sections  46  in absorber column  45 , and/or to the top of contact section  51  in washing section  50 . 
         [0054]    The gaseous phase in the flash tank  94  is withdrawn and is compressed by means of a compressor  95  before the gas is further treated to give dry and compressed CO 2  that is exported from the plant for useful applications or for deposition. The skilled man will understand that several compressor stages and a dehydration unit may be needed, depending on the required CO2 purity and delivery pressure. 
         [0055]      FIG. 2  illustrates an alternative embodiment of the present invention where an optional fuel gas line  101  is provided to supply fuel to the boiler  20 , which is modified by introduction of one or more burners. The fuel can be gas, oil, coal, bio or other fuel. The specific boiler design used will depend on the fuel. In the following description, gas fuel is assumed. According to this embodiment, boiler  20  will first cool the flue gas from line  19  to a temperature suitable for extra firing using the fuel gas, by heat exchange with steam coil  21 . The gas is cooled to a temperature in the range 350 to 500° C., determined by the requirement for a stable flame when firing the partially oxygen depleted flue gas from line  19 , where higher temperature is better, and by the objective to minimize NOx formation, where lower temperature is better. Typically, the flue gas in line  19  contains between 12 and 13% oxygen by volume. After firing with extra fuel gas from line 101, the residual oxygen is reduced to below 6% by volume, preferred below 4% by volume, and even more preferred 3% by volume or less. Energy from this firing is transferred to steam coil 21, thus cooling the flue gas to between 250 and 450° C. This extra firing gives some very important effects. Steam turbine  23  will produce much more energy. The partial pressure of CO 2  in the flue gas from, boiler  20  will increase significantly, greatly simplifying the CO 2  capture in capture system  3 . The residual oxygen in the flue gas is much reduced, reducing the amount of oxygen dissolved in the rich CO 2  absorbent from CO 2  absorber  45 , and thus limiting the amount of oxygen that escapes into the CO 2  product. Depending on the residual oxygen content in the exhaust gas leaving the boiler  20 , and the requirements for the end use of the captured CO 2 , the oxygen reduction unit  73  may be omitted. Additionally, the amount of water vapour in the flue gas from boiler  20  increases, increasing the water condensation temperature in the flue gas, and thus increasing the amount and temperature of the energy available from cooler  41 . 
         [0056]    The skilled man will also understand that the key principle of the complete process is to enable high temperature and therefore efficient power production, systems  1  and  2 , in combination with pressurized exhaust gas purification, system  3 , without re-compression of exhaust gas, fuel conversion or air separation. Pressurized exhaust gas purification enables the use of hot potassium carbonate based absorbent, but will also enable and enhance other CO 2  capture methods such as amines, amino acids, ammonium carbonate, membranes or dry CO 2  absorbent based systems. 
         [0057]    Table 1 below is an illustration on the input and output from an exemplary plant according to the present invention to illustrate the total efficiency obtained by the present solution. Table 1 refers to  FIG. 1 , without extra firing in boiler  20  from a fuel gas line  101 . 
         [0000]    
       
         
               
               
               
               
             
               
               
               
               
             
           
               
                 TABLE 1 
               
               
                   
               
               
                 Variable 
                 Unit 
                 Comment 
                 Numerical 
               
               
                   
               
             
             
               
                   
               
             
          
           
               
                 Fuel gas flow 
                 kg/s 
                 — 
                 4.57 
               
               
                 Fuel gas HHV 
                 kJ/kg 
                 Higher heating value, includes condensation heat 
                 53140 
               
               
                   
                   
                 of water vapor formed in combustion 
               
               
                 Fuel gas LHV 
                 kJ/kg 
                 Lower heating value excluding condensation heat 
                 48260 
               
               
                   
                   
                 of water vapor formed in combustion 
               
               
                 Firing rate 
                 MW 
                 Gas turbine combustor, 12.4 mole % oxygen in flue 
                 242.8 
               
               
                 HHV 
                   
                 gas. 
               
               
                 Firing rate 
                 MW 
                 Gas turbine combustor, 12.4 mole % oxygen in flue 
                 220.6 
               
               
                 LHV 
                   
                 gas. 
               
               
                 Gas turbine air 
                 MW 
                 Gas turbine air compressor. 
                 115 
               
               
                 compr. duty 
               
               
                 Gas turbine 
                 MW 
                 Expanding flue gas from combustor. 
                 115 
               
               
                 expander 
               
               
                 Expander 54 
                 MW 
                 Expanding purified flue gas 
                 45.8 
               
               
                 Steam turbine 
                 MW 
                 Steam turbine parameters 180 bara 565° C. reheat 
                 73.3 
               
               
                 power 
                   
                 to 565° C., adiabatic efficiency 92% 
               
               
                 Gross el 
                 MW 
                 Expanders and steam turbine minus gas turbine 
                 118.8 
               
               
                 production 
                   
                 compressor 
               
               
                 Power plant 
                 MW 
                 4% of steam turbine power 
                 2.9 
               
               
                 parasitic 
               
               
                 CO2 plant 
                 MW 
                 Includes pumps and heat pumps 
                 3.3 
               
               
                 parasitic 
               
               
                 CO2 
                 MW 
                 Compressing about 11.7 kg/s CO2 (90% capture 
                 4.4 
               
               
                 compressor 
                   
                 rate) from 1.0 bara to 100 bara, adiabatic 
               
               
                 parasitic 
                   
                 efficiency 80% 
               
               
                 Power plant 
                 MW 
                 Gross el power minus parasitic 
                 108.2 
               
               
                 net el 
               
               
                 production 
               
               
                 Efficiency 
                 % 
                 Net el production divided by HHV firing rate 
                 44.5 
               
               
                 HHV 
               
               
                 Efficiency LHV 
                 % 
                 Net el production divided by LHV firing rate 
                 49.0 
               
               
                   
               
             
          
         
       
     
         [0058]    Table 2 below shows the feed gas to the CO 2  absorber for the exemplary plant shown in Table 1. Note the partial pressure of CO 2  which is about 0.3 bare. Although much higher than for gas turbine flue gas at atmospheric pressure, this is relatively low for hot potassium carbonate based CO 2  capture, where partial pressure of 0.5 bara or higher is preferred. Such low partial pressure may result in somewhat lower CO 2  capture rate than the desired 90%. Note also the actual volume flow of gas which is very low for a 108 MW system, enabling the use of a relatively small diameter CO 2  capture column. 
         [0000]    
       
         
               
               
               
               
             
               
               
               
               
             
           
               
                   
                 TABLE 2 
               
               
                   
                   
               
               
                   
                 Variable 
                 Unit 
                 Value 
               
               
                   
                   
               
             
             
               
                   
               
             
          
           
               
                   
                 Pressure 
                 bara 
                 8.0 
               
               
                   
                 Temperature 
                 ° C. 
                 92 
               
               
                   
                 Mass flow 
                 kg/s 
                 216.5 
               
               
                   
                 Actual volume flow 
                 m3/s 
                 28.9 
               
               
                   
                 H 2 O 
                 mole fraction 
                 0.097364 
               
               
                   
                 N 2   
                 mole fraction 
                 0.732313 
               
               
                   
                 Ar 
                 mole fraction 
                 0.008720 
               
               
                   
                 O 2   
                 mole fraction 
                 0.124829 
               
               
                   
                 CO 2   
                 mole fraction 
                 0.036775 
               
               
                   
                   
               
             
          
         
       
     
         [0059]    Table 3 below is an illustration of the input and output from an exemplary plant according to the present invention to illustrate the total efficiency obtained by the present solution. Table 3 refers to  FIG. 2 , with fuel line  101 , which includes extra firing in boiler  20 . 
         [0000]    
       
         
               
               
               
               
             
               
               
               
               
             
           
               
                 TABLE 3 
               
               
                   
               
               
                 Variable 
                 Unit 
                 Comment 
                 Numerical 
               
               
                   
               
             
             
               
                   
               
             
          
           
               
                 Fuel gas flow 
                 kg/s 
                 Total firing produces 2.5 mole % residual oxygen 
                 10.90 
               
               
                 Fuel gas HHV 
                 kJ/kg 
                 Higher heating value, includes condensation heat 
                 53140 
               
               
                   
                   
                 of water vapour formed in combustion 
               
               
                 Fuel gas LHV 
                 kJ/kg 
                 Lower heating value excluding condensation heat 
                 48260 
               
               
                   
                   
                 of water vapour formed in combustion 
               
               
                 Firing rate 
                 MW 
                 Gas turbine combustor plus co-firing, 2.5 mole % 
                 579.2 
               
               
                 HHV 
                   
                 oxygen in flue gas. 
               
               
                 Firing rate 
                 MW 
                 Gas turbine combustor plus co-firing, 2.5 mole % 
                 526.1 
               
               
                 LHV 
                   
                 oxygen in flue gas. 
               
               
                 Gas turbine air 
                 MW 
                 Gas turbine air compressor. 
                 115 
               
               
                 compr. duty 
               
               
                 Gas turbine 
                 MW 
                 Expanding flue gas from combustor. 
                 115 
               
               
                 expander 
               
               
                 Expander 54 
                 MW 
                 Expanding purified flue gas. 
                 45.5 
               
               
                 Steam turbine 
                 MW 
                 Steam turbine parameters 180 bara 600° C. reheat 
                 230.1 
               
               
                 power 
                   
                 to 600° C., adiabatic efficiency 92% 
               
               
                 Gross el 
                 MW 
                 Expanders and steam turbine minus gas turbine 
                 275.9 
               
               
                 production 
                   
                 compressor (gross el) 
               
               
                 Power plant 
                 MW 
                 4% of steam turbine power 
                 9.2 
               
               
                 parasitic 
               
               
                 CO 2  plant 
                 MW 
                 Includes pumps and heat pumps 
                 8.9 
               
               
                 parasitic 
               
               
                 CO 2   
                 MW 
                 Compressing about 26.6 kg/s CO2 (85% capture 
                 10.3 
               
               
                 compressor 
                   
                 rate) from 1.0 bara to 100 bara, adiabatic 
               
               
                 parasitic 
                   
                 efficiency 80% 
               
               
                 Power plant 
                 MW 
                 Gross el power minus parasitic 
                 247.5 
               
               
                 net el 
               
               
                 production 
               
               
                 Efficiency 
                 % 
                 Net el production divided by HHV firing rate 
                 42.7 
               
               
                 HHV 
               
               
                 Efficiency LHV 
                 % 
                 Net el production divided by LHV firing rate 
                 47.1 
               
               
                   
               
             
          
         
       
     
         [0060]    Table 4 below shows the feed gas to the CO 2  absorber for the exemplary plant shown in Table 3. Note the partial pressure of CO 2  which is about 0.7 bara. This is within the normal range for hot potassium carbonate based CO 2  capture, where partial pressure of 0.5 bara or higher is preferred. Note also the actual volume flow of gas which is about the same as in Table 2, although the power production is more than doubled. The thermal efficiency, which is very high in Table 1, with both CO 2  capture and compression included, is only slightly reduced with the extra firing. Significantly, the mole fraction of oxygen in the flue gas to the CO 2  absorber is much reduced. 
         [0000]    
       
         
               
               
               
               
             
               
               
               
               
             
           
               
                   
                 TABLE 4 
               
               
                   
                   
               
               
                   
                 Variable 
                 Unit 
                 Value 
               
               
                   
                   
               
             
             
               
                   
               
             
          
           
               
                   
                 Pressure 
                 bara 
                 8.1 
               
               
                   
                 Temperature 
                 ° C. 
                 98 
               
               
                   
                 Mass flow 
                 kg/s 
                 212 
               
               
                   
                 Actual volume flow 
                 m3/s 
                 28.1 
               
               
                   
                 H 2 O 
                 mole fraction 
                 0.120195 
               
               
                   
                 N2 
                 mole fraction 
                 0.754443 
               
               
                   
                 Ar 
                 mole fraction 
                 0.008981 
               
               
                   
                 O2 
                 mole fraction 
                 0.026469 
               
               
                   
                 CO 2   
                 mole fraction 
                 0.089911 
               
               
                   
                   
               
             
          
         
       
     
         [0061]      FIG. 3  illustrates an embodiment based on the embodiment of  FIG. 1 , where the gas in the treated exhaust pipe  53  after being heated in the heat exchanger  40 , is further heated in heating coils  53  provided in the boiler  20 , before the gas is expanded over the turbine  54 . This additional heating of the CO 2  lean exhaust gas increases the output from the turbine  54  with connected generator  55 . 
         [0062]      FIG. 4  illustrates still a different embodiment of the present invention, where both the additional features of the embodiments of  FIGS. 2 and 3  are included. Additional fuel is introduced into the boiler  20  via a fuel line  101 , as described for  FIG. 2 . Additionally, a heat coil  53 ′ as described with reference to  FIG. 3 , is provided to further heat the CO 2  lean exhaust gas before expansion over turbine  53 .