US20090025390A1

US20090025390A1 - Low CO2 Thermal Powerplant

Info

Publication number: US20090025390A1
Application number: US11/918,015
Authority: US
Inventors: Tor Christensen; Henrik Fleischer; Knul Borseth
Original assignee: Sargas AS
Current assignee: Sargas AS
Priority date: 2005-04-05
Filing date: 2005-04-08
Publication date: 2009-01-29
Also published as: RU2378519C2; JP2008534862A; EP1871993A1; RU2007140880A; CA2603529A1; WO2006107209A1

Abstract

A method for generation of electrical power mainly from a coal based fuel, where the combustion gas is separated into a CO₂rich stream and a CO₂poor stream in a CO₂capturing unit, the CO₂poor stream is released into the surroundings, and the CO₂rich stream is prepared for deposition or export, is described. A plant for executing the method and a preferred injector for the plant, is also described

Description

TECHNICAL FIELD

The present invention relates a method for generation of electrical power mainly from a coal based fuel, where the combustion gas is separated into a CO₂rich stream which is exported e.g. for safe deposition, and a CO₂poor stream that is released into the surroundings. The invention additionally relates to a plant for performing the method and a part of the plant.

BACKGROUND

The concentration of CO₂in the atmosphere has increased by nearly 30% in the last 150 years, mainly due to combustion of fossil fuel, such as coal and hydrocarbons. The concentration of methane has doubled and the concentration of nitrogen oxides has increased by about 15%. This has increased the atmospheric greenhouse effect, something which has resulted in:

- The mean temperature near the earth's surface has increased by about 0.5° C. over the last one hundred years, with an accelerating trend in the last ten years.
- Over the same period rainfall has increased by about 1%
- The sea level has increased by 15 to 20 cm due to melting of glaciers and because water expands when heated up.

Increasing discharges of greenhouse gases is expected to give continued changes in the climate. The temperature can increase by as much as 0.6 to 2.5° C. over the coming 50 years. Within the scientific community, it is generally agreed that increasing use of fossil fuels, with exponentially increasing discharges of CO₂, has altered the natural CO₂balance and is therefore the direct reason for this development.
It is important that action is taken immediately to stabilise the CO₂content of the atmosphere. This can be achieved if CO₂generated in a thermal power plant is collected and deposited safely. It is assumed that the collection represents three quarters of the total costs for the control of CO₂discharges to the atmosphere.
Discharge gas from thermal power plants typically contains 4 to 10% by volume of CO₂, where the lowest values are typical for gas turbines, while the highest values are only reached in combustion chambers with cooling, for example, in production of steam.
Capturing of CO₂from CO₂containing gas by means of absorption is well known, see e.g. EP 0 551 876. The CO₂containing gas is here brought into contact with an absorbent, usually an amine solution which absorbs CO₂from the gas. The amine solution is thereafter regenerated by heating the amine solution. The absorption is, however, dependent on the partial pressure of CO₂. If the partial pressure is too low, only a relatively small part of the total CO₂is absorbed. Normally the partial pressure of CO₂in combustion gas is relative low, for gas turbines a value of 0.04 bar is typical. The energy consumption in such a plant is about 3 times higher per weight unit CO₂than if the partial pressure of CO₂in the feed gas is 1.5 bar. The cleaning plant becomes expensive and the degree of cleaning and size of the power plant are limiting factors.
Therefore, the development work is concentrated on increasing the partial pressure of CO₂. According to WO 00/48709, the combustion gas that has been expanded over a gas turbine and cooled, is re-pressurized. The pressurized gas is then brought in contact with an absorbent. In this way, the partial pressure of CO₂is raised, for example to 0.5 bar, and the cleaning becomes more efficient. An essential disadvantage is that the partial pressure of oxygen in the gas also becomes high, for example 1.5 bar, while amines typically degrade quickly at oxygen partial pressures above about 0.2 bar. In addition, costly extra equipment is required.
Another possibility to raise the partial pressure of CO₂is air separation. By separating the air that goes into the combustion installation into oxygen and nitrogen, circulating CO₂can be used as a propellant (for gas turbines) or as a cooling gas (for coal fired boilers) in gas turbine combined cycle or coal fired power plants, respectively. Without nitrogen to dilute the CO₂formed, the CO₂in the exhaust gas will have a relatively high partial pressure, approximately up to 1 bar. Excess CO₂from the combustion can then be separated out relatively simply so that the installation for collection of CO₂can be simplified. However the total costs for such a system becomes relatively high, as one must have a substantial plant for production of oxygen in addition to the power plant. Production and combustion of pure oxygen represent considerable safety challenges, in addition to great demands on the material. This will also most likely require development of new turbines.
From WO 2004/001301 it is known to let the combustion take place under elevated pressure, cool down the combustion gas by generation of steam, split the combustion gas in a CO₂rich stream for deposition, and a CO₂poor stream, and expanding the CO₂poor stream over a turbine before it is released into the atmosphere. The plant in question is however a gas powered plant, and there is no mentioning of the use of coal as a fuel.
WO 2004/026445 relates to a method for separation of combustion gas from a thermal gas fired power plant into a CO₂rich stream and a CO₂poor stream. The combustion gas from the power plant is here used as an oxygen containing gas in a secondary combined power plant and separation plant.
The methods described above mostly relates to natural gas fired power plants. Today, however, coal is a more widely used fuel for thermal power plants than natural gas. Coal fired thermal power plants do, additionally, produce more CO₂per unit of electrical power than plants based on natural gas. Additionally, coal is an easy available and compared with natural gas, less expensive fuel.
Introduction of a coal based fuel, such as pulverized coal, into a pressurized combustion chamber is connected with technical challenges. Using air as a propellant for the coal dust will give an explosive mixture that will cause the combustion to start before entering the combustion chamber, an may even result in an explosion in the means for mixing air and coal or in connecting lines or in the combustion chamber. Using an inert gas as nitrogen would be another possibility but purification of nitrogen would add unacceptable cost to the plant. Additionally, addition of nitrogen would increase the total gas flow and result in a reduced partial pressure of CO₂in the combustion gas, which is disadvantageous for the separation of CO₂.
According to the so-called PFBC process, pulverized coal is mixed with water to give a paste-like mixture that is squeezed into the combustion chamber. The water-coal paste mixture is required in order to pump the fluid and thereby overcome the boiler combustion pressure. The water in the paste will vaporize with resulting loss of efficiency. In order to fire the water-coal paste, a fluid bed combustor is required. This is large and expensive equipment. In addition, the fluid bed gives a significant pressure drop, in the order of 2 bar. This reduces the downstream turbine power.
Accordingly, there is a need for a cost effective method for generation of electrical power from a coal based fuel where the combustion gas is split into a CO₂rich stream for deposition and a CO₂poor stream that may be released into the atmosphere.
According to a first aspect, the present invention relates to a method for generation of electrical power mainly from a coal based fuel, where the coal based fuel and an oxygen containing gas is introduced into a combustion chamber and combusted at an elevated pressure, the combustion gases are cooled down in the combustion chamber by generation of steam for production of electricity, the combustion gas is further cooled down and separated into a CO₂rich stream and a CO₂poor stream in a CO₂capturing unit, the CO₂poor stream is reheated and expanded over a turbine to produce electrical power, before the CO₂poor stream is released into the surroundings, wherein the CO₂rich stream is split into a stream for deposition or export, and a stream that is recycled to the combustion chamber. In the combustion chamber, the recycled CO₂is used to bring the pulverized coal into the combustion zone. If the pulverized coal is fed into the boiler by air instead of CO₂, there is severe explosion hazard. By use of CO₂instead of air, the explosion hazard is removed. Additionally, the pressure drop mentioned for fluidized bed reactors, is eliminated.
According to a preferred embodiment, at least a portion of the CO₂rich stream that is recycled to the combustion chamber is mixed with the coal based fuel before introduction to the combustion chamber and is injected into the combustion chamber together with the coal based fuel. The CO₂rich stream that is recycled to the combustion chamber may be used to fluidize the fuel in the tanks in the intermediary storage means, to avoid that settled coal fuel may hinder the injection into the combustion chamber. Additionally, the CO₂rich stream may be used as a propellant for the fuel to force the fuel from the tank into the combustion chamber.
The CO₂poor stream is preferably heated by heat exchanging against combustion gas from a secondary combustion chamber fired by gas, before the CO₂poor stream is expanded over a turbine. This is done to optimize the energy output from the plant and increase the part of the electricity that is produced by expansion of this stream before it is released into the surroundings.
The pressure in the combustion chambers may be from 5 to 35 bar, preferably 10 to 20 bar, more preferably from about 12 to about 16 bar. The absorption of CO₂in the CO₂capturing device is more effective at an elevated pressure than at a lower pressure. Combustion at an elevated pressure delivers combustion gas at an elevated pressure to the capturing device without energy consuming compressors. By keeping the combustion chamber nearly fully fired, the mass flow of flue gas to be purified is minimized, and the concentration and hence the partial pressure of CO₂are thus maximized.
It is preferred that the temperature in the combustion gas leaving the combustion chamber, is reduced to below about 350° C. by production of steam. By keeping the temperature in the combustion gas leaving the combustion chamber below 350° C., normal quality steel may be used in the equipment for further handling of the gas. Additionally, a high energy output is taken out as steam that is used for production of electric energy.
According to an embodiment, natural gas in introduced into the combustion chamber to support the combustion. The combustion becomes more effective when supported by addition of natural gas.
According to a second aspect, the invention relates to a thermal power plant mainly fired with a coal based fuel, the thermal power plant comprising a combustion chamber, means for introducing the coal based fuel and an oxygen containing gas into the combustion chamber, cooling means for cooling the combustion gas in the combustion chamber and means for separation of the combustion gas into a CO₂rich stream and a CO₂poor stream, wherein the power plant additionally comprises a line for recirculation of a part of the CO₂to the combustion chamber and a CO₂line for delivering the remaining CO₂rich stream for deposition or export.
The cooling means are preferably cooling coils inside the combustion chamber, where the cooling coils are cooling the combustion gas by generation of steam. Cooling coils inside the combustion chamber are effective in cooling the combustion gases at the same time as steam for generation of electric power is produced.
Preferably, the thermal power plant further comprises a steam turbine connected to a generator for the production of electrical power.
According to a preferred embodiment, a secondary combustion chamber fired by gas, for generation of heat for heating the CO₂poor stream, and turbine for expanding of the heated CO₂poor stream before it is released into the surroundings, are employed. Heating of the stream before it is released into the surroundings, adds energy to the gas. As a result the production of electrical power from the expansion of the CO₂poor stream over a turbine becomes more efficient and improves the total efficiency of the plant.
It is preferred that the turbine for expansion of the CO₂poor stream is connected to a generator for production of electrical power.
According to a third aspect the invention relates to an injector for a coal based fuel and an oxygen-containing gas into a pressurized combustion chamber, comprising a central pipe for injection of a mixture of pulverized coal based fuel and CO₂gas, surrounded by a plurality of injectors for oxygen containing gas. The construction of the injector having a central tube for injection of the coal and CO₂surrounded by injectors for oxygen containing gas ensures rapid and intimate mixing of the coal based fuel and the oxygen containing gas. This rapid and intimate mixing of the fuel and oxygen containing gas ensures optimal combustion in the combustion chamber.
According to a preferred embodiment, the injector additionally comprises one or more gas injectors for injection of natural gas. Addition of additional fuel in the form of natural gas may be used both in starting up the combustion and for maintenance of the combustion. Combustion of natural gas in the combustion chamber results in a better and more optimal combustion of the coal as the additional heat ensures that lighter components in the coal evaporates and are more effectively combusted.
Helically ribs may additionally be provided inside the central pipe. The helical ribs will cause the mixture of coal based fuel and CO₂have a vortex motion out of the central tube. This motion ensures even better mixing of the coal based fuel, the oxygen containing gas and any added natural gas.
According to one embodiment, the gas injectors are orientated so the gas rotates the opposite way relative to the coal powder. Rotating of the gas and coal powder opposite relative to each other ensures optimal mixing of gas and coal powder.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic diagram of a preferred embodiment of the invention;

FIG. 2 a) illustrates a longitudinal section through an injector according to the invention;

FIG. 2B illustrates the section A-A in FIG. 2 a;

FIG. 3 illustrates an exemplary grinding and intermediate fuel storage device for the plant according to the invention;

FIG. 4 is a longitudinal section through a combined heat exchanger and secondary combustion chamber for plant according to the invention;

FIG. 5 is a schematic diagram of an intermediate fuel storage device and means for taking care of CO₂; and

FIG. 6 is a schematic diagram of an exemplary CO₂capturing unit.

DETAILED DESCRIPTION OF THE INVENTION

An exemplary embodiment of a thermal power plant fired by natural gas and coal is illustrated in FIG. 1. Coal and optionally limestone, are introduced into a coal mill 12 through a coal line 10 and a lime stone line 11, respectively. The coal and the optional limestone, are milled to a ground mixture in the coal mill 12 to a particle size suitable for feeding into a combustion chamber.
The ground coal and optional limestone are carried on a conveying means 13 to intermediate storage means 14. The intermediate storage 14 in the illustrated embodiment comprises two or more storage units, each unit operated in a batch wise manner. Two or more units are necessary to give a continuous operation of a combustion chamber.
Each intermediate storage unit comprises an inlet valve 15, a storage tank 16 and an outlet valve 17. Additionally, each unit comprises one or more inlets for CO₂coming in from a CO₂-line 18. The ground mixture from the coal mill is conveyed to the intermediate storage device and filled into one storage tank at a time. The inlet valve 15 for the tank 16 to be filled is opened and the outlet valve 17 is closed. During or after filling of a tank 16, air is preferably purged from the tank by means of CO₂from the CO₂-line 18 to avoid creation of dangerous mixtures of air and coal dust.
The CO₂is controlled by means of a CO₂valve 19. After filling the tank and purging air from the tank, the inlet valve 15 is closed. Before the mixture in the tank is to be introduced into a combustion chamber 25, CO₂is filled into the tank to give a pressure in the tank that is higher than the pressure in the combustion, for example 0.5 to 1 bar, such as 0.7 bar, higher.
According to one embodiment, the CO₂inlets in the tank are placed so that the mixture in the tank is at least partly fluidized by the incoming stream of CO₂. The outlet valve 17 is thereafter opened and the mixture is led to an injector 21 through a line 20. The mixture is introduced into the combustion chamber 25 by the injector 21 together with CO₂, compressed oxygen containing gas from an air line 23 and optionally natural gas from a gas line 22. The injector 21 is described in more detail below with reference to FIG. 2. Gas from the gas line 22 is used to promote the combustion in the combustion chamber and to adjust internal combustion therein.
The oxygen containing gas may be air, oxygen enriched air or oxygen. The terms air and oxygen containing gas in the description and claims, used as synonyms to describe these possibilities.
The combustion in the combustion chamber 25 occurs at an elevated pressure, for example from 5 to 25 bar, more preferred from about 10 to about 20 bar, and most preferably about 15 bar.
Solid matter in the combustion chamber, such as non-combustible residues from the coal and calcium sulphate produced in binding of sulphur compounds in the combustion gases, is collected in the bottom of the combustion chamber and removed through a solids removal line 24.
The above described combustion chamber 25 is a presently preferred combustion chamber. The skilled man in the art will, however, understand that other constructions and principles of operation are possible. The described combustion chamber may, e.g. be substituted by a fluidized bed combustion chamber.
A substantial amount of the heat produced from the combustion is removed from the combustion chamber by producing steam in cooling coils 9 inside the combustion chamber. Most of the heat is removed from the top of the combustion chamber to reduce the temperature of the combustion gas leaving the combustion chamber 25 through a combustion gas line 35.
The steam produced in the cooling coil 9 is removed from the combustion chamber through a steam line 26 and is expanded over a turbine 28 to produce electricity in a generator 27. The expanded steam is led in a line 29 to a condenser 30, where the expanded gas is cooled and condensed. The condensed water is pumped by a pump 31 and pre-heated by heat exchanging in a pre-heater 32 before the water again is introduced through a line 33 into the cooling coil 9 in the combustion chamber 25. It must be noted that this circuit may be far more complex. The cooling coil 9 may be divided into two or more cooling coils each taking out a part of the heat to one or more steam turbines.
The combustion gas leaving the combustion chamber 25 through the combustion gas line 35 has preferably a temperature of about 350° C., or lower. A temperature of less than 350° C. in the combustion gas leaving the combustion chamber makes it possible to use relatively inexpensive steel in the construction of lines and processing equipment, and reduces the building cost.
The combustion gas in line 35 contains dust from the combustion chamber. This dust may be harmful for the further processing of the combustion gas. Accordingly, the dust has to be removed in a dust removal unit 36 comprising a plurality of cyclones and/or filters 38.
The illustrated dust removal unit 36 comprises two lines in parallel each comprising a number of cyclones and or filters in series. The unit may, however, comprise of more than two lines in parallel. To allow continuous operation of the dust removal unit, one or more of the parallel lines may be shut down for cleaning and service as long as at least one of the parallel lines are open and in operation at all times.
The inlet side of one of the parallel lines may be closed by means of an upstream valve 37, whereas the other side of the parallel lines, may be closed by a downstream valve 40. Dust, separated in the cyclones and/or filters, is removed through dust removal lines 39.
From the dust removal unit, the dust free combustion gas is led via a line 41 to a selective catalytic reduction unit (SCR unit) for substantial reduction of NOx produced in the combustion chamber. In the SCR unit 42, NOx can be removed with NH₃, according to the reaction 3NO+2NH₃=2.5N₂+3H₂O. This cleaning has up to 90% efficiency at atmospheric pressure, but is assumed to be much better at the working pressure which is typically above 10 bara. It will therefore be possible to clean NOx down to a residual content of 5 ppm or better. By adapting the heat exchangers, the gas can be given a temperature that is optimal for this process. Other known methods for NOx removal without using NH₃may also be used. The NH₃method has the disadvantage that it gives some NH₃“slip”.
The cleaned gas, is leaving the SCR unit in a line 43 and is cooled in a heat exchanger 44. From the heat exchanger 44, the gas is led into a condenser 47 in a line 46. In the condenser, the gas cooled further down and condensed water is removed from the gas. The gas leaving the condenser is led to a CO₂capturing unit 49 in a line 48.
Alternatively, a gas scrubber may be provided upstreams of the condenser. In the optional gas scrubber the gas is saturated with water vapor, and the gas is cooled by countercurrent contact with water at suitable temperatures. The scrubber may employ chemicals to oxidize and/or absorb multiple flue gas stream residuals including NOx, SOx, other acids or gases, and particulates. Such chemical may be the NH₃“slip” from the SCR system which provides an alkaline solution, or a special chemical with alkaline and/or oxidizing properties. In the latter case, the scrubber may replace the SCR unit 42 completely.
The purification of the flue gas is essential to minimize the formation of heat stable salts in the CO₂capturing absorbent, and to minimize the degradation of CO₂capturing performance with time.
The CO₂capturing unit typically comprises an absorber where the flue gas flows countercurrent to an absorbent such as an amine, hot carbonate or a physical absorbent. The amount of CO₂in the flue gas is typically reduced by 90 to 99% in the absorber before the flue gas leaves the absorber as a CO₂poor stream. The absorbent with absorbed CO₂(rich absorbent) is heated in a solvent/solvent heat exchanger and regenerated in a stripper column. The regenerated solvent is cooled in the solvent/solvent exchanger, cooled in a trim cooler and returned to the CO2 absorption tower, whereas the CO₂is removed from the stripper column as a CO₂rich stream. FIG. 6 illustrates an exemplary CO₂capturing unit. The detailed design the unit will, however, depend on the type of solvent used.
The CO₂capturing unit 49 may be any kind of unit capable of splitting the partly cleaned combustion gas in a CO₂-rich stream leaving the unit through a CO₂-line 51, and a CO₂-poor stream leaving the unit through a line 50. The CO₂-rich stream in line 51 is compressed to a pressure of about 100 bar in a compressor 52 powered by a motor 53. A part of compressed CO₂-rich stream is leaving the compressor in line 54 and is recycled as a source of CO₂for the intermediate storage means 14. The remaining CO₂is compressed further and is removed from the plant in a CO₂-line 55.
The CO₂-poor stream leaving the CO₂capturing unit 49 through line 50 is introduced into a re-humidifier, where the gas is heated and saturated with water before it is led through a line 57 to the heat exchanger 44 where the CO₂-depleted gas is heated against the hot gas in line 43. Preferably, air or another suitable gas is introduced into line 57 (or alternatively line 50) through an air line 73 to make up for the mass of the CO₂that has been removed from the combustion gas so that the heat capacity of the CO₂-poor stream is approximately the same as the heat capacity of the combustion gas in line 43. The air is taken into the system through an air intake 70 and is compressed by means of a compressor 71 powered by a motor 72. As an alternative, some air from the compressor 78 may be by-passed the combustor 25 and downstream equipment, and introduced in line 50 or line 57. (This is not shown in FIG. 1).
The heated CO₂-poor stream leaves the heat exchanger 44 through a line 58 and is introduced into a heat exchanger 59 where the CO₂-poor stream is heated against combustion air entering the heat exchanger in a line 82 from a secondary combustion chamber 81. The secondary combustion chamber 81 is fired by natural gas from a gas inlet line 80. Oxygen for the combustion in the secondary combustion chamber 81 is introduced into the secondary combustion chamber through a line 87.
The cooled down gas from the heat exchanger 59 leaves the heat exchanger in a line 86 that is introduced into the line 41 for CO₂-removal. A part of the gas in line 86 may be taken out in a line 83 and recycled into line 82 by means of a fan 84 and a line 85. The recirculation through line 83 is used to increase the mass flow of heated gas through the heat exchanger 59 from line 82. If the heat exchanger is built of material that stand high temperature, such as up to 2000° C., the recirculation is superfluous.
The heated CO₂-poor stream leaving the heat exchanger 59 in a line 60, is expanded over a turbine 61. The expanded CO₂-poor stream leaving the turbine 61 through a line 62 is cooled further in heat exchangers 63 before the gas stream is released into the atmosphere through a line 64. The heat exchanger(s) 63 may be identical to the preheater 32, preheating the water entering the cooling coils in the combustion chamber so that energy in the expanded CO₂-poor stream is used to heat the water in the preheater 32.
Air for both the combustion chamber 25 and the secondary combustion chamber 81 is in the illustrated embodiment introduced to the system through an air intake 75. The air in air intake 75 is compressed, preferably in a two step compressor, having two compressors 76 and 78 and an intercooler 77. The compressed gas leaving the compressor 78 in a line 79, is split into two streams into the air line 23 leading to the injector 21, and into the second air line 87 leading into the secondary combustion chamber 81. A leakage in the compressors 76, 78 and/or the turbine 61 is illustrated by a leakage line 88. The compressors at the illustrated embodiment is placed on a shaft 66 that is common to both the compressors 76, 78, the turbine 61 and a generator 65 for generation of electric power. As an alternative, there may be a two stage compressor 76, 78 (as shown) and a two stage turbine 61 (low pressure stage and high pressure stage)—not shown—such that the low pressure turbine drives the low pressure compressor 76, and the high pressure turbine drives the high pressure compressor 78 plus the generator 65.
FIG. 2 a represents a length section through the combustion chamber and a preferred embodiment of an injector 21. The injector 21 is supported by a collar 101 welded to the wall of the combustion chamber. The injector is inserted into the collar 101 and fastened to the collar by means of a holding plate 100. The injector comprises a central tube 102 for injection of coal, air injectors 103 and gas injectors 104 surrounding the central tube. The collar 101 is preferably cooled down by means of air from air inlet 109 circulating in a cooling jacket 106 surrounding the collar. Preferably the air heated by cooling the collar in the cooling jacket is led in a line 107 and is introduced into the air injectors 103 and injected into the combustion chamber.
The mixture of coal, CO₂and optionally lime stone entering the injector 21 through line 20, is introduced into a central pipe 102. The mixture is blown through the tube by means of pressurized CO₂and injected into the combustion chamber. By using nozzles, as indicated in the figure, to inject the air into the combustion chamber, the venturi effect caused by the nozzles will cause an additional drag of material from the central pipe into the combustion chamber.
The hot and burning gas/coal mixture leaving the injector 21 may be harmful to the wall of the combustion chamber and steam heating coils 9. To avoid damage to the wall of the combustion chamber and steam heating coils 9, a reflector plate 111 is arranged opposite the injector 21 for reduction of velocity of remaining unburned particles and avoid or reduce damages to the inner wall of the combustion chamber. Preferably, the reflector is cooled by means of CO₂delivered through a gas line 110 being circulated trough cooling channels 112 at the rear side of the reflector plate. Normally, one reflector plate is arranged per injector if more than one injector is arranged in the wall of the combustion chamber. Alternatively, the reflector may be frustoconical having openings for the injectors.
FIG. 2 b illustrates the cross section A-A in FIG. 2 a. The central pipe 102 is surrounded by a plurality of air injectors 103. The gas injectors, for injection of natural gas introduced into the injector in gas line 22, are in the illustrated injector, situated inside one or more of the air injectors. A plurality of helically shaped ribs 105 at the inner wall of the central pipe, causes the coal mixture to rotate and accordingly create turbulence in the combustion chamber. The creation of turbulence is important to assure proper mixing of the injected coal, gas and air to promote optimal conditions for combustion.
FIG. 3 illustrates a combined mill and intermediate storage device 14. Coal and lime stone are transported on conveying means 10, 11, 13 into a funnel 150 leading to a mill 12. The funnel 150 has a plurality of internal flaps 151 for reduction of the coal/limestone feeding velocity into the mill 12. The reduced feeding velocity will allow for optimum abatement of air. The mill 12 preferably comprises more than one mill, where the incoming coal and limestone firstly are introduced into a mill and thereafter into a fine mill to give the preferred particle size.
The mill and lower part of the funnel is preferably purged by CO₂entering from a purge line 152 to reduce the amount of oxygen or air that is carried with the coal and limestone, as a mixture of coal dust and oxygen may be explosive. The stream of CO₂in the purge line is controlled by a valve 153.
From the mill, the coal and limestone dust is vertically fed by an Archimedes screw 13 to the tank 16. A valve 15 inserted between the conveyor 13 and the tank 16 is used to close the inlet of the tank when the tank is full of coal and limestone dust. When the tank 16 is to be emptied into the combustion chamber, the valve 15 is closed, CO₂is introduced into the tank at the top of the tank through a CO₂line 154 controlled by a valve 155, and/or through a CO₂line 157 controlled by a valve 158. The introduction of CO₂either through the line 154 or line 157 will boost the pressure in the tank. The pressure in the tank is increased to a pressure that is higher than the pressure in the combustion chamber. Preferably, the pressure in the tank is from 0.5 to 1 bar higher than in the combustion chamber. Introduction of CO₂through line 157, close to the bottom of the tank, will at least partly fluidize the content of the tank. The valve 17 in line 20 is then opened, and the mixture of CO₂, coal dust and limestone is forced through the line 20, through the injector 21 and into the combustion chamber as described above. After the tank 16 is emptied, the valve 17 is again closed, valve 15 is opened, and the tank again filled with dust as described above.
FIG. 4 illustrates a combined secondary combustion chamber and heat exchanger 200 to substitute for the secondary combustion chamber 81, heat exchanger 59 and lines connecting them. This combination is more heat efficient and avoids or reduces the use of connection lines.
Air and natural gas are introduced through an air line 203 and a gas line 202, respectively, into a combustion chamber 201. CO₂is introduced from a CO₂line 204 through a cooling jacket 205 to cool down the upper part of the combustion chamber, and is released into the combustion chamber to adjust the gas composition in the combustion chamber. The burning gas in the combustion is forced downwards in the combustion chamber and through openings 206 near the bottom of the combustion chamber. The warm flue gas from the combustion chamber is circulated in a flue gas chamber surrounding the combustion chamber. The hot flue gas in the flue gas chamber is cooled by heat exchange against the CO₂-poor stream from line 58 entering the device through an inlet 212. The CO₂poor stream circulates in the circulation space defined between the outer wall of the flue gas chamber 207 and a heat exchanger shell 210.
The flue gas from the secondary combustion chamber 201 leaves the device through a flue gas outlet 208 and is introduced into line 86. The heated CO₂poor stream leaves the device through a heat exchanger outlet 213 into line 60. The air to be introduced into air line 203 is preferably preheated by heat exchanging against the CO₂poor stream, as the air is introduced into an air inlet to a jacket 216 surrounding at least a part of the heat exchange shell 210. The heated air is removed through an air outlet 217 and is introduced into air line 203.
This combined combustion chamber and heat exchanger gives a more compact construction of the combined device. A high temperature difference over the wall separating the combustion chamber and the heat exchange part of the device, results in the need of a relatively small heat exchange area.
FIG. 5 illustrates an embodiment of the intermediate storage means 14, including storage means 250 for CO₂. The CO₂storage means 250 comprises a CO₂storage tank 255, a compressor 259 run by a motor 263, a dust filter 252 and connecting lines 257 and 261, and several valves 253, 254, 258, 260 and 262, controlling the flow in the system. The CO₂storage means 250 may be closed of from the intermediate storage means 14 by means of an optional valve 251.
When CO₂under pressure in the tank 255 is to be filled into one of the tanks 16, 16′ or 16″, the valve connected to the tank 16, i.e. 248, 248′ or 248″ is opened. The valves 256 and 262 are then opened to allow the gas in tank 255 flow through the lines 256, 261 and 249, 249′ or 249″. When the flow from tank 255 into tank 16, 16′ or 16″ declines due to lower pressure difference, valve 256 is closed, valves 254, 260 and 258 are opened and the CO₂from the tank 255 is compressed by the compressor 259 until the pressure in the tank 255 is about atmospheric pressure. All valves 253, 254, 256, 258, 260, 262 and 248 are subsequently closed.
To fill excess CO₂from a tank 16, 16′ or 16″, into the tank 255, the corresponding valve 248, 248′ or 248″ is opened. The CO₂is then allowed to flow through the filter 252 from the tank 16, 16′ or 16″ into the tank 255 by opening valves 253 and 254. As soon as the flow decreases due to reduced difference in pressure between the tanks, valve 254 is closed, the valves 260, 258 and 256 are opened and the gas from the tank 16, 16′ or 16″ is compressed and led to tank 255 for temporary storage. When the pressure in the tank 16, 16′ or 16″ is about atmospheric pressure, all the valves 248, 248′, 248″, 253, 254, 256, 258, 260 and 262 are closed.
It is obvious for the skilled man that CO₂may be introduced or removed from the tank 16 through any CO₂lines into the tank, such as line 154, 157 or 18 and that line 249 is illustrative and may cover any of the mentioned lines alone or in combination.
FIG. 6 illustrates an exemplary and somewhat simplified CO₂capturing unit 49. The cooled down combustion gas enters the unit 49 through line 48 and is introduced into an absorber 300 near the bottom. The cleaned combustion gas leaves the absorber 300 in line 50 close to the top of the absorber. An absorbent, such as an amine or hot carbonate solution, is introduced into the absorber through a line 301 close to the top of the absorber, and leaves the absorber as a rich absorbent (rich in CO₂) through a line 302 close to the bottom of the absorber. The countercurrent flow of gas to be cleaned and absorber through the absorber ensures optimal conditions for absorption of CO₂.
The rich absorbent in line 302 is heated in a heat exchanger 303 against regenerated (lean) absorbent before the rich absorbent is introduced into a stripping column 305 close to the top thereof. The temperature in the stripping column is higher and the pressure is lower than in the absorber 300, causing CO₂to be released from the absorbent. CO₂released from the absorbent is removed from the stripping column through a CO₂line 306. The CO₂in line 306 is cooled in a reflux condenser 307 to remove humidity in the CO₂rich stream leaving the CO₂capturing unit through line 51. Humidity that is condensed in the reflux condenser 307 is returned to the stripping column in a reflux line 308.
The stripped or lean absorbent is taken out close to the bottom from the stripping column 305 in line 301. The lean absorbent in line 301 is cooled in heat exchanger 303 and cooler 311 before it is reentered into the absorber 300. A part of the lean adsorbent may be taken out in a heating circuit 309 where it is heated in a reboiler 310 before the heated lean absorbent is reintroduced into the stripping column 305.
In an exemplary plant according to FIG. 1, key figures for temperature, pressure and mass flow may be as follows:

TABLE 1

Pressure, temperature, mass flow and effect for different
units/at different locations in a 400 MW plant

		Temperature	Mass flow
Ref. No.	Pressure (bara)	(° C.)	(kg/s)	Effect (MW)

13	1,013	30	21 (coal)
22	20	15	2.3
23	16	300	300
26	300	600	272
27				428
35	16	350	323
46		120-130
48		40-90
55	100	30	78
58	15	330	385
60	15	850	385
65				80
73	16	145	50
75	1,013	15	400
80	20	15	5
82		870
86	15	330	90
87	16	300	85
88	16	300	15

The skilled man in the art will understand the mentioned heat exchangers, turbines, compressors and the like may represent two or more parallel and/or serially connected devices. Additionally, where two or more parallels are mentioned, the number of parallels may be different from the exemplified embodiment.

Claims

1. A method for generation of electrical power mainly from a coal based fuel, where the coal based fuel and an oxygen containing gas are introduced into a combustion chamber and combusted at an elevated pressure, the combustion gases are cooled down in the combustion chamber by generation of steam for production of electricity, the combustion gas is further cooled down and separated into a CO₂rich stream and a CO₂poor stream in a CO₂capturing unit, the CO₂poor stream is reheated and expanded over a turbine to produce electrical power, before the CO₂poor stream is released into the surroundings, wherein the CO₂rich stream is split into a stream for deposition or export, and a stream that is recycled to the combustion chamber.

2. The method according to claim 1, wherein at least a portion of the CO₂rich stream that is recycled to the combustion chamber is mixed with the coal based fuel before introduction to the combustion chamber and is injected into the combustion chamber together with the coal based fuel.

3. The method according to claim 1, wherein the CO₂poor stream is heated by heat exchanging against combustion gas from a secondary combustion chamber fired by gas, before the CO₂poor stream is expanded over a turbine.

4. The method according to claim 1, wherein the pressure in the combustion chambers is from 5 to 35 bar.

5. The method according to claim 4, wherein the pressure is from 10 to 20 bar, more preferably from about 12 to about 16 bar.

6. The method according to claim 1, wherein the temperature in the combustion gas leaving the combustion chamber, is reduced to below about 350° C. by production of steam.

7. The method according to claim 1, wherein natural gas in introduced into the combustion chamber to support the combustion.

8. A thermal power plant mainly fired with a coal based fuel, the thermal power plant comprising a combustion chamber (25), means (21) for introducing the coal based fuel and an oxygen containing gas into the combustion chamber (25), cooling means for cooling the combustion gas in the combustion chamber and means (49) for separation of the combustion gas into a CO₂rich stream and a CO₂poor stream, wherein the power plant additionally comprises a line (54) for recirculation of a part of the CO₂to the combustion chamber and a CO₂line (55) for delivering the remaining CO₂rich stream for deposition or export.

9. The thermal power plant according to claim 8, wherein the cooling means are cooling coils (9) inside the combustion chamber (25), where the cooling coils are cooling the combustion gas by generation of steam.

10. The thermal power plant according to claim 9, further comprising a steam turbine (28) connected to a generator (27) for the production of electrical power.

11. The thermal power plant according to claim 8, further comprising a secondary combustion chamber (81) fired by gas, for generation of heat for heating the CO₂poor stream, and turbine (61) for expanding of the heated CO₂poor stream before it is released into the surroundings.

12. The thermal power plant according to claim 11, wherein the turbine (61) is connected to a generator (65) for production of electrical power.

13. An injector for a coal based fuel and an oxygen-containing gas into a pressurized combustion chamber, comprising a central pipe (102) for injection of a mixture of pulverized coal based fuel and CO₂gas, surrounded by a plurality of injectors (103) for oxygen containing gas.

14. The injector according to claim 13, additionally comprising one or more gas injectors (104) for injection of natural gas.

15. The injector according to claim 13, wherein helically ribs (105) are provided inside the central pipe (102).

16. The injector according to claim 15, wherein the gas injectors (104) are orientated so the gas rotates the opposite way relative to the coal powder.

17. The method according to claim 2, wherein the CO₂poor stream is heated by heat exchanging against combustion gas from a secondary combustion chamber fired by gas, before the CO₂poor stream is expanded over a turbine.

18. The method according to claim 2, wherein the pressure in the combustion chambers is from 5 to 35 bar.

19. The method according to claim 3, wherein the pressure in the combustion chambers is from 5 to 35 bar.

20. The method according to claim 2, wherein the temperature in the combustion gas leaving the combustion chamber, is reduced to below about 350° C. by production of steam.