Coal-fired power station and method for operating the coal-fired power station

Abstract

In a method for operating and controlling/regulating a power station comprising a coal-fired steam generator (11), the steam generator (11) of which is rated for the steam parameters achievable by the heat transfer onto the steam mass flow upon coal firing in the steam generator (11) carried out using combustion air, a solution is to be created, which enables the operation of coal-fired power stations rated for air operation utilizing a firing of the fuel carried out according to the oxy-fuel process in the firing chamber of the steam generator of the coal-fired power station. This is achieved in that a firing of the fuel containing coal is carried out in the steam generator (11) according to the oxy-fuel process utilizing approximately pure oxygen containing more than 95% by volume, and recirculated flue gas containing a high amount of CO2, such that the mass flows of all fuel flows supplied to the coal-fired burners (10) and to the steam generator (11), and the combustion gas, carrier gas, and process gas flows from the combustion oxygen and/or recirculated flue gas are configured and adjusted to each other with respect to the respective composition ratio thereof of oxygen and/or flue gas such that the heat transfer occurring in the steam generator by means of flame radiation, gas radiation, and convection onto the steam mass flow is maintained equal overall in the steam/water cycle as compared to air combustion, in particular, that the same steam parameters are obtained.

Description

The invention relates to a method for operating and for controlling a power station which comprises a coal-fired steam generator, whose steam generator is designed for steam parameters which can be achieved for coal combustion, which is carried out with combustion air, in the steam generator by heat transfer to the steam mass flow.

The invention furthermore relates to a coal-fired power station having a coal-fired steam generator whose steam generator is designed for steam parameters which can be achieved for coal combustion, which is carried out with combustion air, in the steam generator by heat transfer to the steam mass flow.

In order to make it possible to greatly reduce the CO₂ emissions when electricity is generated from fossil fuels in the future, the two concepts described in the following text are currently being developed, which can be used in conventionally designed coal-dust-fired power stations (hard coal or brown coal) with large steam generators, and which are intended to be commercially available for future power station generations.

1. Post-combustion CO₂ capture by downstream CO₂ flue gas washing.

In this case, the CO₂ which is present in a small concentration (˜13% by volume) in the flue gas is absorbed with washing solutions in a packed column with energy being released, and is desorbed in a second column, with energy being supplied. The additional energy supply which is required for desorption (generally in the form of energy supplied from steam tapped off from the medium-pressure turbine) leads to decreases in efficiency of 10-12 percentage points in comparison to power stations without such CO₂ capture. This technology has the advantage, inter alia, that the method is carried out after the combustion process and has no reactions on the steam generator, thus allowing existing power stations to be retrofitted. The disadvantages include the large amount of space required for the flue gas washer and the high energy consumption which—in the case of possible retrofitting—results in a large amount of modification effort in the area of the steam circuit and of the turbine.

2. Oxyfuel combustion with direct CO₂ compression

In the oxyfuel process, the CO₂ concentration in the flue gas is greatly increased by using a mixture of fed-back flue gas and virtually pure oxygen instead of air for combustion of the coal. In this case, in particular, the sealing of the power station installation—which for safety reasons is still operated at a slightly reduced pressure—with all its components, the purity of the oxygen taken from an air separation unit (ASU), the quality of the flue gas cleaning installations (denitrification (DeNOx), desulfurization (DeSOx), dust removal) and the process control—particularly the location of the flue gas feed back (for example the points/locations 1-6 in FIG. 1)—are the critical factors for the purity of the CO₂ which leaves the process after flue gas drying (condensation of the water by cooling). In this case, the CO₂ concentration should in any case be sufficiently high, and the hazardous-substance load so low, that the CO₂ can be compressed directly and be supplied for storage. The advantage of this concept is that both the steam generator as well as the steam circuit and the turbine design, which are designed for a conventional air mode, do not fundamentally differ from those which are designed for the oxyfuel mode. In addition, the efficiency reductions in this process are 8-10 percentage points lower than in the case of downstream CO₂ flue gas washing, in comparison to power stations without CO₂ capture. These reductions are contributed to significantly by the electrical energy required for the air separation unit that has to be installed itself (>60% of the reductions) as well as the additional flue gas compression (>25% of the reductions). The proportion of the other units required in comparison to conventional coal-fired power stations in the additional energy requirement is <15%.

In order now to provide the value stability of investments that have already been made in newly built coal-fired power stations with the greatest possible flexibility in terms of future developments related to CO₂ capture which may still have to be retrofitted, it is necessary for present newly built power stations to be able to (continue to) operate in the future by conversion to the oxyfuel mode, and as low-CO₂ power stations. However, it is also desirable for older, already existing coal-fired power stations to be equipped with CO₂ capture cost-effectively, that is to say with as little investment cost as possible and with as little loss of efficiency as possible, and to allow them to be converted to oxyfuel operation with CO₂ capture.

The invention is therefore based on the object of providing a solution which allows coal-fired power stations designed for air operation to be operated with combustion of the fuel based on the oxyfuel process in the furnace area of the steam generator of the coal-fired power station.

In one method of the type mentioned initially, this object is achieved according to the invention in that combustion of the fuel, which contains carbon, is carried out in the steam generator on the basis of the oxyfuel process with approximately pure oxygen, which contains more than 95% by volume of O₂, and recirculated flue gas with a high CO₂ content, such that the mass flows of all the fuel flows as well as combustion gas flows, feed gas flows and process gas flows which are supplied to the coal-burners and to the steam generator are formed from combustion oxygen and/or recirculated flue gas in their respective composition ratio of oxygen and/or flue gas, and are matched to one another, such that the heat transfer which takes place in the steam generator by flame radiation, gas radiation and convection to the steam mass flow in the steam/water circuit of the steam generator is kept the same overall in comparison to the air combustion, in particular with the same steam parameters being maintained.

In a power station of the type referred to in more detail initially, the above-mentioned object is achieved according to the invention in an analogous manner in that combustion of the fuel, which contains carbon, is carried out in the steam generator on the basis of the oxyfuel process with approximately pure oxygen, which contains more than 95% by volume of O₂, and recirculated flue gas with a high CO₂ content, such that the mass flows of all the fuel flows as well as combustion gas flows, feed gas flows and process gas flows which are supplied to the coal-burners and to the steam generator are formed from combustion oxygen and/or recirculated flue gas in their respective composition ratio of oxygen and/or flue gas, and are matched to one another, such that the heat transfer which takes place in the steam generator by flame radiation, gas radiation and convection to the steam mass flow in the steam/water circuit of the steam generator remains the same overall in comparison to the air combustion, in particular with the resultant steam parameters being the same.

Advantageous developments and expedient refinements of the invention are specified in the respective dependent claims.

The invention means that a coal-fired power station designed for combustion with air can also be operated without any problems as a CO₂-free or low-CO₂ power station operating on the basis of the oxyfuel process with recirculated flue gas, and can be converted to or retrofitted with the oxyfuel process or oxyfuel mode. In a power station such as this, the burners are then operated with a supply of pure oxygen of with >95% by volume of O₂, or a mixture of pure oxygen and recirculated flue gas with a high CO₂ content.

In order to allow a conventional power station, designed for the air mode, to be operated in the oxyfuel mode, flue gas which is created during the combustion process is fed back, that is to say recirculated, into the burner and the burner or furnace area. In order to achieve the same steam parameters as during the air mode in the oxyfuel mode, it is possible, according to one refinement of the invention, for treated and/or untreated flue gas to be fed back in a recirculating manner to the steam generator. “Untreated” flue gas means flue gas which is tapped off in the flue gas path after the steam generator for recirculation before any flue gas treatment is carried out in the flue gas path, for example by an electrical filter, a flue gas desulfurization installation or a flue gas drier. The process of passing through heat displacement systems or elements by means of which energy is simply extracted from the flue gas does not mean that the flue gas can then be regarded as having been treated. The exemplary embodiment illustrated in FIG. 1 shows possible points and locations for tapping off untreated flue gas, provided with the reference symbols 1, 2 and 3. The term “treated” flue gas means a treatment which changes the flue gas composition. Possible points or locations for tapping off treated flue gas for recirculation are identified by the reference symbols 4, 5 and 6 in FIG. 1.

Since modern power stations in particular are expediently intended to be capable of subsequent conversion to the oxyfuel mode, the invention furthermore provides that an existing power station, in particular a so-called 600° C. power station, is retrofitted with the method as claimed in claim 1 or 2.

In order to achieve the same steam parameters in the oxyfuel mode as in the air mode, it is expedient according to a further refinement of the invention that the recirculation rate of the flue gas is 65% to 80%, in particular 74% to 78%.

A power station designed for the air mode can be operated in the oxyfuel mode with particularly minor conversion or modification effort if the flue gas is tapped off after desulfurization (DeSOx) or after a flue gas desulfurization (DeSOx) installation or a flue gas cooler, which is installed in particular additionally and/or subsequently, for recirculation, as the invention likewise provides.

According to one refinement of the invention, it is also a major advantage for the flue gas to be tapped off after a flue gas condensation drier in the flow direction.

Because of the high proportion of CO₂ in the flue gas, it is also expedient in the oxyfuel mode for quicklime (CaO) to be used as absorbent in the flue gas DeSOx installation.

In one refinement of the power station according to the invention, the invention provides that a heat displacement system is installed between a suction draft and desulfurization or a desulfurization installation. This makes it possible to influence the thermal balance of the recirculating flue gas flow, as well as the temperature of the recirculated flue gas, via energy removal.

In order to allow the temperature of the flue gas or else that of the oxygen which is supplied to the steam generator after air separation in an air separation unit to be influenced in an advantageous manner, the power station according to the invention is, finally, distinguished in that the flue gas channel has a bypass line, which is routed in particular parallel to an air preheater (LUVO) and has a gas/gas heat exchanger arranged therein, after a denitrification (DeNOx) device in the flow direction.

It is self-evident that the features mentioned above and those which are still to be explained in the following text can be used not only in the respectively stated combination but also in other combinations. The scope of the invention is defined only by the claims.

The invention will be explained in more detail in the following text with reference to a drawing, in which:

FIG. 1 shows a schematic illustration of a method and installation layout for the gas and combustion side of a steam generator,

FIG. 2 shows a schematic outline illustration of a method layout for the gas and combustion side of a steam generator,

FIG. 3 shows a schematic outline illustration of a further embodiment of a method layout on the gas and combustion side of a steam generator,

FIG. 4 shows a schematic outline and section illustration of the design of a steam generator,

FIG. 5 shows a comparison of the temperature profile over the furnace height in the radiation part of a steam generator in comparison between the air mode and the oxyfuel mode,

FIG. 6 shows a comparison of the temperature profile in the convective part of a steam generator in comparison between the air mode and the oxyfuel mode,

FIG. 7 shows the temperature profile of the water/steam system in the convective part of a steam generator in comparison between the air mode and the oxyfuel mode,

FIG. 8 shows an illustration in the form of a table of the difference between various characteristic values in comparison between the oxyfuel mode and the air mode, on the one hand using metric units and on the other hand percentages,

FIG. 9 shows an illustration in the form of a table of the difference in the flue gas composition after the electrical filter in comparison between the air mode and the oxyfuel process,

FIG. 10 shows a table of a comparison between the air mode and the oxyfuel mode in respect of different physical characteristics and

FIG. 11 shows an illustration, corresponding to

FIG. 2, with additional details of the gas temperatures in ° C. and of the mass flows in kg/s.

The installation additions and modifications will be described in the following text, with reference to FIGS. 1-3, which allow a conventional coal-fired power station to be converted to the oxyfuel mode. A method is also described, on the basis of which the oxyfuel mode can then be carried out in an optimum manner. A special feature of the conversion and of the method is that normal air operation is also still possible after conversion. For example, the installation can be safely started in the air mode before switching to the oxyfuel mode, and with switching once again taking place to the air mode, which can be coped with more easily (with high efficiency) and with CO₂ emission, before shutdown, in the event of disturbances in operation, or in the event of an interruption in the CO₂ storage capability downstream from the power station.

FIG. 2 shows a method layout on the gas side of a coal-fired power station, on the basis and by means of which the coal-fired power station can be operated both in the air mode and in the oxyfuel mode on the burner side. In this case, when the installation is in the air mode, the combustion air is preheated after induction by the fresh-air fan 7 in a heat displacement system (WVS) 35 (WÜ3) which may be provided. However, this is not provided in all power stations nowadays. After further heating in the air preheater (LUVO) 8, the air is split into carrier air, other burner air, and —if present—into a mill circuit flow. The carrier air is supplied upstream of the mill to a further fan (primary fan) 9, whose pressure increase ensures that the coal is removed to the burners 10.

The mill circuit flow is used for heat displacement (WÜ1 and WÜ2) from the off-gas to the feed water preheating path. This has a positive effect on the overall efficiency of the installation, because a greater heat flow of the off-gas is used, thus reducing the off-gas losses. Furthermore, it is possible to save tapped-off steam for feed water preheating.

After combustion in the steam generator 11, in addition to exchanging heat with the combustion air (LUVO), the flue gas is also subjected to catalytic denitrification 12 in order to reduce the NOx emissions, dust removal 13 and desulfurization 14, in order to comply with the respective emission limit values.

In the area of the steam generator 11, the coal is burnt in the combustion area and a portion of the heat transfer takes place to the working medium steam/water in the wall heating surfaces of the steam generator (mainly by radiation). A convective heat transfer takes place in the subsequent convective heating surfaces to superheater, intermediate superheater and economizer heater surfaces.

During operation of an installation such as this, on the basis of the oxyfuel process, it would now be problematic to use recirculation gas (flue gas) at a high temperature level and flue gas taken before completion of the flue gas cleaning at the points 1-4 shown in FIG. 1, for example, and fed back to the steam generator 11, because of the high dust and/or SO₂/SO₃ content. The increased temperature level in comparison to that when the installation is designed for the air mode, the higher dust and SO₂/SO₃ content and the risk of erosion/corrosion resulting from this to flue gas channels, air channels, suction draft fans, any mill air fans that are present, mill air heat exchangers, mills, burner fittings and boiler materials would necessitate complete replacement of these items, because of the increased risk of wear. Furthermore, the heat technology/connection of the heat exchangers would also have to be completely revised as far as the burner, because of the change in the temperature levels. Although such conversion is in principle possible, it would no longer be possible to subsequently operate the installation (easily) in air mode without further modifications/additions. The provision of both operating modes and the creation/setting of all the items required in this case as well as air channels and recirculation channels is, however, virtually precluded for retrofit purposes in modern power stations, because of the lack of available space, or is in any case associated with very high technical complexity and financial cost. The risk of increased SO₃ formation in the flue gas with corresponding enrichment and repeated contact with catalytically active surfaces in the DeNOx reactor (denitrification reactor) 12 and LUVO (air preheater) 8 would be impossible to avoid.

For the described reasons, in the case of the oxyfuel mode method according to the invention, described here, the flue gas which is enriched with oxygen as recirculation gas and is used as a substitute for the combustion air is therefore in one preferred embodiment tapped off after the desulfurization 14, 15 at the point 5 or after a flue gas cooler 16, which has to be additionally installed, at the point 6, in which case, of course, mixtures of flue gas fed back at the points to 4 or 1 to 5 or one of these points are also possible. The flue gas has a very high purity level at these points 5 and 6 (in respect of dust, SO₂/SO₃ content) and is at a sufficiently low temperature. This ensures that, when changing over to the oxyfuel mode, all the existing items and air/flue gas channels can be still be used. All that is needed is to connect the flue gas return channel 22, 23 to the fresh-air induction 7 and to install a valve, which forms as good a seal as possible, for switching between the oxyfuel mode and the air mode. In the oxyfuel mode, the steam parameters of air operation can then be achieved, as can be seen from FIGS. 5 to 7. FIG. 5 shows that the temperature profile curve 43 for the oxyfuel mode 43 provides a good match with the curve 44 for the air mode. In addition, in a comparison of the result illustrated in the left-hand part of the figure for oxyfuel operation with the air mode as illustrated in the right-hand part of the figure, FIG. 6 likewise shows that essentially the same temperatures can be created both on the combustion area side and on the steam side in the oxyfuel mode as the respectively stated temperature values show over the height of a steam generator 11. It is therefore evident that the heat transfer which takes place in the steam generator 11 by flame radiation, gas radiation and convection to the steam mass flow in the steam/water circuit of the steam generator remains at least essentially the same overall, in comparison to air combustion, in particular the same steam parameters being maintained. This is also evident from FIG. 7, which shows that the curve 45 for the air mode and the curve 46 for the oxyfuel mode, which each represent the heat transfer into the water/steam system over the height of the vaporizer and therefore the heat transfer in the convection path, exhibit essentially the same temperature profile over the height of the steam generator 11.

It may be necessary to install a heat displacement system (WVS) 16, 35 between the suction draft 17 and the desulfurization 14, 15, if the installation does not already have this. Further changes relate to the area of the oxidation in the desulfurization installation 15 and in the denitrification 12, oxygen preheating 19 and the mill barrier gas 40.

To avoid intervening to a greater extent in the heat technology of the power station, it is ensured that the heat transfer in the area of the combustion area 18 and in the area of the downstream convective heating surfaces is ensured in the oxyfuel mode as well, in a corresponding manner to the design for combustion using air. In the method according to the invention, this is achieved in that the amount of flue gas which flows through the convective heating surfaces when the output temperature of the combustion area is the same is governed such that virtually the same amounts of heat are transferred to the steam, as the working medium, despite the changed heat transfer conditions (density, flue gas temperature profile, flow rate and heat transfer coefficient) resulting from the combustion of O₂ with flue gas containing CO₂ being fed back.

The combustion side, that is to say the flue gas/gas side of the steam generator 11, is adapted because of the changed flue gas characteristics, both with respect to the heat content (density, heat capacity) and heat transfer (changed flow rates, heat transfer coefficients). The aim is that the water/steam circuit should remain at least substantially unchanged. In the case of the oxyfuel mode (oxyfuel case), the magnitude of the total amount of recirculated flue gas, the split between the various combustion gas, feed gas and process gas flows (burner “air”, mill “air”, over fire “air”, curtain “air”) as well as the oxygen contents of these gas flows and the total amount of excess oxygen result in new degrees of freedom which are used for adaptation of the combustion.

First of all, the total amount of recirculated gas is determined such that the heat transfer in the convective heating surfaces corresponds to the old design data.

As shown in FIG. 8, which figure lists average values of variables which characterize the heat transfer in the convective surfaces, this is done in the oxyfuel case with an amount of recirculated gas which causes a flue gas density which is higher by 38.5% than the air mode, a higher heat transfer (alpha) by radiation (+23%) and convection (+6.8%), a flue gas mass flow increased by 7.8% and a reduction in the mean logarithmic temperature difference by 11.2% or produces these effects. In this case, the recirculation rate of the flue gas is 75.7%. However, this value is dependent on the precise fuel characteristics and the basic design of the power station, and can assume values between 65 and 80%. The recirculation rate means the proportion of the recirculated flue gas in the total amount of flue gas.

Nowadays, power stations are equipped with low-NOx burners and combustion systems as a primary measure against nitrogen oxide emissions, which, in addition to the carrier “air” which transports the fuel, have at least one—generally twisted—secondary “air” and, in the case of a twist-stage burner, furthermore an outer tertiary “air” and an inner core “air” flow. By appropriate choice of the twist and impulses/impulse ratios of the individual flows, it is possible to optimally control the combustion of the coal and the NOx emission by control of the oxygen-rich and low-oxygen zones in the flame. A burner such as this is therefore able to operate with different gas compositions and therefore offers the capability to adjust the combustion and temperature profile in a suitable manner in the oxyfuel mode such that analogous amounts of heat are transferred in the combustion chamber as in the air mode, combustion furthermore taking place with low levels of hazardous substances.

Furthermore, in the oxyfuel mode, because the flue gas is very largely free of nitrogen, virtually no thermal NOx is formed, thus resulting in lower NOx emission (in comparison to the air mode).

The proportion of the recirculated flue gas which is required for the burner in the oxyfuel mode is obtained to a first approximation from the requirement to maintain the impulse flows at the burners in the various operating modes.

The impulse flow is given by equation 1:

I_PG,SG=n&_PG,SGW_PG,SG  Equation 1

where

I_PG,SG impulse flow of the primary and secondary gases

m_PG,SG mass flow of the primary and secondary gases

W_PG,SG flow rate of the primary and secondary gases

If the cross section is constant and the impulse flow does not change, then:

$\begin{array}{cc}{\stackrel{.}{m}}_{\mathrm{PG},\mathrm{SG}}={\stackrel{.}{m}}_{\mathrm{PL},\mathrm{SL}}\sqrt{\frac{{\rho }_{\mathrm{PL},\mathrm{SL}}}{{\rho }_{\mathrm{PG},\mathrm{SG}}}}& \mathrm{Equation}2\end{array}$

where

n&_PF,SG mass flow of the primary and secondary gases in the oxyfuel mode

n&_PL,SL mass flow of the primary and secondary gases in the air mode

p_PL,SL density of the primary air and secondary air

p_PG,SG density of the recirculated flue gas as a function of the composition of the primary and secondary gas.

The component 47 of the burner “air” which is used as a flow element of the combustion gas in order to remove the coal from the mill 36 (carrier gas) must also be determined corresponding to the equality of the impulse forces acting on the coal particles.

Whether the impulse flow maintenance at the burner means that that carrier gas is able to remove coal from the mill 36 depends on the flow resistance (equation 3), the lift force (equation 4) and the weight force (equation 5).

$\begin{array}{cc}{F}_{\mathrm{SW}}=c_w·A_S2\frac{{\rho }_F·w_{F^2}}{2}& \mathrm{Equation}3\\ F_S=g·{\rho }_S·V_S& \mathrm{Equation}4\\ F_A=g·{\rho }_F·V_S& \mathrm{Equation}5\end{array}$

where

F_SW—flow force

c_w—flow coefficient of drag of a dust grain

w—flow rate of the fluid

F_S—weight force of the dust grain

A_s, V_s—surface, volume of the dust grain

p_F,p_S—density of the fluid, of the dust grain

G—acceleration due to gravity

In both cases, the weight forces are of equal magnitude and will not be considered any further. The lift force is negligibly small, because the density difference between flue gas and dust grain is very great. This means that only the flow force need be compared.

$\begin{array}{cc}{c}_w·A_S·\frac{{\rho }_{F·\mathrm{air}}·w_{\mathrm{air}}^2}{2}=c_w·A_S·\frac{{\rho }_{F·\mathrm{Oxy}}·w_{\mathrm{Oxy}}^2}{2}& \mathrm{Equation}6\end{array}$

Equation 2 for the impulse flow maintenance is therefore applicable and this ensures that the coal is removed.

The oxygen content of the burner gas flows 38 or of the burner “airs” is set such that the adiabatic combustion temperature remains virtually constant.

Since the stoichiometry in the burner area in modern power stations is restricted on the one hand at the top by the formation of NOx which is then increased and on the other hand at the bottom by the risk of the formation of skeins of reducing atmosphere in the combustion area 18, resulting in the possibility of increased wall corrosion, the design value for the combustion stoichiometry must also be complied with approximately in the oxyfuel case. Since the risk of the formation of thermal nitrogen oxide is reduced by the lack of nitrogen from the air, slightly increased stoichiometries may also be used, however, to set the level of the combustion area temperatures.

Furthermore the oxygen contents of the transport gas and of the other gas flows should differ by up to 15% by mass depending on the fuel characteristics, in particular the capability to ignite the coal. This allows the over fire speed in the flame to be controlled in order to allow the temperature profiles in the combustion chamber 25 of the steam generator 11 to be similar to those of the air combustion.

Finally, the temperature profile and temperature level are responsible for the heat transfer, which dominates in the combustion area 18 of the steam generator 11, by radiation in this area, which is the governing design criterion in order to comply with the required combustion chamber final temperature and the amount of heat transferred to the water, as the working medium, in the combustion chamber walls.

FIG. 2 does not illustrate the so-called curtain or side-gas injection which is used in some power stations in order to reduce the risk of reducing areas in the vicinity of the combustion chamber walls, and to avoid the risk of increased wall corrosion. In the exemplary embodiment, its proportion in the total amount of gas or “air” supplied in the area of the burner 10 remains low without any change, in order to still provide the impulse flow which is necessary for the penetration depth and coverage of the entire wall. However, its oxygen content in the oxyfuel mode is increased by up to 20 percentage points in comparison to the pure air mode, in order to provide effective protection against the higher CO contents (in this part of the combustion area) occur because of the Boudouard equilibrium and the high CO₂ contents.

The proportion of the recirculated flue gas which is added in the upper part of the combustion chamber 25 of the steam generator 11 as over fire air (OFA) 37 is governed by the fixing of the other gas flows. The oxygen content in the over fire air (OFA) is determined from the overall stoichiometry, that is to say from the excess oxygen which is required overall for reliable combustion of all the coal components and so as to minimize the CO content—the stoichiometry factor in the exemplary embodiment is 1.17. Depending on the design basis of the power station, however, it can assume values between 1.1 and 1.25 for the air mode, but should be as low as possible in the oxyfuel case in order to avoid further dilution of the CO₂ by excess oxygen.

This essentially precludes the transfer of the process parameters from the air mode to the oxyfuel mode. In addition to the described analogy of the flow impulses, a further heat-engineering optimization of the combustion for the oxyfuel mode can be implemented by including detailed CFD (computational fluid dynamics) results and experimental results for specific coals, although these have only a minor influence on the amplitude of the process parameters set. In all cases—that is to say even if the recirculation gas flows are split differently and the oxygen contents vary—the described procedure and consideration of the available degrees of freedom for the oxyfuel mode allow both the conventional air mode and an oxyfuel mode to be carried out in a power station installation modified in this way. It is thereby possible in the oxyfuel mode for essentially the same steam parameters to be set in the steam generator 11.

The purging and/or barrier gas (air) which is used nowadays in/on rotating parts of the coal mills 36 associated with the power station is replaced by CO₂ during the conversion to the oxyfuel mode.

As FIG. 2 shows, the air preheater 8 is still required in the illustrated exemplary embodiment. The recirculated amount of flue gas fed back cannot, however, absorb the total amount of heat that is required, because oxygen is still lacking, since the oxygen is not mixed with the flue gas before the air preheater 8. However, this is also undesirable since conventional regenerative air preheaters in the design case for air operation have unavoidable leakage in the direction of the flue gas between the two gas flows (off-gas and recirculated flue gas) which flow in opposite directions. Oxygen losses (and a greater energy consumption) as well as reduced CO₂ purity would therefore be expected in the oxyfuel mode. For this reason, a gas/gas heat exchanger 19 in order to preheat the oxygen, is installed together with a control valve to split the flue gas to be cooled down, in the bypass to the air preheater 8 for the oxyfuel mode. In the pure air mode, the old operating state can therefore still be selected by disconnecting the oxygen preheater by closing the bypass by closing the control valve.

Depending on the type of air preheater 8 (that is to say with a rotating stored mass or with rotating shrouds), the sealing from the environment can be improved with greater or lesser complexity since there is still the reduced pressure at this point on the flue-gas side.

In order to prevent more environmental air from entering the steam generator 11 in the area of the funnel 41 of the steam generator 11, it is in any case advantageous during the conversion process for the steam generator 11 to be equipped for wet ash removal if dry ash removal is installed in the existing installation. In the case of wet ash removal, adequate sealing is ensured in any case by the sealing of the water-filled trough with respect to the steam generator walls.

No significant changes need be made in the area of the electrical filter 13. However, care should be taken to ensure that the shut-off devices to the ash removal system of the electrical filter 13 are designed to be gas-tight (for example gas-tight bucket feed gates). To entirely prevent this leakage flow of leakage air in the system CO₂ should be applied to the shut-off devices as a sealing barrier gas.

In this way, no significant structural change need be made in the denitrification installation (SCR=selective catalytic reduction) 12. Mixed gas flows for which air is used in normal operation are replaced in the oxyfuel mode by CO₂ (see the arrow in FIG. 2) which can be after or in an intermediate stage of compression. In principle, both ammonia and ammonia water can still be used as reactants.

Since the chemical reactions within the flue gas desulfurization installation (REA) 15 take place in an atmosphere composed mainly of CO₂ in the oxyfuel mode, the absorbent should be changed from limestone (CaCO3) to quicklime (CaO) since the CO₂ release which is required to dissolve the limestone in the dissolving process is impeded by the saturation of the wash suspension with CO₂. The absorbent mixing systems must be appropriately modified for this. Next, when flue gas desulfurization is carried out using the methods that are normally used nowadays, the calcium sulfide which is created in the solution is oxidized by air injection to form calcium sulfate, this method step is also modified during the conversion/modification to the oxyfuel mode. Since, for cost reasons, the oxidation in an installation designed for the air mode is carried out by injecting air into the sump of a spray tower, desired oxygen would once again not be introduced when using air without a hardware change. Pure oxygen must not be injected since, on the one hand, the production of this oxygen would result in a correspondingly greater energy requirement for the air separation unit (ASU) 20. On the other hand, the need for excess oxygen leads to the CO₂ provided for storage being of lower purity. For this reason, in the exemplary embodiment, the desulfurization is converted to external oxidation by fitting an external stirring container 39 (FIG. 3), thus preventing N₂ and O₂ from being introduced into the system.

Since the desulfurization installations now being designed for the laws applicable in Germany achieve an SO₂ value of <200 mg/Nm³ (dry, with the current oxygen content), the desulfurization must be improved in order to prevent corrosion problems in downstream process steps (compression, transport to the storage location). Furthermore the fresh-air fan 7 and the fuel/air channels are also not designed for increased SO₂/SO₃ contents on conversion/modification to oxyfuel operation. An increase in separation can be achieved in two ways. On the one hand, the existing DeSOx can be improved within limits by increasing the ratio of liquid circulation to flue gas flow, while on the other hand a further spray level can be retrofitted if sufficient space is available in the head area of the spray tower. Retrofitting a tray or the addition of acids which promote solution likewise improves the desulfurization.

This allows high desulfurization levels to be achieved and SO₂/SO₃ values of 20-40 200 mg/Nm³ (dry, with the current oxygen content). Further purification is carried out before compression and after the flue gas recirculation in order to ensure that only the required flue gas flow need be purified to the pure gas values required by compression.

In order to dry the flue gasses after the flue gas desulfurization installation (REA) process, the flue gas desulfurization installation (REA) 15 is followed by a flue gas condensation drier 21. This cools the flue gases further in order to achieve the required water contents of <3% (for recirculation).

In addition to the cooling water that is required—if present as product—the liquid nitrogen from the air separation unit 20 is also used for this purpose. After drying, the flue gas flow is split, and the majority is recirculated 22, 23. The flow element which is intended to be supplied to the compressor 24 is pased on for further purification.

Before the CO₂ compressor station 24, corrosive elements of the flue gases and water should be removed as far as possible. An NaOH washer with recirculation flow cooling is used for this purpose. During NaOH washing, a further considerable reduction in the corrosive flue gas components is achieved (SO₂/SO₃<<5 mg, HCl<<1 mg, HF 1 mg, dust<<1 mg), the cooling of the circulating liquid ensures that the water content is reduced further. A further, downstream condensation cooler is optionally used.

The flue gases which have been purified in this way are supplied to the compressor station 24. After compression, the residues of O₂ and N₂ which are still present in the gas flow are removed from the liquefied CO₂ by a phase separator, since these gases are not liquefied in these conditions. The CO₂ is now available for storage and further transport.

The processes of more extensive flue gas purification described above require high cooling powers. Liquid nitrogen produced in the air separation unit (ASU) 20 can be used in conjunction with a cooling water flow for this purpose (if oxygen and nitrogen as the products of the air separation are in liquid form). The nitrogen is first of all used in the cooling system of the multistage CO₂ compressor 24, in order to minimize the energy consumption of the compressor. The energy transferred to the “superheated” nitrogen is then optionally partially recovered by means of an expansion turbine, in which process the nitrogen temperature falls again. Furthermore, the mass flow of nitrogen is then used via coupling heat exchangers both for cooling the NaOH recirculation and for cooling the flue gas condensation drier 21 arranged downstream from the flue gas desulfurization installation (REA) 15, where cooling water flows are added to it. The nitrogen can then optionally once again be passed via expansion turbines for energy recovery, and fed back into the environment via a stack.

The described procedure for designing the combustion process of an oxyfuel steam generator can also be iteratively coupled to the normal design of the convective heating surfaces of a steam generator and can be used for cost-optimized design of a new installation by reducing the size of the heating surfaces while at the same time increasing the flue gas speed by reducing the cross section of the combustion chamber. From the flow mechanics point of view, it is now necessary to depart from a direct analogy with the impulse relationships: the case of air combustion can then be designed (for the same flow speed which is limiting under erosion viewpoints) with a correspondingly reduced power (partial load for starting/shut-down processes and operating disturbances).

The following explanations likewise relate to a conversion concept for a coal-fired power station. The options for implementation of a CO₂-free power station in which the CO₂ is separated and stored is discussed, and what the advantages and disadvantages are. The state of research relating to the oxyfuel process is described briefly. After a discussion of possible variants of the oxyfuel process, two variants are selected. These are analyzed in terms of the conversion measures required to the power station components: combustion gas system, flue gas cleaning installation, mills, burners and steam generators. Heat engineering calculations relating to heat transfer in the steam generator indicate that the required steam parameters are achieved without conversion of the steam generator heating surfaces. Subsequent calculations, with the recirculation mass flow and the radiation change coefficients of the combustion chambers being varied indicate ways to influence the heat transfer in the steam generator. Assessments of the conversion effort for the two selected process variants and a final estimate of the overall efficiency indicate which considered variant is technically and economically the most advantageous.

The aim of the oxyfuel process is to achieve as high a CO₂ concentration as possible in the flue gas in order to save the energy-consuming CO₂ washing of the “post combustion process”. During the compression of the CO₂, the energy consumption can be reduced if the CO₂ has a high concentration. The compressor power is then applied only to the CO₂ and not to the impurities as well. During combustion with air, the nitrogen component of approximately 78% by volume prevents high CO₂ enrichment in the flue gas. If, in contrast, to this, pure oxygen is used for combustion, considerably higher CO₂ contents of up to 80% by volume can be achieved during combustion using dry brown coal, and more than 90% by volume when using hard coal. These values may fluctuate depending on the combustion conditions and the coal composition. Nevertheless, they are good preconditions for separation and storage of CO₂.

When burning coal with pure oxygen in the oxyfuel mode, there is no nitrogen, which on the one hand acts as heat carrier for flame temperatures that can be coped with technically and on the other hand ensures that the flue gas volume flow is increased. This flue gas volume flow removes the required heat flow into the convective part of the steam generator where it also ensures the high flow speeds required for heat transfer. In order to provide this volume flow, the flue gas is at least partially recirculated after combustion in the oxyfuel mode and, after being mixed with oxygen, is once again supplied to the steam generator 11. The flue gas can be removed at various points downstream from the steam generator 11. The choice of the recirculation location 1 to 6 results in different concentrations of dust, SO_x and water in the flue gas.

The heat transfer in the steam generator 11 takes place by convection or by radiation. For convective heat transfer, a changed flue gas composition results in changed values of heat capacity, viscosity and thermal conductivity as well as flue gas density, as shown in FIG. 8. The flow speed of the flue gas is therefore also changed. However, it is possible to achieve similar heat flows in the convective heating surfaces as well with oxyfuel flue gas in the oxyfuel mode. The initial supposition that larger heating surfaces would be required in oxyfuel conditions, in order to transfer the heat flows, proves incorrect. Brown coal with a combustion heat of 22 MJ/kg (net) and a moisture content of 19.95% is thus burnt, and the flue gas is dried before recirculation. With the same flue gas mass flow and a combustion area outlet temperature that is higher by 46 K, a flue gas temperature that is reduced by 4 K in comparison to the air process is measured at the outlet of the economizer heating area. A higher heat flow is therefore transferred in the convective part. When using the oxyfuel process in already existing installations or installations that are being built, and which are designed for air operation, there is therefore no need for any relatively major modifications to the convective heating surfaces.

The heat transfer ratios can therefore be matched by adaptation of the molar recirculation ratio.

Molar recirculation ratios of 3.25 are determined for the moist feedback of the flue gas (removed at location 5) and 2.6 for feedback at location 6 after the flue gas drying 21. As the recirculation ratio rises, the heat transfer by radiation decreases, because the flame temperatures are lower.

The radiation heat transfer varies in particular as a function of the composition and the temperature of the gas. There are various possible ways to adjust the flame and flue gas temperatures as well as the gas compositions. The most important ways include the oxygen content in the combustion gas and the proportion of the recirculated gas mass flow in the flue gas mass flow that is produced overall.

The following flue gas constituents principally influence the gas radiation behavior:

• • CO₂ content
  • H₂O content
  • Proportion of solid particles.

The high proportion of nitrogen in the flue gas in the case of air combustion is replaced by CO₂ in the oxyfuel process. Depending on the recirculation location 1 to 6, the flue gas contains a greater or lesser amount of water. However, CO₂ and H₂O are not diathermic in the same way as N₂ and O₂, but themselves absorb and emit heat radiation depending on the gas temperature. In addition, the higher heat capacity of the combustion gas, primarily caused by CO₂ and water, changes important flame characteristics.

Emissitivity of the flame in the oxyfuel mode and in the air mode is similar. It depends in particular on the coal, the fly ash, soot particles in the flame, but not on the CO₂ concentration.

In comparison with air operation, for the same oxygen content in the combustion gas, it is generally observed in the oxyfuel process that

• • the flame propagation speed falls,
  • the flame temperatures fall, and
  • the ignition delay increases.

The ignition delay is calculated by dividing the movement distance over which the coal particles travel before ignition by the particle speed.

The ignition delay rises when

• • the temperature falls,
  • the oxygen content in the combustion gas falls,
  • the heat capacity of the combustion gas rises,
  • the thermal conductivity of the combustion gas falls, and
  • the proportion of volatile components in the coal falls.

In this case, each of the other parameters remained constant.

In a CO₂-rich atmosphere, the ignition delay is greater than in a nitrogen-rich atmosphere (air operation), given the same oxygen content. In order to achieve the same ignition delay as with air combustion, the gas must consist of 30% by volume of oxygen and 70% by volume of CO₂ in the oxyfuel gas.

The influence of the motor recirculation ratio is also evident here. Given a recirculation R

$R=\frac{{\stackrel{.}{m}}_{\mathrm{Reci}}}{{\stackrel{.}{m}}_{\mathrm{Reci}}+\stackrel{.}{m}{,}_{\mathrm{off}\text{-}\mathrm{gas}}}$

of 0.58, in addition to the adiabatic combustion temperature, which is the same as that for the air mode, similar flame temperature profiles and stabilities are also observed in the oxyfuel mode (R=recirculation ratio, m_Reci=mass flow of recirculated flue gas, m_off-gas=mass flow of off gas).

As FIG. 4 shows, various heating surfaces, which differ in terms of the heat transfer method, exist in a steam generator 11. Heat transfer by radiation is dominant in the combustion chamber 25 and in the radiation areas 26 and 27, and these are therefore referred to as radiation heating surfaces. The combustion chamber 25, the radiation areas 26 and 27 are together referred to as the combustion area 18. The heat transfer in superheater heating surfaces 28 and 29 and intermediate superheater heating surfaces 30 and 31 as well as the economizer heating surface 32 takes place mainly by convection, as a result of which these heating surfaces are referred to as convective heating surfaces. The convective part of the steam generator 11 represents the totality of all convective heating surfaces.

The supporting tube bulkhead 49 has the special feature of also having a large radiation component as a convective heating surface. This can be explained by its position as the first bundle heating surface above the combustion area 18.

The final stages of the HP (high-pressure) and MP (medium-pressure) parts and of the economizer heating surface have flow passing through them in the sense of a parallel-flow device. In the final stages, this is used to reduce the corrosion tendency by means of lower material temperatures, and to protect the turbine against temperature fluctuations. The economizer heating surface 32 is intended to guarantee that any steam bubbles that may occur are removed.

The aim is to convert a 600° C. or 700° C. power station designed for air operation to the oxyfuel process. This means that the steam generator 11 must be able to supply the turbine with the required steam parameters in both the air mode and the oxyfuel mode. The aim is to do this without any modifications to the steam generator heating surfaces, mills and burners.

The critical criterion for the economy of the oxyfuel process is to achieve a high CO₂ content in the off-gas. Only considerable energy savings in the CO₂ concentration and compression justify the high-energy oxygen generation as an additional process in comparison to simple flue gas washing with a washing agent (for example monoethylamine). Any air leakages which enter in addition to the purging air and barrier air that is supplied counteract this aim, and must therefore be reduced to a minimum.

As FIG. 1 shows, it is possible to tap off flue gas for flue gas circulation at the following points:

• • 1, before the denitrification 12,
  • 2, after the denitrification 12,
  • 3, after the regenerative air preheater 8,
  • 4, after the dust removal 13,
  • 5, after the desulfurization 15 or
  • 6, after the drying 21.

It is also possible to combine a plurality of these tapping options.

The recirculation of the flue gas at the point 1 before the desulfurization installation 12, which is arranged in the empty draft in modern coal-fired power stations, results in enrichment of the flue gas with dust, sulfur oxides and water. All lines and components which come into contact with flue gas must be designed to be appropriately dust-compatible. This applies in particular to the recirculation fan 48, 48a, 48b which has to be additionally installed. The higher concentration of water and sulfur oxides results in the sulfuric acid dew point rising.

Neither existing regenerative air preheaters 8 nor a heat displacement system 16 before the flue gas desulfurization installation 14, 15 are required in the oxyfuel mode since, when a large proportion of the flue gas is tapped off before the air preheater 8, there is no substance flow to be cooled down or heated. An existing electrical filter 13 and the flue gas desulfurization installation 15 are then overdesigned for the oxyfuel mode. The flow ratios can be adapted, if necessary, for optimum dust separation and desulfurization rate by shutting down individual electrical filter passages or washer levels. The drier 21 which is provided only for the oxyfuel mode can in this case be designed for small volume flows. The oxygen flow is then heated in an additional heat exchanger 33, which is arranged before the electrical filter 13, where the flue gas temperature is about 380° C.

When the flue gas is recirculated from the point 2, only the conversion rate from SO₂ to SO₂ is increased in comparison to this, since the flue gas passes through the area of the catalytic surfaces of the denitrification installation 12, resulting in a higher sulfuric acid dew-point temperature.

When flue gas is tapped off at the recirculation point 3, only the air preheater (LUVO) 8 is then used to cool down the flue gas. The flue gas temperature behind the air preheater (LUVO) 8 is then above the sulfuric acid dew point. The temperature of the flue gas after the air preheater (LUVO) 8 is regulated by the inlet temperature of the medium to be heated and is passed through in the opposite direction. However, this results in the problem that, because the recirculated flue gas is heated up in the recirculation fan, the mass flow to be heated on re-entering the air preheater is hotter than the mass flow to be cooled down at the outlet. This problem can be solved by fitting a heat sink in the form of a heat exchanger. The discrepancy between the flue gas mass flow on the side of the air preheater (LUVO) to be cooled down and on the side to be heated up is solved by an air preheater (LUVO) bypass 34 with oxygen preheating 33.

When the flue gas is recirculated from the point 4, behind the electrical filter 13, the flue gas is enriched with sulfur oxides and water. The dust load for flue gas channels and fans decreases considerably. The electrical filter 13 is then designed and constructed such that it can be used both for the air mode and for the oxyfuel mode.

When the flue gas is recirculated from the point 5, after the desulfurization 14, 15, the flue gas is now further enriched only with water since large amounts of the sulfur are removed in the flue gas desulfurization installation 14, 15. This reduces the risk of corrosion caused by sulfuric acid. The quench effect in the flue gas desulfurization installation 15 cools the flue gas by partial vaporization of the absorber suspension. In this case, the water content and the outlet temperature of the flue gas are set as a function of the saturation temperature.

When the flue gas is recirculated from the point 6, behind the drier 21, the flue gas is sucked back or fed back (recirculated) with all the dust removed, after desulfurization and dried. With this flue gas quality, the fresh-air fan can be used as recirculation fan. All the heat exchangers and flue gas treatment components used in the air mode can be operated in the oxyfuel mode without any change from the air mode. However, the entire flue gas mass flow is passed via the drier 21 which means that this must be designed to be appropriately large in order to be able to carry away large heat flows.

The advantages and disadvantages of the respective recirculation points can be combined by recirculation of specific flue gas flow elements at various ones of the points 1-6.

A flow element which has been passed through all the flue gas treatment components is correspondingly purified, as a result of which the concentrations of hazardous substances such as dust, water and sulfur oxides are reduced. A second flow element can then be recirculated very close to the steam generator 11, for example at the point 1, at a high energy level. There is therefore no need for this flue gas flow element to be cooled down and heated up again later.

In the case of later recirculation, that is to say when the overall flue gas mass flow flows through an increasing number of components for flue gas treatment along the flue gas path after emerging from the economizer heating surface, this results, rising from the points 1 to 6, in increasingly

• • less enrichment of the flue gas with water, dust and sulfur oxides,
  • better usefulness of the original components and parts of this section of the coal-fired power station in the air and oxyfuel modes, and
  • less need to introduce or to install diverse additional components and/or installation parts.

Conversion or modification to the oxyfuel process changes the recirculation mass flow which, together with the mixed-in oxygen mass flow and with the flue gas temperature profile unchanged, primarily influences the flow speeds in and on the heating surfaces. The higher density of CO₂ (oxyfuel mode) in comparison to N₂ (air mode) results in a slower flow for the same mass flow. The flow speed of the flue gas plays an important role, in addition to physical characteristics such as viscosity, thermal conductivity and heat capacity, in the heat transfer from the flue gas to the heating surface. The required steam parameters are achieved, despite the changes in the heat transfer conditions. In the case of steam generators based on the Benson principle, the control system introduces as much fuel as is required, and for as long as is required, to reach the high-pressure (HP) outlet mass flow, and the temperature is controlled by enthalpy control and injection. The medium-pressure (MP) outlet temperature can be influenced by the magnitude, that is to say the amount, of the recirculation mass flow which ensures advantageous flow speeds for heat transfer. The excess oxygen λ₀₂ means the ratio of the oxygen flow m₀₂ supplied to the stoichiometrically required oxygen flow m_O2,min. For air combustion, the combustion air mass flow m_air required for this is calculated using the equation

${\stackrel{.}{m}}_{\mathrm{air}}={\stackrel{.}{m}}_{O2,\min }·\frac{100}{21}·{\lambda }_{O2}.$

The excess air then corresponds to the excess oxygen.

There is no point in using excess air or producing a relationship with the burner gas in the oxyfuel process. It is possible to achieve virtually any desired oxygen contents in the burner gas and flue gas. The original term excess oxygen, which relates to the fuel mass flow, is therefore reverted to. This is calculated in the case of oxyfuel combustion using

${\lambda }_{O2}=\frac{{\stackrel{.}{m}}_{\mathrm{ASU}}·x_{O2,\mathrm{ASU}}+{\stackrel{.}{m}}_{\mathrm{leak}}·x_{O2,\mathrm{leak}}+{\stackrel{.}{m}}_{\mathrm{Reci}}·x_{O2,\mathrm{Reci}}}{{\stackrel{.}{m}}_{O2,\min }}$

where

• • m_LZA—mass flow from the air separation unit
  • x_02,LZA—oxygen content after the air separation unit
  • m_leak—leakage air mass flow
  • x_02,leak—oxygen content of leakage air
  • m_Reci-recirculation mass flow
  • x_02,Reci—oxygen content of the recirculated flue gas
  • m_02,min—stoichiometric oxygen flow.

In this case, the numerator contains all the oxygen mass flows (combustion gas, feed gas, process gas) supplied for combustion. The denominator contains the stoichiometric oxygen requirement, which is calculated from the reaction of the coal components C, H, O and S to form CO₂, H₂O and SO₂.

A comparison of the flue gas compositions that occur between the air mode and the oxyfuel mode with flow gas circulation after the electrical filter 13 at the point 4 and after the drier 21 at the point 6 is shown in FIG. 9.

The change in the gas composition also results in different physical characteristics. FIG. 10 shows the higher density of the flue gas in the oxyfuel process (+23.9%+33.3%). The heat capacity, dynamic viscosity and thermal conductivity of the flue gases vary only slightly in comparison to the air mode when the flue gas is taken off at the point 6. In the oxyfuel process, the higher heat capacity and the higher thermal conductivity at the point 4 in comparison to the point 6 can be explained by the water content of the flue gas being even higher there.

In order to achieve the steam parameters before the turbine in the oxyfuel process as well, the fuel mass flow and the recirculation mass flow are adapted. Because of the higher density of the flue gas in the oxyfuel process, the flow in the convective part is slowed down, despite the flue gas mass flow being higher.

The physical characteristics from FIG. 10 are included in the Reynolds number and Prandtl number, which in turn lead to the Nusselt number.

${\alpha }_{\mathrm{outer}·\mathrm{convective}}=\frac{{\lambda }_{\mathrm{FG}}·\mathrm{Nu}}{l}$ ${\alpha }_{\mathrm{outer}}={\alpha }_{\mathrm{outer}·\mathrm{convective}}+{\alpha }_{\mathrm{outer}·\mathrm{radiation}}$ $\frac{1}{k}=\frac{1}{{\alpha }_{\mathrm{outer}}}+\sum _{n=1}^N\frac{{\delta }_n}{{\lambda }_n}+\frac{1}{{\alpha }_{\mathrm{inner}}}$ $\stackrel{.}{Q}=k·A·\Delta T_m$

where

• • l—characteristic dimension (for example pipe diameter)
  • Nu—Nusselt number
  • δ_n—layer thickness
  • λ_n—coefficient of thermal conductivity of the layer (for example pipe)
  • A—heat exchanger area

The improved heat transfer by radiation in the area of the convective heating surfaces by more than 39% is significant. In the case of the oxyfuel process with recirculation at the points 4 and 6, this is because of the high CO₂ concentration, and at the point 4, it is because of the increased water concentration. The heat transfer coefficient k is increased by the greater proportion of the radiation in the heat transfer in the convective part.

Overall, as can be seen from FIG. 10, the heat flow transferred in the convective part is increased. However, the heat transfer in the convective part also depends on the heat transfer in the radiation heating surfaces. This is because of the conditional flue gas and water/steam temperatures. The radiation heating surfaces are located before the convective heating surfaces 28 to 32, 49 along the flue gas path in the combustion chamber 25 and the radiation areas 26, 27. With the economizer heating surface 32, the water first of all flows through a convective heating surface, followed by the radiation heating surfaces for vaporization, and finally once again convective heating surfaces for superheating the steam.

If the total heat flow transferred in the steam generator 11 is the same, the flue gas will be considerably cooler because of the higher heat capacity in the oxyfuel process in the combustion chamber 25 and, at the end before the air precooler, will be somewhat hotter than in the case of the air process. It is therefore not absolutely essential to reach the adiabatic combustion temperature of the air process.

A change in the warming-up ranges in the superheaters and intermediate superheater heating surfaces should be observed. In all convective high-pressure heating surfaces, the warming-up ranges are higher than in the air process in the oxyfuel process using the circulation points 4 and 6. In contrast, only the heating surface 39 reaches a greater warming-up range in the medium-pressure heating surfaces.

The most important conversion for the oxyfuel mode is to feed back a portion of the flue gases. The recirculation gases are tapped off and fed back after the suction draft 17. FIGS. 2 and 11 illustrate the feed back, with FIG. 11 additionally showing the temperature and mass flow details of the fed-back flue gas flow, of the oxygen supplied from the oxygen preheater, as well as thermal energy flows. The components to be converted or to be added in comparison to an air mode are shown on a grey background. The required pressure increase in order to overcome the flow resistances and in order to produce a pressure gradient in the air preheater 8 and in the gas channels is produced by a recirculation fan 48, 48a, 48b.

After heating the flue gas by means of the suction draft 17 and then by means of one of the recirculation fans 48, 48a, 48b, the temperature on the recirculation side is higher in the flow direction before the air preheater (LUVO) 8 than on the flue gas side in the flow direction behind the air preheater (LUVO) 8. The flue gas can therefore not be cooled down to a lower temperature, without any further measures, in the air preheater (LUVO) 8 before entering the electrical filter 13. The cooling down in the air preheater (LUVO) 8 on the flue gas side is therefore controlled via the heat exchanger 35 (WÜ3), 16 by setting a temperature on the recirculation side before the air preheater (LUVO) 8. Furthermore, the heat transfer in the air preheater (LUVO) 8 is governed by the mass flows. In order to achieve the same flue gas temperatures at the inlet to the flue gas desulfurization installation (REA) 15 as in the air process, the flue gas is cooled down further after the suction draft 17.

The flue gas desulfurization installation 15 designed for the air mode is normally overdesigned for the oxyfuel mode, and adaptation to the reduced volume flow and the higher sulfur concentration may be necessary. This can be done by a design in which a relatively large portion of the washer can be shut down in the oxyfuel mode. Appropriate required flow speeds are then set in the smaller part that is used. The entire flue gas desulfurization installation (REA) 15 would be used in the air mode. The air supplied in the air process in order to improve the reaction must be replaced in the oxyfuel mode by external oxygen injection (external oxidation) 39, in order not to reduce the CO₂ concentration in the flue gas. These two heat exchangers are used for feed water preheating. The flow speed in the oxyfuel mode is reduced in comparison to the air mode because of the increased density of the flue gas. In addition, the heat transfer on the flue gas side is changed because the physical characteristics are different. A reduced heat flow is transferred. In order to change the intermediate temperatures of the feed water preheating as little as possible, the mill circulating flow can be increased by about 60%. This then results in negative feedbacks to the bleeds on the turbine, and in a positive increase in the heat-absorbing mass flow in the air preheater (LUVO).

The hot-gas temperature required for coal drying can be determined. Cold air is admixed before the mill in the air process, in order to control this temperature. Instead of this, recirculated flue gas containing CO₂ is used for a high CO₂ concentration in the off gas in the oxyfuel process. Correspondingly cold flue gas is tapped off behind the flue gas drier and condenser 21 at about 25° C. After increasing the pressure and heating, it is mixed in the required proportion before the mills 36 at 30° C., by means of an additional fan.

The flue gas can absorb the fuel moisture and the conventional sifter temperature in the mills 36 of 90° C. need not be increased for saturation reasons. The dew-point temperature of the sulfuric acid is undershot in the mills 36 and likewise in the oxygen preheater, in the heat exchangers and in the mill circuit fan, as well as the corresponding associated gas channels. As a countermeasure, the surfaces of these components may be coated with plastic, if required. However, this additional layer has the disadvantages that it impedes heat transport and offers scarcely any resistance against erosion.

The flue gas recirculation mass flow has an important influence on the flow speed of the flue gases in the convective part of the steam generator and on the adiabatic combustion temperature. A reduction in the flue gas mass flow at the burner acts like an increase in the oxygen content on the processes in the combustion chamber 25 and in the combustion area 18.

Overall, the increase in the recirculation mass flow results in a slightly greater heat flow being transferred in the convective heating surfaces, and a reduced heat flow being transferred in the radiation heating surfaces.

FIGS. 1, 2 and 11 show the process layouts in a flue gas circulation at the point 6. The flue gases are tapped off behind the flue gas drier 21, and are fed back. Since the flue gas is cooled down to 25° C. in the drier 21 and a major level of dust removal and desulfurization are carried out, the fresh-air fan 7 can also be used as a recirculation fan.

Behind the fresh-air fan, the recirculated flue gas is heated in the heat displacement system (WÜ3) 35 to 107° C. This temperature has an influence on the cooling down of the flue gas in the air preheater 8, which should be done at most to above the sulfuric acid dew point. The heat displacement system (WÜ3) 35 is no longer in the form of a regenerative heat exchanger in the oxyfuel mode, because this does not allow the desired media temperatures to be achieved. The heat transfer in the air preheater (LUVO) 8 is controlled by the distribution of the flue gas mass flow between the air preheater (LUVO) 8 and the air preheater (LUVO) bypass 34.

The inlet temperature into the flue gas desulfurization installation (REA) 14, 15 is predetermined by the heat flow which can be transferred to the recirculated flue gas in the heat displacement system (WÜ3) 35, 16, without any negative influence on the cooling down of the flue gas in the air preheater (LUVO) 8. The flue gas in the flue gas desulfurization installation (REA) 14, 15 is 12% warmer than in the air process.

The processes in the steam generator will be considered in order to examine possible ways to influence the heat transfer in the steam generator in the oxyfuel mode. Constant preheating of the combustion gases is assumed. The injections in the HP and MP parts of the steam generator are kept constant. The results are determined with the optimum operating point of the fuel, oxygen and recirculation mass flows in order to achieve the steam parameters before the turbine.

In the oxyfuel mode, the adiabatic combustion temperature rises because a reduced flue gas mass flow has to be heated at the burner. This results in a greater heat flow being absorbed in the vaporizer. The reduced flue gas mass flow is cooled down more quickly in the convective part, as a result of which the flue gas after the intermediate superheater heating surfaces 31 is cooler than in the air mode. The steam outlet temperature in the HP part is 17 K higher than in the air mode. This is probably because of the increased heat absorption in the vaporizer. The MP part of the steam generator 11, consisting of pure heating surfaces, in contrast does not reach the required warming-up range, as a result of which the temperature before the turbine is 17 K lower than in the air mode.

While the heat absorption in the convective heating surfaces in the steam generator 11 falls, it rises in the radiation heating surfaces.

If the recirculated mass flow is reduced by 20% and the conditions of impulse maintenance and oxygen content in the carrier gas are maintained, then the recirculated gas mass flow is furthermore not sufficient for impulse maintenance in the secondary gas. Less flue gas is then passed via the secondary gas, and no more is passed via the upper gas nozzles into the steam generator.

The fuel mass flow is now set such that the required HP outlet mass flow is achieved. This is linked with adapting the oxygen mass flow in order to maintain the desired excess oxygen of 1.17. The water mass flow injected for cooling before the intermediate superheater heating surfaces 31 is used to control the MP outlet temperature. This reduces the fuel mass flow by 2.5% in comparison to the optimum state in the air mode. In consequence, the adiabatic combustion temperature rises less severely and a somewhat reduced heat flow is absorbed by the radiation heating surfaces. The flue gas cools down more quickly due to the reduced heat flow introduced, and is already cooler behind the superheater heating surfaces 29 than in the optimum case in the air mode. Together with the reduced flue gas mass flow, this affects the heat transfer in the MP part. Despite reducing the injected cooling mass flow by 100%, the required outlet temperature on the intermediate superheater heating surfaces 31 cannot be achieved.

If, in contrast, the recirculated flue gas mass flow is increased by 20% and the conditions for impulse maintenance and oxygen content in the carrier gas and secondary gas are maintained, and if, furthermore, the upper gas nozzles pass excess sucked-back flue gas into the steam generator, the required HP outlet mass flow can be achieved by adaptation of the fuel mass flow. The excess oxygen of 1.17 should in this case be retained. The water mass flow injected for cooling before the intermediate superheater heating surfaces 31 is used to control the MP outlet temperature.

In this case, the steam generator control reacts to the steam temperature not being achieved at the outlet of the HP part by increasing the fuel mass flow by 2.5%. This results in the adiabatic combustion temperature rising and thus also the heat absorbed in the combustion chamber and the bulkhead heating surface. The somewhat greater volume flow as a result of the increased flue gas temperatures fuels better heat transfer in the convective part of the steam generator. The MP part is affected negatively by this. The warming-up ranges of the heating surfaces before the water injection are enlarged, which can be compensated for by quadrupling the injected water mass flow.

If the radiation exchange coefficient in the combustion chamber 18 is reduced by 30% from 1.636 to 1.145 and the fuel, oxygen and recirculation mass flows are kept constant, the reduction in the radiation exchange coefficient also causes the heat absorbed in the combustion chamber 18 to fall. The steam at the separator is 25 K cooler. The reduced heat absorption in the vaporizer is virtually completely compensated for by the convective heating surfaces of the HP part.

This is because the flue gas leaves the combustion chamber at a higher temperature. The heat transfer coefficient resulting from radiation α_radiation is increased in the next heating surfaces up to the heating surface 31. The final heating surfaces 31 and 29 exhibit increased warming-up ranges. This leads to the required outlet temperature in the MP part being exceeded by 5 K. The effects are similar to those when the recirculation mass flow is increased, although weaker. In both cases, the heat transfer in the convective part is improved, while it is lower on the radiation heating surfaces.

If the radiation exchange coefficient of the combustion chamber 18 is increased by 30% from 1.636 to 2.127 and the fuel, oxygen and recirculation mass flows are kept constant, a larger heat flow is absorbed in the combustion chamber 18, as a result of which the flue gas leaves the combustion chamber cooled down to a greater extent. Overall, a reduced heat flow is transferred in the convective part. The outlet temperature from the HP part is somewhat too high, and that of the MP part is somewhat too low. This is comparable to the effects of reducing the recirculation mass flow.

The effects of a change in the radiation exchange coefficient C of the combustion chamber 18 can be compensated for by adaptation of the fuel (HP outlet) and recirculation (MP outlet) mass flows. The excess oxygen is kept constant during this process.

A reduced radiation exchange coefficient C can be compensated for by a minimal reduction of the fuel mass flow and an increase of the recirculation mass flow. It is more difficult to compensate for the effects of a varied recirculation mass flow. It is therefore more important to accurately set the circulation mass flow during generator operation.

The required steam parameters can be achieved in the oxyfuel process as follows, without any changes to the steam generator heating surfaces. The heat transfer can be adapted by adjusting the fuel, oxygen and recirculation mass flows. However, an increase in the fuel mass flow reduces the overall efficiency, and should therefore be avoided. If, in contrast, variable combustion gas compensations are used to influence the heat transfer in the steam generator, this has a much more advantageous effect. The possibility of mixing in the oxygen into the primary, secondary and upper gases and therefore of adjusting the oxygen component as required provides the oxyfuel process with an additional degree of freedom for controlling the flame temperatures. With the distribution of the oxygen and recirculation mass flows between the burner gases and the upper gas it is possible to influence the radiation processes in the vaporizer via the flame temperature and the convective heat transfer via the flue gas temperature and flow rate. It is therefore possible to achieve a corresponding distribution of the heat flow absorption between the radiation heating surfaces and the convective heating surfaces. The adiabatic combustion temperature in the air process cannot be reached with the same level of excess oxygen. The effects, in the form of reduced heat absorption in the combustion chamber because of the high temperature influence in the radiation heat transfer can be compensated for in the convective part, thus achieving the required steam parameters.

Because of the higher density and heat capacity of the flue gas, flow speed and flue gas temperature decrease in the oxyfuel process when the same heat flow is introduced into the steam generator 11. The weaker convective heat transfer which results from this is compensated for by the higher gas radiation, because of the high CO₂ content, in the convective heating surfaces.

This development has a positive influence on the material temperatures of the HP part, since these depend mainly on the water and steam temperatures because of the greater heat transfer on the inside. In the HP part, high steam temperatures are achieved only at a late stage because of the lower heat absorption in the vaporizer, as a result of which the material temperatures are also somewhat lower than those in the air process. The slight shift in the heat transfer toward the convective part results in a rise in the steam temperatures in the first MP part of the steam generator 11 by a maximum of 10 K. Because of the wide safety margins in the material design and the slightly increased temperatures, this is not problematic.

In the air process, the excess air is controlled on the basis of the CO₂ and O₂ contents in the off gas. This procedure cannot be adopted for the oxyfuel mode because the oxygen and carbon dioxide mass flows recirculated with the flue gas must be included in the balance.

Increased NO_x concentrations are created in an air process without any steps by the nitrogen in the air and high combustion temperatures. In contrast, in the oxyfuel process, the nitrogen component introduced in the combustion gas is less than 7%, as a result of which virtually only fuel NO_x can still be formed. In consequence, the creation of the nitrogen oxides is dependent mainly on the combusted coal mass flow and its composition. In consequence, there is no need for air steps or gas steps in the combustion chamber in order to avoid NO_x. Instead of this, compositions and mass flows of the burner gases and of the upper gas can be varied in order to optimally adapt the heat absorption in the combustion area and convective part of the steam generator to the operating conditions. For example, during operation of the steam generator, the reduced heat absorption in the vaporizer resulting from dirt can be compensated for by adaptation of the recirculation mass flow.

This procedure leads to increased measurement and balancing complexity, but this can be coped with the aid of boiler diagnosis programs.

When flue gas is tapped off for flue gas circulation after the electrical filter 13 at the point 4, the shorter flue gas lines and the higher temperature at which the flue gas is recirculated are advantageous. In contrast, the enrichment of the flue gas with sulfur compounds which are still present at this point, and the sulfuric acid resulting from this, have a disadvantageous effect. In this case, heat exchangers and flue gas lines that are affected must in this case be converted so as to be appropriately corrosion-resistant for the oxyfuel mode.

In addition, two additional heat exchangers are required in recirculation behind the electrical filter 13, in order to reach the temperatures at the air preheater (LUVO) 8 and before the flue gas desulfurization installation (REA) 15.

In tie recirculation of the flue gas at the point 6 after the drier 21, longer flue gas channels are admittedly required, but, however, most components of the installation can still be used, without any change, for the air mode. The changes are limited for shutting down some passages in the electrical filter 13, adaptation of the flue gas desulfurization installation (REA) 15 to higher flue gas temperatures, and the construction of the air preheater (LUVO) bypass 34. The latter-mentioned component must be designed individually to be corrosion-resistant.

Drying the entire flue gas mass flow in the drier 21 increases the energy consumption. Nevertheless, this results in reduced conversion costs than in a recirculation at the point 4 behind the electrical filter 13. In consequence, the variant with recirculation of the flue gas at the point 6 behind the flue gas drier 21 is technically and economically more advantageous.

In both variants the efficiency is reduced by the additional electrical consumption for the air separation 20 and the CO₂ compression by about 10%. However, the efficiency losses are small in comparison to the flue gas washing (MEA).

Claims

1. A method for operating and for controlling a power station that comprises a coal-fired steam generator, the steam generator being designed for steam parameters that can be achieved for coal combustion, which is carried out with combustion air in the steam generator by heat transfer to the steam mass flow,

wherein combustion of the fuel, which contains carbon, is carried out in the steam generator on the basis of the oxyfuel process with approximately pure oxygen, which contains more than 95% by volume of O2, and recirculated flue gas with a high CO2 content, such that the mass flows of all the fuel flows as well as combustion gas flows, feed gas flows and process gas flows that are supplied to the coal-burners and to the steam generator are formed from combustion oxygen and/or recirculated flue gas in their respective composition ratio of oxygen and/or flue gas, and are matched to one another, such that the heat transfer that takes place in the steam generator by flame radiation, gas radiation and convection to the steam mass flow in the steam/water circuit of the steam generator is kept at least essentially the same overall in comparison to the air combustion.

2. The method according to claim 1, wherein treated and/or untreated flue gas is fed back in a recirculating manner to the steam generator.

3. The method according to claim 1, wherein an existing power station is retrofitted with the method as claimed in claim 1.

4. The method according to claim 1, wherein the recirculation rate of the flue gas is 65% to 80%.

5. The method according to claim 1, wherein the flue gas is tapped off after desulfurization or after a flue gas desulfurization installation or a flue gas cooler, which is installed additionally and/or subsequently, for recirculation.

6. The method according to claim 1, wherein the flue gas is tapped off after a flue gas condensation drier in the flow direction.

7. The method according to claim 1, wherein quicklime (CaO) is used as absorbent in the flue gas desulfurization installation.

8. A power station having a coal-fired steam generator that is designed for steam parameters that can be achieved for coal combustion, which is carried out with combustion air, in the steam generator by heat transfer to the steam mass flow,

wherein combustion of the fuel, which contains carbon, is carried out in the steam generator on the basis of the oxyfuel process with approximately pure oxygen, which contains more than 95% by volume of O2, and recirculated flue gas with CO2 content, such that the mass flows of all the fuel flows as well as combustion gas flows, feed gas flows and process gas flows that are supplied to the coal-burners and to the steam generator are formed from combustion oxygen and/or recirculated flue gas in their respective composition ratio of oxygen and/or flue gas, and are matched to one another, such that the heat transfer that takes place in the steam generator by flame radiation, gas radiation and convection to the steam mass flow in the steam/water circuit of the steam generator remains the same overall in comparison to the air combustion.

9. The power station according to claim 8, wherein a heat displacement system is installed between a suction draft and desulfurization or a desulfurization installation.

10. The power station according to claim 8, wherein the flue gas channel has a bypass line that is routed parallel to an air preheater (LUVO) and has a gas/gas heat exchanger arranged therein, after a denitrification device in the flow direction.

11. The method according to claim 1, wherein the recirculation rate of the flue gas is 74% to 78%.

12. The method according to claim 1, wherein an existing 600° C. power station is retrofitted with the method as claimed in claim 1.

13. The method according to claim 1, wherein the same steam parameters are maintained.

14. The power station according to claim 8, wherein the resultant steam parameters remain the same.