U.S. patent application number 11/918015 was filed with the patent office on 2009-01-29 for low co2 thermal powerplant.
This patent application is currently assigned to Sargas AS. Invention is credited to Knul Borseth, Tor Christensen, Henrik Fleischer.
Application Number | 20090025390 11/918015 |
Document ID | / |
Family ID | 35529540 |
Filed Date | 2009-01-29 |
United States Patent
Application |
20090025390 |
Kind Code |
A1 |
Christensen; Tor ; et
al. |
January 29, 2009 |
Low CO2 Thermal Powerplant
Abstract
A method for generation of electrical power mainly from a coal
based fuel, where the combustion gas is separated into a CO.sub.2
rich stream and a CO.sub.2 poor stream in a CO.sub.2 capturing
unit, the CO.sub.2 poor stream is released into the surroundings,
and the CO.sub.2 rich 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
Inventors: |
Christensen; Tor;
(Sandefjord, NO) ; Fleischer; Henrik; (Slependen,
NO) ; Borseth; Knul; (Tarnasen, NO) |
Correspondence
Address: |
BIRCH STEWART KOLASCH & BIRCH
PO BOX 747
FALLS CHURCH
VA
22040-0747
US
|
Assignee: |
Sargas AS
Oslo
NO
|
Family ID: |
35529540 |
Appl. No.: |
11/918015 |
Filed: |
April 8, 2005 |
PCT Filed: |
April 8, 2005 |
PCT NO: |
PCT/NO2005/000117 |
371 Date: |
November 21, 2007 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60669004 |
Apr 7, 2005 |
|
|
|
Current U.S.
Class: |
60/670 ; 110/204;
110/347; 239/418; 60/645 |
Current CPC
Class: |
F23C 9/003 20130101;
F23J 2219/10 20130101; Y02E 20/326 20130101; F23J 15/006 20130101;
Y02C 10/06 20130101; Y02A 50/20 20180101; Y02A 50/2342 20180101;
Y02E 20/18 20130101; Y02C 10/04 20130101; F23J 2217/10 20130101;
Y02E 20/344 20130101; Y02C 20/40 20200801; B01D 53/1475 20130101;
B01D 2257/504 20130101; F23C 2900/10006 20130101; F23C 6/04
20130101; F23J 2215/10 20130101; F23L 2900/07005 20130101; F23J
2215/50 20130101; Y02E 20/16 20130101; Y02E 20/34 20130101; F23J
2217/40 20130101; B01D 53/62 20130101; F01K 23/067 20130101; F23J
2219/40 20130101; Y02E 20/32 20130101 |
Class at
Publication: |
60/670 ; 60/645;
110/204; 110/347; 239/418 |
International
Class: |
F23B 80/02 20060101
F23B080/02; F23L 7/00 20060101 F23L007/00; F23D 1/00 20060101
F23D001/00 |
Foreign Application Data
Date |
Code |
Application Number |
Apr 5, 2005 |
NO |
20051687 |
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 CO.sub.2 rich stream and a CO.sub.2 poor stream in
a CO.sub.2 capturing unit, the CO.sub.2 poor stream is reheated and
expanded over a turbine to produce electrical power, before the
CO.sub.2 poor stream is released into the surroundings, wherein the
CO.sub.2 rich 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 CO.sub.2 rich 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 CO.sub.2 poor
stream is heated by heat exchanging against combustion gas from a
secondary combustion chamber fired by gas, before the CO.sub.2 poor
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.degree. 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 CO.sub.2 rich stream and a
CO.sub.2 poor stream, wherein the power plant additionally
comprises a line (54) for recirculation of a part of the CO.sub.2
to the combustion chamber and a CO.sub.2 line (55) for delivering
the remaining CO.sub.2 rich 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 CO.sub.2 poor stream, and
turbine (61) for expanding of the heated CO.sub.2 poor 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
CO.sub.2 gas, 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 CO.sub.2 poor
stream is heated by heat exchanging against combustion gas from a
secondary combustion chamber fired by gas, before the CO.sub.2 poor
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.degree. C. by production of steam.
Description
TECHNICAL FIELD
[0001] 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 CO.sub.2 rich stream which is
exported e.g. for safe deposition, and a CO.sub.2 poor 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
[0002] The concentration of CO.sub.2 in 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:
[0003] The mean temperature near the earth's surface has increased
by about 0.5.degree. C. over the last one hundred years, with an
accelerating trend in the last ten years. [0004] Over the same
period rainfall has increased by about 1% [0005] The sea level has
increased by 15 to 20 cm due to melting of glaciers and because
water expands when heated up.
[0006] 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.degree. 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 CO.sub.2, has altered the natural CO.sub.2 balance
and is therefore the direct reason for this development.
[0007] It is important that action is taken immediately to
stabilise the CO.sub.2 content of the atmosphere. This can be
achieved if CO.sub.2 generated 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
CO.sub.2 discharges to the atmosphere.
[0008] Discharge gas from thermal power plants typically contains 4
to 10% by volume of CO.sub.2, 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.
[0009] Capturing of CO.sub.2 from CO.sub.2 containing gas by means
of absorption is well known, see e.g. EP 0 551 876. The CO.sub.2
containing gas is here brought into contact with an absorbent,
usually an amine solution which absorbs CO.sub.2 from the gas. The
amine solution is thereafter regenerated by heating the amine
solution. The absorption is, however, dependent on the partial
pressure of CO.sub.2. If the partial pressure is too low, only a
relatively small part of the total CO.sub.2 is absorbed. Normally
the partial pressure of CO.sub.2 in 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
CO.sub.2 than if the partial pressure of CO.sub.2 in 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.
[0010] Therefore, the development work is concentrated on
increasing the partial pressure of CO.sub.2. 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 CO.sub.2 is 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.
[0011] Another possibility to raise the partial pressure of
CO.sub.2 is air separation. By separating the air that goes into
the combustion installation into oxygen and nitrogen, circulating
CO.sub.2 can 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 CO.sub.2 formed, the CO.sub.2 in the exhaust gas will
have a relatively high partial pressure, approximately up to 1 bar.
Excess CO.sub.2 from the combustion can then be separated out
relatively simply so that the installation for collection of
CO.sub.2 can 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.
[0012] 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 CO.sub.2 rich
stream for deposition, and a CO.sub.2 poor stream, and expanding
the CO.sub.2 poor 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.
[0013] WO 2004/026445 relates to a method for separation of
combustion gas from a thermal gas fired power plant into a CO.sub.2
rich stream and a CO.sub.2 poor 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.
[0014] 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 CO.sub.2 per unit of
electrical power than plants based on natural gas. Additionally,
coal is an easy available and compared with natural gas, less
expensive fuel.
[0015] 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 CO.sub.2 in the combustion gas, which is
disadvantageous for the separation of CO.sub.2.
[0016] 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.
[0017] 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 CO.sub.2 rich stream for deposition
and a CO.sub.2 poor stream that may be released into the
atmosphere.
[0018] 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 CO.sub.2 rich stream and a CO.sub.2 poor stream in
a CO.sub.2 capturing unit, the CO.sub.2 poor stream is reheated and
expanded over a turbine to produce electrical power, before the
CO.sub.2 poor stream is released into the surroundings, wherein the
CO.sub.2 rich 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 CO.sub.2 is used to bring the
pulverized coal into the combustion zone. If the pulverized coal is
fed into the boiler by air instead of CO.sub.2, there is severe
explosion hazard. By use of CO.sub.2 instead of air, the explosion
hazard is removed. Additionally, the pressure drop mentioned for
fluidized bed reactors, is eliminated.
[0019] According to a preferred embodiment, at least a portion of
the CO.sub.2 rich 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 CO.sub.2 rich 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 CO.sub.2 rich stream may be used as a
propellant for the fuel to force the fuel from the tank into the
combustion chamber.
[0020] The CO.sub.2 poor stream is preferably heated by heat
exchanging against combustion gas from a secondary combustion
chamber fired by gas, before the CO.sub.2 poor 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.
[0021] 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 CO.sub.2 in the CO.sub.2 capturing
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 CO.sub.2
are thus maximized.
[0022] It is preferred that the temperature in the combustion gas
leaving the combustion chamber, is reduced to below about
350.degree. C. by production of steam. By keeping the temperature
in the combustion gas leaving the combustion chamber below
350.degree. 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.
[0023] 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.
[0024] 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 CO.sub.2 rich stream and a CO.sub.2 poor
stream, wherein the power plant additionally comprises a line for
recirculation of a part of the CO.sub.2 to the combustion chamber
and a CO.sub.2 line for delivering the remaining CO.sub.2 rich
stream for deposition or export.
[0025] 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.
[0026] Preferably, the thermal power plant further comprises a
steam turbine connected to a generator for the production of
electrical power.
[0027] According to a preferred embodiment, a secondary combustion
chamber fired by gas, for generation of heat for heating the
CO.sub.2 poor stream, and turbine for expanding of the heated
CO.sub.2 poor 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 CO.sub.2 poor stream
over a turbine becomes more efficient and improves the total
efficiency of the plant.
[0028] It is preferred that the turbine for expansion of the
CO.sub.2 poor stream is connected to a generator for production of
electrical power.
[0029] 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 CO.sub.2
gas, 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 CO.sub.2 surrounded 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.
[0030] 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.
[0031] Helically ribs may additionally be provided inside the
central pipe. The helical ribs will cause the mixture of coal based
fuel and CO.sub.2 have 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.
[0032] 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
[0033] FIG. 1 is a schematic diagram of a preferred embodiment of
the invention;
[0034] FIG. 2a) illustrates a longitudinal section through an
injector according to the invention;
[0035] FIG. 2B illustrates the section A-A in FIG. 2a;
[0036] FIG. 3 illustrates an exemplary grinding and intermediate
fuel storage device for the plant according to the invention;
[0037] FIG. 4 is a longitudinal section through a combined heat
exchanger and secondary combustion chamber for plant according to
the invention;
[0038] FIG. 5 is a schematic diagram of an intermediate fuel
storage device and means for taking care of CO.sub.2; and
[0039] FIG. 6 is a schematic diagram of an exemplary CO.sub.2
capturing unit.
DETAILED DESCRIPTION OF THE INVENTION
[0040] 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.
[0041] 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.
[0042] 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 CO.sub.2 coming in from a
CO.sub.2-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
CO.sub.2 from the CO.sub.2-line 18 to avoid creation of dangerous
mixtures of air and coal dust.
[0043] The CO.sub.2 is controlled by means of a CO.sub.2 valve 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, CO.sub.2 is 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.
[0044] According to one embodiment, the CO.sub.2 inlets in the tank
are placed so that the mixture in the tank is at least partly
fluidized by the incoming stream of CO.sub.2. 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 CO.sub.2, 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.
[0045] 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.
[0046] 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.
[0047] 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.
[0048] 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.
[0049] 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.
[0050] 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.
[0051] The combustion gas leaving the combustion chamber 25 through
the combustion gas line 35 has preferably a temperature of about
350.degree. C., or lower. A temperature of less than 350.degree. 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.
[0052] 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.
[0053] 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.
[0054] 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.
[0055] 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 NH.sub.3,
according to the reaction 3NO+2NH.sub.3=2.5N.sub.2+3H.sub.2O. 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
NH.sub.3 may also be used. The NH.sub.3 method has the disadvantage
that it gives some NH.sub.3 "slip".
[0056] 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 CO.sub.2 capturing unit
49 in a line 48.
[0057] 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 NH.sub.3 "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.
[0058] The purification of the flue gas is essential to minimize
the formation of heat stable salts in the CO.sub.2 capturing
absorbent, and to minimize the degradation of CO.sub.2 capturing
performance with time.
[0059] The CO.sub.2 capturing 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
CO.sub.2 in the flue gas is typically reduced by 90 to 99% in the
absorber before the flue gas leaves the absorber as a CO.sub.2 poor
stream. The absorbent with absorbed CO.sub.2 (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 CO.sub.2 is removed from the
stripper column as a CO.sub.2 rich stream. FIG. 6 illustrates an
exemplary CO.sub.2 capturing unit. The detailed design the unit
will, however, depend on the type of solvent used.
[0060] The CO.sub.2 capturing unit 49 may be any kind of unit
capable of splitting the partly cleaned combustion gas in a
CO.sub.2-rich stream leaving the unit through a CO.sub.2-line 51,
and a CO.sub.2-poor stream leaving the unit through a line 50. The
CO.sub.2-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 CO.sub.2-rich stream is leaving the compressor in line
54 and is recycled as a source of CO.sub.2 for the intermediate
storage means 14. The remaining CO.sub.2 is compressed further and
is removed from the plant in a CO.sub.2-line 55.
[0061] The CO.sub.2-poor stream leaving the CO.sub.2 capturing 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 CO.sub.2-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 CO.sub.2 that
has been removed from the combustion gas so that the heat capacity
of the CO.sub.2-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).
[0062] The heated CO.sub.2-poor stream leaves the heat exchanger 44
through a line 58 and is introduced into a heat exchanger 59 where
the CO.sub.2-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.
[0063] 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
CO.sub.2-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.degree. C., the recirculation is
superfluous.
[0064] The heated CO.sub.2-poor stream leaving the heat exchanger
59 in a line 60, is expanded over a turbine 61. The expanded
CO.sub.2-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 CO.sub.2-poor stream is used to heat
the water in the preheater 32.
[0065] 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.
[0066] FIG. 2a 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.
[0067] The mixture of coal, CO.sub.2 and 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 CO.sub.2 and 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.
[0068] 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 CO.sub.2 delivered 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.
[0069] FIG. 2b illustrates the cross section A-A in FIG. 2a. 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.
[0070] 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.
[0071] The mill and lower part of the funnel is preferably purged
by CO.sub.2 entering 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
CO.sub.2 in the purge line is controlled by a valve 153.
[0072] 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, CO.sub.2 is introduced into the tank at the top of
the tank through a CO.sub.2 line 154 controlled by a valve 155,
and/or through a CO.sub.2 line 157 controlled by a valve 158. The
introduction of CO.sub.2 either 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
CO.sub.2 through 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 CO.sub.2, 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.
[0073] 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.
[0074] Air and natural gas are introduced through an air line 203
and a gas line 202, respectively, into a combustion chamber 201.
CO.sub.2 is introduced from a CO.sub.2 line 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
CO.sub.2-poor stream from line 58 entering the device through an
inlet 212. The CO.sub.2 poor stream circulates in the circulation
space defined between the outer wall of the flue gas chamber 207
and a heat exchanger shell 210.
[0075] 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 CO.sub.2 poor 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 CO.sub.2 poor 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.
[0076] 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.
[0077] FIG. 5 illustrates an embodiment of the intermediate storage
means 14, including storage means 250 for CO.sub.2. The CO.sub.2
storage means 250 comprises a CO.sub.2 storage 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 CO.sub.2 storage means 250
may be closed of from the intermediate storage means 14 by means of
an optional valve 251.
[0078] When CO.sub.2 under 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
CO.sub.2 from 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.
[0079] To fill excess CO.sub.2 from a tank 16, 16' or 16'', into
the tank 255, the corresponding valve 248, 248' or 248'' is opened.
The CO.sub.2 is 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.
[0080] It is obvious for the skilled man that CO.sub.2 may be
introduced or removed from the tank 16 through any CO.sub.2 lines
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.
[0081] FIG. 6 illustrates an exemplary and somewhat simplified
CO.sub.2 capturing 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 CO.sub.2) 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 CO.sub.2.
[0082] 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 CO.sub.2 to be released
from the absorbent. CO.sub.2 released from the absorbent is removed
from the stripping column through a CO.sub.2 line 306. The CO.sub.2
in line 306 is cooled in a reflux condenser 307 to remove humidity
in the CO.sub.2 rich stream leaving the CO.sub.2 capturing unit
through line 51. Humidity that is condensed in the reflux condenser
307 is returned to the stripping column in a reflux line 308.
[0083] 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.
[0084] In an exemplary plant according to FIG. 1, key figures for
temperature, pressure and mass flow may be as follows:
TABLE-US-00001 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) (.degree. 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
[0085] 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.
* * * * *