U.S. patent application number 13/515160 was filed with the patent office on 2012-11-15 for heat recovery system and heat recovery method of co2 recovery unit.
This patent application is currently assigned to THE KANSAI ELECTRIC POWER CO., INC.. Invention is credited to Masaki Iijima, Kazuhiko Kaibara, Tsuyoshi Oishi, Masahiko Tatsumi, Yasuyuki Yagi.
Application Number | 20120285171 13/515160 |
Document ID | / |
Family ID | 44355260 |
Filed Date | 2012-11-15 |
United States Patent
Application |
20120285171 |
Kind Code |
A1 |
Iijima; Masaki ; et
al. |
November 15, 2012 |
HEAT RECOVERY SYSTEM AND HEAT RECOVERY METHOD OF CO2 RECOVERY
UNIT
Abstract
A heat recovery system of a CO.sub.2 recovery unit (55)
including an absorber that removes CO.sub.2 in flue gas (101)
discharged from a boiler (51) by absorbing CO.sub.2 by an
absorbent, and a regenerator that emits CO.sub.2 from the absorbent
having absorbed CO.sub.2 for reusing the absorbent in the absorber.
The heat recovery system further includes a Ljungstrom heat
exchanger (57) that performs heat exchange between the flue gas
(101) discharged from the boiler (51) and before reaching the
CO.sub.2 recovery unit (55) and unburned air (102) supplied to the
boiler (51), and an air preheater (58) that preheats the unburned
air (102) before reaching the Ljungstrom heat exchanger (57) by
exhaust heat from the CO.sub.2 recovery unit (55).
Inventors: |
Iijima; Masaki; (Tokyo,
JP) ; Oishi; Tsuyoshi; (Tokyo, JP) ; Tatsumi;
Masahiko; (Hyogo, JP) ; Yagi; Yasuyuki;
(Hyogo, JP) ; Kaibara; Kazuhiko; (Hyogo,
JP) |
Assignee: |
THE KANSAI ELECTRIC POWER CO.,
INC.
Osaka-shi, Osaka
JP
MITSUBISHI HEAVY INDUSTRIES, LTD.
Tokyo
JP
|
Family ID: |
44355260 |
Appl. No.: |
13/515160 |
Filed: |
January 11, 2011 |
PCT Filed: |
January 11, 2011 |
PCT NO: |
PCT/JP2011/050286 |
371 Date: |
June 11, 2012 |
Current U.S.
Class: |
60/670 ;
165/104.13 |
Current CPC
Class: |
F28D 19/041 20130101;
Y02P 20/57 20151101; Y02P 20/50 20151101; C01B 32/50 20170801; Y02P
20/10 20151101; Y02E 20/34 20130101; Y02P 20/151 20151101; Y02P
20/124 20151101; Y02C 10/04 20130101; Y02E 20/32 20130101; F28D
21/001 20130101; Y02E 20/348 20130101; Y02C 10/06 20130101; B01D
53/1425 20130101; F23L 15/00 20130101; B01D 2252/204 20130101; Y02E
20/326 20130101; Y02P 20/152 20151101; Y02C 20/40 20200801; Y02P
20/129 20151101; B01D 53/1475 20130101; B01D 2258/0283
20130101 |
Class at
Publication: |
60/670 ;
165/104.13 |
International
Class: |
F28D 15/00 20060101
F28D015/00; F01K 23/06 20060101 F01K023/06 |
Foreign Application Data
Date |
Code |
Application Number |
Feb 8, 2010 |
JP |
2010-025901 |
Claims
1. A heat recovery system of a CO.sub.2 recovery unit including an
absorber that removes CO.sub.2 in flue gas discharged from a boiler
by absorbing CO.sub.2 by an absorbent, and a regenerator that emits
CO.sub.2 from the absorbent having absorbed CO.sub.2 for reusing
the absorbent in the absorber, the heat recovery system comprising:
a Ljungstrom heat exchanger that performs heat exchange between
flue gas discharged from the boiler and before reaching the
CO.sub.2 recovery unit and unburned air supplied to the boiler; and
an air preheater that preheats the unburned air before reaching the
Ljungstrom heat exchanger by exhaust heat from the CO.sub.2
recovery unit.
2. The heat recovery system of a CO.sub.2 recovery unit according
to claim 1, further comprising a heat recovery device that recovers
heat of the flue gas before reaching the CO.sub.2 recovery unit
through the Ljungstrom heat exchanger and supplies recovered heat
to the CO.sub.2 recovery unit.
3. The heat recovery system of a CO.sub.2 recovery unit according
to claim 1, wherein the heat recovery system is applied to a power
generation plant that drives a steam turbine by superheated steam
from the boiler to generate power.
4. The heat recovery system of a CO.sub.2 recovery unit according
to claim 1, wherein the air preheater indirectly heats the unburned
air by circulating a heat medium heated by heat transfer of exhaust
heat from the CO.sub.2 recovery unit.
5. The heat recovery system of a CO.sub.2 recovery unit according
to claim 1, wherein the air preheater directly heats the unburned
air by circulating a exhaust heat fluid from the CO.sub.2 recovery
unit.
6. A heat recovery method of a CO.sub.2 recovery unit including a
CO.sub.2 recovery step of removing CO.sub.2 in flue gas discharged
from a boiler by absorbing CO.sub.2 by an absorbent, emitting
CO.sub.2 from the absorbent having absorbed CO.sub.2, and of
reusing the absorbent for absorbing CO.sub.2, the heat recovery
method comprising: a heat exchanging step of performing heat
exchange between flue gas discharged from the boiler and before
reaching the CO.sub.2 recovery step and unburned air supplied to
the boiler; and an air preheating step of preheating the unburned
air before reaching the heat exchanging step by exhaust heat from
the CO.sub.2 recovery step.
7. The heat recovery method of a CO.sub.2 recovery unit according
to claim 6, further comprising a heat recovery step of recovering
heat of the flue gas before reaching the CO.sub.2 recovery step
through the heat exchanging step and of supplying recovered heat to
the CO.sub.2 recovery step.
8. The heat recovery method of a CO.sub.2 recovery unit according
to claim 6, further comprising a power generation step of driving a
steam turbine by superheated steam from the boiler to generate
power.
Description
FIELD
[0001] The present invention relates to a heat recovery system and
a heat recovery method of a CO.sub.2 recovery unit that effectively
use heat discharged from the CO.sub.2 recovery unit.
BACKGROUND
[0002] The greenhouse effect due to CO.sub.2 has been pointed out
as a cause of global warming, and there has been an urgent need to
take measures against the greenhouse effect for protecting the
global environment in an international scale. Generation sources of
CO.sub.2 extend over all human activities that burn fossil fuel,
and demands for emission limitation are further increasing. Under
these circumstances, a method of removing and recovering CO.sub.2
in flue gas by bringing flue gas discharged from a boiler into
contact with an amine absorbent such as an amine compound solution
has been intensively studied. The method is targeted for power
generation facilities such as a thermal power plant that uses a
large amount of fossil fuel.
[0003] As a CO.sub.2 recovery unit that recovers CO.sub.2 from flue
gas by using an absorbent, there has been known an apparatus that
removes CO.sub.2 in flue gas by bringing flue gas into contact with
a CO.sub.2 absorbent in an absorber, heats the absorbent that has
absorbed CO.sub.2 in a regenerator, thereby emitting CO.sub.2 and
regenerating the absorbent, and returns the absorbent to the
absorber and reuses the absorbent (see, for example, Patent
Literature 1).
CITATION LIST
Patent Literature
[0004] Patent Literature 1: Japanese Patent Application Laid-open
No. 5-245339
SUMMARY
Technical Problem
[0005] In the CO.sub.2 recovery unit described above, a large
amount of low-temperature flue gas at a temperature level of
70.degree. C. to 80.degree. C. is discharged. Generally, however,
because the heat of flue gas is low, the flue gas is cooled by
cooling water and disposed.
[0006] The present invention has been achieved to solve the above
problems, and an object of the present invention is to provide a
heat recovery system and a heat recovery method of a CO.sub.2
recovery unit that can effectively use low-temperature exhaust heat
discharged at the time of recovering CO.sub.2.
Solution to Problem
[0007] According to an aspect of the present invention, a heat
recovery system of a CO.sub.2 recovery unit include an absorber
that removes CO.sub.2 in flue gas discharged from a boiler by
absorbing CO.sub.2 by an absorbent, and a regenerator that emits
CO.sub.2 from the absorbent having absorbed CO.sub.2 for reusing
the absorbent in the absorber. The heat recovery system includes: a
Ljungstrom heat exchanger that performs heat exchange between flue
gas discharged from the boiler and before reaching the CO.sub.2
recovery unit and unburned air supplied to the boiler; and an air
preheater that preheats the unburned air before reaching the
Ljungstrom heat exchanger by exhaust heat from the CO.sub.2
recovery unit.
[0008] According to the heat recovery system of a CO.sub.2 recovery
unit, the flow rate of low-pressure steam consumed by the CO.sub.2
recovery unit can be decreased by preheating unburned air before
reaching the Ljungstrom heat exchanger by low-temperature exhaust
heat discharged at the time of recovering CO.sub.2.
[0009] Furthermore, because the Ljungstrom heat exchanger performs
heat exchange between flue gas containing sulfur content and
unburned air, a heat reservoir may be subjected to sulfuric acid
corrosion due to dew condensation generated on a heat transfer
surface of the heat reservoir. However, according to the heat
recovery system of a CO.sub.2 recovery unit, the gas temperature of
unburned air on an inlet side of the Ljungstrom heat exchanger is
raised, and the gas temperature of flue gas on an outlet side of
the Ljungstrom heat exchanger is also raised. As a result, an
average cold-end temperature ((the gas temperature on the outlet
side of flue gas+the gas temperature on the inlet side of unburned
air)/2) of the Ljungstrom heat exchanger increases. Consequently,
dew condensation on the heat transfer surface of the heat reservoir
of the Ljungstrom heat exchanger can be prevented to suppress
sulfuric acid corrosion of the heat reservoir.
[0010] Advantageously, the heat recovery system of a CO.sub.2
recovery unit further includes a heat recovery device that recovers
heat of the flue gas before reaching the CO.sub.2 recovery unit
through the Ljungstrom heat exchanger and supplies recovered heat
to the CO.sub.2 recovery unit.
[0011] According to the heat recovery system of a CO.sub.2 recovery
unit, the flow rate of low-pressure steam consumed by the CO.sub.2
recovery unit can be further decreased by recovering the heat of
flue gas after passing through the Ljungstrom heat exchanger, while
preheating unburned air before reaching the Ljungstrom heat
exchanger by low-temperature exhaust heat discharged at the time of
recovering CO.sub.2.
[0012] Advantageously, in the heat recovery system of a CO.sub.2
recovery unit, the heat recovery system is applied to a power
generation plant that drives a steam turbine by superheated steam
from the boiler to generate power.
[0013] According to the heat recovery system of a CO.sub.2 recovery
unit, because the gas temperature of unburned air supplied to the
boiler increases, the flow rate of superheated steam to be supplied
from the boiler to the steam turbine increases, thereby enabling to
improve the power generation efficiency of a power generation
plant.
[0014] Advantageously, in the heat recovery system of a CO.sub.2
recovery unit, the air preheater indirectly heats the unburned air
by circulating a heat medium heated by heat transfer of exhaust
heat from the CO.sub.2 recovery unit.
[0015] According to the heat recovery system of a CO.sub.2 recovery
unit, exhaust heat fluid can be prevented from flowing out, as
compared to a case where unburned air is directly heated by using
exhaust heat fluid of the CO.sub.2 recovery unit.
[0016] Advantageously, in the heat recovery system of a CO.sub.2
recovery unit, the air preheater directly heats the unburned air by
circulating a exhaust heat fluid from the CO.sub.2 recovery
unit.
[0017] According to the heat recovery system of a CO.sub.2 recovery
unit, the heat transfer efficiency can be improved with respect to
a case where unburned air is indirectly heated via a heat
medium.
[0018] According to another aspect of the present invention, a heat
recovery method of a CO.sub.2 recovery unit including a CO.sub.2
recovery step of removing CO.sub.2 in flue gas discharged from a
boiler by absorbing CO.sub.2 by an absorbent, emitting CO.sub.2
from the absorbent having absorbed CO.sub.2, and of reusing the
absorbent for absorbing CO.sub.2, includes: a heat exchanging step
of performing heat exchange between flue gas discharged from the
boiler and before reaching the CO.sub.2 recovery step and unburned
air supplied to the boiler; and an air preheating step of
preheating the unburned air before reaching the heat exchanging
step by exhaust heat from the CO.sub.2 recovery step.
[0019] According to the heat recovery method of a CO.sub.2 recovery
unit, the flow rate of low-pressure steam consumed by the CO.sub.2
recovery unit can be decreased by preheating unburned air before
reaching the heat exchanging step by low-temperature exhaust heat
discharged at the time of recovering CO.sub.2.
[0020] Furthermore, because the heat exchange between flue gas
containing sulfur content and unburned air is performed at the heat
exchanging step, a heat reservoir may be subjected to sulfuric acid
corrosion due to dew condensation generated on a heat transfer
surface of the heat reservoir. However, according to the heat
recovery method of a CO.sub.2 recovery unit, the gas temperature of
unburned air on an inlet side of the heat exchanging step is
raised, and the gas temperature of flue gas on an outlet side of
the heat exchanging step is also raised. As a result, an average
cold-end temperature ((the gas temperature on the outlet side of
flue gas+the gas temperature on the inlet side of unburned air)/2)
at the heat exchanging step increases. Consequently, dew
condensation on the heat transfer surface of the heat reservoir at
the heat exchanging step can be prevented to suppress sulfuric acid
corrosion of the heat reservoir.
[0021] Advantageously, the heat recovery method of a CO.sub.2
recovery unit further includes a heat recovery step of recovering
heat of the flue gas before reaching the CO.sub.2 recovery step
through the heat exchanging step and of supplying recovered heat to
the CO.sub.2 recovery step.
[0022] According to the heat recovery method of a CO.sub.2 recovery
unit, the flow rate of low-pressure steam consumed at the CO.sub.2
recovery step can be further decreased by recovering the heat of
flue gas after passing through the heat exchanging step, while
preheating unburned air before reaching the Ljungstrom heat
exchanger by low-temperature exhaust heat discharged at the time of
recovering CO.sub.2.
[0023] Advantageously, the heat recovery method of a CO.sub.2
recovery unit, further includes a power generation step of driving
a steam turbine by superheated steam from the boiler to generate
power.
[0024] According to the heat recovery method of a CO.sub.2 recovery
unit, because the gas temperature of unburned air supplied to the
boiler increases, the flow rate of superheated steam to be supplied
from the boiler to the steam turbine increases, thereby enabling to
improve the power generation efficiency at a power generation step.
Advantageous Effects of Invention
[0025] According to the present invention, low-temperature exhaust
heat discharged at the time of recovering CO.sub.2 can be
effectively used.
BRIEF DESCRIPTION OF DRAWINGS
[0026] FIG. 1 is a schematic diagram of a power generation plant to
which a heat recovery system of a CO.sub.2 recovery unit according
to a first embodiment of the present invention is applied.
[0027] FIG. 2 is a schematic diagram of the heat recovery system of
a CO.sub.2 recovery unit according to the first embodiment of the
present invention.
[0028] FIG. 3 is a chart of a pattern of the heat recovery system
of a CO.sub.2 recovery unit according to the first embodiment of
the present invention.
[0029] FIG. 4 is a schematic diagram of an effect of the heat
recovery system of a CO.sub.2 recovery unit according to the first
embodiment of the present invention.
[0030] FIG. 5 is a schematic diagram of a heat recovery system of a
CO.sub.2 recovery unit according to a second embodiment of the
present invention. FIG. 6 is a chart of a pattern of the heat
recovery system of a CO.sub.2 recovery unit according to the second
embodiment of the present invention.
[0031] FIG. 7 is a schematic diagram of an effect of the heat
recovery system of a CO.sub.2 recovery unit according to the second
embodiment of the present invention.
[0032] FIG. 8 is a schematic diagram of a power generation plant to
which a heat recovery system of a CO.sub.2 recovery unit according
to a third embodiment of the present invention is applied. FIG. 9
is a schematic diagram of the heat recovery system of a CO.sub.2
recovery unit according to the third embodiment of the present
invention.
[0033] FIG. 10 is a chart of a pattern of the heat recovery system
of a CO.sub.2 recovery unit according to the third embodiment of
the present invention.
[0034] FIG. 11 is a schematic diagram of an effect of the heat
recovery system of a CO.sub.2 recovery unit according to the third
embodiment of the present invention.
[0035] FIG. 12 is a schematic diagram of a heat recovery system of
a CO.sub.2 recovery unit according to a fourth embodiment of the
present invention.
[0036] FIG. 13 is a schematic diagram of an effect of the heat
recovery system of a CO.sub.2 recovery unit according to the fourth
embodiment of the present invention.
DESCRIPTION OF EMBODIMENTS
[0037] Exemplary embodiments of the present invention will be
explained below in detail with reference to the accompanying
drawings. The present invention is not limited to these
embodiments. In addition, constituent elements in the following
embodiments include elements that can be easily replaced by those
skilled in the art, or substantially the same elements.
First Embodiment
[0038] A first embodiment is explained with reference to the
drawings. FIG. 1 is a schematic diagram of a power generation plant
to which a heat recovery system of a CO.sub.2 recovery unit
according to the first embodiment is applied. FIG. 2 is a schematic
diagram of the heat recovery system of a CO.sub.2 recovery unit
according to the first embodiment. FIG. 3 is a chart of a pattern
of the heat recovery system of a CO.sub.2 recovery unit according
to the first embodiment. FIG. 4 is a schematic diagram of an effect
of the heat recovery system of a CO.sub.2 recovery unit according
to the first embodiment.
[0039] As shown in FIG. 1, a power generation plant 50 mainly
includes a boiler 51 that heats water in a sealed vessel by thermal
energy acquired by burning fuel to acquire high-temperature and
high-pressure superheated steam 100, a steam turbine 52 that
acquires rotative power by the superheated steam 100 from the
boiler 51, and a power generator 53 that generates power by the
rotative power of the steam turbine 52. Furthermore, the power
generation plant 50 includes a flue gas desulfurizer 54 that
removes sulfur content (including a sulfur compound) contained in
flue gas 101 discharged from the boiler 51, and a CO.sub.2 recovery
unit 55 that removes CO.sub.2 (carbon dioxide) contained in the
flue gas 101 discharged from the boiler 51. That is, the power
generation plant 50 generates power by the superheated steam 100
from the boiler 51, and discharges decarbonated flue gas 101a, in
which sulfur content and CO.sub.2 discharged from the boiler 51 are
removed, from a stack 56.
[0040] In the power generation plant 50, the boiler 51 is attached
with a Ljungstrom heat exchanger 57. The Ljungstrom heat exchanger
57 performs heat exchange between the flue gas 101 discharged from
the boiler 51 and unburned air 102 supplied to the boiler 51. The
Ljungstrom heat exchanger 57 improves the thermal efficiency of the
boiler 51 by preheating the unburned air 102 supplied to the boiler
51.
[0041] The heat recovery system of the CO.sub.2 recovery unit 55
according to the present embodiment includes an air preheater 58
that preheats the unburned air 102 before reaching the Ljungstrom
heat exchanger 57 by exhaust heat from the CO.sub.2 recovery unit
55.
[0042] Exhaust heat from the CO.sub.2 recovery unit 55 is
specifically explained below. The CO.sub.2 recovery unit 55
includes a cooling column 1 that cools the flue gas 101 discharged
from the boiler 51 by cooling water 103, an absorber 2 that brings
a lean solution 104a of an absorbent 104, which is an aqueous
solution of an amine compound that absorbs CO.sub.2, into
countercurrent contact with the flue gas 101 so that CO.sub.2 in
the flue gas 101 is absorbed by the absorbent 104 and discharges
the decarbonated flue gas 101a in which CO.sub.2 has been removed,
and a regenerator 3 that emits CO.sub.2 from a rich solution 104b
of the absorbent 104 having absorbed CO.sub.2 to regenerate it to
the lean solution 104a.
[0043] In the cooling column 1, the flue gas 101 containing
CO.sub.2 is boosted by a flue gas blower (not shown) and fed into
the cooling column 1, and brought into countercurrent contact with
the cooling water 103, thereby cooling the flue gas 101.
[0044] The cooling water 103 is accumulated in a lower part of the
cooling column 1 and is supplied to an upper part of the cooling
column 1 by a humidified cooling-water circulating pump 1a through
a cooling water pipe 1b outside of the cooling column 1. The
cooling water 103 is brought into countercurrent contact with the
flue gas 101 moving upward at a position of a packed bed 1d
provided in a process leading to the lower part of the cooling
column 1, while flowing down from a nozzle 1c provided in the upper
part of the cooling column 1. Furthermore, a cooler 1e that
condenses the cooling water 103 by cooling to acquire condensed
water is provided in the cooling water pipe 1b. The flue gas 101
cooled in the cooling column 1 is discharged from a top of the
cooling column 1 through a flue gas pipe 1f and supplied to the
absorber 2.
[0045] The absorber 2 has a CO.sub.2 absorbing unit 21 in a lower
half thereof, and a flushing unit 22 in an upper half thereof. The
CO.sub.2 absorbing unit 21 brings the flue gas 101 supplied from
the cooling column 1 into countercurrent contact with the lean
solution 104a of the absorbent 104, so that CO.sub.2 in the flue
gas 101 is absorbed by the absorbent 104.
[0046] The lean solution 104a of the absorbent 104 is supplied from
the regenerator 3, and brought into countercurrent contact with the
flue gas 101 moving upward at a position of a packed bed 21b
provided in a process leading to the lower part of the absorber 2,
while flowing down from a nozzle 21a, to become the rich solution
104b having absorbed CO.sub.2, and is accumulated at a bottom of
the absorber 2. The rich solution 104b of the absorbent 104
accumulated at the bottom of the absorber 2 is pumped by a
rich-solution discharge pump 21d installed in a rich solution pipe
21c outside of the absorber 2, and supplied to the regenerator 3.
Furthermore, while being supplied to the regenerator 3 through the
rich solution pipe 21c, the rich solution 104b of the absorbent 104
is heat-exchanged with the lean solution 104a of the absorbent 104
being supplied to the absorber 2 through a lean solution pipe 33d
described later by a rich-lean heat exchanger 4.
[0047] The flushing unit 22 brings the decarbonated flue gas 101a
with CO.sub.2 being removed by the CO.sub.2 absorbing unit 21 into
countercurrent contact with wash water 105 to remove the amine
compound entrained with the decarbonated flue gas 101a by the wash
water 105, and discharges the decarbonated flue gas 101a with the
amine compound being removed, to outside of the absorber 2.
[0048] The wash water 105 is brought into countercurrent contact
with the decarbonated flue gas 101a moving upward at a position of
a packed bed 22b provided in a process going downward, while
flowing down from a nozzle 22a, and is accumulated in a water
receptor 22c. The wash water 105 accumulated in the water receptor
22c is pumped and circulated by a wash-water discharge pump 22e
installed in a wash water pipe 22d outside of the absorber 2,
cooled by a cooler 22f, and caused to flow down from the nozzle 22a
again.
[0049] The absorber 3 recovers CO.sub.2 from the rich solution 104b
of the absorbent 104, regenerates it as the lean solution 104a, and
accumulates the lean solution 104a at the bottom, thereby emitting
CO.sub.2 from the absorbent 104 having absorbed CO.sub.2. The
regenerator 3 is divided into three parts, which are an upper part,
a middle part, and a lower part. That is, these are an upper
regenerating unit 31, a middle regenerating unit 32, and a lower
regenerating unit 33.
[0050] In the upper regenerating unit 31, the absorbent 104 is
supplied from the rich solution pipe 21c of the CO.sub.2 absorbing
unit 21 in the absorber 2, to flow down from a nozzle 31a, passes
through a packed bed 31b provided in a process going downward, and
accumulated in a chimney tray 31c. The absorbent 104 accumulated in
the chimney tray 31c is supplied to the middle regenerating unit
32, while being pumped to outside of the regenerator 3 by a
semi-lean-solution discharge pump 31e installed in a
semi-lean-solution extracting pipe 31d.
[0051] In the middle regenerating unit 32, the absorbent 104 is
supplied from the semi-lean-solution extracting pipe 31d of the
upper regenerating unit 31 to flow down from a nozzle 32a, passes
through a packed bed 32b provided in a process going downward, and
accumulated in a chimney tray 32c. The absorbent 104 accumulated in
the chimney tray 32c is supplied to the lower regenerating unit 33,
while being pumped to outside of the regenerator 3 by a
semi-lean-solution discharge pump 32e installed in a
semi-lean-solution extracting pipe 32d.
[0052] In the lower regenerating unit 32, the absorbent 104 is
supplied from the semi-lean-solution extracting pipe 32d of the
middle regenerating unit 32 to flow down from a nozzle 33a, passes
through a packed bed 33b provided in a process going downward, and
accumulated at a bottom 33c of the regenerator 3. The absorbent 104
accumulated at the bottom 33c of the regenerator 3 is pumped to
outside of the regenerator 3 by a lean-solution discharge pump 33e
installed in a lean-solution extracting pipe 33d, heat-exchanged
with the rich solution 104b of the absorbent 104 being supplied to
the regenerator 3 through the rich solution pipe 21c by the
rich-lean heat exchanger 4, and then, supplied to the absorber 2
while being cooled by a cooler 33f.
[0053] A regenerating heater 34 that uses low-pressure steam 106
from the steam turbine 52 as a source of heat is provided outside
of the regenerator 3. A part of the absorbent 104 accumulated at
the bottom 33c of the regenerator 3 is heated by the regenerating
heater 34 while being extracted to outside of the regenerator 3 via
a heating pipe 34a to become the lean solution 104a, and returned
to the bottom 33c of the regenerator 3 and accumulated therein. The
low-pressure steam 106 supplied to the regenerating heater 34 heats
the absorbent 104 while passing through the heating pipe 34a, to
become steam drain 106a and discharged via a drain pipe 34b.
[0054] A lean-solution/steam-drain heat recovery unit 35 is
provided in the semi-lean-solution extracting pipe 31d of the upper
regenerating unit 31. The lean-solution/steam-drain heat recovery
unit 35 performs heat exchange between the absorbent 104 being
supplied to the middle regenerating unit 32 through the
semi-lean-solution extracting pipe 31d and the lean solution 104a
of the absorbent 104 being supplied to the absorber 2 via the lean
solution pipe 33d and the steam drain 106a being discharged via the
drain pipe 34b.
[0055] A lean-solution/steam-drain heat recovery unit 36 is
provided in the semi-lean-solution extracting pipe 32d of the
middle regenerating unit 32. The lean-solution/steam-drain heat
recovery unit 36 performs heat exchange between the absorbent 104
being supplied to the lower regenerating unit 33 through the
semi-lean-solution extracting pipe 32d and the lean solution 104a
of the absorbent 104 being supplied to the absorber 2 via the lean
solution pipe 33d and the steam drain 106a being discharged via the
drain pipe 34b.
[0056] That is, in the regenerator 3, the rich solution 104b of the
absorbent 104 to be supplied to the upper regenerating unit 31
flows down from the nozzle 31a, while being heated by heat exchange
with the lean solution 104a of the absorbent 104 being supplied to
the absorber 2 by the rich-lean heat exchanger 4, in the process of
being supplied to the regenerator 3 via the rich solution pipe 21c.
The rich solution 104b of the absorbent 104 becomes a semi-lean
solution 104c with the most part of CO.sub.2 being emitted by an
endothermic reaction, while passing through the packed bed 31b in
the process going downward, and is accumulated in the chimney tray
31c.
[0057] The semi-lean solution 104c of the absorbent 104 to be
supplied to the middle regenerating unit 32 from the upper
regenerating unit 31 through the semi-lean-solution extracting pipe
31d flows down from the nozzle 32a, while being heated by heat
exchange by the lean-solution/steam-drain heat recovery unit 35 in
the process of being supplied to the middle regenerating unit 32
via the semi-lean-solution extracting pipe 31d. CO.sub.2 is further
emitted from the semi-lean solution 104c of the absorbent 104 by
the endothermic reaction, while passing through the packed bed 32b
in the process going downward, and the semi-lean solution 104c is
accumulated in the chimney tray 32c.
[0058] The semi-lean solution 104c of the absorbent 104 to be
supplied to the lower regenerating unit 33 from the middle
regenerating unit 32 through the semi-lean-solution extracting pipe
32d flows down from the nozzle 33a, while being heated by heat
exchange by the lean-solution/steam-drain heat recovery unit 36 in
the process of being supplied to the lower regenerating unit 33 via
the semi-lean-solution extracting pipe 32d. The semi-lean solution
104c of the absorbent 104 becomes the lean solution 104a with
substantially whole CO.sub.2 being emitted by the endothermic
reaction, while passing through the packed bed 33b in the process
going downward, and is accumulated at the bottom 33c of the
regenerator 3. The lean solution 104a accumulated at the bottom 33c
of the regenerator 3 is heated by the low-pressure steam 106 in the
regenerating heater 34.
[0059] CO.sub.2 gas 107 removed from the absorbent 104 in the
respective regenerating units 31, 32, and 33 is recovered by a
CO.sub.2 recovering unit 37. In the CO.sub.2 recovering unit 37,
the CO.sub.2 gas 107 removed from the absorbent 104 moves upward in
the regenerator 3, and is discharged to outside of the regenerator
3 from a top of the regenerator 3 through a condensed water pipe
37a. After the CO.sub.2 gas 107 is cooled by a regenerator reflux
condenser 37b while passing through the condensed water pipe 37a,
moisture is condensed by a CO.sub.2 separator 37c and separated
from condensed water 108, and the CO.sub.2 gas 107 is guided to a
CO.sub.2 processing step (not shown) by a recovered CO.sub.2
discharge pipe 37d. The condensed water 108 separated from CO.sub.2
by the CO.sub.2 separator 37c is pumped by a condensed water pump
37e installed in the condensed water pipe 37a and supplied to the
regenerator 3, to flow down from a nozzle 37f provided at the top
in the regenerator 3.
[0060] In the configuration described above, the regenerator 3
includes three stages, which are an upper stage, a middle stage,
and a lower stage. That is, these are the upper regenerating unit
31, the middle regenerating unit 32, and the lower regenerating
unit 33. However, the regenerator 3 can include two stages, which
are upper and lower stages. That is, these are the upper
regenerating unit 31 and the lower regenerating unit 33.
Furthermore, the regenerator 3 is not limited to the upper, middle,
and lower stages, which are the upper regenerating unit 31, the
middle regenerating unit 32, and the lower regenerating unit 33,
and can include three or more regenerating units.
[0061] In the CO.sub.2 recovery unit 55, a heat recovery system
that effectively uses low-temperature exhaust heat discharged at
the time of recovering CO.sub.2 is explained with reference to FIG.
2. In the lean solution pipe 33d for supplying the lean solution
104a of the absorbent 104 from the regenerator 3 to the absorber 2,
a first heat exchanger ex1 is provided between the rich-lean heat
exchanger 4 and the cooler 33f. The first heat exchanger ex1
performs heat exchange between the lean solution 104a of the
absorbent 104 before being cooled by the cooler 31f via the lean
solution pipe 33d and a heat medium (for example, water) 109, and
circulates the heat medium to which the exhaust heat of the lean
solution 104a is transferred.
[0062] In the wash water pipe 22d in the flushing unit 22 of the
absorber 2, a second heat exchanger ex2 is provided between the
wash-water discharge pump 22e and the cooler 22f. The second heat
exchanger ex2 performs heat exchange between the heat medium (for
example, water) 109 and the wash water 105 before being cooled by
the cooler 22f via the wash water pipe 22d, and circulates the heat
medium to which the exhaust heat of the wash water 105 is
transferred.
[0063] Furthermore, in the condensed water pipe 37a in the CO.sub.2
recovering unit 37 of the regenerator 3, a third heat exchanger ex3
is provided between the regenerator 3 and the regenerator reflux
condenser 37b. The third heat exchanger ex3 performs heat exchange
between the CO.sub.2 gas 107 before being cooled by the regenerator
reflux condenser 37b via the condensed water pipe 37a and the heat
medium 109 in the first heat exchanger ex1 or the second heat
exchanger ex2 and circulates the heat medium 109, while
transferring the exhaust heat of the CO.sub.2 gas 107 to the heat
medium 109.
[0064] All or at least one of the heat medium 109 heat-exchanged by
these heat exchangers ex1, ex2, and ex3 is circulated from [a] to
[b] of the CO.sub.2 recovery unit 55 so as to pass through the air
preheater 58 of the power generation plant 50 shown in FIG. 1, and
used for preheating the unburned air 102 before reaching the
Ljungstrom heat exchanger 57.
[0065] Specifically, respective patterns in which all or at least
one of the heat medium 109 heat-exchanged by the respective heat
exchangers ex1, ex2, and ex3 is used for preheating the unburned
air 102 are explained below with reference to FIGS. 1 to 3.
[0066] A pattern 1 shown in FIG. 3 uses the heat medium 109
circulated only to the first heat exchanger ex1, in which the heat
medium 109 at a temperature of 44.3.degree. C. heat-transferred by
the first heat exchanger ex1 is supplied from [a-1] (corresponding
to [a] shown in FIG. 1) to the air preheater 58. The heat medium
109 at a temperature of 33.1.degree. C. heat-exchanged via the air
preheater 58 is returned to [b-1] (corresponding to [b] in FIG. 1)
and heat-transferred again through the first heat exchanger
ex1.
[0067] A pattern 2 shown in FIG. 3 uses the heat medium 109
circulated only to the second heat exchanger ex2, in which the heat
medium 109 at a temperature of 47.degree. C. heat-transferred by
the second heat exchanger ex2 is supplied from [a-2] (corresponding
to [a] shown in FIG. 1) to the air preheater 58. The heat medium
109 at a temperature of 33.1.degree. C. heat-exchanged via the air
preheater 58 is returned to [b-2] (corresponding to [b] in FIG. 1)
and heat-transferred again through the second heat exchanger
ex2.
[0068] A pattern 3 shown in FIG. 3 uses the heat medium 109
circulated to the first heat exchanger ex1 and the second heat
exchanger ex2, in which the heat medium 109 at a temperature of
44.3.degree. C. heat-transferred by the first heat exchanger ex1 is
supplied from [a-1] to [b-2], and then the heat medium 109 at a
temperature of 47.degree. C. heat-transferred by the second heat
exchanger ex2 is supplied from [a-2] (corresponding to [a] shown in
FIG. 1) to the air preheater 58. The heat medium 109 at a
temperature of 33.1.degree. C. heat-exchanged via the air preheater
58 is returned to [b-1] (corresponding to [b] in FIG. 1) and
heat-transferred again through the first heat exchanger ex1 and the
second heat exchanger ex2.
[0069] A pattern 4 shown in FIG. 3 uses the heat medium 109
circulated to the first heat exchanger ex1 and the third heat
exchanger ex3, in which the heat medium 109 at a temperature of
44.3.degree. C. heat-transferred by the first heat exchanger ex1 is
supplied from [a-1] to [x] (corresponding to [a] in FIG. 1), and
then the heat medium 109 at a temperature of 78.6.degree. C.
heat-transferred by the third heat exchanger ex3 is supplied from
[a-3] to the air preheater 58. The heat medium 109 at a temperature
of 33.4.degree. C. heat-exchanged via the air preheater 58 is
returned to [b-1] (corresponding to [b] in FIG. 1) and
heat-transferred again through the first heat exchanger ex1 and the
third heat exchanger ex3.
[0070] A pattern 5 shown in FIG. 3 uses the heat medium 109
circulated to the second heat exchanger ex2 and the third heat
exchanger ex3, in which the heat medium 109 at a temperature of
47.degree. C. heat-transferred by the second heat exchanger ex2 is
supplied from [a-2] to [x], and then the heat medium 109 at a
temperature of 79.2.degree. C. heat-transferred by the third heat
exchanger ex3 is supplied from [a-3] (corresponding to [a] in FIG.
1) to the air preheater 58. The heat medium 109 at a temperature of
33.4.degree. C. heat-exchanged via the air preheater 58 is returned
to [b-2] (corresponding to [b] in FIG. 1) and heat-transferred
again through the second heat exchanger ex2 and the third heat
exchanger ex3.
[0071] A pattern 6 shown in FIG. 3 uses the heat medium 109
circulated to the first heat exchanger ex1, the second heat
exchanger ex2, and the third heat exchanger ex3, in which the heat
medium 109 at a temperature of 44.3.degree. C. heat-transferred by
the first heat exchanger ex1 is supplied from [a-1] to [b-2], the
heat medium 109 at a temperature of 47.degree. C. heat-transferred
by the second heat exchanger ex2 is supplied from [a-2] to [x], and
then the heat medium 109 at a temperature of 79.3.degree. C.
heat-transferred by the third heat exchanger ex3 is supplied from
[a-3] (corresponding to [a] in FIG. 1) to the air preheater 58. The
heat medium 109 at a temperature of 33.degree. C. heat-exchanged
via the air preheater 58 is returned to [b-1] (corresponding to [b]
in FIG. 1) and heat-transferred again through the first heat
exchanger ex1, the second heat exchanger ex2, and the third heat
exchanger ex3.
[0072] In the heat recovery system of the CO.sub.2 recovery unit 55
according to the present embodiment, an effect of a case where the
air preheater 58 is provided, assuming the temperature efficiency
of the Ljungstrom heat exchanger 57 to be 90%, and the pattern 6
shown in FIG. 3 is applied is explained below with reference to
FIG. 4. As shown in FIG. 4, in the case of the gas temperature of
the unburned air 102 being 30.degree. C. corresponding to the
ambient air, the gas temperature of the unburned air 102 at a
position A in an upstream of the air preheater 58 in FIG. 1 was
30.degree. C., and the gas temperature of the preheated unburned
air 102 at a position B in an upstream of the Ljungstrom heat
exchanger 57 became 72.degree. C. by passing through the air
preheater 58. The gas temperature of the heat-exchanged unburned
air 102 at a position C in an upstream of the boiler 51 via the
Ljungstrom heat exchanger 57 became 322.degree. C. Furthermore, the
gas temperature of the flue gas 101 at a position D in the upstream
of the Ljungstrom heat exchanger 57 via the boiler 51 became
350.degree. C. Further, the gas temperature of the heat-exchanged
flue gas 101 at a position E in an upstream of the flue gas
desulfurizer 54 via the Ljungstrom heat exchanger 57 became
141.degree. C. At this time, a flow rate G of the low-pressure
steam 106 supplied to the regenerating heater 34 of the CO.sub.2
recovery unit 55 was 870 t/hr.
[0073] On the other hand, an effect in a conventional case where
the air preheater 58 is not provided and the temperature efficiency
of the Ljungstrom heat exchanger 57 is 82.6% is as described below.
As shown in FIG. 4, when the gas temperature of the unburned air
102 is 30.degree. C. corresponding to the ambient air, in FIG. 1,
the gas temperature of the unburned air 102 at the position A is
30.degree. C. Because the air preheater 58 is not provided, the gas
temperature of the unburned air 102 at the position B in the
upstream of the Ljungstrom heat exchanger 57 becomes 30.degree. C.
The gas temperature of the heat-exchanged unburned air 102 at the
position C in the upstream of the boiler 51 via the Ljungstrom heat
exchanger 57 became 294.degree. C. Furthermore, the gas temperature
of the flue gas 101 at the position D in the upstream of the
Ljungstrom heat exchanger 57 via the boiler 51 became 350.degree.
C. Furthermore, the gas temperature of the heat-exchanged flue gas
101 at the position E in the upstream of the flue gas desulfurizer
54 via the Ljungstrom heat exchanger 57 became 130.degree. C. At
this time, the flow rate G of the low-pressure steam 106 supplied
to the regenerating heater 34 of the CO.sub.2 recovery unit 55 was
870 t/hr.
[0074] In this manner, in the heat recovery system of the CO.sub.2
recovery unit 55 according to the first embodiment, the air
preheater 58 that preheats the unburned air 102 before reaching the
Ljungstrom heat exchanger 57 by exhaust heat from the CO.sub.2
recovery unit 55 is provided.
[0075] According to the heat recovery system of the CO.sub.2
recovery unit 55, low-temperature exhaust heat equal to or lower
than a temperature level of 70.degree. C. to 80.degree. C.
discharged at the time of recovering CO.sub.2 can be used
efficiently. Specifically, as described above, a gas temperature of
294.degree. C. of the unburned air 102 at the position C supplied
to the boiler 51 in the conventional case is raised by 28.degree.
C. to be 322.degree. C. A heat input to the boiler 51 increases due
to the increase of 28.degree. C., and effects equivalent to those
of decreasing the flow rate of the low-pressure steam 106 consumed
by the CO.sub.2 recovery unit 55 by 56 t/hr can be acquired. The
flow rate of 56 t/hr corresponds to 6% of the flow rate of the
low-pressure steam 106 consumed by the CO.sub.2 recovery unit 55.
As a result, by preheating the unburned air 102 before reaching the
Ljungstrom heat exchanger 57 by low-temperature exhaust heat equal
to or lower than a temperature level of 70.degree. C. to 80.degree.
C. discharged at the time of recovering CO.sub.2, effects
equivalent to those of decreasing the flow rate of the low-pressure
steam 106 consumed by the CO.sub.2 recovery unit 55 can be
acquired.
[0076] Furthermore, because the Ljungstrom heat exchanger 57
performs heat exchange between the flue gas 101 containing sulfur
content and the unburned air 102, the heat reservoir may be
subjected to sulfuric acid corrosion due to dew condensation
generated on the heat transfer surface of the heat reservoir. In
this regard, according to the heat recovery system of the CO.sub.2
recovery unit 55 of the first embodiment, as described above, the
gas temperature of 30.degree. C. of the unburned air 102 at the
position B on an inlet side of the Ljungstrom heat exchanger 57 in
the conventional case is raised to 72.degree. C., and the gas
temperature of 130.degree. C. of the flue gas 101 at the position E
on an outlet side of the Ljungstrom heat exchanger 57 in the
conventional case is also raised to 141.degree. C. As a result, an
average cold-end temperature ((the gas temperature on the outlet
side of flue gas+the gas temperature on the inlet side of unburned
air)/2) of the Ljungstrom heat exchanger 57 increases from
80.degree. C. to 106.5.degree. C. by 26.5.degree. C. Consequently,
dew condensation on the heat transfer surface of the heat reservoir
of the Ljungstrom heat exchanger 57 can be prevented and sulfuric
acid corrosion of the heat reservoir can be suppressed.
[0077] The heat recovery system of the CO.sub.2 recovery unit 55
according to the first embodiment is applied to the power
generation plant 50 that drives the steam turbine 52 by the
superheated steam 100 from the boiler 51 to generate power by the
power generator 53.
[0078] As described above, according to the heat recovery system of
the CO.sub.2 recovery unit 55, the gas temperature of 294.degree.
C. of the unburned air 102 at the position C supplied to the boiler
51 in the conventional case is raised by 28.degree. C. to be
322.degree. C. Therefore, because the flow rate of the superheated
steam 100 supplied from the boiler 51 to the steam turbine 52
increases, the power generation efficiency of the power generation
plant 50 can be improved.
[0079] In the heat recovery system of the CO.sub.2 recovery unit 55
according to the first embodiment, the air preheater 58 circulates
the heat medium 109, to which exhaust heat from the CO.sub.2
recovery unit 55 is heat-transferred, to heat the unburned air 102
indirectly.
[0080] According to the heat recovery system of the CO.sub.2
recovery unit 55, a exhaust heat fluid such as the absorbent 104,
the wash water 105, or the CO.sub.2 gas 107 can be prevented from
flowing out, with respect to a case where the exhaust heat fluid is
used to heat the unburned air 102 directly.
[0081] A heat recovery method of the CO.sub.2 recovery unit 55
according to the first embodiment includes a step of removing
CO.sub.2 in the flue gas 101 discharged from the boiler 51 by
absorbing CO.sub.2 by the absorbent 104, emitting CO.sub.2 from the
absorbent 104 having absorbed CO.sub.2, and of reusing the
absorbent 104 for absorbing CO.sub.2 (CO.sub.2 recovery step). The
heat recovery method further includes a step of performing heat
exchange between the flue gas 101 discharged from the boiler 51 and
before reaching the CO.sub.2 recovery step and the unburned air 102
supplied to the boiler 51 (heat exchanging step), and a step of
preheating the unburned air 102 before reaching the heat exchanging
step by exhaust heat from the CO.sub.2 recovery step (air
preheating step).
[0082] According to the heat recovery method of the CO.sub.2
recovery unit 55, low-temperature exhaust heat equal to or lower
than a temperature level of 70.degree. C. to 80.degree. C.
discharged at the time of recovering CO.sub.2 can be used
efficiently. Specifically, the gas temperature of 294.degree. C. of
the unburned air 102 at the position C supplied to the boiler 51 in
the conventional case is raised by 28.degree. C. to be 322.degree.
C. A heat input to the boiler 51 increases due to the increase of
28.degree. C., and effects equivalent to those of decreasing the
flow rate of the low-pressure steam 106 consumed by the CO.sub.2
recovery unit 55 by 56 t/hr can be acquired. The flow rate of 56
t/hr corresponds to 6% of the flow rate of the low-pressure steam
106 consumed by the CO.sub.2 recovery unit 55. As a result, by
preheating the unburned air 102 before reaching the heat exchanging
step by low-temperature exhaust heat equal to or lower than a
temperature level of 70.degree. C. to 80.degree. C. discharged at
the time of recovering CO.sub.2, effects equivalent to those of
decreasing the flow rate of the low-pressure steam 106 consumed by
the CO.sub.2 recovery unit 55 can be acquired.
[0083] Furthermore, because heat exchange between the flue gas 101
containing sulfur content and the unburned air 102 is performed at
the heat exchanging step, the heat reservoir may be subjected to
sulfuric acid corrosion due to dew condensation generated on the
heat transfer surface of the heat reservoir. In this regard,
according to the heat recovery method of the CO.sub.2 recovery unit
55 of the first embodiment, the gas temperature of 30.degree. C. of
the unburned air 102 at the position B on the inlet side of the
heat exchanging step in the conventional case is raised to
72.degree. C., and the gas temperature of 130.degree. C. of the
flue gas 101 at the position E on the outlet side of the heat
exchanging step in the conventional case is also raised to
141.degree. C. As a result, an average cold-end temperature ((the
gas temperature on the outlet side of flue gas+the gas temperature
on the inlet side of unburned air)/2) at the heat exchanging step
increases from 80.degree. C. to 106.5.degree. C. by 26.5.degree. C.
Consequently, dew condensation on the heat transfer surface of the
heat reservoir at the heat exchanging step can be prevented and
sulfuric acid corrosion of the heat reservoir can be
suppressed.
[0084] The heat recovery method of the CO.sub.2 recovery unit 55
according to the first embodiment further includes a power
generation step of driving the steam turbine 52 by the superheated
steam 100 from the boiler 51 to generate power by the power
generator 53.
[0085] According to the heat recovery method of the CO.sub.2
recovery unit 55, the gas temperature of 294.degree. C. of the
unburned air 102 at the position C supplied to the boiler 51 in the
conventional case is raised by 28.degree. C. to be 322.degree. C.
Therefore, because the flow rate of the superheated steam 100
supplied from the boiler 51 to the steam turbine 52 increases, the
power generation efficiency of the power generation plant 50 can be
improved.
Second Embodiment
[0086] A second embodiment is explained with reference to the
drawings. FIG. 5 is a schematic diagram of a heat recovery system
of a CO.sub.2 recovery unit according to the second embodiment.
FIG. 6 is a chart of a pattern of the heat recovery system of a
CO.sub.2 recovery unit according to the second embodiment. FIG. 7
is a schematic diagram of an effect of the heat recovery system of
a CO.sub.2 recovery unit according to the second embodiment.
[0087] As in the heat recovery system of the first embodiment, the
heat recovery system of the CO.sub.2 recovery unit 55 according to
the second embodiment includes the air preheater 58 that preheats
the unburned air 102 before reaching the Ljungstrom heat exchanger
57 by exhaust heat from the CO.sub.2 recovery unit 55, but the mode
of exhaust heat in the CO.sub.2 recovery unit 55 is different from
that of the first embodiment. Therefore, in the second embodiment,
exhaust heat from the CO.sub.2 recovery unit 55 is explained, and
elements equivalent to those in the first embodiment described
above are denoted by like reference signs and explanations thereof
will be omitted.
[0088] The heat recovery system that efficiently uses
low-temperature exhaust heat discharged at the time of recovering
CO.sub.2 in the CO.sub.2 recovery unit 55 is explained with
reference to FIG. 5. The lean solution pipe 33d for supplying the
lean solution 104a of the absorbent 104 from the regenerator 3 to
the absorber 2 is provided between the rich-lean heat exchanger 4
and the cooler 33f via the air preheater 58.
[0089] The wash water pipe 22d in the flushing unit 22 of the
absorber 2 is provided between the wash-water discharge pump 22e
and the cooler 22f via the air preheater 58.
[0090] Furthermore, the condensed water pipe 37a in the CO.sub.2
recovering unit 37 is provided between the regenerator 3 and the
regenerator reflux condenser 37b via the air preheater 58.
[0091] All of the lean solution 104a of the absorbent 104 passing
through the lean solution pipe 33d, the wash water 105 passing
through the wash water pipe 22d, and the CO.sub.2 gas 107 passing
through the condensed water pipe 37a or at least one of these
exhaust heat fluids is circulated from [a] to [b] of the CO.sub.2
recovery unit 55 through the air preheater 58 shown in FIG. 1 of
the power generation plant 50 and used for preheating the unburned
air 102 before reaching the Ljungstrom heat exchanger 57.
[0092] Specifically, respective patterns in which all or at least
one of the respective exhaust heat fluids (the lean solution 104a
of the absorbent 104, the wash water 105, and the CO.sub.2 gas 107)
is used for preheating the unburned air 102 are explained with
reference to FIGS. 1, 5, and 6.
[0093] In a pattern 1 shown in FIG. 6, the lean solution 104a of
the absorbent 104 at a temperature of 47.3.degree. C.
heat-exchanged by the rich-lean heat exchanger 4 is supplied from
[a-1'] (corresponding to [a] shown in FIG. 1) to the air preheater
58. The lean solution 104a at a temperature of 44.9.degree. C.
heat-exchanged via the air preheater 58 is returned to [b-1']
(corresponding to [b] shown in FIG. 1), cooled by the cooler 33f,
and used for absorbing CO.sub.2.
[0094] In a pattern 2 shown in FIG. 6, the wash water 105 at a
temperature of 50.degree. C. heat-exchanged with the decarbonated
flue gas 101a is supplied from [a-2'] (corresponding to [a] shown
in FIG. 1) to the air preheater 58. The wash water 105 at a
temperature of 48.5.degree. C. heat-exchanged via the air preheater
58 is returned to [b-2'] (corresponding to [b] shown in FIG. 1),
cooled by the cooler 22f, and used for cleaning of the decarbonated
flue gas 101a.
[0095] In a pattern 3 shown in FIG. 6, the CO.sub.2 gas 107 at a
temperature of 85.9.degree. C., which has been removed from the
rich solution 104b of the absorbent 104 by the endothermic
reaction, is supplied from [a-3'] (corresponding to [a] shown in
FIG. 1) to the air preheater 58. The CO.sub.2 gas 107 at a
temperature of 75.5.degree. C. heat-exchanged via the air preheater
58 is returned to [b-3'] (corresponding to [b] shown in FIG. 1),
cooled by the regenerator reflux condenser 37b, and recovered.
[0096] A pattern 4 shown in FIG. 6 uses the pattern 1 and the
pattern 2 in parallel, in which the lean solution 104a of the
absorbent 104 at a temperature of 47.3.degree. C. is supplied from
[a-1'] (corresponding to [a] shown in FIG. 1) to the air preheater
58, and the wash water 105 at a temperature of 50.degree. C. is
supplied from [a-2'] (corresponding to [a] shown in FIG. 1) to the
air preheater 58. The lean solution 104a at a temperature of
44.9.degree. C. heat-exchanged via the air preheater 58 is returned
to [b-1'] (corresponding to [b] shown in FIG. 1), and the wash
water 105 at a temperature of 49.6.degree. C. heat-exchanged via
the air preheater 58 is returned to [b-2'] (corresponding to [b]
shown in FIG. 1.
[0097] A pattern 5 shown in FIG. 6 uses the pattern 1 and the
pattern 3 in parallel, in which the lean solution 104a of the
absorbent 104 at a temperature of 47.3.degree. C. is supplied from
[a-1'] (corresponding to [a] shown in FIG. 1) to the air preheater
58, and the CO.sub.2 gas 107 at a temperature of 85.9.degree. C. is
supplied from [a-3'] (corresponding to [a] shown in FIG. 1) to the
air preheater 58. The lean solution 104a at a temperature of
44.9.degree. C. heat-exchanged via the air preheater 58 is returned
to [b-1'] (corresponding to [b] shown in FIG. 1), and the CO.sub.2
gas 107 at a temperature of 78.9.degree. C. heat-exchanged via the
air preheater 58 is returned to [b-3'] (corresponding to [b] shown
in FIG. 1).
[0098] A pattern 6 shown in FIG. 6 uses the pattern 2 and the
pattern 3 in parallel, in which the wash water 105 at a temperature
of 50.degree. C. is supplied from [a-2'] (corresponding to [a]
shown in FIG. 1) to the air preheater 58, and the CO.sub.2 gas 107
at a temperature of 85.9.degree. C. is supplied from [a-3']
(corresponding to [a] shown in FIG. 1) to the air preheater 58. The
wash water 105 at a temperature of 48.5.degree. C. heat-exchanged
via the air preheater 58 is returned to [b-2'] (corresponding to
[b] shown in FIG. 1), and the CO.sub.2 gas 107 at a temperature of
79.6.degree. C. heat-exchanged via the air preheater 58 is returned
to [b-3'] (corresponding to [b] shown in FIG. 1).
[0099] A pattern 7 shown in FIG. 6 uses the pattern 1, the pattern
2 and the pattern 3 in parallel, in which the lean solution 104a of
the absorbent 104 at a temperature of 47.3.degree. C. is supplied
from [a-1'] (corresponding to [a] shown in FIG. 1) to the air
preheater 58, the wash water 105 at a temperature of 50.degree. C.
is supplied from [a-2'] (corresponding to [a] shown in FIG. 1) to
the air preheater 58, and the CO.sub.2 gas 107 at a temperature of
85.9.degree. C. is supplied from [a-3'] (corresponding to [a] shown
in FIG. 1) to the air preheater 58. The lean solution 104a at a
temperature of 44.9.degree. C. heat-exchanged via the air preheater
58 is returned to [b-1'] (corresponding to [b] shown in FIG. 1),
the wash water 105 at a temperature of 49.6.degree. C.
heat-exchanged via the air preheater 58 is returned to [b-2']
(corresponding to [b] shown in FIG. 1), and the CO.sub.2 gas 107 at
a temperature of 79.8.degree. C. heat-exchanged via the air
preheater 58 is returned to [b-3'] (corresponding to [b] shown in
FIG. 1).
[0100] In the heat recovery system of the CO.sub.2 recovery unit 55
according to the present embodiment, an effect of a case where the
air preheater 58 is provided, assuming the temperature efficiency
of the Ljungstrom heat exchanger 57 to be 90%, and the pattern 7
shown in FIG. 6 is applied is explained below with reference to
FIG. 7. As shown in FIG. 7, in the case of the gas temperature of
the unburned air 102 being 30.degree. C. corresponding to the
ambient air, the gas temperature of the unburned air 102 at the
position A in the upstream of the air preheater 58 in FIG. 1 was
30.degree. C., and the gas temperature of the preheated unburned
air 102 at the position B in the upstream of the Ljungstrom heat
exchanger 57 became 82.degree. C. by passing through the air
preheater 58. The gas temperature of the heat-exchanged unburned
air 102 at the position C in the upstream of the boiler 51 via the
Ljungstrom heat exchanger 57 became 323.degree. C. Furthermore, the
gas temperature of the flue gas 101 at the position D in the
upstream of the Ljungstrom heat exchanger 57 via the boiler 51
became 350.degree. C. Furthermore, the gas temperature of the
heat-exchanged flue gas 101 at the position E in the upstream of
the flue gas desulfurizer 54 via the Ljungstrom heat exchanger 57
became 148.degree. C. At this time, the flow rate G of the
low-pressure steam 106 supplied to the regenerating heater 34 of
the CO.sub.2 recovery unit 55 was 870 t/hr.
[0101] On the other hand, an effect in the conventional case where
the air preheater 58 is not provided and the temperature efficiency
of the Ljungstrom heat exchanger 57 is 82.6% in the conventional
case is as described below. As shown in FIG. 7, when the gas
temperature of the unburned air 102 is 30.degree. C. corresponding
to the ambient air, in FIG. 1, the gas temperature of the unburned
air 102 at the position A is 30.degree. C. Because the air
preheater 58 is not provided, the gas temperature of the unburned
air 102 at the position B in the upstream of the Ljungstrom heat
exchanger 57 becomes 30.degree. C. The gas temperature of the
heat-exchanged unburned air 102 at the position C in the upstream
of the boiler 51 via the Ljungstrom heat exchanger 57 became
294.degree. C. Furthermore, the gas temperature of the flue gas 101
at the position D in the upstream of the Ljungstrom heat exchanger
57 via the boiler 51 became 350.degree. C. Further, the gas
temperature of the heat-exchanged flue gas 101 at the position E in
the upstream of the flue gas desulfurizer 54 via the Ljungstrom
heat exchanger 57 became 130.degree. C. At this time, the flow rate
G of the low-pressure steam 106 supplied to the regenerating heater
34 of the CO.sub.2 recovery unit 55 was 870 t/hr.
[0102] In this manner, in the heat recovery system of the CO.sub.2
recovery unit 55 according to the second embodiment, the air
preheater 58 that preheats the unburned air 102 before reaching the
Ljungstrom heat exchanger 57 by exhaust heat from the CO.sub.2
recovery unit 55 is provided.
[0103] According to the heat recovery system of the CO.sub.2
recovery unit 55, low-temperature exhaust heat equal to or lower
than a temperature level of 70.degree. C. to 80.degree. C.
discharged at the time of recovering CO.sub.2 can be used
efficiently. Specifically, as described above, the gas temperature
of 294.degree. C. of the unburned air 102 at the position C
supplied to the boiler 51 in the conventional case is raised by
29.degree. C. to be 323.degree. C. A heat input to the boiler 51
increases due to the increase of 29.degree. C., and effects
equivalent to those of decreasing the flow rate of the low-pressure
steam 106 consumed by the CO.sub.2 recovery unit 55 by 58 t/hr can
be acquired. The flow rate of 58 t/hr corresponds to 7% of the flow
rate of the low-pressure steam 106 consumed by the CO.sub.2
recovery unit 55. As a result, by preheating the unburned air 102
before reaching the Ljungstrom heat exchanger 57 by low-temperature
exhaust heat equal to or lower than the temperature level of
70.degree. C. to 80.degree. C. discharged at the time of recovering
CO.sub.2, effects equivalent to those of decreasing the flow rate
of the low-pressure steam 106 consumed by the CO.sub.2 recovery
unit 55 can be acquired.
[0104] Furthermore, because the Ljungstrom heat exchanger 57
performs heat exchange between the flue gas 101 containing sulfur
content and the unburned air 102, the heat reservoir may be
subjected to sulfuric acid corrosion due to dew condensation
generated on the heat transfer surface of the heat reservoir. In
this regard, according to the heat recovery system of the CO.sub.2
recovery unit 55 of the second embodiment, the gas temperature of
30.degree. C. of the unburned air 102 at the position B on the
inlet side of the Ljungstrom heat exchanger 57 in the conventional
case is raised to 82.degree. C., and the gas temperature of
130.degree. C. of the flue gas 101 at the position E on the outlet
side of the Ljungstrom heat exchanger 57 in the conventional case
is also raised to 148.degree. C. As a result, an average cold-end
temperature ((the gas temperature on the outlet side of flue
gas+the gas temperature on the inlet side of unburned air)/2) of
the Ljungstrom heat exchanger 57 increases from 80.degree. C. to
115.degree. C. by 35.degree. C. Consequently, dew condensation on
the heat transfer surface of the heat reservoir of the Ljungstrom
heat exchanger 57 can be prevented and sulfuric acid corrosion of
the heat reservoir can be suppressed.
[0105] The heat recovery system of the CO.sub.2 recovery unit 55
according to the second embodiment is applied to the power
generation plant 50 that drives the steam turbine 52 by the
superheated steam 100 from the boiler 51 to generate power by the
power generator 53.
[0106] As described above, according to the heat recovery system of
the CO.sub.2 recovery unit 55, the gas temperature of 294.degree.
C. of the unburned air 102 at the position C supplied to the boiler
51 in the conventional case is raised by 29.degree. C. to be
323.degree. C. Therefore, because the flow rate of the superheated
steam 100 supplied from the boiler 51 to the steam turbine 52
increases, the power generation efficiency of the power generation
plant 50 can be improved.
[0107] In the heat recovery system of the CO.sub.2 recovery unit 55
according to the second embodiment, the air preheater 58 circulates
all or at least one of the respective exhaust heat fluids (the lean
solution 104a of the absorbent 104, the wash water 105, and the
CO.sub.2 gas 107) from the CO.sub.2 recovery unit 55, thereby
directly heating the unburned air 102.
[0108] According to the heat recovery system of the CO.sub.2
recovery unit 55, the heat transfer efficiency can be improved with
respect to the case where the unburned air 102 is indirectly heated
via the heat medium.
[0109] A heat recovery method of the CO.sub.2 recovery unit 55
according to the second embodiment includes a step of removing
CO.sub.2 in the flue gas 101 discharged from the boiler 51 by
absorbing CO.sub.2 by the absorbent 104, emitting CO.sub.2 from the
absorbent 104 having absorbed CO.sub.2, and of reusing the
absorbent 104 for absorbing CO.sub.2 (CO.sub.2 recovery step). The
heat recovery method further includes a step of performing heat
exchange between the flue gas 101 discharged from the boiler 51 and
before reaching the CO.sub.2 recovery step and the unburned air 102
supplied to the boiler 51 (heat exchanging step), and a step of
preheating the unburned air 102 before reaching the heat exchanging
step by exhaust heat from the CO.sub.2 recovery step (air
preheating step).
[0110] According to the heat recovery method of the CO.sub.2
recovery unit 55, low-temperature exhaust heat equal to or lower
than the temperature level of 70.degree. C. to 80.degree. C.
discharged at the time of recovering CO.sub.2 can be used
efficiently. Specifically, the gas temperature of 294.degree. C. of
the unburned air 102 at the position C supplied to the boiler 51 in
the conventional case is raised by 29.degree. C. to be 323.degree.
C. A heat input to the boiler 51 increases due to the increase of
29.degree. C., and effects equivalent to those of decreasing the
flow rate of the low-pressure steam 106 consumed at the CO.sub.2
recovery step by 58 t/hr can be acquired. The flow rate of 58 t/hr
corresponds to 7% of the flow rate of the low-pressure steam 106
consumed at the CO.sub.2 recovery step. As a result, by preheating
the unburned air 102 before reaching the heat exchanging step by
low-temperature exhaust heat equal to or lower than the temperature
level of 70.degree. C. to 80.degree. C. discharged at the time of
recovering CO.sub.2, effects equivalent to those of decreasing the
flow rate of the low-pressure steam 106 consumed at the CO.sub.2
recovery step can be acquired.
[0111] Furthermore, because heat exchange between the flue gas 101
containing sulfur content and the unburned air 102 is performed at
the heat exchanging step, the heat reservoir may be subjected to
sulfuric acid corrosion due to dew condensation generated on the
heat transfer surface of the heat reservoir. In this regard,
according to the heat recovery method of the CO.sub.2 recovery unit
55 of the second embodiment, the gas temperature of 30.degree. C.
of the unburned air 102 at the position B on the inlet side of the
heat exchanging step in the conventional case is raised to
82.degree. C., and the gas temperature of 130.degree. C. of the
flue gas 101 at the position E on the outlet side of the heat
exchanging step in the conventional case is also raised to
148.degree. C. As a result, an average cold-end temperature ((the
gas temperature on the outlet side of flue gas+the gas temperature
on the inlet side of unburned air)/2) at the heat exchanging step
is increased from 80.degree. C. to 115.degree. C. by 35.degree. C.
Consequently, dew condensation on the heat transfer surface of the
heat reservoir at the heat exchanging step can be prevented and
sulfuric acid corrosion of the heat reservoir can be
suppressed.
[0112] The heat recovery method of the CO.sub.2 recovery unit 55
according to the second embodiment further includes a step of
driving the steam turbine 52 by the superheated steam 100 from the
boiler 51 to generate power by the power generator 53 (power
generation step).
[0113] According to the heat recovery method of the CO.sub.2
recovery unit 55, the gas temperature of 294.degree. C. of the
unburned air 102 at the position C supplied to the boiler 51 in the
conventional case is raised by 29.degree. C. to be 323.degree. C.
Therefore, because the flow rate of the superheated steam 100
supplied from the boiler 51 to the steam turbine 52 increases, the
power generation efficiency of the power generation plant 50 can be
improved.
Third Embodiment
[0114] A third embodiment is explained with reference to the
drawings. FIG. 8 is a schematic diagram of a power generation plant
to which a heat recovery system of a CO.sub.2 recovery unit
according to the third embodiment is applied. FIG. 9 is a schematic
diagram of the heat recovery system of a CO.sub.2 recovery unit
according to the third embodiment. FIG. 10 is a chart of a pattern
of the heat recovery system of a CO.sub.2 recovery unit according
to the third embodiment. FIG. 11 is a schematic diagram of an
effect of the heat recovery system of a CO.sub.2 recovery unit
according to the third embodiment.
[0115] The heat recovery system of the CO.sub.2 recovery unit 55
according to the third embodiment includes, as shown in FIG. 8, a
heat recovery device 59 that recovers the heat of the flue gas 101
before reaching the CO.sub.2 recovery unit 55 via the Ljungstrom
heat exchanger 57 and supplies the heat to the CO.sub.2 recovery
unit 55 in addition to the heat recovery system of the first
embodiment. Therefore, in the third embodiment, heat recovery from
the heat recovery device 59 to the CO.sub.2 recovery unit 55 is
explained, and elements equivalent to those in the first embodiment
described above are denoted by like reference signs and
explanations thereof will be omitted.
[0116] Supply of recovered heat to the CO.sub.2 recovery unit 55 is
explained with reference to FIG. 9. As shown in FIG. 9, the rich
solution pipe 21c for supplying the rich solution 104b of the
absorbent 104 from the absorber 2 to the regenerator 3 is provided
between the rich-lean heat exchanger 4 and the nozzle 31a of the
regenerator 3 via the heat recovery device 59.
[0117] The semi-lean-solution extracting pipe 31d in the
regenerator 3 is provided between the lean-solution/steam-drain
heat recovery unit 35 and the nozzle 32a via the heat recovery
device 59.
[0118] The semi-lean-solution extracting pipe 32d in the
regenerator 3 is provided between the lean-solution/steam-drain
heat recovery unit 36 and the nozzle 33a via the heat recovery
device 59.
[0119] All or at least one of the exhaust heat fluids of the rich
solution 104b of the absorbent 104 passing through the rich
solution pipe 21c, the semi-lean solution 104c passing through the
semi-lean-solution extracting pipe 31d, and the semi-lean solution
104c passing through the semi-lean-solution extracting pipe 32d is
circulated from [c] to [d] of the CO.sub.2 recovery unit 55 via the
heat recovery device 59 of the power generation plant 50 shown in
FIG. 8, and used for recovering the heat of the flue gas 101 before
reaching the CO.sub.2 recovery unit 55 via the Ljungstrom heat
exchanger 57.
[0120] Specifically, respective patterns in which all or at least
one of the respective exhaust heat fluids (the rich solution 104b
and the semi-lean solution 104c of the absorbent 104, the wash
water 105, and the CO.sub.2 gas 107) is used for recovering the
heat of the flue gas 101 are explained with reference to FIGS. 8 to
10.
[0121] In a pattern 1 shown in FIG. 10, the rich solution 104b of
the absorbent 104 at a temperature of 91.2.degree. C.
heat-exchanged by the rich-lean heat exchanger 4 is supplied from
[c-1] (corresponding to [c] shown in FIG. 8) to the heat recovery
device 59. The rich solution 104b at a temperature of 100.8.degree.
C. heat-recovered via the heat recovery device 59 is returned to
[d-1] (corresponding to [d] shown in FIG. 8), caused to flow down
from the nozzle 31a into the regenerator 3, thereby reacting
endothermically.
[0122] In a pattern 2 shown in FIG. 10, the semi-lean solution 104c
of the absorbent 104 at a temperature of 105.0.degree. C.
heat-recovered by the lean-solution/steam-drain heat recovery unit
35 is supplied from [c-2] (corresponding to [c] shown in FIG. 8) to
the heat recovery device 59. The semi-lean solution 104c at a
temperature of 112.4.degree. C. heat-recovered via the heat
recovery device 59 is returned to [d-2] (corresponding to [d] shown
in FIG. 8), caused to flow down from the nozzle 32a into the
regenerator 3, thereby reacting endothermically.
[0123] In a pattern 3 shown in FIG. 10, the semi-lean solution 104c
of the absorbent 104 at a temperature of 117.6.degree. C.
heat-recovered by the lean-solution/steam-drain heat recovery unit
36 is supplied from [c-3] (corresponding to [c] shown in FIG. 8) to
the heat recovery device 59. The semi-lean solution 104c at a
temperature of 123.2.degree. C. heat-recovered via the heat
recovery device 59 is returned to [d-3] (corresponding to [d] shown
in FIG. 8), caused to flow down from the nozzle 33a into the
regenerator 3, thereby reacting endothermically.
[0124] A pattern 4 shown in FIG. 10 uses the pattern 1 and the
pattern 2 in parallel, in which the rich solution 104b of the
absorbent 104 at a temperature of 91.2.degree. C. is supplied from
[c-1] (corresponding to [c] shown in FIG. 8) to the heat recovery
device 59, and the semi-lean solution 104c of the absorbent 104 at
a temperature of 105.0.degree. C. is supplied from [c-2]
(corresponding to [c] shown in FIG. 8) to the heat recovery device
59. The rich solution 104b at a temperature of 94.1.degree. C.
heat-recovered via the heat recovery device 59 is returned to [d-1]
(corresponding to [d] shown in FIG. 8), and the semi-lean solution
104c at a temperature of 112.4.degree. C. heat-recovered via the
heat recovery device 59 is returned to [d-2] (corresponding to [d]
shown in FIG. 8).
[0125] A pattern 5 shown in FIG. 10 uses the pattern 1 and the
pattern 3 in parallel, in which the rich solution 104b of the
absorbent 104 at a temperature of 91.2.degree. C. is supplied from
[c-1] (corresponding to [c] shown in FIG. 8) to the heat recovery
device 59, and the semi-lean solution 104c of the absorbent 104 at
a temperature of 117.6.degree. C. is supplied from [c-3]
(corresponding to [c] shown in FIG. 8) to the heat recovery device
59. The rich solution 104b at a temperature of 95.6.degree. C.
heat-recovered via the heat recovery device 59 is returned to [d-1]
(corresponding to [d] shown in FIG. 8), and the semi-lean solution
104c at a temperature of 123.2.degree. C. heat-recovered via the
heat recovery device 59 is returned to [d-3] (corresponding to [d]
shown in FIG. 8).
[0126] A pattern 6 shown in FIG. 10 uses the pattern 2 and the
pattern 3 in parallel, in which the semi-lean solution 104c of the
absorbent 104 at a temperature of 105.0.degree. C. is supplied from
[c-2] (corresponding to [c] shown in FIG. 8) to the heat recovery
device 59, and the semi-lean solution 104c of the absorbent 104 at
a temperature of 117.6.degree. C. is supplied from [c-3]
(corresponding to [c] shown in FIG. 8) to the heat recovery device
59. The semi-lean solution 104c at a temperature of 107.4.degree.
C. heat-recovered via the heat recovery device 59 is returned to
[d-2] (corresponding to [d] shown in FIG. 8), and the semi-lean
solution 104c at a temperature of 123.2.degree. C. heat-recovered
via the heat recovery device 59 is returned to [d-3] (corresponding
to [d] shown in FIG. 8).
[0127] A pattern 7 shown in FIG. 10 uses the pattern 1, the pattern
2 and the pattern 3 in parallel, in which the rich solution 104b of
the absorbent 104 at a temperature of 91.2.degree. C. is supplied
from [c-1] (corresponding to [c] shown in FIG. 8) to the heat
recovery device 59, the semi-lean solution 104c of the absorbent
104 at a temperature of 105.0.degree. C. is supplied from [c-2]
(corresponding to [c] shown in FIG. 8) to the heat recovery device
59, and the semi-lean solution 104c of the absorbent 104 at a
temperature of 117.6.degree. C. is supplied from [c-3]
(corresponding to [c] shown in FIG. 8) to the heat recovery device
59. The rich solution 104b at a temperature of 93.4.degree. C.
heat-recovered via the heat recovery device 59 is returned to [d-1]
(corresponding to [d] shown in FIG. 8), the semi-lean solution 104c
at a temperature of 107.4.degree. C. heat-recovered via the heat
recovery device 59 is returned to [d-2] (corresponding to [d] shown
in FIG. 8), and the semi-lean solution 104c at a temperature of
123.2.degree. C. heat-recovered via the heat recovery device 59 is
returned to [d-3] (corresponding to [d] shown in FIG. 8).
[0128] In the heat recovery system of the CO.sub.2 recovery unit 55
according to the present embodiment, an effect of a case where the
air preheater 58 and the heat recovery device 59 are provided and
the pattern 7 shown in FIG. 10 is applied is explained below with
reference to FIG. 11. As shown in FIG. 11, in the case of the gas
temperature of the unburned air 102 being 30.degree. C.
corresponding to the ambient air, the gas temperature of the
unburned air 102 at the position A in the upstream of the air
preheater 58 in FIG. 8 was 30.degree. C., and the gas temperature
of the preheated unburned air 102 at the position B in the upstream
of the Ljungstrom heat exchanger 57 became 72.degree. C. by passing
through the air preheater 58. The gas temperature of the
heat-exchanged unburned air 102 at the position C in the upstream
of the boiler 51 via the Ljungstrom heat exchanger 57 became
302.degree. C. Furthermore, the gas temperature of the flue gas 101
at the position D in the upstream of the Ljungstrom heat exchanger
57 via the boiler 51 became 350.degree. C. Further, the gas
temperature of the heat-exchanged flue gas 101 at the position E in
the upstream of the heat recovery device 59 via the Ljungstrom heat
exchanger 57 became 158.degree. C. Further, the gas temperature of
the heat-recovered flue gas 101 at a position F in the upstream of
the flue gas desulfurizer 54 via the heat recovery device 59 became
104.degree. C. At this time, the flow rate G of the low-pressure
steam 106 supplied to the regenerating heater 34 of the CO.sub.2
recovery unit 55 was 800 t/hr.
[0129] On the other hand, an effect in the conventional case where
the air preheater 58 and the heat recovery device 59 are not
provided is as described below. As shown in FIG. 11, when the gas
temperature of the unburned air 102 is 30.degree. C. corresponding
to the ambient air, in FIG. 8, the gas temperature of the unburned
air 102 at the position A is 30.degree. C. Because the air
preheater 58 is not provided, the gas temperature of the unburned
air 102 at the position B in the upstream of the Ljungstrom heat
exchanger 57 becomes 30.degree. C. The gas temperature of the
heat-exchanged unburned air 102 at the position C in the upstream
of the boiler 51 via the Ljungstrom heat exchanger 57 became
294.degree. C. Furthermore, the gas temperature of the flue gas 101
at the position D in the upstream of the Ljungstrom heat exchanger
57 via the boiler 51 became 350.degree. C. Furthermore, the gas
temperature of the heat-exchanged flue gas 101 at the position E in
the upstream of the flue gas desulfurizer 54 via the Ljungstrom
heat exchanger 57 became 130.degree. C. Because the heat recovery
device 59 is not provided, the gas temperature of the flue gas 101
corresponding to the position F is 130.degree. C. At this time, the
flow rate G of the low-pressure steam 106 supplied to the
regenerating heater 34 of the CO.sub.2 recovery unit 55 was 870
t/hr.
[0130] In this manner, in the heat recovery system of the CO.sub.2
recovery unit 55 according to the third embodiment, the heat
recovery device 59 that recovers the heat of the flue gas 101
before reaching the CO.sub.2 recovery unit 55 via the Ljungstrom
heat exchanger 57 and supplies the heat to the CO.sub.2 recovery
unit 55 is further provided, with respect to the heat recovery
system of the first embodiment.
[0131] According to the heat recovery system of the CO.sub.2
recovery unit 55, recovered heat can be effectively used, while
effectively using low-temperature exhaust heat equal to or lower
than a temperature level of 70.degree. C. to 80.degree. C.
discharged at the time of recovering CO.sub.2. Specifically, as
described above, the gas temperature of 294.degree. C. of the
unburned air 102 at the position C supplied to the boiler 51 in the
conventional case is raised by 8.degree. C. to be 302.degree. C. A
heat input to the boiler 51 increases due to the increase of
8.degree. C., and effects equivalent to those of decreasing the
flow rate of the low-pressure steam 106 consumed by the CO.sub.2
recovery unit 55 by 15 t/hr can be acquired. The flow rate of 15
t/hr corresponds to 1.7% of the flow rate of the low-pressure steam
106 consumed by the CO.sub.2 recovery unit 55. Furthermore, the
flow rate of 870 t/hr of the low-pressure steam 106 supplied to the
regenerating heater 34 of the CO.sub.2 recovery unit 55 in the
conventional case is decreased to 800 t/hr by 70 t/hr. The flow
rate of 70 t/hr corresponds to 8% of the flow rate of the
low-pressure steam 106 consumed by the CO.sub.2 recovery unit 55.
That is, the flow rate of the low-pressure steam 106 consumed by
the CO.sub.2 recovery unit 55 is decreased by 9.7% in total. As a
result, by recovering the heat of the flue gas 101 after passing
through the Ljungstrom heat exchanger 57 while preheating the
unburned air 102 before reaching the Ljungstrom heat exchanger 57
by low-temperature exhaust heat equal to or lower than the
temperature level of 70.degree. C. to 80.degree. C. discharged at
the time of recovering CO.sub.2, the flow rate of the low-pressure
steam 106 consumed by the CO.sub.2 recovery unit 55 can be
decreased.
[0132] Furthermore, because the Ljungstrom heat exchanger 57
performs heat exchange between the flue gas 101 containing sulfur
content and the unburned air 102, the heat reservoir may be
subjected to sulfuric acid corrosion due to dew condensation
generated on the heat transfer surface of the heat reservoir. In
this regard, according to the heat recovery system of the CO.sub.2
recovery unit 55 of the third embodiment, the gas temperature of
30.degree. C. of the unburned air 102 at the position B on the
inlet side of the Ljungstrom heat exchanger 57 in the conventional
case is raised to 72.degree. C., and the gas temperature of
130.degree. C. of the flue gas 101 at the position E on the outlet
side of the Ljungstrom heat exchanger 57 in the conventional case
is also raised to 158.degree. C. As a result, an average cold-end
temperature ((the gas temperature on the outlet side of flue
gas+the gas temperature on the inlet side of unburned air)/2) of
the Ljungstrom heat exchanger 57 increases from 80.degree. C. to
115.degree. C. by 35.degree. C. Consequently, dew condensation on
the heat transfer surface of the heat reservoir of the Ljungstrom
heat exchanger 57 can be prevented and sulfuric acid corrosion of
the heat reservoir can be suppressed.
[0133] The heat recovery system of the CO.sub.2 recovery unit 55
according to the third embodiment is applied to the power
generation plant 50 that drives the steam turbine 52 by the
superheated steam 100 from the boiler 51 to generate power by the
power generator 53.
[0134] As described above, according to the heat recovery system of
the CO.sub.2 recovery unit 55, the gas temperature of 294.degree.
C. of the unburned air 102 at the position C supplied to the boiler
51 in the conventional case is raised by 8.degree. C. to be
302.degree. C. Therefore, because the flow rate of the superheated
steam 100 supplied from the boiler 51 to the steam turbine 52
increases, the power generation efficiency of the power generation
plant 50 can be improved.
[0135] A heat recovery method of the CO.sub.2 recovery unit 55
according to the third embodiment further includes a step of
recovering the heat of the flue gas 101 before reaching the
CO.sub.2 recovery step through the heat exchanging step, and of
supplying the heat to the CO.sub.2 recovery step (heat recovery
step), with respect to the heat recovery method of the first
embodiment.
[0136] According to the heat recovery method of the CO.sub.2
recovery unit 55, low-temperature exhaust heat equal to or lower
than the temperature level of 70.degree. C. to 80.degree. C.
discharged at the time of recovering CO.sub.2 can be used
efficiently. Specifically, the gas temperature of 294.degree. C. of
the unburned air 102 at the position C supplied to the boiler 51 in
the conventional case is raised by 8.degree. C. to be 302.degree.
C. A heat input to the boiler 51 increases due to the increase of
8.degree. C., and effects equivalent to those of decreasing the
flow rate of the low-pressure steam 106 consumed at the CO.sub.2
recovery step by 15 t/hr can be acquired. The flow rate of 15 t/hr
corresponds to 1.7% of the flow rate of the low-pressure steam 106
consumed at the CO.sub.2 recovery step. Furthermore, the flow rate
of 870 t/hr of the low-pressure steam 106 supplied to the CO.sub.2
recovery step in the conventional case is decreased to 800 t/hr by
70 t/hr. The flow rate of 70 t/hr corresponds to 8% of the flow
rate of the low-pressure steam 106 consumed at the CO.sub.2
recovery step. That is, the flow rate of the low-pressure steam 106
consumed at the CO.sub.2 recovery step is decreased by 9.7% in
total. As a result, by recovering the heat of the flue gas 101
after passing through the heat exchanging step while preheating the
unburned air 102 before reaching the heat exchanging step by
low-temperature exhaust heat equal to or lower than the temperature
level of 70.degree. C. to 80.degree. C. discharged at the time of
recovering CO.sub.2, the flow rate of the low-pressure steam 106
consumed at the CO.sub.2 recovery step can be decreased.
[0137] Furthermore, because heat exchange between the flue gas 101
containing sulfur content and the unburned air 102 is performed at
the heat exchanging step, the heat reservoir may be subjected to
sulfuric acid corrosion due to dew condensation generated on the
heat transfer surface of the heat reservoir. In this regard,
according to the heat recovery method of the CO.sub.2 recovery unit
55 of the third embodiment, the gas temperature of 30.degree. C. of
the unburned air 102 at the position B on the inlet side of the
heat exchanging step in the conventional case is raised to
72.degree. C., and the gas temperature of 130.degree. C. of the
flue gas 101 at the position E on the outlet side of the heat
exchanging step in the conventional case is also raised to
158.degree. C. As a result, an average cold-end temperature ((the
gas temperature on the outlet side of flue gas+the gas temperature
on the inlet side of unburned air)/2) at the heat exchanging step
is increased from 80.degree. C. to 115.degree. C. by 35.degree. C.
Consequently, dew condensation on the heat transfer surface of the
heat reservoir at the heat exchanging step can be prevented and
sulfuric acid corrosion of the heat reservoir can be
suppressed.
[0138] The heat recovery method of the CO.sub.2 recovery unit 55
according to the third embodiment further includes a power
generation step of driving the steam turbine 52 by the superheated
steam 100 from the boiler 51 to generate power by the power
generator 53.
[0139] According to the heat recovery method of the CO.sub.2
recovery unit 55, the gas temperature of 294.degree. C. of the
unburned air 102 at the position C supplied to the boiler 51 in the
conventional case is raised by 8.degree. C. to be 302.degree. C.
Therefore, because the flow rate of the superheated steam 100
supplied from the boiler 51 to the steam turbine 52 increases, the
power generation efficiency of the power generation plant 50 can be
improved.
[0140] In the configuration described above, the regenerator 3
includes three stages, which are an upper stage, a middle stage,
and a lower stage. That is, these are the upper regenerating unit
31, the middle regenerating unit 32, and the lower regenerating
unit 33. However, the regenerator 3 can include two stages, which
are upper and lower stages. That is, these are the upper
regenerating unit 31 and the lower regenerating unit 33. In this
case, the semi-lean-solution extracting pipe 31d in the regenerator
3 is provided between the lean-solution/steam-drain heat recovery
unit 35 and the nozzle 32a via the heat recovery device 59, and the
pattern 2 and patterns including the pattern 2 shown in FIG. 10 are
deleted. Furthermore, the regenerator 3 is not limited to the
upper, middle, and lower stages, which are the upper regenerating
unit 31, the middle regenerating unit 32, and the lower
regenerating unit 33, and can include three or more regenerating
units. In this case, a pattern for an increased stage and patterns
including this pattern are added.
Fourth Embodiment
[0141] A fourth embodiment is explained with reference to the
drawings. FIG. 12 is a schematic diagram of a heat recovery system
of a CO.sub.2 recovery unit according to the fourth embodiment.
FIG. 13 is a schematic diagram of an effect of the heat recovery
system of a CO.sub.2 recovery unit according to the fourth
embodiment.
[0142] The heat recovery system of the CO.sub.2 recovery unit 55
according to the fourth embodiment further includes, as shown in
FIGS. 8 and 12, the heat recovery device 59 that recovers the heat
of the flue gas 101 before reaching the CO.sub.2 recovery unit 55
via the Ljungstrom heat exchanger 57 and supplies the heat to the
CO.sub.2 recovery unit 55 in addition to the heat recovery system
of the second embodiment. Furthermore, heat recovery from the heat
recovery device 59 to the CO.sub.2 recovery unit 55 in the fourth
embodiment is identical to that of the third embodiment described
above. Therefore, in the fourth embodiment, explanations of heat
recovery will be omitted because it has been explained in the
second and third embodiments described above.
[0143] In the heat recovery system of the CO.sub.2 recovery unit 55
according to the present embodiment, an effect of a case where the
air preheater 58 and the heat recovery device 59 are provided and
the pattern 7 shown in FIG. 10 is applied is explained below with
reference to FIG. 13. As shown in FIG. 13, in the case of the gas
temperature of the unburned air 102 being 30.degree. C.
corresponding to the ambient air, the gas temperature of the
unburned air 102 at the position A in the upstream of the air
preheater 58 in FIG. 8 was 30.degree. C., and the gas temperature
of the preheated unburned air 102 at the position B in the upstream
of the Ljungstrom heat exchanger 57 became 82.degree. C. by passing
through the air preheater 58. The gas temperature of the
heat-exchanged unburned air 102 at the position C in the upstream
of the boiler 51 via the Ljungstrom heat exchanger 57 became
303.degree. C. Furthermore, the gas temperature of the flue gas 101
at the position D in the upstream of the Ljungstrom heat exchanger
57 via the boiler 51 became 350.degree. C.
[0144] Further, the gas temperature of the heat-exchanged flue gas
101 at the position E in the upstream of the heat recovery device
59 via the Ljungstrom heat exchanger 57 became 165.degree. C.
Further, the gas temperature of the heat-recovered flue gas 101 at
the position F in the upstream of the flue gas desulfurizer 54 via
the heat recovery device 59 became 104.degree. C. At this time, the
flow rate G of the low-pressure steam 106 supplied to the
regenerating heater 34 of the CO.sub.2 recovery unit 55 was 791
t/hr.
[0145] On the other hand, an effect in the conventional case where
the air preheater 58 and the heat recovery device 59 are not
provided is as described below. As shown in FIG. 13, when the gas
temperature of the unburned air 102 is 30.degree. C. corresponding
to the ambient air, in FIG. 8, the gas temperature of the unburned
air 102 at the position A is 30.degree. C. Because the air
preheater 58 is not provided, the gas temperature of the unburned
air 102 at the position B in the upstream of the Ljungstrom heat
exchanger 57 becomes 30.degree. C. The gas temperature of the
heat-exchanged unburned air 102 at the position C in the upstream
of the boiler 51 via the Ljungstrom heat exchanger 57 became
294.degree. C. Furthermore, the gas temperature of the flue gas 101
at the position D in the upstream of the Ljungstrom heat exchanger
57 via the boiler 51 became 350.degree. C. Furthermore, the gas
temperature of the heat-exchanged flue gas 101 at the position E in
the upstream of the flue gas desulfurizer 54 via the Ljungstrom
heat exchanger 57 became 130.degree. C. Because the heat recovery
device 59 is not provided, the gas temperature of the flue gas 101
corresponding to the position F is 130.degree. C. At this time, the
flow rate G of the low-pressure steam 106 supplied to the
regenerating heater 34 of the CO.sub.2 recovery unit 55 was 870
t/hr.
[0146] In this manner, in the heat recovery system of the CO.sub.2
recovery unit 55 according to the fourth embodiment, the heat
recovery device 59 that recovers the heat of the flue gas 101
before reaching the CO.sub.2 recovery unit 55 via the Ljungstrom
heat exchanger 57 and supplies the heat to the CO.sub.2 recovery
unit 55 is further provided, with respect to the heat recovery
system of the second embodiment.
[0147] According to the heat recovery system of the CO.sub.2
recovery unit 55, recovered heat can be effectively used, while
effectively using low-temperature exhaust heat equal to or lower
than a temperature level of 70.degree. C. to 80.degree. C.
discharged at the time of recovering CO.sub.2. Specifically, as
described above, the gas temperature of 294.degree. C. of the
unburned air 102 at the position C supplied to the boiler 51 in the
conventional case is raised by 9.degree. C. to be 303.degree. C. A
heat input to the boiler 51 increases due to the increase of
9.degree. C., and effects equivalent to those of decreasing the
flow rate of the low-pressure steam 106 consumed by the CO.sub.2
recovery unit 55 by 17 t/hr can be acquired. The flow rate of 17
t/hr corresponds to 2% of the flow rate of the low-pressure steam
106 consumed by the CO.sub.2 recovery unit 55. Furthermore, the
flow rate of 870 t/hr of the low-pressure steam 106 supplied to the
regenerating heater 34 of the CO.sub.2 recovery unit 55 in the
conventional case is decreased to 791 t/hr by 79 t/hr. The flow
rate of 79 t/hr corresponds to 9.1% of the flow rate of the
low-pressure steam 106 consumed by the CO.sub.2 recovery unit 55.
That is, the flow rate of the low-pressure steam 106 consumed by
the CO.sub.2 recovery unit 55 is decreased by 11.1% in total. As a
result, by recovering the heat of the flue gas 101 after passing
through the Ljungstrom heat exchanger 57 while preheating the
unburned air 102 before reaching the
[0148] Ljungstrom heat exchanger 57 by low-temperature exhaust heat
equal to or lower than the temperature level of 70.degree. C. to
80.degree. C. discharged at the time of recovering CO.sub.2, the
flow rate of the low-pressure steam 106 consumed by the CO.sub.2
recovery unit 55 can be decreased.
[0149] Furthermore, because the Ljungstrom heat exchanger 57
performs heat exchange between the flue gas 101 containing sulfur
content and the unburned air 102, the heat reservoir may be
subjected to sulfuric acid corrosion due to dew condensation
generated on the heat transfer surface of the heat reservoir. In
this regard, according to the heat recovery system of the CO.sub.2
recovery unit 55 of the fourth embodiment, the gas temperature of
30.degree. C. of the unburned air 102 at the position B on the
inlet side of the Ljungstrom heat exchanger 57 in the conventional
case is raised to 82.degree. C., and the gas temperature of
130.degree. C. of the flue gas 101 at the position E on the outlet
side of the
[0150] Ljungstrom heat exchanger 57 in the conventional case is
also raised to 165.degree. C. As a result, an average cold-end
temperature ((the gas temperature on the outlet side of flue
gas+the gas temperature on the inlet side of unburned air)/2) of
the Ljungstrom heat exchanger 57 increases from 80.degree. C. to
123.5.degree. C. by 43.5.degree. C. Consequently, dew condensation
on the heat transfer surface of the heat reservoir of the
Ljungstrom heat exchanger 57 can be prevented and sulfuric acid
corrosion of the heat reservoir can be suppressed.
[0151] The heat recovery system of the CO.sub.2 recovery unit 55
according to the fourth embodiment is applied to the power
generation plant 50 that drives the steam turbine 52 by the
superheated steam 100 from the boiler 51 to generate power by the
power generator 53.
[0152] As described above, according to the heat recovery system of
the CO.sub.2 recovery unit 55, the gas temperature of 294.degree.
C. of the unburned air 102 at the position C supplied to the boiler
51 in the conventional case is raised by 9.degree. C. to be
303.degree. C. Therefore, because the flow rate of the superheated
steam 100 supplied from the boiler 51 to the steam turbine 52
increases, the power generation efficiency of the power generation
plant 50 can be improved.
[0153] A heat recovery method of the CO.sub.2 recovery unit 55
according to the fourth embodiment further includes a step of
recovering the heat of the flue gas 101 before reaching the
CO.sub.2 recovery step through the heat exchanging step, and of
supplying the heat to the CO.sub.2 recovery step (heat recovery
step), with respect to the heat recovery method of the first
embodiment.
[0154] According to the heat recovery method of the CO.sub.2
recovery unit 55, low-temperature exhaust heat equal to or lower
than the temperature level of 70.degree. C. to 80.degree. C.
discharged at the time of recovering CO.sub.2 can be used
efficiently. Specifically, the gas temperature of 294.degree. C. of
the unburned air 102 at the position C supplied to the boiler 51 in
the conventional case is raised by 9.degree. C. to be 303.degree.
C. A heat input to the boiler 51 increases due to the increase of
9.degree. C., and effects equivalent to those of decreasing the
flow rate of the low-pressure steam 106 consumed at the CO.sub.2
recovery step by 17 t/hr can be acquired. The flow rate of 17 t/hr
corresponds to 2% of the flow rate of the low-pressure steam 106
consumed at the CO.sub.2 recovery step. Furthermore, the flow rate
of 870 t/hr of the low-pressure steam 106 supplied to the CO.sub.2
recovery step in the conventional case is decreased to 791 t/hr by
79 t/hr. The flow rate of 79 t/hr corresponds to 9.1% of the flow
rate of the low-pressure steam 106 consumed at the CO.sub.2
recovery step. That is, the flow rate of the low-pressure steam 106
consumed at the CO.sub.2 recovery step is decreased by 11.1% in
total. As a result, by recovering the heat of the flue gas 101
after passing through the heat exchanging step while preheating the
unburned air 102 before reaching the heat exchanging step by
low-temperature exhaust heat equal to or lower than the temperature
level of 70.degree. C. to 80.degree. C. discharged at the time of
recovering CO.sub.2, the flow rate of the low-pressure steam 106
consumed at the CO.sub.2 recovery step can be decreased.
[0155] Furthermore, because heat exchange between the flue gas 101
containing sulfur content and the unburned air 102 is performed at
the heat exchanging step, the heat reservoir may be subjected to
sulfuric acid corrosion due to dew condensation generated on the
heat transfer surface of the heat reservoir. In this regard,
according to the heat recovery method of the CO.sub.2 recovery unit
55 of the fourth embodiment, the gas temperature of 30.degree. C.
of the unburned air 102 at the position B on the inlet side of the
heat exchanging step in the conventional case is raised to
82.degree. C., and the gas temperature of 130.degree. C. of the
flue gas 101 at the position E on the outlet side of the heat
exchanging step in the conventional case is also raised to
165.degree. C. As a result, an average cold-end temperature ((the
gas temperature on the outlet side of flue gas+the gas temperature
on the inlet side of unburned air)/2) at the heat exchanging step
is increased from 80.degree. C. to 123.5.degree. C. by 43.5.degree.
C. Consequently, dew condensation on the heat transfer surface of
the heat reservoir at the heat exchanging step can be prevented and
sulfuric acid corrosion of the heat reservoir can be
suppressed.
[0156] The heat recovery method of the CO.sub.2 recovery unit 55
according to the fourth embodiment further includes a power
generation step of driving the steam turbine 52 by the superheated
steam 100 from the boiler 51 to generate power by the power
generator 53.
[0157] According to the heat recovery method of the CO.sub.2
recovery unit 55, the gas temperature of 294.degree. C. of the
unburned air 102 at the position C supplied to the boiler 51 in the
conventional case is raised by 9.degree. C. to be 303.degree. C.
Therefore, because the flow rate of the superheated steam 100
supplied from the boiler 51 to the steam turbine 52 increases, the
power generation efficiency of the power generation plant 50 can be
improved.
[0158] In the configuration described above, the regenerator 3
includes three stages, which are an upper stage, a middle stage,
and a lower stage. That is, these are the upper regenerating unit
31, the middle regenerating unit 32, and the lower regenerating
unit 33. However, the regenerator 3 can include two stages, which
are upper and lower stages. That is, these are the upper
regenerating unit 31 and the lower regenerating unit 33. In this
case, the semi-lean-solution extracting pipe 31d in the regenerator
3 is provided between the lean-solution/steam-drain heat recovery
unit 35 and the nozzle 32a via the heat recovery device 59, and the
pattern 2 and patterns including the pattern 2 shown in FIG. 10 are
deleted. Furthermore, the regenerator 3 is not limited to the
upper, middle, and lower stages, which are the upper regenerating
unit 31, the middle regenerating unit 32, and the lower
regenerating unit 33, and can include three or more regenerating
units. In this case, a pattern for an increased stage and patterns
including this pattern are added.
REFERENCE SIGNS LIST
[0159] 1 cooling column [0160] 2 absorber [0161] 3 regenerator
[0162] 4 rich-lean heat exchanger [0163] 50 power generation plant
[0164] 51 boiler [0165] 52 steam turbine [0166] 53 power generator
[0167] 54 flue gas desulfurizer [0168] 55 CO.sub.2 recovery unit
[0169] 56 stack [0170] 57 Ljungstrom heat exchanger [0171] 58 air
preheater [0172] 59 heat recovery device [0173] 100 superheated
steam [0174] 101 flue gas [0175] 101a decarbonated flue gas [0176]
102 unburned air [0177] 103 cooling water [0178] 104 absorbent
[0179] 104a lean solution [0180] 104b rich solution [0181] 104c
semi-lean solution [0182] 105 wash water [0183] 106 low-pressure
steam [0184] 106a steam drain [0185] 107 CO.sub.2 gas [0186] 108
condensed water [0187] 109 heat medium
* * * * *