U.S. patent application number 12/831183 was filed with the patent office on 2012-01-12 for systems for compressing a gas.
This patent application is currently assigned to GENERAL ELECTRIC COMPANY. Invention is credited to Indrajit Mazumder, Bhaskar Pemmi, Rajeshkumar Ravikumar, Anil Kumar Sharma.
Application Number | 20120009075 12/831183 |
Document ID | / |
Family ID | 45438714 |
Filed Date | 2012-01-12 |
United States Patent
Application |
20120009075 |
Kind Code |
A1 |
Ravikumar; Rajeshkumar ; et
al. |
January 12, 2012 |
SYSTEMS FOR COMPRESSING A GAS
Abstract
Systems for efficiently compressing a gas are included. In one
embodiment, a system includes a carbonous gas compression system
and a vapor absorption chiller (VAC). The carbonous gas compression
system comprises a compressor configured to compress the carbonous
gas. The VAC is configured to circulate a coolant through at least
one coolant path through the carbonous gas compression system.
Utilization of the VAC may aid in cooling the carbonous gas, which
may allow for less energy to be expended by the compression
system.
Inventors: |
Ravikumar; Rajeshkumar;
(Bangalore, IN) ; Mazumder; Indrajit; (Bangalore,
IN) ; Pemmi; Bhaskar; (Durg, IN) ; Sharma;
Anil Kumar; (Dist, IN) |
Assignee: |
GENERAL ELECTRIC COMPANY
Schenectady
NY
|
Family ID: |
45438714 |
Appl. No.: |
12/831183 |
Filed: |
July 6, 2010 |
Current U.S.
Class: |
417/313 |
Current CPC
Class: |
F04B 41/06 20130101;
F04B 37/12 20130101 |
Class at
Publication: |
417/313 |
International
Class: |
F04B 39/00 20060101
F04B039/00 |
Claims
1. A system, comprising: a carbonous gas compression system
comprising a compressor configured to compress the carbonous gas;
and a vapor absorption chiller (VAC) configured to circulate a
coolant through at least one coolant path through the carbonous gas
compression system.
2. The system of claim 1, wherein the carbonous gas comprises
carbon dioxide that is at least approximately 60 percent pure by
volume.
3. The system of claim 1, wherein the carbonous gas compression
system comprises a heat exchanger in a gas path upstream of the
compressor, and the at least one coolant path of the VAC extends
through the heat exchanger.
4. The system of claim 3, wherein the heat exchanger upstream of
the compressor comprises a heated water heat exchanger.
5. The system of claim 3, wherein the heat exchanger upstream of
the compressor comprises a chilled water heat exchanger.
6. The system of claim 1, wherein the carbonous gas compression
system comprises a chilled water heat exchanger and a heated water
heat exchanger in a gas path upstream of the compressor, and the at
least one coolant path of the VAC comprises a chilled temperature
coolant path extending through the first chilled water heat
exchanger and a heated temperature coolant path extending through
the heated water heat exchanger.
7. The system of claim 1, wherein the carbonous gas compression
system comprises a first chilled water heat exchanger in a gas path
downstream of the compressor, a second chilled water heat exchanger
and a heated water heat exchanger in the gas path upstream of the
compressor, and the at least one coolant path of the VAC comprises
a chilled temperature coolant path extending through the first
chilled water heat exchanger and through the second chilled water
heat exchanger, and a heated temperature coolant path extending
through the heated water heat exchanger.
8. The system of claim 1, wherein the carbonous gas compression
system is configured to liquefy the carbonous gas.
9. The system of claim 8, wherein the carbonous gas compression
system comprises a liquid pump configured to raise the pressure of
the liquefied carbonous gas to a super critical pressure.
10. The system of claim 8, wherein the carbonous gas compression
system comprises a plurality of compression stages with respective
compressors, the carbonous gas compression system comprises a heat
exchanger in a gas path between the plurality of compression stages
and the liquid pump, and wherein the at least one coolant path
extends through the heat exchanger.
11. The system of claim 1, wherein the VAC comprises an evaporator
configured to boil a refrigerant, an absorber configured to
generate a refrigerant vapor from the refrigerant, a generator
configured to transfer heat to the refrigerant vapor, and a
condenser configured to liquefy the refrigerant vapor.
12. A system, comprising: a carbonous gas capture system configured
to extract a carbonous gas; a carbonous gas compression system
comprising a compressor configured to receive the carbonous gas
from the carbonous gas capture system and to compress and liquefy
the carbonous gas; a vapor absorption chiller (VAC) configured to
circulate a coolant through at least one coolant path through the
carbonous gas compression system; and a carbon sequestration system
or an enhanced oil recovery (EOR) pipeline configured to receive
the carbonous gas compressed and liquefied by the carbonous gas
compression system.
13. The system of claim 12, wherein the carbonous gas comprises
carbon dioxide that is at least approximately 60 percent pure by
volume.
14. The system of claim 12, wherein the carbonous gas compression
system comprises a heat exchanger in a gas path upstream of the
compressor, and the at least one coolant path of the VAC extends
through the heat exchanger.
15. The system of claim 12, wherein the carbonous gas compression
system comprises a heat exchanger in a gas path downstream of the
compressor, and the coolant path extends through the heat
exchanger.
16. The system of claim 12, comprising a liquid pump configured to
raise the pressure of the liquefied carbonous gas compressed by the
carbonous gas compression system to a supercritical pressure,
wherein the carbonous gas compression system comprises a plurality
of compression stages with respective compressors and with at least
one heat exchanger in a gas path between the plurality of
compression stages and the liquid pump, and the at least one
coolant path extends through the heat exchanger.
17. The system of claim 12, wherein the at least one coolant path
comprises a chilled temperature coolant path extending through a
chilled water heat exchanger in a gas path upstream of the
compressor, and a heated temperature coolant path extending through
a heated water heat exchanger in the gas path upstream of the
compressor.
18. A system, comprising: a carbon dioxide (CO.sub.2) compression
system comprising a compressor configured to compress the CO.sub.2;
a vapor absorption chiller (VAC) configured to circulate a coolant
through at least one coolant path through the CO.sub.2 compression
system; and a liquid pump configured to raise the pressure of the
CO.sub.2.
19. The system of claim 18, wherein the CO.sub.2 is converted to a
supercritical liquid.
20. The system of claim 18, wherein the CO.sub.2 compression system
comprises a heat exchanger in a gas path upstream of the
compressor, and the at least one coolant path of the VAC extends
through the heat exchanger.
Description
BACKGROUND OF THE INVENTION
[0001] The subject matter disclosed herein relates to systems for
efficiently compressing a gas, such as carbon dioxide (CO.sub.2),
in a power plant such as an integrated coal gasification combined
cycle (IGCC) or a coal-fired conventional power plant.
[0002] Power plants, for example IGCC power plants, may produce a
carbonous gas such as CO.sub.2. In IGCC power plants, a syngas is
created by gasifying a carbonaceous fuel such as coal. The syngas
may be utilized as fuel for power generation. The syngas may be fed
into a combustor of a gas turbine of the IGCC power plant and
ignited to power the gas turbine, which may then drive a load such
as an electrical generator. One byproduct of such plants may be
CO.sub.2. Carbon capture and sequestration is very likely to be a
key element of any future greenhouse gas legislation, such as
CO.sub.2 legislation. Thus, power plants may be under provisions to
separate the CO.sub.2, either pre-combustion or post combustion.
The CO.sub.2 may be captured, compressed, and sequestered. However,
the compression of CO.sub.2 requires a considerable amount of
energy. Accordingly, there is a need for systems that can reduce
power consumption and overall cost in the compression of
CO.sub.2.
BRIEF DESCRIPTION OF THE INVENTION
[0003] Certain embodiments commensurate in scope with the
originally claimed invention are summarized below. These
embodiments are not intended to limit the scope of the claimed
invention, but rather these embodiments are intended only to
provide a brief summary of possible forms of the invention. Indeed,
the invention may encompass a variety of forms that may be similar
to or different from the embodiments set forth below.
[0004] In a first embodiment, a system includes a carbonous gas
compression system and a vapor absorption chiller (VAC). The
carbonous gas compression system comprises a compressor configured
to compress the carbonous gas. The VAC is configured to circulate a
coolant through at least one coolant path through the carbonous gas
compression system.
[0005] In a second embodiment, a system includes a carbonous gas
capture system, a carbonous gas compression system, a vapor
absorption chiller (VAC), and at least a carbon sequestration
system or an enhanced oil recovery (EOR) pipeline. The carbonous
gas capture system is configured to extract the carbonous gas. The
carbonous gas compression system comprises at least a compressor
which is configured to receive the carbonous gas from the carbonous
gas capture system and to compress and liquefy the carbonous gas.
The VAC is configured to circulate a coolant through at least one
coolant path through the carbonous compression system. The carbon
sequestration system or the enhanced oil recovery (EOR) pipeline
are configured to receive carbonous gas compressed and liquefied by
the carbonous gas compression system.
[0006] In a third embodiment, a system includes a carbon dioxide
(CO.sub.2) compression system, a VAC, and a liquid pump. The
CO.sub.2 compression system comprises at least a compressor
configured to compress the CO.sub.2. The VAC is configured to
circulate a coolant through at least one coolant path through the
CO.sub.2 compression system. The liquid pump is configured to raise
the pressure of the CO.sub.2.
BRIEF DESCRIPTION OF THE DRAWINGS
[0007] These and other features, aspects, and advantages of the
present invention will become better understood when the following
detailed description is read with reference to the accompanying
drawings in which like characters represent like parts throughout
the drawings, wherein:
[0008] FIG. 1 depicts a block diagram of an embodiment of an
integrated gasification combined cycle (IGCC) power plant,
including a gas compression system and a vapor absorption chiller
system;
[0009] FIG. 2 depicts a block diagram of embodiments of the gas
compression system and the vapor absorption chiller system depicted
in FIG. 1;
[0010] FIG. 3 is a depicts a block diagram of an embodiment of a
vapor absorption chiller system; and,
[0011] FIG. 4 depicts a block diagram of other embodiments of the
gas compression system and the vapor absorption chiller system
depicted in FIG. 1.
DETAILED DESCRIPTION OF THE INVENTION
[0012] One or more specific embodiments of the present invention
will be described below. In an effort to provide a concise
description of these embodiments, all features of an actual
implementation may not be described in the specification. It should
be appreciated that in the development of any such actual
implementation, as in any engineering or design project, numerous
implementation-specific decisions must be made to achieve the
developers' specific goals, such as compliance with system-related
and business-related constraints, which may vary from one
implementation to another. Moreover, it should be appreciated that
such a development effort might be complex and time consuming, but
would nevertheless be a routine undertaking of design, fabrication,
and manufacture for those of ordinary skill having the benefit of
this disclosure.
[0013] When introducing elements of various embodiments of the
present invention, the articles "a," "an," "the," and "said" are
intended to mean that there are one or more of the elements. The
terms "comprising," "including," and "having" are intended to be
inclusive and mean that there may be additional elements other than
the listed elements.
[0014] The disclosed embodiments include systems for efficiently
compressing a carbonous gas (e.g., CO.sub.2) produced, for example,
by extracting CO.sub.2 from syngas in the integrated gasification
combined cycle (IGCC) system. The compression of the carbonous gas
allows the gas to be stored, for example, in a carbon sequestration
system or redirected to an enhanced oil recovery (EOR) pipeline.
Power plants such as IGCC power plant described in more detail with
respect to FIG. 1 below, may gasify a fuel and provide for the
pre-combustion capture of CO.sub.2 from the fuel. Additionally, the
CO.sub.2 may be extracted after the fuel is combusted (i.e.,
post-combustion extraction), for example, from a flue gas. The
CO.sub.2 may then be transported, and stored or sequestered, for
example, in a supercritical state. The supercritical state of the
CO.sub.2 refers to CO.sub.2 that is in a fluid state while also
being above both of its critical pressure and critical temperature.
In such a supercritical state, CO.sub.2 may behave as a
supercritical fluid, expanding to fill a container like a gas but
with a density like that of a liquid. Compressors are used to
increase the CO.sub.2 pressure from near atmospheric pressure to a
supercritical phase (i.e., state), in some cases, of upwards of
approximately 2215 pounds per square inch absolute (PSIA) at
upwards of approximately 100.degree. F. A more efficient system for
compressing the carbonous gas is disclosed that is capable of using
vapor absorption chiller (VAC) systems to lower the carbonous gas
temperatures, resulting in a more efficient and less costly
compression of the carbonous gas. Further, liquid compressors
(e.g., liquid pumps) may also be used that use significantly less
power to operate than gas compressors. Indeed, by combining vapor
chiller systems with liquid compressors it may be possible to
substantially reduce the amount of energy expended in reaching a
supercritical phase of the carbonous gas, thereby increasing
efficiency and reducing cost.
[0015] With the foregoing in mind, FIG. 1 depicts an embodiment of
an IGCC power plant 100 that may produce and burn a synthetic gas,
i.e., syngas. Elements of the IGCC power plant 100 may include a
fuel source 102, such as a solid feed, that may be utilized as a
source of energy for the IGCC power plant 100. The fuel source 102
may include coal, petroleum coke, biomass, wood-based materials,
agricultural wastes, tars, coke oven gas and asphalt, or other
carbon containing items.
[0016] The solid fuel of the fuel source 102 may be passed to a
feedstock preparation unit 104. The feedstock preparation unit 104
may, for example, resize or reshape the fuel source 102 by
chopping, milling, shredding, pulverizing, briquetting, or
palletizing the fuel source 102 to generate feedstock.
Additionally, water, or other suitable liquids may be added to the
fuel source 102 in the feedstock preparation unit 104 to create
slurry feedstock. In certain embodiments, no liquid is added to the
fuel source, thus yielding dry feedstock. The feedstock may be
conveyed into a gasifier 106 for use in gasification
operations.
[0017] The gasifier 106 may convert the feedstock into a syngas,
e.g., a combination of carbon monoxide and hydrogen. This
conversion may be accomplished by subjecting the feedstock to a
controlled amount of any moderator and limited oxygen at elevated
pressures (e.g., from approximately 600 pounds per square inch
gauge (PSIG)-1200 PSIG) and elevated temperatures (e.g.,
approximately 2200.degree. F.-2700.degree. F.), depending on the
type of feedstock used. The heating of the feedstock during a
pyrolysis process may generate a solid (e.g., char) and residue
gases (e.g., carbon monoxide, hydrogen, and nitrogen).
[0018] A combustion process may then occur in the gasifier 106. The
combustion may include introducing oxygen to the char and residue
gases. The char and residue gases may react with the oxygen to form
carbon dioxide and carbon monoxide, which provides heat for the
subsequent gasification reactions. The temperatures during the
combustion process may range from approximately 2200.degree. F. to
approximately 2700.degree. F. In addition, steam may be introduced
into the gasifier 106. The gasifier 106 utilizes steam and limited
oxygen to allow some of the feedstock to be burned to produce
carbon monoxide and energy, which may drive a second reaction that
converts further feedstock to hydrogen and additional carbon
dioxide.
[0019] In this way, a resultant gas is manufactured by the gasifier
106. This resultant gas may include approximately 85% of carbon
monoxide and hydrogen in equal proportions, as well as CH.sub.4,
HCl, HF, COS, NH.sub.3, HCN, and H.sub.2S (based on the sulfur
content of the feedstock). This resultant gas may be termed
untreated syngas, since it contains, for example, H.sub.2S. The
gasifier 106 may also generate waste, such as slag 108, which may
be a wet ash material. This slag 108 may be removed from the
gasifier 106 and disposed of, for example, as road base or as
another building material. To treat the untreated syngas, a gas
treatment unit 110 may be utilized. In one embodiment, the gas
treatment unit 110 may be a water gas shift reactor. The gas
treatment unit 110 may scrub the untreated syngas to remove the
HCl, HF, COS, HCN, and H.sub.2S from the untreated syngas, which
may include separation of sulfur 111 in a sulfur processor 112 by,
for example, an acid gas removal process in the sulfur processor
112. Furthermore, the gas treatment unit 110 may separate salts 113
from the untreated syngas via a water treatment unit 114 that may
utilize water purification techniques to generate usable salts 113
from the untreated syngas. Subsequently, the gas from the gas
treatment unit 110 may include treated syngas, (e.g., the sulfur
111 has been removed from the syngas), with trace amounts of other
chemicals, e.g., NH.sub.3 (ammonia) and CH.sub.4 (methane). A gas
processor 115 may be used to remove additional residual gas
components 116, such as ammonia and methane, as well as methanol or
any residual chemicals from the treated syngas. However, removal of
residual gas components from the treated syngas is optional, since
the treated syngas may be utilized as a fuel even when containing
the residual gas components, e.g., tail gas.
[0020] In some embodiments, a carbon capture system 117 may extract
and process the carbonous gas (e.g., CO.sub.2 that is approximately
60-80 percent, approximately 80-100 percent or approximately 90-100
percent pure by volume) from the syngas (i.e., pre-combustion
extraction). Additionally, the carbon capture system 117 may
extract and process the carbonous gas after combustion (i.e.,
post-combustion extraction), for example, by extracting the
CO.sub.2 from a flue gas. An extracted CO.sub.2 may then be
transferred into a gas compression system 118. In certain
embodiments, the gas compression system 118 may compress,
dehydrate, and liquefy the extracted CO.sub.2, resulting in a
CO.sub.2 that is more easily transported and stored. The CO.sub.2
may then be redirected into a carbon sequestration system 119,
and/or an EOR pipeline 120 for use in, for example, oil recovery
activities. Accordingly, emissions of the extracted CO.sub.2 into
the atmosphere may be reduced or eliminated by redirecting the
extracted CO.sub.2 for use in such activities.
[0021] Gas compression activities may be able to more efficiently
compress the extracted CO.sub.2 by cooling the compressed CO.sub.2
to lower temperatures. Accordingly, a VAC system 122 may operate to
transmit water to cool the compression system 118 during operation.
The VAC system 122 may also operate to retrieve water made hot
through absorption of heat generated by the compression system 118
while compressing. The VAC system 122 may further cycle the water
used in conjunction with the compression system 118 through a
cooling tower 124 that may act as a water reservoir. By cooling the
compression system 118 via the VAC system 122 utilizing the cooling
tower 124, the CO.sub.2 in the compression system 118 may be
compressed more easily, that is, use less energy to compress the
CO.sub.2, and, thus, the efficiency of the compression system 118
may be increased. Furthermore, the use of the VAC system 122 may be
beneficial because of its ability to reuse heat that might
otherwise be wasted.
[0022] Continuing with the syngas processing, once the CO.sub.2 has
been captured from the syngas, the treated syngas may be then
transmitted to a combustor 125, e.g., a combustion chamber, of a
gas turbine engine 126 as combustible fuel. The IGCC power plant
100 may further include an air separation unit (ASU) 128. The ASU
128 may operate to separate air into component gases by, for
example, distillation techniques. The ASU 128 may separate oxygen
from the air supplied to it from a supplemental air compressor 129,
and the ASU 128 may transfer the separated oxygen to the gasifier
106. Additionally the ASU 128 may transmit separated nitrogen to a
diluent nitrogen (DGAN) compressor 130.
[0023] The DGAN compressor 130 may compress the nitrogen received
from the ASU 128 at least to pressure levels equal to those in the
combustor 125, so as not to interfere with the proper combustion of
the syngas. Thus, once the DGAN compressor 130 has adequately
compressed the nitrogen to a proper level, the DGAN compressor 130
may transmit the compressed nitrogen to the combustor 125 of the
gas turbine engine 126. The nitrogen may be used as a diluent to
facilitate control of emissions, for example.
[0024] As described previously, the compressed nitrogen may be
transmitted from the DGAN compressor 130 to the combustor 125 of
the gas turbine engine 126. The gas turbine engine 126 may include
a turbine 132, a drive shaft 133 and a compressor 134, as well as
the combustor 125. The combustor 125 may receive fuel, such as
syngas, which may be injected under pressure from fuel nozzles.
This fuel may be mixed with compressed air as well as compressed
nitrogen from the DGAN compressor 130, and combusted within
combustor 125. This combustion may create hot pressurized exhaust
gases.
[0025] The combustor 125 may direct the exhaust gases towards an
exhaust outlet of the turbine 132. As the exhaust gases from the
combustor 125 pass through the turbine 132, the exhaust gases force
turbine blades in the turbine 132 to rotate the drive shaft 133
along an axis of the gas turbine engine 126. As illustrated, the
drive shaft 133 is connected to various components of the gas
turbine engine 126, including the compressor 134.
[0026] The drive shaft 133 may connect the turbine 132 to the
compressor 134 to form a rotor. The compressor 134 may include
blades coupled to the drive shaft 133. Thus, rotation of turbine
blades in the turbine 132 may cause the drive shaft 133 connecting
the turbine 132 to the compressor 134 to rotate blades within the
compressor 134. This rotation of blades in the compressor 134
causes the compressor 134 to compress air received via an air
intake in the compressor 134. The compressed air may then be fed to
the combustor 125 and mixed with fuel and compressed nitrogen to
allow for higher efficiency combustion. Drive shaft 133 may also be
connected to a load 136, which may be a stationary load, such as an
electrical generator for producing electrical power, for example,
in a power plant. Indeed, the load 136 may be any suitable device
that is powered by the rotational output of the gas turbine engine
126.
[0027] The IGCC power plant 100 also may include a steam turbine
engine 138 and a heat recovery steam generation (HRSG) system 139.
The steam turbine engine 138 may drive a second load 140. The
second load 140 may also be an electrical generator for generating
electrical power. However, both the first and second loads 136, 140
may be other types of loads capable of being driven by the gas
turbine engine 126 and steam turbine engine 138. In addition,
although the gas turbine engine 126 and steam turbine engine 138
may drive separate loads 136 and 140, as shown in the illustrated
embodiment, the gas turbine engine 126 and steam turbine engine 138
may also be utilized in tandem to drive a single load via a single
shaft. The specific configuration of the steam turbine engine 138,
as well as the gas turbine engine 126, may be
implementation-specific and may include any combination of
sections.
[0028] The system 100 may also include the HRSG 139. Heated exhaust
gas from the gas turbine engine 126 may be transported into the
HRSG 139 and used to heat water and produce steam used to power the
steam turbine engine 138. Exhaust from, for example, a low-pressure
section of the steam turbine engine 138 may be directed into a
condenser 142. The condenser 142 may utilize the cooling tower 124
to exchange heated water for chilled water. The cooling tower 124
acts to provide cool water to the condenser 142 to aid in
condensing the steam transmitted to the condenser 142 from the
steam turbine engine 138. Condensate from the condenser 142 may, in
turn, be directed into the HRSG 139. Again, exhaust from the gas
turbine engine 126 may also be directed into the HRSG 139 to heat
the water from the condenser 142 and produce steam.
[0029] In combined cycle power plants such as IGCC power plant 100,
hot exhaust may flow from the gas turbine engine 126 and pass to
the HRSG 139, where it may be used to generate high-pressure,
high-temperature steam. The steam produced by the HRSG 139 may then
be passed through the steam turbine engine 138 for power
generation. In addition, the produced steam may also be supplied to
any other processes where steam may be used, such as to the
gasifier 106. The gas turbine engine 126 generation cycle is often
referred to as the "topping cycle," whereas the steam turbine
engine 126 generation cycle is often referred to as the "bottoming
cycle." By combining these two cycles as illustrated in FIG. 1, the
IGCC power plant 100 may lead to greater efficiencies in both
cycles. In particular, exhaust heat from the topping cycle may be
captured and used to generate steam for use in the bottoming
cycle.
[0030] FIG. 2 illustrates the compression system 118 in conjunction
with the VAC system 122 of the IGCC system 100. As illustrated,
compression system 118 may be a multi-stage compression system 118.
That is, the compression system 118 may include a first stage
compressor 144, a second stage compressor 146, and a liquid pump
148. The compressors 144 and 146 may operate in conjunction (e.g.,
in series) with the liquid pump 148 to compress the CO.sub.2
received from the CO.sub.2 extraction system (e.g., pre-combustion
or post-combustion extraction) to a level that facilitates
transmission to the CO.sub.2 sequestration system 119 and/or EOR
pipeline 120. The VAC system 122 is capable of using the chilled
water 155 to liquefy the CO.sub.2 at intermediate pressures and
then use the liquid pump 148 to raise the liquid CO.sub.2 to a
super critical pressure. Such a method is a more efficient way of
liquefying CO.sub.2 than, for example, when the chilled water 155
is not used. Because of the irreversibility during compression, the
exit temperature of the CO.sub.2 after compression increases. To
reduce this temperature increase, inter-cooling between the stages
of compression and/or the liquid pump may be desirable. Indeed, by
using VAC inter-cooling as detailed below, it may be possible to
more efficiently compress and liquefy the CO.sub.2.
[0031] The compression system 118 may include an intermediate
chilled water heat exchanger 152, and a final chilled water heat
exchanger 154 that may receive a coolant through a chilled
temperature coolant path 155. The compression system 118 may also
include an intermediate heated water heat exchanger 156, and a
final heated water heat exchanger 158 that may receive a coolant
through a heated temperature coolant path 159. Collectively, the
chilled water heat exchangers 152, 154 and the heated water heat
exchangers 156, 158 may be utilized to reduce the temperature of
the CO.sub.2 flowing through a gas path 163 of the compression
system 118. It should be noted that instead of water, other
suitable liquids may be utilized in conjunction with the heat
exchangers 152, 154, 156, 158 as a coolant. An example of the
operation of the heat exchangers 152, 154, 156, 158 in conjunction
with the compressors 144, 146 and the liquid pump 148 will be
discussed below.
[0032] A CO.sub.2 flow from, for example, the carbon capture system
117 may be redirected to the first stage compressor 144. The
CO.sub.2 flow may be at an inlet pressure of approximately 15 PSIA
to 40 PSIA and a temperature of between approximately 80.degree.
F.-120.degree. F. The first stage compressor 144 may compress the
CO.sub.2 to a pressure of approximately 200 PSIA-400 PSIA and a
temperature of approximately between 400.degree. F. to 600.degree.
F. To aid in reducing the temperature of the CO.sub.2, so that the
second stage compressor 146 may expend less energy in compressing
the CO.sub.2, the CO.sub.2 may pass through the intermediate heated
water heat exchanger 156.
[0033] The intermediate heated water heat exchanger 156 may receive
heated water from a generator 164, e.g. a heat exchanger, of the
VAC system 122. The water may be at a temperature of approximately
90.degree. F.-200.degree. F. The heated water may pass through the
intermediate heated water heat exchanger 156, through a conduit
(e.g., coolant path 159), such as a tube. This coolant path 159 may
contact the CO.sub.2 as it passes through the intermediate heated
water heat exchanger 156, thus reducing the temperature of the
CO.sub.2 from, for example, approximately 400.degree.
F.-600.degree. F., to approximately 100.degree. F.-to 300.degree.
F., while increasing the temperature of the heated water to, for
example, approximately 150.degree. F.-250.degree. F. Subsequent to
passing through the intermediate heated water heat exchanger 156,
the CO.sub.2 may be passed to the intermediate chilled water heat
exchanger 152, so as to come into contact with a conduit (e.g.,
coolant path 155), containing chilled water. The chilled water may
be transmitted from an evaporator 160 of the VAC system 122 via a
pump 162 to the final chilled water heat exchanger 154 and then
subsequently to the intermediate chilled water heat exchanger 152.
The CO.sub.2 may contact the conduit carrying the chilled water as
it passes through the intermediate chilled water heat exchanger
152, thus reducing the temperature of the CO.sub.2, for example, to
approximately 60.degree. F.-100.degree. F., while increasing the
temperature of the chilled water to approximately 50.degree.
F.-80.degree. F.
[0034] The CO.sub.2 may then pass to the second stage compressor
146. The CO.sub.2 entering the second stage compressor 146 may be
at a temperature of approximately 60.degree. F.-100.degree. F. and
at a pressure of approximately 200 PSIA-400 PSIA. The second stage
compressor 146 may compress the CO.sub.2 to approximately 550
PSIA-950 PSIA. However, in compressing the CO.sub.2, the
temperature of the CO.sub.2 may also increase from, for example,
approximately 60.degree. F.-100.degree. F. to approximately
150.degree. F.-350.degree. F. Again, to aid in reducing the
temperature of the CO.sub.2 such that it may be condensed or
liquefied at a more reduced pressure, and so that the liquid pump
148 may expend less energy for raising the liquid CO.sub.2 to
supercritical stage, the CO.sub.2 may pass through the final heated
water heat exchanger 158.
[0035] The final heated water heat exchanger 158 may receive heated
water from the intermediate heated water heat exchanger 156. The
water may be at a temperature of approximately 90.degree.
F.-250.degree. F. The heated water may pass through the final
heated water heat exchanger 158, through a conduit, such as a tube.
This conduit may contact the CO.sub.2 as it passes through the
final heated water heat exchanger 158, thus reducing the
temperature of the CO.sub.2 from, for example, approximately
150.degree. F.-350.degree. F. to approximately 100.degree.
F.-300.degree. F., while increasing the temperature of the heated
water. The heated water may then be transmitted to the generator
164 of the VAC system 122 via a pump 166. Subsequent to passing
through the final heated water heat exchanger 158, the CO.sub.2 may
be passed to the final chilled water heat exchanger 154, so as to
come into contact with a conduit containing chilled water. Chilled
water may be transmitted from the evaporator 160 of the VAC system
122 via the pump 162 to the final chilled water heat exchanger 154.
The chilled water may be, for example, at approximately 20.degree.
F.-50.degree. F. The chilled water may pass through the final
chilled water heat exchanger 154, through a conduit, such as a
tube. The CO.sub.2 may contact the conduit carrying the chilled
water as it passes through the final chilled water heat exchanger
154, thus reducing the temperature of the CO.sub.2 from, for
example, approximately 100.degree. F.-300.degree. F. to
approximately 25.degree. F.-75.degree. F., while increasing the
temperature of the chilled water from approximately 20.degree.
F.-50.degree. F. to approximately 40.degree. F.-70.degree. F.
Indeed, the temperature of the CO.sub.2 in the gas path 163 after
the chilled water heat exchanger 154 may be set such that all
gaseous CO.sub.2 becomes condensed or liquefied.
[0036] The liquefied CO.sub.2 may then pass to the liquid pump 148.
The CO.sub.2 entering the liquid pump 148 may be at a temperature
of approximately 25.degree. F.-75.degree. F. and at a pressure of
approximately 550 PSIA-950 PSIA. The liquid pump 148 may further
compress the CO.sub.2 to super critical pressure. Accordingly,
CO.sub.2 exiting the liquid pump 148 may be at a pressure of
upwards of approximately 2215 PSIA at a temperature of upwards of
approximately 60.degree. F. At this pressure, the compressed
CO.sub.2 may be introduced into, for example the carbon
sequestration system 119 and/or the EOR pipeline 120. The flow of
chilled and warm water through the compression system 118 above may
be supplied by the VAC system 122, increasing compression and
liquefaction efficiency. Accordingly, FIG. 3 illustrates the
operation of a VAC system 122.
[0037] FIG. 3 illustrates an embodiment of VAC system 122. Heat
from, for example, the heat exchangers 156 and 158 of FIG. 2, may
operate as waste heat sources to provide hot water or steam that
may be used to power the VAC system 122. The use of waste heat is
advantageous because heat that may have otherwise have been wasted
or cast off is used to aid in compression activities. Accordingly,
the VAC system 122 may include an evaporator 160, a generator 164,
an absorber 168, and a condenser 170. The evaporator 160 may be
kept at low pressure, for example, at a pressure approximately near
a vacuum. The low-pressure of the evaporator 160 may cause a
refrigerant, such as NH.sub.3 (ammonia), to boil at very low
temperatures. As illustrated, the evaporator 160 includes a heat
exchanger 161 to exchange heat with the compression system 118 via
heat exchangers 152 and 154. In particular, heat exchangers 152 and
154 remove heat from the compression system 118, and the heat
exchanger 161 adds heat to the evaporator 160. The evaporator 160
may also take heat from the surroundings of the evaporator 160.
Because of this heat transfer, the refrigerant may be converted
into vapor which may flow into the absorber 168. The absorber 168
may combine the refrigerant vapor with water. In addition, the
absorber 168 cools and condenses the refrigerant vapor and water
via a heat exchanger 169 that circulates a coolant (e.g., water)
with cooling tower 124. The water, rich with refrigerant, may then
be pumped via an absorbent pump 172 to the generator 164.
[0038] In the generator 164, heat may be transferred to the
refrigerant rich liquid by an external heat source, such as hot
water or steam from the compression system 118 (e.g., heat
exchangers 156 and 158). In particular, the generator 164 has a
heat exchanger 165 to receive heat from the heat exchangers 156 and
158 in the compression system 118. The heat from the hot water or
steam may boil the refrigerant off from the refrigerant rich
liquid. The hot and refrigerant lean liquid then may return back to
the absorber 168, where heat may be removed by cooling water flow
from cooling tower 124. The refrigerant vapor from the generator
164 may be transmitted to the condenser 170, where the refrigerant
vapor may be converted into liquid by exchanging heat with cooling
water from the cooling tower 124. In particular, the condenser 170
has a heat exchanger 171 to remove heat via circulation of water
with the cooling tower 124. The cooled refrigerant may then
returned to the low-pressure evaporator 160, where it takes heat
from the water from the compression system 118, thus completing a
VAC thermodynamic cycle. The VAC thermodynamic cycle may be able to
capture heat from the compression activities and reuse the heat to
create a chilling effect to cool the CO.sub.2 flow, thus more
efficiently compressing the CO.sub.2.
[0039] FIG. 4 illustrates an embodiment of an N-stage compression
system 118 in conjunction with the VAC system 122 of the IGCC
system 100. As illustrated, the compression system 118 may be a
multi-stage compression system 118. That is, the compression system
118 may include a first stage compressor 144, a final stage
compressor 148, and multiple intermediate stages (e.g., 2, 3, 4, 5,
6, 7, 8, 9, 10, or more) each stage including a compressor 146.
These compressors 144, 146, 148 may operate in conjunction (e.g.,
in series) with the liquid pump 148 to compress and liquefy the
CO.sub.2 received from the carbon capture system 117 to a level
that is easily transported and stored. The compression system 118
may include an inlet chilled water heat exchanger 174, a final
chilled water heat exchanger 154, and multiple intermediate chilled
water heat exchangers 152, for example, one or more per each of the
multiple intermediate stages including an intermediate compressor
146. The chilled water heat exchangers 152, 154, 174 may receive a
coolant through the chilled temperature coolant path 155.
Collectively, the chilled water heat exchangers 152, 154, 174 and
the heated water heat exchangers 156, 158 may be utilized to reduce
the temperature of the CO.sub.2 flowing through the gas path 163 of
the compression system 118. The compression system 118 may also
include a final heated water heat exchanger 158 and multiple
intermediate heated water heat exchangers 156, one or more per each
of the multiple intermediate stages including an intermediate
compressor 146, as described below. The heated water heat
exchangers 152, 154, 174 may receive a coolant through the heated
temperature coolant path 159.
[0040] Chilled water may be transmitted from the evaporator 160 of
the VAC system 122 via the pump 162 to the inlet chilled water heat
exchanger 174. The chilled water may pass through the inlet chilled
water heat exchanger 174, through a conduit (e.g., coolant path
155), such as a tube. This conduit may contact the CO.sub.2 as it
passes through the inlet chilled water heat exchanger 174, thus
reducing the temperature of the CO.sub.2 while increasing the
temperature of the chilled water. The CO.sub.2 may then pass to the
first stage compressor 144. The first stage compressor 144 may
compress the CO.sub.2. However, in compressing the CO.sub.2, the
temperature of the CO.sub.2 may also increase. To aid in reducing
the temperature of the CO.sub.2, so that the intermediate
compressor 146 may expend less energy in compressing the CO.sub.2,
the CO.sub.2 may pass through the intermediate heated water heat
exchanger 156.
[0041] The intermediate heated water heat exchanger 156 may receive
heated water from the generator 164, e.g. a heat exchanger, of the
VAC system 122. The heated water may pass through the intermediate
heated water heat exchanger 156, through a conduit, such as a tube.
This conduit may contact the CO.sub.2 as it passes through the
intermediate heated water heat exchanger 156, thus reducing the
temperature of the CO.sub.2 while increasing the temperature of the
heated water. The temperate of the CO.sub.2 is reduced because the
heated water may be cooler than the CO.sub.2. Subsequent to passing
through the intermediate heated water heat exchanger 156, the
CO.sub.2 may be passed to the intermediate chilled water heat
exchanger 152, so as to come into contact with a conduit containing
chilled water. The CO.sub.2 may contact the conduit carrying the
chilled water as it passes through the intermediate chilled water
heat exchanger 152, thus reducing the temperature of the CO.sub.2
while increasing the temperature of the chilled water.
[0042] The CO.sub.2 may then pass to the intermediate compressor
146. The intermediate compressor 146 may compress the CO.sub.2.
However, in compressing the CO.sub.2, the temperature of the
CO.sub.2 may also increase. To aid in reducing the temperature of
the CO.sub.2, so that the next compressor stage may expend less
energy in compressing the CO.sub.2, the CO.sub.2 may pass through a
final heated water heat exchanger 158. The final heated water heat
exchanger 158 may receive heated water from the intermediate heated
water heat exchanger 156. The heated water may pass through the
final heated water heat exchanger 158, through a conduit, such as a
tube. This conduit may contact the CO.sub.2 as it passes through
the final heated water heat exchanger 158, thus reducing the
temperature of the CO.sub.2, while increasing the temperature of
the heated water. The heated water may then be transmitted to the
generator 164 of the VAC system 122 via a pump 166. Subsequent to
passing through the final heated water heat exchanger 158, the
CO.sub.2 may be passed to the final chilled water heat exchanger
154, so as to come into contact with a conduit containing chilled
water. The CO.sub.2 may contact the conduit carrying the chilled
water as it passes through the final chilled water heat exchanger
154, thus reducing the temperature of the CO.sub.2, while
increasing the temperature of the chilled water. The CO.sub.2 may
then pass to the liquid pump 148. The liquid pump 148 may compress
the CO.sub.2 to super critical state. Consequently, the liquefied
CO.sub.2 may be more easily transported and stored, through, for
example, the use of liquid pumps and liquid conduits.
[0043] Collectively, the chilled water heat exchangers 152, 154,
174 and the heated water heat exchangers 156, 158 may be utilized
to reduce the temperature of the CO.sub.2 flowing through the
compression system 118. In this manner, each stage of a N-stage
compression system 118 may include corresponding heat exchangers
designed to cool the CO.sub.2 gas flowing through the various
compressors corresponding to a given compression stage.
[0044] Technical effects of the invention include the ability to
capture and employ waste heat to efficiently compress a carbonous
gas, e.g., CO.sub.2. Vapor absorption chiller (VAC) systems may be
utilized to reclaim heat generated during compression activities.
The reclaimed heat may be further utilized to drive a thermodynamic
cycle that can result in cooling of the CO.sub.2 flow at a reduced
pressure such that it becomes liquid, thus allowing for enhanced
efficiencies of CO.sub.2 compression in reaching the super-critical
state. Indeed, by combining vapor chiller systems with liquid
compressors it may be possible to substantially reduce the amount
of energy expended in reaching a liquid phase of the carbonous gas,
increasing efficiency and reducing cost. The liquefied CO.sub.2 may
be more efficiently transported and stored. Accordingly, more
efficient and less costly liquid conduits and liquid pumps may be
used to transport the CO.sub.2 for storage and use, for example, in
oil recovery activities.
[0045] This written description uses examples to disclose the
invention, including the best mode, and also to enable any person
skilled in the art to practice the invention, including making and
using any devices or systems and performing any incorporated
methods. The patentable scope of the invention is defined by the
claims, and may include other examples that occur to those skilled
in the art. Such other examples are intended to be within the scope
of the claims if they have structural elements that do not differ
from the literal language of the claims, or if they include
equivalent structural elements with insubstantial differences from
the literal languages of the claims.
* * * * *