U.S. patent application number 12/524177 was filed with the patent office on 2010-07-01 for process for reducing carbon dioxide emission in a power plant.
This patent application is currently assigned to SHELL INTERNATIONALE RESEARCH MAATSCHAPPIJ B.V.. Invention is credited to Kuei-Jung Li, Georgios Protopapas.
Application Number | 20100162703 12/524177 |
Document ID | / |
Family ID | 38110448 |
Filed Date | 2010-07-01 |
United States Patent
Application |
20100162703 |
Kind Code |
A1 |
Li; Kuei-Jung ; et
al. |
July 1, 2010 |
PROCESS FOR REDUCING CARBON DIOXIDE EMISSION IN A POWER PLANT
Abstract
A process for reducing CO.sub.2 emission in a power plant,
wherein the power plant comprises at least one gas turbine coupled
to a heat recovery steam generator unit and the CO.sub.2 capture
unit comprises an absorber and a regenerator, the process
comprising the steps of: (a) introducing hot exhaust gas exiting a
gas turbine having a certain elevated pressure into a heat recovery
steam generator unit to produce steam and a flue gas stream
comprising carbon dioxide; (b) removing carbon dioxide from the
flue gas stream comprising carbon dioxide by contacting the flue
gas stream with absorbing liquid in an absorber having an elevated
operating pressure to obtain absorbing liquid enriched in carbon
dioxide and a purified flue gas stream, wherein the settings and/or
construction of the gas turbine are adjusted such that the hot
exhaust gas exiting the gas turbine has a pressure of at least 40%
of the elevated operating pressure of the absorber.
Inventors: |
Li; Kuei-Jung; (San
Francisco, CA) ; Protopapas; Georgios; (Amsterdam,
NL) |
Correspondence
Address: |
SHELL OIL COMPANY
P O BOX 2463
HOUSTON
TX
772522463
US
|
Assignee: |
SHELL INTERNATIONALE RESEARCH
MAATSCHAPPIJ B.V.
The Hague
NL
|
Family ID: |
38110448 |
Appl. No.: |
12/524177 |
Filed: |
January 23, 2008 |
PCT Filed: |
January 23, 2008 |
PCT NO: |
PCT/EP2008/050735 |
371 Date: |
March 5, 2010 |
Current U.S.
Class: |
60/670 ;
60/689 |
Current CPC
Class: |
Y02C 10/04 20130101;
B01D 2252/204 20130101; B01D 53/1425 20130101; Y02A 50/20 20180101;
Y02E 20/326 20130101; B01D 53/62 20130101; F05D 2230/50 20130101;
Y02A 50/2342 20180101; Y02C 20/40 20200801; Y02E 20/32 20130101;
B01D 2257/504 20130101; F01K 23/10 20130101; F05D 2270/301
20130101; F02C 9/00 20130101 |
Class at
Publication: |
60/670 ;
60/689 |
International
Class: |
F01K 23/06 20060101
F01K023/06; F01D 5/08 20060101 F01D005/08 |
Foreign Application Data
Date |
Code |
Application Number |
Jan 25, 2007 |
EP |
07101148.0 |
Claims
1. A process for reducing CO.sub.2 emission in a power plant, the
process comprising the steps of: (a) introducing a hot exhaust gas
exiting a gas turbine having a certain elevated pressure into a
heat recovery steam generator unit to produce steam and a flue gas
stream comprising carbon dioxide; (b) removing carbon dioxide from
the flue gas stream comprising carbon dioxide by contacting the
flue gas stream with an absorbing liquid in an absorber having an
elevated operating pressure in the range of from 50 to 200 mbarg to
obtain an absorbing liquid enriched in carbon dioxide and a
purified flue gas stream, wherein the settings and/or construction
of the gas turbine are adjusted such that the hot exhaust gas
exiting the gas turbine has a pressure of at least 40% of the
elevated operating pressure of the absorber.
2. A process according to claim 1, wherein the hot exhaust gas
exiting the gas turbine has a pressure of at least 50%, of the
elevated operating pressure of the absorber.
3. A process according to claim 2, wherein the elevated operation
pressure of the absorber is in the range of from 70 to 150
mbarg.
4. A process according to claim 3, further comprising the step of:
(c) regenerating the absorbing liquid enriched in carbon dioxide by
contacting the absorbing liquid enriched in carbon dioxide with a
stripping gas at elevated temperature in a regenerator to obtain a
regenerated absorbing liquid and a gas stream enriched in carbon
dioxide.
5. A process according to claim 4, the process further comprising
the step of: (d) pressurising the gas stream enriched in carbon
dioxide using a carbon dioxide compressor, wherein a first part of
the steam produced in the heat recovery steam generator unit is
used to drive the carbon dioxide compressor.
6. A process according to claim 5, wherein an amount of fuel is
combusted in the heat recovery steam generator unit to produce an
additional amount of steam, wherein the amount of fuel combusted in
the heat recovery steam generator unit is such that the additional
amount of steam is sufficient to provide at least 80% of the heat
needed for the regeneration of the absorbing liquid.
7. A process according to claim 6, wherein at least part of the
steam produced in the heat recovery steam generator unit is high
pressure steam, having a pressure in the range of from 90 to 125
bara.
8. A process according to claim 7, wherein the pressurised gas
stream enriched in carbon dioxide is used for enhanced oil
recovery.
9. A process according to claim 8, wherein the absorbing liquid
comprises an amine, selected from the group consisting of
monethanolamine (MEA),diethanolamine (DEA), diglycolamine (DGA),
methyldiethanolamine (MDEA), triethanolamine (TEA),
N-ethyldiethanolamine (EDEA), N,N'-di(hydroxyalkyl)piperazine,
N,N,N',N'-tetrakis(hydroxyalkyl)-1,6-hexanediamine and tertiary
alkylamine sulfonic acid compounds.
10. A process according to claim 9, wherein the absorbing liquid
comprises a physical solvent or ammonia.
Description
[0001] The invention relates to a process for reducing carbon
dioxide (CO.sub.2) emission in a power plant.
[0002] A substantial portion of the world's energy supply is
provided by combustion of fuels, especially natural gas or
synthesis gas, in a power plant. Generally the fuel is combusted in
one or more gas turbines and the resulting gas is used to produce
steam. The steam is then used to generate power. Combustion of fuel
results in the production of CO.sub.2. During the last decades
there has been a substantial global increase in the amount of
CO.sub.2 emission to the atmosphere. Following the Kyoto agreement,
CO.sub.2 emission has to be reduced in order to prevent or
counteract unwanted changes in climate.
[0003] The CO.sub.2 concentration of a gas turbine flue gas depends
on the fuel and the combustion and heat recovery process applied
and is generally relatively low, typically in the range of 3-15%.
Thus, a reduction in the emission of CO.sub.2 makes it desirable to
separate the CO.sub.2 from the exhaust gas because it will be too
expensive to compress and deposit the whole flue gas stream. For
this reason, it is advantageous to use a dedicated CO.sub.2 capture
unit, to remove CO.sub.2 from the flue gas stream and thereby
generate a concentrated CO.sub.2 stream.
[0004] Such a process is described for example in EP 1,688,173,
wherein a process for carbon dioxide recovery and power generation
on an off-shore platform is described using a CO.sub.2 capture unit
with an absorber and a regenerator. Exhaust gas containing CO.sub.2
is pressurised using a blower prior to entering the absorber. The
need for this blower adds to the overall cost and operational
complexity of the process.
[0005] It has now been found that a more simplified process can be
achieved when a pressurised exhaust gas containing CO.sub.2 is
produced.
[0006] To this end, the invention provides a process for reducing
CO.sub.2 emission in a power plant, wherein the power plant
comprises at least one gas turbine coupled to a heat recovery steam
generator unit and the CO.sub.2 capture unit comprises an absorber
and a regenerator, the process comprising the steps of:
(a) introducing hot exhaust gas exiting a gas turbine having a
certain elevated pressure into a heat recovery steam generator unit
to produce steam and a flue gas stream comprising carbon dioxide;
(b) removing carbon dioxide from the flue gas stream comprising
carbon dioxide by contacting the flue gas stream with absorbing
liquid in an absorber having an elevated operating pressure to
obtain absorbing liquid enriched in carbon dioxide and a purified
flue gas stream, wherein the settings of the gas turbine are
adjusted such that the hot exhaust gas exiting the gas turbine has
a pressure of at least 40% of the elevated operating pressure of
the absorber.
[0007] In the process, a power plant comprising at least one gas
turbine is used. Typically, fuel and an oxygen-containing gas are
introduced into a combustion section of the gas turbine. In the
combustion section of the gas turbine, the fuel is combusted to
generate a hot combustion gas. The hot combustion gas is expanded
in the gas turbine, usually via a sequence of expander blades
arranged in rows, and used to generate power via a generator.
Suitable fuels to be combusted in the gas turbine include natural
gas and synthesis gas.
[0008] In step (a), hot exhaust gas exiting the gas turbine is
introduced into a heat recovery steam generator unit. The hot
exhaust gas exiting the gas turbine has a certain elevated
pressure. The pressure of the hot exhaust gas is determined by the
settings and/or construction of the gas turbine. For example,
usually the gas turbine comprises a sequence of expander blades
arranged in rows: by changing the number of expander blade rows,
the back pressure of the gas turbine can be increased, resulting in
a hot exhaust gas having an elevated pressure. In the process, the
settings and/or construction of the gas turbine are adjusted such,
that the hot exhaust gas exiting the gas turbine has a pressure of
at least 40% of the operating pressure of the absorber in the
CO.sub.2 capture unit. Preferably, the hot exhaust gas exiting the
gas turbine has a pressure of at least 50%, more preferably at
least 60%, still more preferably at least 70% of the elevated
operating pressure of the absorber.
[0009] One of the factors that determine the power output of the
gas turbine is the pressure difference between the inlet and the
outlet of the gas turbine. Without wishing to be bound by a
specific theory, it is assumed that a more substantial pressure
difference will result in a higher power output. A more substantial
pressure difference would normally mean that the inlet pressure of
the gas turbine will be high and the outlet pressure will be as
close to ambient as possible. In the process, the settings and/or
construction of the gas turbine are adjusted such that the outlet
pressure is purposely elevated, meaning that the outlet pressure is
above ambient pressure. As a result, the power output of the gas
turbine will be slightly less compared to a gas turbine having an
outlet pressure close to ambient pressure. It has been found that
in spite of a slightly lower power output of the gas turbine, the
overall process is still more favourable because the energy
requirements for the CO.sub.2 capture unit are significantly less.
The flue gas now needs little or no pressurising prior to entering
the absorber of the CO.sub.2 capture unit. Thus, expensive and
energy consuming equipment normally needed for the pressurisation
of the flue gas stream prior to entering the CO.sub.2 absorber can
now be dispensed with.
[0010] Preferably, the hot exhaust gas has a temperature in the
range of from 350 to 700.degree. C., more preferably from 400 to
650.degree. C. The composition of the hot exhaust gas can vary,
depending on the fuel gas combusted in the gas turbine and on the
conditions in the gas turbine. Generally, the hot exhaust gas
comprises in the range of from 10 to 15% of O.sub.2. Generally, the
hot exhaust gas comprises in the range of from 3 to 6% of
CO.sub.2.
[0011] The heat recovery steam generator unit is any unit providing
means for recovering heat from the hot exhaust gas and converting
this heat to steam. For example, the heat recovery steam generator
unit can comprise a plurality of tubes mounted stackwise. Water is
pumped and circulated trough the tubes and can be held under high
pressure at high temperatures. The hot exhaust gas heats up the
tubes and is used to produce steam. The heat recovery steam
generator unit can be designed to produce one, two or three types
of steam: high-pressure steam, intermediate pressure steam and
low-pressure steam.
[0012] Preferably, the steam generator is designed to produce at
least a certain amount of high-pressure steam, because
high-pressure steam can be used to generate power. Suitably,
high-pressure steam has a pressure in the range of from 90 to 150
bara, preferably from 90 to 125 bara, more preferably from 100 to
115 bara. Suitably, low-pressure steam is also produced, the
low-pressure steam preferably having a pressure in the range of
from 2 to 10 bara, more preferably from to 8 bara, still more
preferably from 4 to 6 bara. This low-pressure steam is used for
the regeneration of the absorbing liquid comprising CO.sub.2.
[0013] In a preferred embodiment, an amount of fuel is combusted in
the heat recovery steam generation unit to produce additional
steam. This embodiment offers the possibility of controlling the
amount and type of steam produced in the heat recovery steam
generator unit, by adjusting the amount of fuel added to the heat
recovery steam generator unit. Preferably, low pressure steam
piping is used to deliver the heating steam from the heat recovery
steam generator to the CO.sub.2 capture unit. Suitably, the low
pressure steam piping is arranged in a closed loop to segregate the
steam produced which is used for power production from steam used
in process heat exchangers.
[0014] The heat recovery steam generator unit emits a flue gas
comprising CO.sub.2. The composition of the flue gas depends among
others on the type of fuel used in the gas turbine. Suitably, the
flue gas comprises in the range of from 0.25 to 30% (v/v) of
CO.sub.2, preferably from 1 to 20% (v/v). The flue gas usually also
comprises oxygen, preferably in the range of from 0.25 to 20%
(v/v), more preferably from 5 to 15% (v/v), still more preferably
from 1 to 10% (v/v).
[0015] In step (b), CO.sub.2 is removed by contacting the flue gas
with an absorbing liquid at elevated pressure, suitably in an
absorber. Suitably, absorption takes place at relatively low
temperature and at elevated operating pressure. Elevated pressure
means that the operating pressure of the CO.sub.2 absorber is above
ambient pressure. Preferably, the operating pressure of the
absorber is in the range of from 50 to 200 mbarg, more preferably
from 70 to 150 mbarg. As the flue gas already has an elevated
pressure, the pressure difference between the flue gas pressure and
the operating pressure of the absorber is relatively small. Thus,
the flue gas does not need to be pressurised or needs to be
pressurised to a lesser extent prior to entering the absorber.
Given the large volume of flue gas to be pressurised, the use of a
smaller blower or elimination of the need for a blower altogether
will result in a considerable cost-saving for the overall process.
As the temperature of the flue gas will typically be relatively
high, preferably the flue gas is cooled prior to entering the
absorber.
[0016] The absorbing liquid may be any absorbing liquid capable of
removing CO.sub.2 from a flue gas stream, which flue gas stream
comprises oxygen and has a relatively low concentration of
CO.sub.2. Such absorbing liquids may include chemical and physical
solvents or combinations of these.
[0017] Suitable physical solvents include dimethylether compounds
of polyethylene glycol.
[0018] Suitable chemical solvents include ammonia and amine
compounds.
[0019] In one embodiment, the absorbing liquid comprises one or
more amines selected from the group of monethanolamine (MEA),
diethanolamine (DEA), diglycolamine (DGA), methyldiethanolamine
(MDEA) and triethanolamine (TEA). MEA is an especially preferred
amine, due to its ability to absorb a relatively high percentage of
CO.sub.2 (volume CO.sub.2 per volume MEA). Thus, an absorbing
liquid comprising MEA is suitable to remove CO.sub.2 from flue
gases having low concentrations of CO.sub.2, typically 3-10 volume
% CO.sub.2.
[0020] In another embodiment, the absorbing liquid comprises one or
more amines selected from the group of methyldiethanolamine (MDEA),
triethanolamine (TEA), N,N'-di(hydroxyalkyl)piperazine,
N,N,N',N'-tetrakis(hydroxyalkyl)-1,6-hexanediamine and tertiary
alkylamine sulfonic acid compounds.
[0021] Preferably, the N,N'-di(hydroxyalkyl)piperazine is
N,N'-d-(2-hydroxyethyl)piperazine and/or
N,N'di-(3-hydroxypropyl)piperazine.
[0022] Preferably, the tetrakis(hydroxyalkyl)-1,6-hexanediamine is
N,N,N',N'-tetrakis(2-hydroxyethyl)-1,6-hexanediamine and/or
N,N,N',N'-tetrakis(2-hydroxypropyl)-1,6-hexanediamine.
[0023] Preferably, the tertiary alkylamine sulfonic compounds are
selected from the group of
4-(2-hydroxyethyl)-1-piperazineethanesulfonic acid,
4-(2-hydroxyethyl)-1-piperazinepropanesulfonic acid,
4-(2-hydroxyethyl)piperazine-1-(2-hydroxypropanesulfonic acid) and
1,4-piperazinedi(sulfonic acid).
[0024] In yet another embodiment, the absorbing liquid comprises
N-ethyldiethanolamine (EDEA).
[0025] In an especially preferred embodiment, the absorbing liquid
comprises ammonia.
[0026] In the event that the flue gas stream comprises an
appreciable quantity of oxygen, suitably in the range of from 1 to
20% (v/v) of oxygen, preferably a corrosion inhibitor is added to
the absorbing liquid. Suitable corrosion inhibitors are described
for example in U.S. Pat. No. 6,036,888.
[0027] In most cases it will be desirable to have a continuous
process, including regeneration of the absorbing liquid. Thus,
preferably the process further comprises a step (c) of regenerating
the absorbing liquid enriched in carbon dioxide by contacting the
absorbing liquid enriched in carbon dioxide with a stripping gas at
elevated temperature in a regenerator to obtain regenerated
absorbing liquid and a gas stream enriched in carbon dioxide. It
will be understood that the conditions used for regeneration depend
inter alia on the type of absorbing liquid and on the conditions
used in the absorption step. Suitably, regeneration takes place at
a different temperature and/or different pressure than the
absorption.
[0028] In the event that the absorbing liquid comprises an amine,
preferred regeneration temperatures are in the range of from 100 to
200.degree. C. In the event that the absorbing liquid comprises an
aqueous amine, regeneration preferably takes place at pressure in
the range of from 1 to 5 bara.
[0029] In the event that the absorbing liquid comprises ammonia,
suitably the absorbing step is performed at temperatures below
ambient temperature, preferably in the range of from 0 to
10.degree. C., more preferably from 2 to 8.degree. C. The
regeneration step is suitably performed at temperatures higher than
used in the absorption step. When using an absorbing liquid
comprising ammonia, the CO.sub.2-enriched gas stream exiting the
regenerator has a elevated pressure. Suitably, the pressure of the
CO.sub.2-enriched gas stream is in the range of from 5 to 8 bara,
preferably from 6 to 8 bara. In applications where the
CO.sub.2-enriched gas stream needs to be at a high pressure, for
example when it will be used for injection into a subterranean
formation, it is an advantage that the CO.sub.2-enriched gas stream
is already at an elevated pressure. Normally, a series of
compressors is needed to pressurise the CO.sub.2-enriched gas
stream to the desired high pressures. A CO.sub.2-enriched gas
stream which is already at elevated pressure is easier to further
pressurise.
[0030] Optionally, the process further comprises a step (d) of
combusting an amount of fuel in the heat recovery steam generation
unit to produce additional steam. Preferably, the heat requirements
of the regeneration step are at least partly fulfilled using the
additional amount of steam. The amount of fuel combusted is
preferably such that the additional amount of steam is sufficient
to provide at least 80%, more preferably at least 90%, still more
preferably at least 95%, and most preferably 100% of the heat
needed for the regeneration of the absorbing liquid.
[0031] A preferred way of performing of step (d) is to monitor the
power generated by the heat recovery steam generator unit and
adjust the amount of fuel introduced into the heat recovery steam
generator unit in dependence of the amount of power. As explained
earlier, in the heat recovery steam generator unit preferably high
pressure steam is produced in a steam turbine, which high pressure
steam is converted to power, for example via a generator coupled to
the steam turbine. The power output of the generator coupled to the
steam turbine will decrease when the CO.sub.2 capture unit is in
operation, due to the amount of steam extracted from the heat
recovery steam generator unit needed to heat up the regenerator of
the CO.sub.2 capture unit. By monitoring the output of generator
coupled to the steam turbine of the heat recovery generator unit,
the amount of fuel combusted in the heat recovery steam generator
unit can be adjusted. In the event that the output decreases, the
amount of fuel combusted can be increased. Preferably, the amount
of fuel to be combusted in order to enable fulfilling the heat
requirements of the regenerator of the CO.sub.2 capture unit
without significantly diminishing the power output of the generator
coupled to the steam turbine is predetermined. The power output of
the generator coupled to the steam turbine when the CO.sub.2
capture unit is not in operation is taken as a base case and the
amount of fuel to be combusted in order to achieve the same output
is then determined.
[0032] Suitable fuels to be combusted in the heat recovery steam
generator unit include natural gas and synthesis gas.
[0033] Combustion of the amount of fuel in step (d) requires the
presence of oxygen. This oxygen can be supplied to the heat
recovery steam generator unit, but preferably the hot exhaust gas
comprises oxygen and at least part of this oxygen is used in the
combustion of the fuel in step (d). As a result of using oxygen
from the hot exhaust gas, the amount of oxygen in the flue gas
exiting the heat recovery steam generator unit will be lower. This
is favourable for the CO.sub.2 absorption process, especially when
an amine absorbing liquid is used. Oxygen can cause amine
degradation and can lead to the formation of degradation products
in the absorbing liquid. A lower oxygen content of the flue gas
will therefore result in less amine degradation and less formation
of degradation products.
[0034] Preferably, the gas stream enriched in carbon dioxide is
pressurised using a carbon dioxide compressor to produce a
pressurised carbon dioxide stream. The carbon dioxide compressor
needs to be driven. An elegant heat integration is achieved when
part of the steam produced in the heat recovery steam generator
unit is used to drive the carbon dioxide compressor.
[0035] Preferably, the pressurised CO.sub.2 stream has a pressure
in the range of from 40 to 300 bara, more preferably from 50 to 300
bara. A CO.sub.2 stream having a pressure in these preferred ranges
can be used for many purposes, in particular for enhanced recovery
of oil, coal bed methane or for sequestration in a subterranean
formation. Especially for purposes wherein the pressurised CO.sub.2
stream is injected into a subterranean formation, high pressures
are required. In a preferred embodiment, the pressurised CO.sub.2
stream is used for enhanced oil recovery. By injecting CO.sub.2
into an oil reservoir, the oil recovery rate can be increased.
Typically, the pressurised CO.sub.2 stream is injected into the oil
reservoir, where it will be mixed with some of the oil which is
present. The mixture of CO.sub.2 and oil will displace oil which
cannot be displaced by traditional injections.
[0036] The invention will now be illustrated, by means of example
only, with reference to the accompanying FIG. 1.
[0037] In FIG. 1, a power plant comprising a gas turbine (1), a
heat recovery steam generator unit (2) and a CO.sub.2 capture unit
(3) is shown. In the gas turbine, an oxygen-containing gas is
supplied via line 4 to compressor 5. Fuel is supplied via line 6 to
combustor 7 and combusted in the presence of the compressed
oxygen-containing gas. The resulting combustion gas is expanded in
expander 8 and used to generate power in generator 9. Remaining
exhaust gas comprising CO.sub.2 and oxygen is led via line 10 to a
heat recovery steam generator unit 2. In the heat recovery steam
generator unit, water is heated against the hot exhaust gas in
heating section 11 to generate steam. The steam is led via line 12
into a steam turbine 13 to produce additional power in generator
14. Optionally, an amount of fuel is led via line 15 to the heat
recovery steam generator unit and combusted, using oxygen from the
exhaust gas, to produce additional steam. Hot flue gas comprising
CO.sub.2 and oxygen and having an increased pressure is led via
line 16 to an amine absorber 17. Preferably, the hot flue gas is
first cooled in a cooler (not shown). In amine absorber 17,
CO.sub.2 is transferred at from the flue gas to the amine liquid
contained in the amine absorber. Purified flue gas, depleted in
carbon dioxide, is led from the amine absorber via line 18. Amine
liquid, enriched in CO.sub.2 is led from the amine absorber via
line 19 to a regenerator 20. In the regenerator, amine liquid
enriched in CO.sub.2 is depressurised and contacted with a
stripping gas at elevated temperature, thereby transferring
CO.sub.2 from the amine liquid to the stripping gas to obtain
regenerated amine liquid and a gas stream enriched in CO.sub.2. The
gas stream enriched in CO.sub.2 is led from the regenerator via
line 21. Preferably, the gas stream enriched in CO.sub.2 is
pressurised using a CO.sub.2 compressor (not shown) and the
pressurised CO.sub.2 stream is used elsewhere. Regenerated amine
liquid is led from the regenerator via line 22 to the amine
absorber. The heat needed to provide the elevated temperature of
the regenerator is supplied using low pressure steam, which is led
from steam turbine 13 via line 23 to the regenerator.
* * * * *