U.S. patent application number 15/310909 was filed with the patent office on 2017-03-30 for power plant with zero emissions.
This patent application is currently assigned to AKER SOLUTIONS AS. The applicant listed for this patent is AKER SOLUTIONS AS. Invention is credited to Geir Inge OLSEN, Tom-Arne SOLHAUG, Kjell Olav STINESSEN.
Application Number | 20170089574 15/310909 |
Document ID | / |
Family ID | 53189797 |
Filed Date | 2017-03-30 |
United States Patent
Application |
20170089574 |
Kind Code |
A1 |
STINESSEN; Kjell Olav ; et
al. |
March 30, 2017 |
POWER PLANT WITH ZERO EMISSIONS
Abstract
A method for generation of electrical power and/or steam or
vapour, by combustion of carbonaceous fuels, where carbonaceous
fuel is combusted in a combustion chamber at a pressure of 40 to
200 bar in the presence of oxygen enriched air or substantially
pure oxygen to produce electrical power and/or to generate steam
from fluids circulating in steam tubes arranged inside the
combustion chamber, and a flue gas, where the flue gas is withdrawn
from the combustion chamber and is cooled to a temperature that
results in condensation of the flue gas, or conversion of the flue
gas to a supercritical fluid having a density of at least 600
kg/m.sup.3, and where the liquid or supercritical fluid formed, is
safely deposited, and a plant for carrying out the method, are
described.
Inventors: |
STINESSEN; Kjell Olav;
(Oslo, NO) ; OLSEN; Geir Inge; (Oslo, NO) ;
SOLHAUG; Tom-Arne; (Vollen, NO) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
AKER SOLUTIONS AS |
Lysaker |
|
NO |
|
|
Assignee: |
AKER SOLUTIONS AS
Lysaker
NO
|
Family ID: |
53189797 |
Appl. No.: |
15/310909 |
Filed: |
May 11, 2015 |
PCT Filed: |
May 11, 2015 |
PCT NO: |
PCT/EP2015/060350 |
371 Date: |
November 14, 2016 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
Y02E 20/30 20130101;
F23J 2900/15061 20130101; F23L 7/007 20130101; Y02E 20/363
20130101; Y02E 20/344 20130101; F23J 15/06 20130101; F23J 2215/50
20130101; Y02E 20/34 20130101 |
International
Class: |
F23J 15/06 20060101
F23J015/06; F23L 7/00 20060101 F23L007/00 |
Foreign Application Data
Date |
Code |
Application Number |
May 13, 2014 |
NO |
20140605 |
Claims
1. A method for generation of electrical power and/or steam or
vapour, by combustion of carbonaceous fuels, where carbonaceous
fuel is combusted in a combustion chamber at a pressure of 40 to
200 bar in the presence of oxygen enriched air or substantially
pure oxygen to produce electrical power and/or to generate steam
from fluids circulating in steam tubes arranged inside the
combustion chamber, and a flue gas, where the flue gas is withdrawn
from the combustion chamber and is cooled to a temperature that
according to the plots in FIG. 1 result in condensation of the flue
gas, or conversion of the flue gas to a supercritical fluid having
a density of at least 600 kg/m.sup.3, and where the liquid or
supercritical fluid formed, is safely deposited.
2. The method of claim 1, wherein the flue gas is cooled to a
temperature of 40 .degree. C. or lower, such as 30.degree. C. or
lower, such as 20 .degree. C. or lower, or 10 .degree. C. or
lower.
3. The method claim 1, wherein the cooling is performed in two or
more steps, where water present in the flue gas is condensed and
separated from the remaining flue gas, and where the remaining flue
gas thereafter is further cooled for condensing of CO.sub.2 or
conversion of the CO.sub.2 to a supercritical fluid.
4. The method of claim 1, wherein CO.sub.2 and water is condensed
together to give a mixed fluid and/or supercritical fluid.
5. The method according to claim 1, wherein the combustion chamber
is a boiler for generation of steam or vapour, and where the steam
or vapour is used to produce electrical power in a steam power
plant.
6. The method of claim 1, wherein the combustion is an oxidation in
a fuel cell to generate electrical power.
7. The method of claim 1, wherein the carbonaceous fuel is natural
gas and/or gas condensate, and where the natural gas and/or gas
condensate is introduced at the production pressure, or is expanded
to the pressure in the combustion chamber if the production
pressure is higher than the pressure of the combustion.
8. The method of claim 1, wherein the carbonaceous fuel is
methane-hydrate.
9. The method according to claim 1, wherein the supercritical fluid
or condensed CO.sub.2 or mixture of CO.sub.2 and H.sub.2O, is
deposited by injection into a sub-terrain formation such as an
aquifer, an abandoned oil or gas well, or into an oil well for
enhanced oil recovery.
10. A plant for generation of electrical power and capturing of
CO.sub.2, the plant comprising a source for substantially pure
oxygen or oxygen enriched air to a combustion chamber for
combustion of carbonaceous fuel at a pressure of 40 bar or more,
where steam tubes are arranged in the combustion chamber for
cooling the combustion gases in the combustion chamber by
generation of steam or vapour from a fluid circulating in the steam
tubes, a flue line for withdrawal of flue gas from the combustion
chamber and for introduction of the flue gas into a condenser in
which the flue gas is cooled for condensing of, or forming a
supercritical fluid having a density of at least 600 kg/m.sup.3, of
CO.sub.2 and any H.sub.2O, present in the flue gas, and a CO.sub.2
withdrawal line for withdrawal of condensed liquid or supercritical
fluid from the condenser.
11. The plant according to claim 10, wherein the combustion chamber
is boiler for generation of steam, or a fuel cell.
12. The plant according to claim 1, wherein the plant comprises
different modules like combustion module, boiler module, heat
exchanger module, turbine module, pump module, compressor module,
that all may be isolated from the remaining plant for maintenance
and repair, or for exchanging one module with a spare module.
13. The plant according to claim 12, wherein redundant modules is
arranged in parallel for redundancy.
Description
TECHNICAL FIELD
[0001] The present invention relates a method for generation of
power plant with CO.sub.2 capture, where electrical power and/or
steam is/are produced from combustion of carbonaceous fuel, and to
a plant for carrying out the method. More specifically the present
invention relates to a method and plant where the carbonaceous fuel
is combusted at an elevated pressure using oxygen enriched air or
substantially pure oxygen as oxidant, and where CO.sub.2 is
captured by cooling the exhaust gas from the combustion at an
elevated pressure to produce liquid or supercritical CO.sub.2.
BACKGROUND ART
[0002] Many of the oil and /or gas reservoirs are relatively small,
but the total amount of oil and gas in such reservoirs is
substantial. At remote locations, such as at offshore locations,
the start-up and running cost today are too high to start
production. Additionally, large volumes of natural gas, produced as
associated gas is separated from the oil and is re-injected into
the reservoir as pressure support as the cost for transporting the
gas to the marked is too high.
[0003] Infrastructure such as pipelines, or loading facilities for
loading tank vessels, including necessary pre-processing, or a LNG
plant, is often a limiting factor for subsea production of oil and
gas, and most specifically natural gas and gas-condensate.
[0004] If no infrastructure for transport of the natural gas is
present where subterrain natural gas is found, and the natural gas
source is too small to build a new infrastructure, the natural gas
may be characterized as "stranded gas", and any wellbores will be
sealed and the site closed. Additionally, the pressure of the
produced gas is reduced with time, and compression is necessary to
keep the production at a profitable level, also resulting in either
added cost or abandoning the gas production.
[0005] To reduce the capital costs, large amounts of stranded gas
are known but never exploited as setting up pipelines or an LNG
plant to transport the gas by ships are too expensive given the
price of natural gas at the worlds marked. Natural gas associated
with, and produced together with oil, is in many cases, compressed
and re-injected into the gas and oil field to maintain the pressure
therein, and to avoid the need for expensive handling of the
natural gas. Stranded gas is a substantial energy source that may
be exploited e.g. by production of electrical energy, in addition
to heat as steam, for local use at an oil and gas field, or for
production of electrical energy for export from an oil or gas
field.
[0006] In the present situation with the discussion of global
heating and emission of CO.sub.2, the authorities in most countries
would be reluctant to, or even not allow construction of an
offshore power plant. This is due to the CO.sub.2 emission from
such a plant, as all combustion of carbonaceous fuels results in
production of CO.sub.2 that if released into the atmosphere will
contribute to the increase in CO.sub.2 concentration in the
atmosphere. However, CO.sub.2 if captured from any source, such as
from exhaust gas from combustion, is of high value if injected into
an oil well, for avoiding that the pressure in the oil well drops
below a level where oil production becomes low and difficult of
expense to produce.
[0007] In Norway, the authorities has decided to ban the present
practice with local gas turbine based power plants on offshore oil
and/or gas fields, and plans are being made for electrification of
some fields, i.e. building power lines to transport electricity
from shore to offshore oil and gas fields to reduce the CO.sub.2
footprint of such fields.
[0008] Offshore power production for delivery of electricity to
local and remote consumers, may be an alternative to export of the
natural gas. However, it is assumed that most relevant national
authorities and or international requirements will not allow such
power plants without CO.sub.2 capture.
[0009] Technology for CO.sub.2 capture and storage (CCS) have been
developed to capture CO.sub.2 from production facilities where
carbonaceous fuels are combusted to produce electric power. The
presently available technology for the carbon capture part are
either based on CO.sub.2 capture from the flue gas by means or
absorbents, or oxyfuel plants where purified oxygen is used for the
combustion instead of air, to obtain a flue gas mainly comprising
CO.sub.2 and some water.
[0010] Plants for absorption of CO.sub.2 from flue gas are
presently too large, and too expensive both in capital cost and
operating cost, even for operation onshore, and would be far too
expensive to build offshore. Pilot scale oxyfuel plants using coal
as fuel have been built i.a. by Vattenfall, and tests are presently
done at such plants. The combustion in such oxyfuel plants is at
atmospheric pressure or somewhat higher, and the flue gas has to be
pre-treated for removing pollutants and particles therein before
the flue gas is further treated and compressed for transport /
injection into a deposition site.
[0011] U.S. Pat. No. 3,736,745 relates to a supercritical thermal
power system where a fuel oil is combusted using pure oxygen at
high pressure. The exhaust gas is partly expanded over a gas
turbine to produce electrical power. The exhaust gas is cooled,
dried and further cooled to give a fluid or supercritical fluid
CO.sub.2, which is recycled into the combustion chamber to control
the combustion and temperature therein. The excess CO.sub.2 is
removed from the system.
[0012] US 2009293782 relates to method and a system for generation
of electrical power, where a carbonaceous fuel is combusted in a
furnace in the presence of pure oxygen to generate heat. After
cooling by heat exchanging to generate steam, water is removed from
the exhaust gas to leaving an exhaust gas mainly comprising
CO.sub.2. A part of the CO.sub.2 is recycled into the combustion
chamber, whereas the remaining exhaust gas is compressed and cooled
to produce fluid or supercritical CO.sub.2.
[0013] WO2013036132 relates to an integrated system for offshore
industrial activities with fume injection. It is described to
inject the exhaust gas (CO.sub.2+N.sub.2) into a hydrocarbon
reservoir to enhance the hydrocarbon recovery.
[0014] One object of the present invention is to provide a
technology allowing for offshore power production of electrical
power and/or heat, based on combustion of carbonaceous fuels,
combined with capture of CO.sub.2 at a lower cost than by known
prior known solutions. Other objects of the invention will be clear
to the skilled person by reading the present description.
SUMMARY OF INVENTION
[0015] According to a first aspect, the present invention relates
to a method for generation of electrical power and/or steam or
vapour, by combustion of carbonaceous fuels, where carbonaceous
fuel is combusted in a combustion chamber at a pressure of 40 to
200 bar in the presence of oxygen enriched air or substantially
pure oxygen to produce electrical power and/or to generate steam
from fluids circulating in steam tubes arranged inside the
combustion chamber, and a flue gas, where the flue gas is withdrawn
from the combustion chamber and is cooled to a temperature that
according to the plots in FIG. 1 result in condensation of the flue
gas, or conversion of the flue gas to a supercritical fluid having
a density of at least 600 kg/m.sup.3, and where the liquid or
supercritical fluid formed, is safely deposited.
[0016] High pressure combustion using pure oxygen or oxygen
enriched air as defined herein makes it possible to convert the
flue gas from the combustion to liquid or supercritical dense phase
fluid CO.sub.2 or a combination of H.sub.2O and CO.sub.2 by cooling
by heat exchanging against surrounding water and/or air.
Preferably, cooling water is used.
[0017] As may be seen from FIG. 1, at a pressure of 40 bar, the
exhaust gas from the present power plant will have a density
>600 kg/m.sup.3 at a temperature of 5.degree. C. or colder.
Accordingly, in areas having a water temperature of about 3.degree.
C. or colder, it is possible to obtain a liquid or supercritical
fluid exhaust gas having a density of >600 kg/m.sup.3 at a
pressure of >40 bar. At 50 bar, the temperature at which the
exhaust gas will be liquid or a supercritical fluid having a
density of >600 kg/m.sup.3 is about 15.degree. C.
[0018] According to one embodiment, the flue gas is cooled to a
temperature of 40.degree. C. or lower, such as 30.degree. C. or
lower, such as 20.degree. C. or lower, or 10.degree. C. or lower.
The preferred temperature is dependent on the pressure at which the
combustion takes place, as is evident from the plot of FIG. 1 and
the phase diagrams of FIGS. 2 and 3.
[0019] According to one embodiment, the cooling is performed in two
or more steps, where water present in the flue gas is condensed and
separated from the remaining flue gas, and where the remaining flue
gas thereafter is further cooled for condensing of CO.sub.2 or
conversion of the CO.sub.2 to a supercritical fluid. Separation of
H.sub.2O and CO.sub.2 may be preferred in embodiments where dry, or
substantially dry CO.sub.2 is requested.
[0020] According to one embodiment, CO.sub.2 and water is condensed
together to give a mixed fluid and/or supercritical fluid.
Depending on the requirements set for the use of the CO.sub.2, it
may be allowed to combine CO.sub.2 and water. This is the case if
the CO.sub.2 is to be deposited as a CO.sub.2 hydrate, or if a
mixture of CO.sub.2 and water is needed or allowed for injection in
a subterrain formation.
[0021] According to one embodiment, the combustion chamber is a
boiler for generation of steam or vapour, and where the steam or
vapour is used to produce electrical power in a steam power
plant.
[0022] According to an embodiment, the combustion is an oxidation
in a fuel cell to generate electrical power.
[0023] According to one embodiment, the carbonaceous fuel is
natural gas and/or condensate, and where the natural gas and/or
condensate is/are introduced at the production pressure, or is
expanded to the pressure in the combustion chamber if the
production pressure is higher than the pressure of the combustion.
The natural gas and/or condensate may be introduced at the
production pressure, or expanded to a preferred pressure for the
combustion, to avoid the necessity of compressing the natural gas
as will be the case with a normal gas power plant. Accordingly, no
compression is needed, a fact that recuses the energy demand for
the capture of the CO.sub.2 by making the flue gas liquid or to a
dense supercritical fluid for safe depositing.
[0024] The carbonaceous fuel may alternatively be methane
hydrate.
[0025] According to one embodiment, the supercritical fluid or
condensed CO.sub.2 or CO.sub.2 and H.sub.2O mixture, is deposited
by injection into a sub-terrain formation such as an aquifer, an
abandoned oil or gas well, or into an oil well for enhanced oil
recovery.
[0026] According to a second aspect, the present invention relates
to a plant for generation of electrical power and capturing of
CO.sub.2, the plant comprising a source for substantially pure
oxygen or oxygen enriched air to a combustion chamber for
combustion of carbonaceous fuel at a pressure of 40 bar or more,
where steam tubes are arranged in the combustion chamber for
cooling the combustion gases in the combustion chamber by
generation of steam or vapour from a fluid circulating in the steam
tubes, a flue line for withdrawal of flue gas from the combustion
chamber and for introduction of the flue gas into a condenser in
which the flue gas is cooled for condensing of, or forming a
supercritical fluid having a density of at least 600 kg/m.sup.3, of
CO.sub.2 and any H.sub.2O, present in the flue gas, and a CO.sub.2
withdrawal line for withdrawal of condensed liquid or supercritical
fluid from the condenser.
[0027] The combustion chamber may be a boiler for generation of
steam, or a fuel cell.
[0028] According to one embodiment, the plant comprises different
modules like combustion module, boiler module, heat exchanger
module, turbine module, pump module, compressor module, that all
may be isolated from the remaining plant for maintenance and
repair, or for exchanging one module with a spare module.
Modularisation may be the key for success for such a plant,
especially if located subsea or in remote locations, as changing
modules prepared for being replaced, may reduce time and cost for
repair by changing modules for service or repair.
[0029] According to one embodiment, redundant modules are arranged
in parallel for redundancy.
BRIEF DESCRIPTION OF DRAWINGS
[0030] FIG. 1 shows plots of fluid density as a function of
temperature of a flue gas at different pressures,
[0031] FIG. 2 is a phase diagram for CO.sub.2,
[0032] FIG. 3 is a phase diagram for H.sub.2O,
[0033] FIG. 4 shows plots of fluid density as a function of
temperature at 100 bar pressure for a flue gas including different
amounts of nitrogen,
[0034] FIG. 5 is a flow diagram of a typical plant according to the
present invention,
[0035] FIG. 6 is a principle sketch of a gas turbine power plant,
and
[0036] FIG. 7 is a principle sketch of an embodiment of the present
invention.
DETAILED DESCRIPTION OF THE INVENTION
[0037] The present invention is based on the fact that natural gas
and oil with associated gas have a pressure of typically 40 to 300
bar when coming up from a well bore. The pressure of the gas is
reduced during the lifespan of a gas well, and when the pressure
falls below about 70 bar the production is normally so low that it
needs boosting by compression of the produced gas to keep
profitable, and when the pressure falls to 20 bar, the gas well is
normally closed down and production stopped.
[0038] Additionally, the invention takes advantage of the basically
unlimited availability of cold water for cooling in some coastal
areas and at the sea bed at many offshore gas fields. The proposed
invention eliminates or significantly reduces the above challenges
and disadvantages of subsea gas production and well-stream
transportation by introducing pressurized combustion of the gas and
use the heat to produce electric power that can be used locally,
transported to other offshore locations or transmitted to shore in
a power cable that can be connected to electric grid. In other
cases all or some of the power can be used at receiving platform,
e.g. for running compressors, or for industrial purposes at
shore.
[0039] Carbonaceous fuels as used in the present description and
claims is used to encompass all kind of materials comprising
carbon, such as coal, natural gas, hydrocarbon condensate, oil,
lignite, and methane-hydrates, in addition to wood and other
biomaterials. Preferred carbonaceous fuels for use as fuels
according to the present invention, are natural gas, methane
hydrates, hydrocarbon condensates, or higher hydrocarbons, such as
oil, or mixtures of any of the mentioned preferred carbonaceous
fuels.
[0040] Natural gas produced at a combined oil and gas field or a
gas field, normally comprises high amounts of methane, some ethane,
butane and propane and minor amount of C.sub.5+ hydrocarbons. Gas
condensate is gaseous at the temperature and pressure in the
sub-terrain formation, but is liquid at atmospheric pressure and
ambient temperature. Gas-condensate comprises mostly C.sub.2-12
alkanes. The term "natural gas" is herein used to encompass
hydrocarbons that are gaseous at ambient temperatures, methane
hydrates, i.e. methane clathrates forming solids in subterrain
formations and sediments on ocean floors, and gas-condensate, i.e.
hydrocarbons that are gaseous in the subterrain reservoir but
condensates to a liquid at atmospheric pressure and ambient
temperature at the surface.
[0041] The term oxidant as used herein is used to encompass
substantially pure oxygen and oxygen enriched air comprising 90% or
more oxygen, and where the rest of the gas mainly comprises
nitrogen and/or other gases normally present in air. Preferably,
the oxidant as used herein comprises 95% or more of oxygen, such as
more than 97% or more than 99% oxygen.
[0042] Percentages as used herein with regard to gases, relates to
% by volume if not specifically indicated elsewise. The term
"combustion" as used herein is used to include combustion with an
open flame, the oxidation finding place in a fuel cell, or any form
of catalysed oxidation of the carbonaceous fuel in the presence of
an oxidant as defined herein to form CO.sub.2 or a mixture of
CO.sub.2 and H.sub.2O dependent on the composition of the fuel.
"Elevated pressure " as used herein, relates to pressures of 40 bar
or more if not specifically indicated.
[0043] According to the present invention produced natural gas, or
any other carbonaceous fuel, is introduced into a combustion
chamber at the pressure of at least 40 bar, and substantially pure
oxygen or oxygen-enriched air is introduced into the combustion
chamber as oxidant. When using natural gas, oil or hydrocarbon
condensate, the fuel is introduced into the combustion chamber at
the production pressure, or the fuel is expanded to a pressure of
at least 40 bar, if the pressure of the produced stream is too high
to be introduced directly into the combustion chamber. The skilled
person will also understand that the pressure may be reduced
relative to the production pressure at the well head, due to
pressure drop in intervening pipelines and any process steps for
preparing the fuel for the combustion chamber.
[0044] The phrase "combustion chamber" as used herein is meant to
encompass any structure in which combustion of the fuel in form of
natural gas, or any other carbonaceous fuel is combusted by
oxidation with oxygen. The combustion chamber may thus be a steam
boiler, a combustion chamber of a gas turbine, a fuel cell etc.
[0045] Combustion of a carbonaceous fuel using an oxidant that is
substantially pure oxygen or oxygen enriched air results in a flue
gas mainly comprising CO.sub.2 or CO.sub.2 and water, dependent on
the composition of the fuel. Combustion of coal will result a flue
gas mainly comprising CO.sub.2, whereas all hydrocarbons will give
a flue gas comprising some water. The skilled person is able with
simple means to calculate the ration of CO.sub.2 to H.sub.2O in the
flue gas based on the composition of the fuel used.
[0046] The flue gas from the combustion is after leaving the
combustion chamber, cooled in a conventional way in several steps
by means of heat exchangers and coolers, to reduce the temperature
of the flue gas. The skilled person will understand that flue gas
at a temperature that is useful in generating steam preferably is
used for steam generation by heat exchanging. Flue gas at lower
temperatures are cooled against water, such as sea water
surrounding an offshore installation.
[0047] The fluid properties of a given compound at a given
combination of temperature and pressure may be found by studying
the phase diagram of the compound in question. The phase diagrams
of CO.sub.2 and H.sub.2O are shown in FIGS. 2 and 3, respectively.
The critical point of a compound is the combination of temperature
and pressure at which the compound may exist in gas phase, liquid
phase or in a supercritical phase. The critical point of CO.sub.2
is 31.1.degree. C. and a pressure of 72.9 bar. At a temperature
higher than the critical temperature, i.e. 31.1.degree. C. for
CO.sub.2, CO.sub.2 will exist in a supercritical phase, a
supercritical fluid, provided that the pressure is above 72.9 bar.
The density of a supercritical depends on the pressure. The higher
the pressure is, the higher is the density, and will approach the
density of a liquid. Dense supercritical phase CO.sub.2 having a
density of higher than about 600 kg/m.sup.3, such as higher than
about 650 kg/m.sup.3, or preferably higher than 700 kg/m.sup.3 may
be treated as a liquid for pumping etc. The skilled person knows
that supercritical fluids share properties with both gases and
liquids. In compressing, a supercritical fluid density will be
increased with increasing pressure, and a dense critical phase
having a density as indicated here, is "pumpable", i.e. the
pressure may be further increased by using a pump as for
liquids.
[0048] FIG. 1 is a diagram showing how CO.sub.2 liquid forms from a
mixed flue gas of CO.sub.2 and H.sub.2O (the composition of the
flue gas used for the calculation has a content of 44.1657%
CO.sub.2 and 55.6425% H.sub.2O and the rest is excess of O2,
0.001928%,resulting from combustion of a typical natural gas with a
stoichiometric amount of oxygen). FIG. 1 illustrates the
combination of pressure and temperature which ascertains that a
flue gas consisting of CO.sub.2 and H.sub.2O, in addition to a
minor amount of oxygen, has a sufficiently high density to either
be liquid, or in a liquid like dense supercritical phase allowing
the fluid to be pumped. At pressures examined and plotted in FIG.
1, i.e. 40 to 200 bar, CO.sub.2 will be a supercritical fluid if
pressure and temperature are above the critical point, and will
change phase from supercritical fluid to a liquid if the pressure
is above the critical pressure and the temperature is lower than
the critical temperature of CO.sub.2. FIG. 1 clearly shows that the
flue gas will condense at pressures down to about 40 bar and at a
temperature of about 5.degree. C., a temperature that is achievable
by heat exchanging against seawater at the sea bed in cold to
temperate climates. At a pressure of 70 bar, the flue gas will
condense at about 30.degree. C. For pressures between 70 bar and 40
bar, the flue gas will condense at temperatures between the one
indicated for 40 bar and 70 bar. For pressures above 70 bar, FIG. 1
indicates that supercritical fluid is formed at pressures above 80.
A dense phase fluid having a density making the fluid "pumpable",
is obtainable at temperatures from about 35.degree. C. at 80 bar,
to about 95.degree. C. at 200 bar. Accordingly, FIG. 1 clearly
indicates that the flue gas according to the present invention may
be condensed or optionally form a dense supercritical fluid that
may be pumped as a liquid. The pressure in the combustion chamber
is set sufficiently high to ascertain that the flue gas from the
combustion will condense or form dense phase supercritical CO.sub.2
or CO.sub.2 plus H.sub.2O, as soon as the temperature is
sufficiently low to form a liquid mixture of CO.sub.2 and water
when cooled at substantially the same pressure as mentioned above.
The skilled person is able to calculate the pressure needed at
given temperatures based on the plots in FIG. 1 and the phase
diagrams for CO.sub.2 and water, respectively, found in FIGS. 2 and
3, and the composition of the flue gas. The gas used for the
calculations plotted in FIG. 1 consists of 0.2% oxygen, 55.6%
H.sub.2O and 44.2% CO.sub.2, and corresponds to a typical flue gas
from combustion of natural gas using substantially pure oxygen as
oxidant.
[0049] It is clear from the density increase as the temperature is
decreased, and that the flue gas used for the calculations, is
liquid at a temperature of about 5.degree. C. and a pressure of 40
bar, at about 15.degree. C. at a pressure of 50 bar, at about
22.degree. C. at a pressure of 60 bar, and at about 30.degree. C.
at a pressure of 70 bar. At a pressure of 80 bar or higher, the
more "S" shaped plots indicate that the flue gas is compressed to a
dense phase supercritical fluid. At 80 bar, the supercritical fluid
phase has a density of about 600 kg/m.sup.3, which makes the
supercritical fluid pumpable. The corresponding temperatures for
resulting in a supercritical fluid having a density of 600
kg/m.sup.3 at 90, 100, 150 and 200 bar, are about 42.degree. C.,
47.degree. C., 75.degree. C. and 98.degree. C., respectively.
Accordingly, at a pressure of 40 bar or more, a flue gas from
combustion of natural gas with pure oxygen will be in liquid state
or will be a supercritical fluid having a density of higher than
700 kg/m.sup.3 at a temperature of about 5.degree. C. Further
detail on the density as a function of pressure and temperature for
the flue gas, and the conditions for obtaining the flue gas as a
liquid or a pumpable dense phase supercritical fluid are easy
understandable for the skilled person studying FIG. 1 and the phase
diagrams in FIGS. 2 and 3. It is assumed that even by using oxygen
enriched air, CO.sub.2 and water will condensate and form a liquid,
or form a pumpable dense supercritical fluid at the temperatures
obtainable by using seawater as cooling medium.
[0050] The use of a oxidant having a too high content of
contaminants, such as primarily nitrogen, will shift the phase
diagram for the mixture and result in a demand for more cooling of
the flue gas to obtain a flue gas being liquid or a liquid like
dense phase. FIG. 4 illustrates the density of the flue gas as a
function of temperature at a pressure of 100 bar using pure oxygen,
99% oxygen and 95% oxygen as oxidant. The figure shows that a
density of higher than about 600 kg/m.sup.3 is obtained at about
47.degree. C. by using pure oxygen, at about 40.degree. C. by using
99% oxygen, and at about 30.degree. C. by using 95% oxygen. A high
content of contaminants, normally nitrogen, in the oxygen demands
cooling to a lower temperature compared to pure oxygen for a given
pressure. Pressure and temperature are to some extent
interchangeable, but from a practical point of view when naturally
existing wellhead pressure shall be used for combustion followed by
cooling the flue gas with low temperature seawater to achieve
liquid CO.sub.2, the oxidant preferably comprises 95% or more, and
most preferably substantially pure oxygen comprising 99% or more
oxygen.
[0051] Cooling of the flue gas requires substantial cooling
capacity, a capacity that is present at deep offshore locations, in
some coastal areas, and in some larger lakes where the water
temperature at the sea bottom all year through is about 4.degree.
C. or colder. In deep ocean locations, such as below 500 meters,
the temperature of the sea may be about 0.degree. C., or even as
low as -2.degree. C.
[0052] The critical point of CO.sub.2 is 31.1.degree. C. and a
critical pressure of about 73 bar, as illustrated in FIG. 2. The
access to substantially unlimited cooling capacity as cold sea
water makes it possible to cool the flue gas to a temperature lower
than the critical temperature of CO.sub.2, 31.1.degree. C. To
ascertain that the temperature is lower than the critical
temperature, the flue gas is preferably cooled to a temperature
lower than 20.degree. C., such as e.g. lower than 15.degree. C.,
such as about 10.degree. C. At a temperature lower than 20.degree.
C. and a pressure of about 55 bar, or above, the CO.sub.2 present
in the flue gas will condense and be present as a liquid, together
with water present in the natural gas and water formed by
combustion of the natural gas.
[0053] The phase diagram for H.sub.2O shows that the critical point
for water is at 374.degree. C. and 218 bar (.about.atm), whereas
the triple point is at 0.01.degree. C. at 0.006 bar. The water will
thus condensate at far higher temperatures than CO.sub.2 at the
pressures in question. This fact may be used to separate H.sub.2O
and CO.sub.2 by stepwise cooling where condensed water is separated
from gaseous CO.sub.2 by means of a water separator between each
step. Normally, a two-step cooling with a water separator between
the cooling steps will be sufficient to remove most of the water
from the flue gas if needed.
[0054] The liquefied CO.sub.2 or CO.sub.2/H.sub.2O mixture captured
this way may be deposited in different ways. Provided that the
captured CO.sub.2 fulfils the requirements for injection into a
reservoir, the CO.sub.2 may be injected for pressure support /
Enhanced Oil Recovery (EOR). Alternatively, the CO.sub.2 or
CO.sub.2/H.sub.2O mixture may be injected into a depleted oil
and/or gas well, or into stable geological formations or an
aquifer, that ensures permanent safe deposit of the CO.sub.2.
[0055] At temperatures below 20.degree. C., and a pressure of more
than 20 bar, i.e. at a water depth of 200 meters or more, CO.sub.2
or a mixture of CO.sub.2 and H.sub.2O in combination with produced
water and/or surrounding water will spontaneously form CO.sub.2
hydrate (clatherate). The CO.sub.2 hydrate is an ice-like solid
that will remain as a stable solid as long as it is kept below said
temperature and at 200 meters water depth or deeper. If needed, the
kinetics of hydrate formation may be accelerated by the use of a
hydrate formation reactor, a mixer ensuring good distribution and
contact between CO.sub.2 and the surrounding water, and the walls
and surfaces of the reactor for promotion of hydrate formation,
and/or by use of a catalytically active coating on the mentioned
walls and surfaces, or by adding a chemical catalyst.
[0056] As shown above, the combination of combustion at an elevated
pressure using substantially pure oxygen or oxygen enriched air as
defined above as oxidant to produce electrical power and / or heat,
cooling the pressurized flue gas resulting from the combustion to
below the temperature causing the CO.sub.2 to condense, and safely
depositing the thus captured CO.sub.2, makes it possible to produce
power without emitting CO.sub.2 into the atmosphere.
[0057] It should also be underscored that although the conditions
for condensation of CO.sub.2 are favourable subsea, the same can be
achieved at power plants above sea, i.e. at surface, either on
fixed or floating platforms, ships and vessels or on land by
operating at the pressure found in the mentioned subsea depths. By
providing the power plant/combustion chamber in the area of the
wells from which the gas is produced, unprocessed or partly
processed gas can be routed to the combustion chamber at high
pressure and the flue gas can be cooled either by seawater from the
ocean or freshwater from a lake pumped to heat exchangers at
surface. Alternatively, ambient air can be used for cooling by heat
exchanging e.g. in cooling towers or other types of heat
exchangers. The air temperature might form a limitation with regard
to achieving sufficient cooling capacity by air-cooling, especially
in hot climate areas. This can be solved by higher combustion and
hence higher condensation pressure, e.g. 70 bar or more (ref. FIG.
1).
[0058] Further, it should be noted that the process of high
pressure combustion with oxygen or oxygen enriched air, can also be
done by using low pressure sales quality gas from a process plant
by compressing the gas to necessary high pressure, e.g. to 40 bar
or higher, for achieving CO.sub.2 condensation to liquid by using
the ambient water-temperature or the ambient air for cooling. The
pressure of the combustion must then be high enough to achieve
condensation given by the temperature of the available cooling
medium water or air. The skilled person is able to calculate the
required pressure by the physical properties of the constituents of
the flue gas as illustrated by the phase diagrams in FIGS. 2 and 3.
In this case the process of condensation does not have the
inherently favourable conditions of combustion of gas from wells
with high pressure and within the reach of available cold deep sea
water. Still the process of generation of electric power and rather
expensive compression of the gas before combustion and less
efficient cooling by air or water at higher temperature than
seawater from deep water depth (200 m or more) can be attractive
due to the simple process of CO.sub.2 condensation to liquid
followed by permanent deposition by pumping it into suitable
geological formations or aquifers or as stable CO.sub.2
hydrate.
[0059] Compression of the fuel gas can also be achieved by supply
of liquid oxygen to the combustion chamber or burner because the
liquid oxygen with a density of 1141 kg/m.sup.3 will expand when
evaporated by heating it. The density of oxygen gas at 25.degree.
C. and 1.013 bar is 1.429 kg/ m.sup.3. This means that the pressure
of a combustion chamber with some limited volume can be controlled
to being at a desired pressure level by adjustment of the flow of
carbonaceous fuel and of the expansion of the supplied oxygen
necessary for the combustion. The combustion pressure will be a
result of the supply of carbonaceous fuel at 1 bar and of the
expansion of oxygen in the confined combustion chamber. If the
required pressure not can be achieved by adjustment of the volume
of the combustion chamber and flow of fuel with its necessary
supply of liquid oxygen alone, compression of the carbonaceous fuel
will also be necessary. Some control valves will normally be needed
to control the pressure and the process in general, but such valve
are not included in this patent description, because they are not
necessary to understand the invention.
[0060] In addition to CO.sub.2 and H.sub.2O formed by combustion of
the carbonaceous fuel, the flue gas can also contain water vapour
from water that flows together with the carbonaceous fuel, which
can be water vapour and free water, e.g. produced water from gas
and oil wells. In well streams of hydrocarbons, there will normally
be some content of particles, so called fines, and in coal, there
will be ashes. If there is some content of nitrogen in the oxygen,
this can form nitrous gases. In the case of injection of liquid
water and CO.sub.2, all mentioned contaminants might follow the
liquid and thereby be permanently disposed. If the method of
CO.sub.2-hydrate formation is used, the particles may be trapped in
the hydrate disposed at seabed. Injection of CO.sub.2-hydrate
before it solidifies, i.e. in a kind of slurry, can also be used,
and particles and other contaminants will follow the slurry to the
receiver (i.e. geological formation or aquifer).
[0061] A generic process of subsea power generation is illustrated
in FIG. 5. It is important to note that the combustion or burning
will be performed at a high pressure, typically between 40 and 250
bar to make it possible to directly produce liquid CO.sub.2 or
CO.sub.2-hydrate by cooling of the flue gas towards ambient
(seawater, freshwater or air) temperature without additional
compression of the flue gas.
[0062] The skilled person will understand that combustion pressure
has to be optimized, taking into account combustion technical
issues, the design of equipment for the combustion and handling of
pressurized fluids, power demand for compression of air or the
oxidant as defined herein, etc. It may therefore be necessary /
preferable to choke, or reduce, the pressure of natural gas having
a higher pressure than the preferred combustion pressure. It is
presently believed that a combustion pressure of 50 to 100 bar is
practical. A pressure of 60 to 90 bar is presently more preferred,
and it is assumed that the most preferred pressure of combustion is
from 75 to 85 bar. As previously mentioned, a too low pressure that
typically can occur at the late phase of gas production can be
corrected by compressing the fuel to an optimum pressure before
entering the combustion chamber.
[0063] FIG. 5 is a principle sketch of an embodiment of a power
plant according to the present invention. Carbonaceous fuel, such
as natural gas, and an oxidant as defined above, are introduced
into a combustion chamber 2 from a source 20 of the carbonaceous
fuel via a fuel line 1, and from an oxidant source 11, via a
pressurized oxidant line 7, respectively. Both the carbonaceous
fuel and the oxidant are introduced into the combustion chamber at
the pressure in the combustion chamber 2. An optional compressor or
pump may be arranged between the oxidant source 11 and the
combustion chamber 2, if needed to give a sufficiently high
pressure. If the oxidant is at a high pressure in the oxidant
source 11, the pump or compressor 15 may be omitted.
[0064] According to the embodiment illustrated in FIG. 5, and in
further detail in FIG. 6, the combustion chamber is a boiler, i.e.
a combustion chamber where steam tubes 19 are arranged inside the
combustion chamber to cool the combustion gases by means of a fluid
circulating in the flowing in steam tubes 19. The flowing fluid may
be water or any other convenient heat transfer fluid that may be
vaporized and further heated in the steam tubes 19. Water/steam is
the preferred fluid but other heat transfer fluids, such as organic
fluids, may be used without leaving the scope of the invention.
[0065] Steam, or other vapour, generated in the steam tubes 19 is
withdrawn through one or more steam line(s) 8. According to the
embodiment illustrated in FIGS. 5 and 6, the steam in steam line(s)
8 is introduced into a power-generating unit 6, illustrated as a
steam power plant, for generation of electrical power that is
withdrawn through a power line 10. The steam is cooled, expanded
and partly liquefied by generation of electrical power in the power
generation unit 6, and is further cooled to condensate the
steam/vapour, before returning the liquid into the steam tubes 19
in the boiler 2.
[0066] The skilled person will understand that all or some of the
steam/vapour in steam line(s) 8, may be used for other purposes
than power generation, such as local heat demanding processes.
[0067] The flue gas is withdrawn from the combustion chamber 2
through a flue gas line 3, and is introduced into a condenser 4,
wherein the pressurized flue gas is cooled by heat exchanging
against a cooling medium, circulating in the condenser 4 so that
the H.sub.2O and CO.sub.2 are condensed or are forming a dense
supercritical fluid having a density of above 600 kg/m.sup.3, as
according to the definition above is pumpable. The skilled person
will understand that the condenser 4 normally comprises several
heat exchange steps for stepwise cooling of the flue gas. It can be
seen from the phase diagrams for water and CO.sub.2, see FIGS. 3
and 4, water will condensate at higher temperature than CO.sub.2
for a given pressure. Accordingly, water and CO.sub.2 may be
fractionated by first cooling to a temperature where substantially
all water is condensed, and separate the liquid water from the
gaseous CO.sub.2, before the CO.sub.2 is further cooled and
condensed, if it is required to deliver CO.sub.2 without water. Any
separated water may be withdrawn through a not shown water
extraction line, and may be released into the sea if allowed by the
authorities, or be injected into a water injection well.
[0068] The cooling may be direct or indirect cooling. Direct
cooling is effected by circulating surrounding water as a cooling
medium through the condenser 4. Indirect cooling is effected by
circulating a cooling medium between the condenser 4 and heat
exchangers 9 where the cooling medium is heat exchanged against the
surrounding water. The cooling medium to cool the flue gas is
introduced into the condenser from a cooling medium intake line 12
and withdrawn through a cooling medium return line 13.
[0069] High-density supercritical fluid or liquid formed by cooling
of the flue gas is withdrawn through a condensed flue gas line 16
for deposition in a deposit 5. Not condensed flue gas, comprising
mainly nitrogen minor amounts of any inert gases may be withdrawn
through a line 16' and may be released into the surrounding sea or
air. Alternatively, the gas can follow the liquid and form
multi-phase flow for injection, or for discharge to sea when the
method of CO.sub.2-hydrate formation is used for safe disposal.
[0070] Cooling capacity for condensing of the expanded steam for
the power generation unit may be provided by means of heat
exchanger(s) 9' where a cooling medium is circulated between the
power generation unit 6 and the heat exchanger(s) 9'in cooling
medium lines 12' and 13'. Electrical power and/or steam is
withdrawn from the power generation unit in power line 10.
[0071] The oxidant source 11 may be any convenient source for an
oxidant being substantially pure oxygen or oxygen enriched air. The
skilled person knows that such an oxidant may be provided by means
of membrane-based systems and by means of cryogenic systems, both
for separation of air gases. Electrolysis of water is an optional
way for production of the oxidant to be used according to the
present invention. Additionally, for smaller systems, substantially
pure oxygen or oxygen-enriched air may be provided in tanks from
remote facilities.
[0072] A facility for separation of air gases is conveniently
arranged either at the sea bed, onboard a floater or on land. For a
subsea plant according to the present invention, air for production
of an oxidant as defined herein, or the oxidant as such has to be
pressurized and transported in a riser or snorkel from a floater to
the plant. If the facility for air gas separation is arranged at
the seabed, the remaining air gases has to be transported by means
of a snorkel or riser to the surface to be released into the
surroundings.
[0073] Production of the present oxidant, i.e. substantially pure
oxygen or oxygen enriched air, is energy demanding processes, and
will require a part of the power produced in the present power
plant. If electrolysis is used, the oxidant will be substantially
pure oxygen. Additionally, hydrogen will be produced. The produced
hydrogen may be a sales product by itself by exporting the hydrogen
from the plant, may be used locally for further power production,
and/or be used in a local or remote process plant for hydrogen
demanding processes.
[0074] Natural gas, as produced from a subterrain gas producing
well, either from a gas well or a combined gas and oil well,
normally comprises water, particles, CO.sub.2, and higher
hydrocarbons in addition to the hydrocarbon gas. Normally the
natural gas is separated from the water, particles, CO.sub.2and
higher hydrocarbons for efficient transport of the saleable gas.
The natural gas to be used locally, i.e. close to the gas producing
well, may be used as is. Optional separation of water (produced and
condensed) and particles from the carbonaceous fuel, such as
natural gas, may be arranged upstream of the combustion chamber,
dependent on the composition of the gas in question. The separated
water and any particles may be re-injected in an injection well, or
disposed into the sea if allowed by the authorities.
[0075] Natural gas may alternatively be combusted without prior
separation of water and/or particles. The presence of contaminants
may require use of specially designed burner designed with selected
materials to make it robust for the conditions.
[0076] By using substantially pure oxygen or oxygen enriched air
with such low content of argon and nitrogen and other contaminants,
the flue gas is not "diluted" with other gases than could prevent
condensation of CO.sub.2 and H.sub.2O to liquids when cooling down
the flue gas towards the level of the temperature of the ambient
water or air. It is assumed that the maximum allowed content of
argon and nitrogen combined is about 5%, so that the oxidant
comprises 95% or more oxygen. More preferred the oxidant comprises
more than 97% oxygen, such 99% or more oxygen. This relates to all
the embodiments described herein if nothing else is specifically
stated.
[0077] Combustion of carbonaceous materials using an oxidant as
described herein may result in high temperatures, temperatures that
are not compatible with most materials used for construction of
burners and combustion chambers. Dependent on the composition of
the carbonaceous fuel used, recirculation of flue gas, i.e.
CO.sub.2 and H.sub.2O and minor amounts of other gases, and/or
addition of water into the combustion chamber, may be necessary for
controlling the temperature in the combustion therein.
[0078] If methane hydrate is introduced into a combustion chamber
as a carbonaceous fuel, the water content of the hydrate that is
released when burning the hydrate, inherently gives the benefit of
cooling.
[0079] The electrical power generated in a power plant according to
the present invention may be used locally, i.e. at an oil and/or
gas-producing field, or be exported by cables to remote locations,
either offshore or onshore.
[0080] FIG. 6 illustrates the principles of a steam turbine power
plant. Elements having the same reference numerals as FIG. 5
illustrates the corresponding elements. Carbonaceous fuel and
oxidant are introduced into a combustion chamber 2 through lines 1
and 7, respectively. Flue gas is withdrawn from the combustion
chamber 2 via flue line 3. Water is introduced into steam tubes 19
arranged in the combustion chamber, and steam generated therein is
withdrawn through steam line 8 and introduced into the power
generation unit 6 indicated with dotted lines in the figure. The
steam is expanded over a high-pressure turbine 20, and the partly
expanded gas is led through a line 24 to a low pressure turbine 21
before the expanded steam is withdrawn in an expanded steam line
26. The turbines 20 and 21 are arranged on a common axle 22 with a
generator 23 for generation of electrical power that is exported
via a power line 23'. Any water being condensed in line 24 is
withdrawn in a condensate line 25. The expanded steam is cooled and
condensed in a condenser 27 receiving cooling medium in cooling
medium line 12'. Heated cooling medium is returned in the return
line 13'. Condensed water is withdrawn from the condenser 27 in
condensate line 28 and is introduced into a feed water heater 30,
together with any condensate in line 25. Heated water from the feed
water heater 30 is withdrawn via line 8' and introduced into the
combustion chamber as above described. Circulation mumps 29, 29'
are arranged for circulation of the water in lines 28 and 8'.
[0081] The skilled person will understand that even though a steam
turbine power plant is described above, alternative power
generation units may be used according to the present invention.
The core of the invention is that the combustion is carried out
under elevated pressure so that the flue gas has a pressure
allowing for condensation of CO.sub.2 when cooling the flue gas
below the critical temperature of CO.sub.2, or to a temperature
where the phase diagram of the gas shows that CO.sub.2 will
condense to form a liquid, alone or in combination with water
present in the flue gas. Accordingly, any combustion using
substantially pure oxygen or oxygen enriched air as oxidant,
producing a flue gas mainly comprising CO.sub.2 or CO.sub.2 and
H.sub.2O, may be applicable.
[0082] An alternative combustion to a combustion chamber as
described herein is a fuel cell, such as molten carbonate fuel
cell, using natural gas as fuel and an oxidant as described herein,
is applicable according to the invention. The skilled person will
understand that heat generated in such a fuel cell may be used for
generating steam for other purposes.
[0083] FIG. 7 is a simplified view of an offshore power plant
according to present invention. Natural gas is being produced from
one or more sub-terrain and subsea gas well(s) and transferred to a
subsea gas production unit 30 via one or more gas line(s) 31. The
incoming gas has a pressure from about 40 bar to about 200 bar.
[0084] All, or some of the produced gas is introduced into a gas
power plant 32 arranged at the seabed, via a gas line 33. Any
additional natural gas may be transferred to a floater 34 via a gas
export line 35 for further treatment and export from the gas field,
or may be compressed subsea and exported via a not illustrated gas
export line.
[0085] A facility for generation of oxygen enriched air or
substantially pure oxygen is arranged either onboard the floater or
at the seabed, as described above. Both cryogenic and membrane
based units for generation of oxygen enriched air or substantially
pure oxygen are known by the skilled person. As used here, the
oxidant being substantially pure oxygen or oxygen enriched air,
comprises more than 95% oxygen, more preferably more than 97%
oxygen, and most preferably 99% oxygen or more. The skilled person
will understand that the non-oxygen part of any of the gases
mentioned mainly comprises nitrogen, often with trace amounts of
noble gases, such as Ar. Oxygen, as air, or as an oxidant mainly
comprising oxygen enriched air or substantially pure oxygen, is
transferred to the power plant 32 in an airline 36, dependent on if
the facility for production of the oxidant is based on the sea bed
or onboard the floater 34. It is presently assumed that it is
preferred to arrange the oxidant producing facility at the seabed,
and have little or no processing equipment on the floater for a
deep-sea installation if this kind.
[0086] The power plant 32 is according to one embodiment a steam
turbine power plant, wherein steam is generated by heating of water
by combustion of natural gas using the oxygen enriched air or
substantially pure oxygen as oxidant. The pressure in the
combustion chamber is typically 50 to 100 bar. A pressure of 60 to
90 bar is presently more preferred, and it is assumed that the most
preferred pressure of combustion is from 75 to 85 bar.
[0087] The skilled person will understand that surrounding water is
used for cooling and condensation of the steam in the steam turbine
cycle as cold water is abundant. Electrical power and/or heat in
the form of steam may be transferred to the floater 34 via a power
umbilical 37, to a remote location by means of a power line 40.
[0088] The combustion in the combustion chamber of the power plant
is controlled to give a substantially complete combustion, i.e. a
substantially stoichiometric combustion so that substantially all
the introduced natural gas and oxygen is used in the combustion.
Combustion leaving less than 1%, such as below 0.5% or even less
than 0.2% rest oxygen in the flue gas is considered to be
substantially stoichiometric.
[0089] The flue gas resulting from the combustion is transferred to
a flue gas unit 38 via a flue gas line 39. The flue gas unit
comprises coolers in which is cooled against the seawater
surrounding the power plant to cool the flue gas to a temperature
of 40 .degree. C. or colder, such as 30 .degree. C. or colder, such
as below 20 .degree. C., or even below 10 .degree. C. The flue gas
comprises mainly CO.sub.2, some H.sub.2O, and any nitrogen
introduced together with the oxygen. Additionally, the flue gas may
comprise minor amounts of impurities introduced together with the
natural gas.
[0090] The CO.sub.2 and water present in the flue gas will
spontaneously condense and form a liquid phase, if the combination
of pressure and temperature of the flue gas is held within the
limits easily derivable from FIG. 1, or FIG. 4. The skilled person
will be able to calculate the combinations of pressure and
temperature that will result in condensation or formation of dense
phase supercritical fluid based on standard calculations and
parameters found in textbooks, for pressures not shown here. Any
nitrogen and not used oxygen present therein will remain in a gas
phase. The liquid and gas phases are easily separated, and the
liquid phase mainly comprising water and CO.sub.2, is exported from
the plant in a CO.sub.2 export line 40 for safe and accepted
deposition of the CO.sub.2. The CO.sub.2 deposited by transferring
the liquid CO.sub.2 and water into a not illustrated injection
module to be introduced into a sub-terrain formation where CO.sub.2
may be safely deposited, such as a closed gas or oil well, or an
aquifer. The CO.sub.2 may also be injected into an oil well for
pressure support for enhanced oil recovery (EOR). The gas phase may
be transferred to the surface and released into the atmosphere, be
released into the surrounding sea, or follow the liquid as
multiphase flow.
[0091] Oxygen enriched air or substantially pure oxygen is used as
oxidant in the combustion to avoid dilution of the flue gas with
nitrogen as such dilution will result in a larger volume of gas to
be cooled and that the condensation temperature for the
CO.sub.2/water mixture is lowered due to the lower partial
pressures of water and CO.sub.2, respectively.
[0092] Even though the embodiment of FIG. 7 has been described with
reference to a specific embodiment where the power plant is
arranged at the sea bed, the skilled person will understand that
invention is directed to pressurized combustion and condensation of
the resulting CO.sub.2 and water at the elevated pressure, and not
if the power plant is at the sea bed or not. According, the power
plant may be arranged on the floater, if it is regarded as more
practical or advantageous to bring the natural gas and cooling
water onboard the floater, and return the condensed CO.sub.2 and
water from the floater to the seabed for safe deposit of the
CO.sub.2 as described above.
[0093] The skilled person will understand that a plant according to
the present invention may be arranged onshore, provided that the
necessary cooling capacity is available. A plant according to the
present invention may be arranged in coastal areas having easy
access to cooling water from the sea or a large lake. If natural
gas is used as the carbonaceous fuel, either from an offshore or
onshore gas well, the present plant is preferably arranged
sufficiently close to the gas well to receive the gas directly at
substantially the same pressure as the gas is produced, as
described above.
[0094] The skilled person will also understand that all or a part
of the steam generated in the combustion chamber / the boiler, may
be used for other heat requiring purposes than generation of
electrical power, depending on the specifics of the installation in
question.
[0095] Independent on if the power plant is arranged at the seabed,
at the floater or ashore, electrical power from the power plant may
be used locally, such as onboard the floater, and/or on
neighbouring power demanding installations, either at the sea bed
and at the surface or onshore, dependent on the location of the
present plant. Any additional electrical power may be exported to
more remote locations offshore or onshore, and may be connected to
the land based electrical grid.
[0096] CO.sub.2 or CO.sub.2+ water generated in the above-described
process and plant, can be of great value for injection into an oil
or gas field for pressure support, and enhanced oil recovery (EOR).
By combusting natural gas as described herein, both electrical
power and/or steam to be used for different purposes, including
optional export of electrical power from the installation, may be
obtained at the same time as the gas volume for reinjection for EOR
is maintained, or even increased, depending on the composition of
the fuel. Accordingly, stranded gas may have a substantial value.
Likewise, associated gas, that otherwise would have been
re-injected for pressure support, may be used for generation of
electrical power and/or steam, at the same time as the CO.sub.2 by
the combustion may be used to replace the natural gas for
re-injection, and thus increasing the value of such gas.
* * * * *