AU2018452624A1 - Process for combined removal of native CO2 and anthropogenic CO2 - Google Patents
Process for combined removal of native CO2 and anthropogenic CO2 Download PDFInfo
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- AU2018452624A1 AU2018452624A1 AU2018452624A AU2018452624A AU2018452624A1 AU 2018452624 A1 AU2018452624 A1 AU 2018452624A1 AU 2018452624 A AU2018452624 A AU 2018452624A AU 2018452624 A AU2018452624 A AU 2018452624A AU 2018452624 A1 AU2018452624 A1 AU 2018452624A1
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- 238000000034 method Methods 0.000 title claims abstract description 37
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 claims abstract description 172
- 239000007788 liquid Substances 0.000 claims abstract description 105
- 239000003345 natural gas Substances 0.000 claims abstract description 78
- UGFAIRIUMAVXCW-UHFFFAOYSA-N Carbon monoxide Chemical compound [O+]#[C-] UGFAIRIUMAVXCW-UHFFFAOYSA-N 0.000 claims abstract description 59
- 239000007789 gas Substances 0.000 claims abstract description 52
- 239000003546 flue gas Substances 0.000 claims abstract description 49
- 238000011282 treatment Methods 0.000 claims abstract description 44
- 230000001172 regenerating effect Effects 0.000 claims abstract description 11
- GLUUGHFHXGJENI-UHFFFAOYSA-N Piperazine Chemical compound C1CNCCN1 GLUUGHFHXGJENI-UHFFFAOYSA-N 0.000 claims description 8
- 230000005611 electricity Effects 0.000 claims description 8
- 150000003512 tertiary amines Chemical class 0.000 claims description 8
- 239000000203 mixture Substances 0.000 claims description 7
- 239000003949 liquefied natural gas Substances 0.000 claims description 6
- CRVGTESFCCXCTH-UHFFFAOYSA-N methyl diethanolamine Chemical group OCCN(C)CCO CRVGTESFCCXCTH-UHFFFAOYSA-N 0.000 claims description 6
- 150000003141 primary amines Chemical class 0.000 claims description 6
- 239000007864 aqueous solution Substances 0.000 claims description 5
- 239000000446 fuel Substances 0.000 claims description 5
- 150000003335 secondary amines Chemical class 0.000 claims description 5
- WFCSWCVEJLETKA-UHFFFAOYSA-N 2-piperazin-1-ylethanol Chemical compound OCCN1CCNCC1 WFCSWCVEJLETKA-UHFFFAOYSA-N 0.000 claims description 2
- 229910002092 carbon dioxide Inorganic materials 0.000 description 119
- 238000002485 combustion reaction Methods 0.000 description 13
- 238000010438 heat treatment Methods 0.000 description 8
- 238000009434 installation Methods 0.000 description 8
- 239000002904 solvent Substances 0.000 description 8
- 238000004519 manufacturing process Methods 0.000 description 6
- 239000006096 absorbing agent Substances 0.000 description 4
- HZAXFHJVJLSVMW-UHFFFAOYSA-N 2-Aminoethan-1-ol Chemical compound NCCO HZAXFHJVJLSVMW-UHFFFAOYSA-N 0.000 description 3
- 238000010521 absorption reaction Methods 0.000 description 3
- 238000012856 packing Methods 0.000 description 3
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 3
- CURLTUGMZLYLDI-UHFFFAOYSA-N Carbon dioxide Chemical compound O=C=O CURLTUGMZLYLDI-UHFFFAOYSA-N 0.000 description 2
- 239000003125 aqueous solvent Substances 0.000 description 2
- 239000013505 freshwater Substances 0.000 description 2
- 229930195733 hydrocarbon Natural products 0.000 description 2
- 150000002430 hydrocarbons Chemical class 0.000 description 2
- 239000000243 solution Substances 0.000 description 2
- 101100037762 Caenorhabditis elegans rnh-2 gene Proteins 0.000 description 1
- MWRWFPQBGSZWNV-UHFFFAOYSA-N Dinitrosopentamethylenetetramine Chemical compound C1N2CN(N=O)CN1CN(N=O)C2 MWRWFPQBGSZWNV-UHFFFAOYSA-N 0.000 description 1
- 102000004190 Enzymes Human genes 0.000 description 1
- 108090000790 Enzymes Proteins 0.000 description 1
- 150000001335 aliphatic alkanes Chemical class 0.000 description 1
- 150000001412 amines Chemical class 0.000 description 1
- 239000003637 basic solution Substances 0.000 description 1
- 229940112112 capex Drugs 0.000 description 1
- 239000001569 carbon dioxide Substances 0.000 description 1
- 230000015556 catabolic process Effects 0.000 description 1
- 238000006243 chemical reaction Methods 0.000 description 1
- 239000003245 coal Substances 0.000 description 1
- 150000001875 compounds Chemical class 0.000 description 1
- 238000005260 corrosion Methods 0.000 description 1
- 230000007797 corrosion Effects 0.000 description 1
- 238000006731 degradation reaction Methods 0.000 description 1
- 238000005265 energy consumption Methods 0.000 description 1
- 238000002955 isolation Methods 0.000 description 1
- 239000012528 membrane Substances 0.000 description 1
- 238000011084 recovery Methods 0.000 description 1
- 230000008929 regeneration Effects 0.000 description 1
- 238000011069 regeneration method Methods 0.000 description 1
- 238000011144 upstream manufacturing Methods 0.000 description 1
- 238000010792 warming Methods 0.000 description 1
Classifications
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
- B01D53/1456—Removing acid components
- B01D53/1475—Removing carbon dioxide
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
- B01D53/1406—Multiple stage absorption
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
- B01D2252/20—Organic absorbents
- B01D2252/204—Amines
- B01D2252/20431—Tertiary amines
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2256/00—Main component in the product gas stream after treatment
- B01D2256/24—Hydrocarbons
- B01D2256/245—Methane
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2257/00—Components to be removed
- B01D2257/50—Carbon oxides
- B01D2257/504—Carbon dioxide
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2258/00—Sources of waste gases
- B01D2258/02—Other waste gases
- B01D2258/0283—Flue gases
-
- Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
- Y02C—CAPTURE, STORAGE, SEQUESTRATION OR DISPOSAL OF GREENHOUSE GASES [GHG]
- Y02C20/00—Capture or disposal of greenhouse gases
- Y02C20/40—Capture or disposal of greenhouse gases of CO2
Landscapes
- Chemical & Material Sciences (AREA)
- Engineering & Computer Science (AREA)
- Analytical Chemistry (AREA)
- General Chemical & Material Sciences (AREA)
- Oil, Petroleum & Natural Gas (AREA)
- Chemical Kinetics & Catalysis (AREA)
- Treating Waste Gases (AREA)
- Gas Separation By Absorption (AREA)
Abstract
A process for treating a flow of natural gas (7) having an initial CO2 concentration and a flow of flue gas (9) having an initial CO2 concentration, comprising the following steps: - a first gas treatment wherein the flow of flue gas reacts with a first flow of liquid (47) having a first CO2 content, in order to obtain a flow of treated flue gas (29) having a final CO2 concentration lower than the initial CO2 concentration of the flow of flue gas (9), and a second flow of liquid (49) having a second CO2 content higher than the first CO2 content, - a second gas treatment wherein the flow of natural gas reacts with said second flow of liquid, and wherein a flow of treated natural gas (17) and a third flow of liquid (51) are obtained, the flow of treated natural gas having a final CO2 concentration lower than the initial CO2 concentration of the flow of natural gas, and the third flow of liquid having a third CO2 content higher than the second CO2 content, and - regenerating said third flow of liquid in order to obtain said first flow of liquid and a flow of residual gas (31) comprising CO2 at a concentration higher than 90vol%.
Description
Process for combined removal of native C02 and anthropogenic C02
The present invention deals with a process for treating a flow of natural gas having an initial C02 (carbon dioxide) concentration, and a flow of flue gas having an initial C02 concentration in order to lower these C02 concentrations to acceptable limits.
The present invention also deals with an installation adapted to perform such a process.
Natural gas is a mixture of hydrocarbons extracted from a subsoil. It mainly comprises alkanes: methane and heavier compounds. These hydrocarbons constitute the recoverable resource of natural gas. However, natural gas from production wells usually contains other components that are not recoverable, such as C02, and that must be removed. In addition to its production, the consumption of natural gas or other combustibles at the natural gas production site also induces C02 emissions.
C02 contained in natural gas is called“native”, as opposed to C02 contained in flue gas from a combustion of combustibles which is called“anthropogenic”.
The 2°C scenario of the International Energy Agency (EIA) aims at reducing C02 emissions in general, in particular by reducing the consumption of coal and oil in favor of that of natural gas, which emits less C02 per unit of produced energy.
However, the production and consumption of natural gas are respectively responsible for emissions of native and anthropogenic C02. In order to limit global warming below 2°C, both of them should be reduced.
Up to about 20vol% of native C02 in natural gas, the most common method for removal of native C02 is absorption by weak basic solutions, typically secondary or tertiary amine solutions. By “removal”, it is meant “reduction to a predetermined acceptable level”.
When the native C02 exceeds 20vol% in natural gas, usually additional treatment steps are required upstream of the abovementioned native C02 removal unit. Such treatment could involve a membrane, a cryogenic process, etc.
Currently, no anthropogenic C02 capture units are mandatory on natural gas production sites. Studies carried out for the capture of anthropogenic C02 in flue gas suggest using absorption processes based on aqueous solutions, for example a primary amine such as monoethanolamine or MEA.
This would result in two solvent loops: primary amine solvent (MEA) for the treatment of flue gas, and secondary or tertiary amine solvents (or their mixture) for the treatment of natural gas.
Their installation will increase the cost of natural gas production, both in terms of investments and operation costs. In addition, using primary amine solutions is complex, because they can degrade rapidly and be highly corrosive.
An aim of the invention is to provide a less expensive process for lowering the C02 concentration of a flow of natural gas and a flow of flue gas.
To this end, the invention proposes a process for treating a flow of natural gas having an initial C02 concentration, and a flow of flue gas having an initial C02 concentration, the process comprising the following steps:
- a first gas treatment wherein the flow of flue gas reacts with a first flow of liquid having a first C02 content, in order to obtain a flow of treated flue gas having a final C02 concentration lower than the initial C02 concentration of the flow of flue gas, and a second flow of liquid having a second C02 content higher than the first C02 content ;
- a second gas treatment wherein the flow of natural gas reacts with said second flow of liquid, and wherein a flow of treated natural gas and a third flow of liquid are obtained, the flow of treated natural gas having a final C02 concentration lower than the initial C02 concentration of the flow of natural gas, and the third flow of liquid having a third C02 content higher than the second C02 content; and
- regenerating said third flow of liquid in order to obtain said first flow of liquid and a flow of residual gas comprising C02 at a concentration higher than 90vol%.
In other embodiments, the process comprises one or several of the following features, taken in isolation or any technically feasible combination:
- the step of regenerating comprises obtaining a fourth flow of liquid having a fourth C02 content equal to the first C02 content ; and in the second gas treatment, the flow of natural gas also reacts with said fourth flow of liquid in order to obtain the flow of treated natural gas;
- each of said first, second and third flows of liquid is a flow of an aqueous solution comprising a primary amine, a secondary amine, a tertiary amine, or a mixture thereof ;
- said tertiary amine is N-methyldiethanolamine;
- the first flow of liquid comprises piperazine, or 1 -(2-Hydroxyethyl)piperazine;
- the first C02 content is below 5g/L, preferably equal to or below 1 g/L, and more preferably equal to or below 0.5g/L;
- the second C02 content is between 20 and 60g/L, preferably between 30 and
55g/L;
- the third C02 content is above 70g/L, preferably above 80g/L;
- the first gas treatment is performed at a pressure of 0 to 0.5barg, and the second gas treatment is performed at a pressure of 15 to 100 barg;
- the final C02 concentration in said flow of treated flue gas is equal to or below
2vol%;
- the final C02 concentration in said flow of treated natural gas is equal to or below 2vol%, and the process further comprises injecting said flow of treated natural gas into a network of treated natural gas;
- the final C02 concentration in said flow of treated natural gas is equal to or below 50ppm, and the process further comprises producing liquefied natural gas out of said flow of treated natural gas;
- the process further comprises the following steps: burning a fuel in order to produce steam or heat, and said flow of flue gas ; and using at least part of said steam or heat in said regenerating step; and
- said burning also produces electricity, and at least part of said electricity is used in said process.
The invention also deals with a gas treatment unit for treating a flow of natural gas having an initial C02 concentration, and a flow of flue gas having an initial C02 concentration, the gas treatment unit comprising:
- a first reactor suitable for performing a first gas treatment wherein the flow of flue gas reacts with a first flow of liquid having a first C02 content, and wherein a flow of treated flue gas and a second flow of liquid are obtained, wherein the flow of treated flue gas has a final C02 concentration lower than the initial C02 concentration of the flow of flue gas, and the second flow of liquid has a second C02 content higher than the first C02 content,
- a second reactor suitable for performing a second gas treatment wherein the flow of natural gas reacts with said second flow of liquid, and wherein a flow of treated natural gas and a third flow of liquid are obtained, the flow of treated natural gas having a final C02 concentration lower than the initial C02 concentration of the flow of natural gas, and the third flow of liquid having a third C02 content higher than the second C02 concentration, and
- a regenerator configured for regenerating said third flow of liquid, in order to obtain said first flow of liquid and a flow of residual gas comprising C02 at concentration higher than 90vol%.
The invention and its advantages will be better understood upon reading the following description, given solely by way of example and with reference to the appended drawings, in which:
- Figure 1 is a schematic view of an installation comprising a gas treatment unit according to the invention, and
- Figure 2 is a schematic view of the gas treatment unit shown in Figure 1.
An installation 1 according to the invention is described with reference to Figure 1.
The installation 1 comprises a gas treatment unit 5 for treating a flow of natural gas 7 having an initial C02 concentration and a flow of flue gas 9 having an initial C02 concentration, advantageously a combustion unit 10 for producing steam or other heating media 12, electricity 14 and the flow of flue gas, and advantageously a liquefier 15 for liquefying a flow of treated natural gas 17 produced by the gas treatment unit and for obtaining liquefied natural gas (LNG) 19.
According to a variant, the installation 1 does not include the combustion unit 10 and the flow of flue gas 9 comes from another unit.
According to another variant (not shown), the installation 1 does not include the liquefier 15. The flow of treated natural gas 17 is for example injected in a natural gas network 20.
The combustion unit 10 is configured for burning a fuel 21 which is natural gas in the example.
According to other variants, the combustion unit 10 burns any other type of fuel.
According to other variants (not represented), the combustion unit 10 produces heat, instead of, or partly instead of steam.
The combustion unit 10 advantageously comprises one or several boilers and one or several steam turbines, or comprises gas turbines, or comprises a mix of these elements (not shown).
The combustion unit 10 is also adapted to receive a flow of fresh water 23 for producing the steam or other heating media 12, and to receive a flow of returned steam or water or other heating media 25 coming from the gas treatment unit 5.
The liquefier 15 is advantageously adapted for using at least a part 27 of the electricity 14 produced by the combustion unit 10 in order to liquefy the flow of treated natural gas 17.
The gas treatment unit 5 is configured to produce a flow of treated flue gas 29 having a final C02 concentration lower than the initial C02 concentration of the flow of flue gas 9, and to produce a flow of residual gas 31 (captured C02) comprising C02 at a
concentration above 90vol%, the flow of treated natural gas 17 also having a final C02 concentration lower than the initial C02 concentration of the flow of natural gas 7.
For example, the initial C02 concentration in the flow of natural gas 7 is between 1 vol% and 20vol%, and is about 6vol% in the example.
The final C02 concentration in the flow of treated natural gas 17 is below 50ppmv in the example, in order for the natural gas to be liquefied.
In variants where no liquefaction is performed, the final C02 concentration in the flow of treated natural gas 17 can be adjusted to higher values, for example equal to or below 2vol%.
The recovery of C02 in flue gas is equal or higher than 90%. The flow of treated flue gas 29 may be further treated, or released in the atmosphere.
The flow of residual gas 31 (captured C02) is for example sequestrated in a subsoil (not shown) or used in another manner as relatively pure C02.
As shown in Figure 2, the gas treatment unit 5 comprises a first reactor 35, a second reactor 40, and a regenerator 45. The reactors 35, 40 may be called“absorbers”, as their function is to absorb C02 from the incoming gas flows.
The first reactor 35 is adapted for performing a first gas treatment wherein the flow of flue gas 9 reacts with a first flow of liquid 47 having a first C02 content, and wherein the flow of treated flue gas 29 and a second flow of liquid 49 having a second C02 content are obtained.
The second reactor 40 is adapted for performing a second gas treatment wherein the flow of natural gas 7 reacts with the second flow of liquid 49, and wherein the flow of treated natural gas 17 and a third flow of liquid 51 having a third C02 content are obtained.
Advantageously the second reactor 40 is also adapted to make the flow of natural gas 7 react afterwards with a fourth flow of liquid 53 having a fourth C02 content in order to obtain the flow of treated natural gas 17 and the third flow of liquid 51.
The regenerator 45 is configured for regenerating the third flow of liquid 51 , in order to obtain the first flow of liquid 47 and the flow of residual gas 31 .
Advantageously the regenerator 45 is also configured for obtaining the fourth flow of liquid 53. For example, the regenerator is adapted to produce a flow of regenerated liquid 55 which is divided into the first flow of liquid 47 and the fourth flow of liquid 53. As a consequence, the first C02 content and the fourth C02 content are identical in the example.
The regenerator 45 is for example adapted for receiving at least part of the steam or other heating media 12 from the combustion unit 10, and for returning the flow of returned steam or water or other heating media 25.
In a particular embodiment, the regenerator 45 is adapted for using at least part of heat or energy generated by combustion of combustibles.
The first C02 content and the fourth C02 content are lower than the second C02 content and the third C02 content. So the first flow of liquid 47 and the fourth flow of liquid 53 can be called“lean liquids”.
The second C02 content is higher than the first C02 content and lower than the third C02 content, so the second flow of liquid 49 can be called a“semi-rich liquid”.
The third C02 content is the highest, so the third flow of liquid 51 can be called a “rich liquid”.
The terms“lean”,“semi-rich” and“rich” of course have a relative meaning here.
By“C02 content”, it is meant the amount of C02 which the considered liquid could release if said liquid was fully regenerated. It does not necessarily mean that the considered liquid actually contains C02 molecules.
For example, each of the first, second, third and fourth flows of liquid 47, 49, 51 , 53 is a flow of an aqueous solution comprising a primary amine, a secondary amine, a tertiary amine, or a mixture thereof.
Amines can fix or release C02. For example, ethanolamine does it according to the reaction RNH2 + C02 ¹ RNHCOO + H+.
So a certain amount of C02 can react and be stored reversibly in the first, second, third and fourth flows of liquid 47, 49, 51 , 53. This stored amount can be expressed in grams per liter of liquid.
Advantageously, the tertiary amine is N-methyldiethanolamine (MDEA).
The first flow of liquid 47 for example comprises piperazine in order to enhance C02 absorption.
Advantageously, the first C02 content is below 5g/L, preferably equal to or below 1 g/L, and more preferably equal to or below 0.5g/L.
Advantageously, the second C02 content is between 20 and 60g/L, preferably between 30 and 55g/L.
Advantageously, the third C02 content is above 70g/L, preferably above 80g/L.
The first reactor 35 is for example adapted for performing the first gas treatment at a pressure of 0 to 0.5barg (bar gauge).
The second reactor 40 is for example adapted for performing the second gas treatment at a pressure of 15 to 100 barg.
In other embodiments, each of the first, second, third and fourth flows of liquid 47, 49, 51 , 53 and 55 is a flow of a solvent adapted to react with C02, for example a non- aqueous solvent, a physical solvent, an aqueous solvent enhanced by an enzyme, or a mixture thereof.
The operation of installation 1 will now be described briefly, as it stems from its structure, in order to illustrate a process according to the invention.
The fuel 21 is burnt in the combustion unit 10 in order to produce the steam or other heating media 12 and the electricity 14. Steam is made out of the flow of fresh water 23 and the flow of returned steam or water or other heating media 25 coming from the gas treatment unit 5. The combustion also produces the flow of flue gas 9 which is sent to the gas treatment unit 5.
The gas treatment unit 5 performs a first gas treatment of the flow of natural gas 7 and a second gas treatment of the flow of flue gas 9.
The flow of flue gas 9 reacts with the first flow of liquid 47 in the first reactor 35. Most of the C02 contained in the flow of flue gas 9 is captured by the first flow of liquid 47. As a result, the final C02 concentration of the flow of treated flue gas 29 is much lower than the initial C02 concentration of the flow of flue gas 9. The flow of treated flue gas 29 is for example released to the atmosphere.
The first gas treatment also results in a second flow of liquid 49 having the second C02 content higher than the first C02 content of the first flow of liquid 47.
The flow of natural 7 reacts with the second flow of liquid 49 in the second reactor 40. Advantageously, the flow of natural 7 also reacts, advantageously afterwards, with the fourth flow of liquid 53 in the second reactor 40.
Advantageously, the pressure in the second reactor 40 is higher than the pressure in the first reactor 35.
Most of the C02 contained in the flow of natural gas 7 is captured by the second flow of liquid 49 and advantageously by the fourth flow of liquid 53. As a result, the final C02 concentration of the flow of treated natural gas 17 is much lower than the initial C02 concentration of the flow of natural gas 7. The flow of treated natural gas 17 is sent to the liquefier 15 which produces the liquefied natural gas 19 using at least part of the electricity 14.
The third flow of liquid 51 is sent to the regenerator 45 where it is heated using at least part of the steam or other heating media 12 in order to be regenerated. Most of the C02 contained in the third flow of liquid 51 is released and recovered as the flow of residual gas 31 (captured C02). As a result of the regenerating step, the flow of regenerated liquid 55 is obtained, which is then divided in the example into the first flow of
liquid 47 and the fourth flow of liquid 53 respectively sent to the first reactor 35 and to the second reactor 40.
The mass flowrate of the fourth liquid 53 is advantageously lower than 20%, preferably lower than 10%, of the mass flowrate of the first flow of liquid 47, so that the loop defined by the first flow of liquid 47 through the first absorber 35, the second absorber 40 and the regenerator 45 is dominant compared with the optional second loop defined by the fourth flow of liquid 53 through the second reactor and the regenerator. In absence of the second loop, all of the flow of regenerated liquid 55 becomes the first flow of liquid 47.
The flow of residual gas 31 is advantageously sequestrated in a subsoil or used as relatively pure C02.
Thanks to the above described features, in particular the use of the second flow of liquid 49 in the second reactor 40, i.e. a use of the lean liquid first in the first reactor 35 and then, as semi-rich liquid, in the second reactor 40, the process for lowering the C02 concentration of the flow of natural gas 7 and the flow of flue gas 9 is less expensive.
Thanks to the optional second loop (the third flow of liquid 53), performances are further enhanced.
The process incorporates removal of native C02 and anthropogenic C02 in a combined way, which results in a more compact gas treatment unit 5 compared to former units with separate removal. Both CAPEX and OPEX costs are lower thanks to a reduced number of equipment pieces: advantageously only one regenerator 45, and a single solvent loop. Thermal energy consumption is also less important. In addition, the loss in the loop defined by the flow of first liquid and the corrosivity of the liquids are reduced compared to currently used units.
Comparison Table
The following table summarizes the differences between the gas treatment unit 5 and prior art gas treatments in arbitrary units:
Overall, the number of regenerators is reduced from two to one. The total solvent flowrate (flows of liquid entering the reactors 35, 40) is reduced by 30%. The duty (or power) needed to perform regeneration is reduced .The risk of solvent degradation and corrosion is minimized.
Example
The flue gas 9 enters in the first absorber 35. The initial C02 concentration is 10vol%.
The first reactor 35 comprises a column (not shown) with a 7m diameter and a packing height of 34m, working at 0.15 barg (bar gauge) and 45°C.
The lean liquid (the first flow of liquid 47) is made of an aqueous solution of MDEA and piperazine and flows at 700m3/hr. Its C02 content (the first C02 content) is 0.5g/L (gram per liter), i.e. 3.103 mol/mol.
Approximatively 90% of the C02 is absorbed in the first reactor 35.
The flow of natural gas 7 enters in the second reactor 40. The initial C02 concentration is 6vol%.
The second reactor 40 comprises a column (not shown) with a 3.5m diameter and a packing height of 20m, working at 70 bara (bar absolute) and 45 °C.
The semi-rich liquid (the second flow of liquid 49) has a C02 content (the second C02 content) of around 50 g/L, i.e. 0.3 mol/mol.
The fourth flow of liquid 53 has a C02 content (the fourth C02 content) of around 0.5g/L (gram per liter).
The final C02 concentration of the flow of treated natural gas 17 is 50ppm of C02.
The rich liquid (the third flow of liquid 51 ) leave second reactor 40 with a C02 content (third C02 content) of around 85g/L.
The regenerator 45 comprises a column (not shown) with a 4m diameter and packing height of 27m, working at 2.1 bara (top) and 2.3 bara (bottom).
Claims (15)
1.- A process for treating a flow of natural gas (7) having an initial C02 concentration, and a flow of flue gas (9) having an initial C02 concentration, the process comprising the following steps:
- a first gas treatment wherein the flow of flue gas (9) reacts with a first flow of liquid (47) having a first C02 content, in order to obtain a flow of treated flue gas (29) having a final C02 concentration lower than the initial C02 concentration of the flow of flue gas (9), and a second flow of liquid (49) having a second C02 content higher than the first C02 content,
- a second gas treatment wherein the flow of natural gas (7) reacts with said second flow of liquid (49), and wherein a flow of treated natural gas (17) and a third flow of liquid (51 ) are obtained, the flow of treated natural gas (17) having a final C02 concentration lower than the initial C02 concentration of the flow of natural gas (7), and the third flow of liquid (51 ) having a third C02 content higher than the second C02 content, and
- regenerating said third flow of liquid (51 ) in order to obtain said first flow of liquid (47) and a flow of residual gas (31 ) comprising C02 at a concentration higher than 90vol%.
2.- The process according to claim 1 , wherein:
- the step of regenerating comprises obtaining a fourth flow of liquid (53) having a fourth C02 content equal to the first C02 content, and
- in the second gas treatment, the flow of natural gas (7) also reacts with said fourth flow of liquid (53) in order to obtain the flow of treated natural gas (17).
3.- The process according to claim 1 or 2, wherein each of said first, second and third flows of liquid (47, 49, 51 ) is a flow of an aqueous solution comprising a primary amine, a secondary amine, a tertiary amine, or a mixture thereof.
4.- The process according to claim 3, wherein said tertiary amine is N- methyldiethanolamine (MDEA).
5.- The process according to any of claims 1 to 4, wherein the first flow of liquid (47) comprises piperazine, or 1 -(2-Hydroxyethyl)piperazine.
6.- The process according to any of claims 1 to 5, wherein the first C02 content is below 5g/L, preferably equal to or below 1 g/L, and more preferably equal to or below 0.5g/L.
7.- The process according to any of claims 1 to 6, wherein the second C02 content is between 20 and 60g/L, preferably between 30 and 55g/L
8.- The process according to any of claims 1 to 7, wherein the third C02 content is above 70g/L, preferably above 80g/L
9.- The process according to any of claims 1 to 8, wherein the first gas treatment is performed at a pressure of 0 to 0.5barg, and the second gas treatment is performed at a pressure of 15 to 100 barg.
10.- The process according to any of claims 1 to 9, wherein the final C02 concentration in said flow of treated flue gas (29) is equal to or below 2vol%.
1 1 .- The process according to any of claims 1 to 10, wherein the final C02 concentration in said flow of treated natural gas (17) is equal to or below 2vol%, and the process further comprises injecting said flow of treated natural gas (17) into a network (20) of treated natural gas.
12.- The process according to any of claims 1 to 10, wherein the final C02 concentration in said flow of treated natural gas (17) is equal to or below 50ppm, and the process further comprises producing liquefied natural gas (19) (LNG) out of said flow of treated natural gas (17).
13.- The process according to any of claims 1 to 12, further comprising the following steps:
- burning a fuel (21 ) in order to produce steam (12) or heat, and said flow of flue gas (9), and
- using at least part of said steam (12) or heat in said regenerating step.
14.- The process according to claim 13, wherein:
- said burning also produces electricity (14), and
- at least part of said electricity (14) is used in said process.
15.- A gas treatment unit (5) for treating a flow of natural gas (7) having an initial C02 concentration, and a flow of flue gas (9) having an initial C02 concentration, the gas treatment unit (5) comprising:
- a first reactor (35) suitable for performing a first gas treatment wherein the flow of flue gas (9) reacts with a first flow of liquid (47) having a first C02 content, and wherein a flow of treated flue gas (29) and a second flow of liquid (49) are obtained, wherein the flow of treated flue gas (29) has a final C02 concentration lower than the initial C02 concentration of the flow of flue gas (9), and the second flow of liquid (49) has a second C02 content higher than the first C02 content,
- a second reactor (40) suitable for performing a second gas treatment wherein the flow of natural gas (7) reacts with said second flow of liquid (49), and wherein a flow of treated natural gas (17) and a third flow of liquid (51 ) are obtained, the flow of treated natural gas (17) having a final C02 concentration lower than the initial C02 concentration of the flow of natural gas (7), and the third flow of liquid (51 ) having a third C02 content higher than the second C02 concentration, and
- a regenerator (45) configured for regenerating said third flow of liquid (51 ), in order to obtain said first flow of liquid (47) and a flow of residual gas (31 ) comprising C02 at concentration higher than 90vol%.
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| PCT/IB2018/001497 WO2020121008A1 (en) | 2018-12-12 | 2018-12-12 | Process for combined removal of native co2 and anthropogenic co2 |
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| AU2018452624A1 true AU2018452624A1 (en) | 2021-06-24 |
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| AU2018452624A Pending AU2018452624A1 (en) | 2018-12-12 | 2018-12-12 | Process for combined removal of native CO2 and anthropogenic CO2 |
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| Country | Link |
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| AU (1) | AU2018452624A1 (en) |
| BR (1) | BR112021010581A2 (en) |
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| JP4138399B2 (en) * | 2002-08-21 | 2008-08-27 | 三菱重工業株式会社 | Method for producing liquefied natural gas |
| DE102010041536A1 (en) * | 2010-09-28 | 2012-03-29 | Siemens Aktiengesellschaft | Process for the separation of carbon dioxide, and gas turbine plant with carbon dioxide separation |
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- 2018-12-12 BR BR112021010581-6A patent/BR112021010581A2/en active Search and Examination
- 2018-12-12 AU AU2018452624A patent/AU2018452624A1/en active Pending
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| WO2020121008A1 (en) | 2020-06-18 |
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