WO2009068594A1

WO2009068594A1 - Process for removal of carbon dioxide from flue gas with ammonia cooled by vaporised liquefied natural gas

Info

Publication number: WO2009068594A1
Application number: PCT/EP2008/066294
Authority: WO
Inventors: Kuei-Jung Li; Bas Kessels
Original assignee: Shell Internationale Research Maatschappij B.V.
Priority date: 2007-11-29
Filing date: 2008-11-27
Publication date: 2009-06-04

Abstract

The invention provides a process for removal of CO2 from flue gas, comprising the steps of: a) removing CO2 from flue gas by contacting said flue gas with cooled ammonia in an absorber (13) operated at low temperature to obtain ammonia enriched in CO2 (14) and a purified flue gas (23); b) regenerating ammonia enriched in CO2 in a regenerator (17) operated at elevated pressure to obtain regenerated ammonia (19) and a gas stream enriched in CO2 (18); c) regasifying liquefied natural gas via heat exchange against a heat transfer fluid, thereby obtaining natural gas and cooled heat transfer fluid (10); d) at least part of the cooled heat transfer fluid is used to provide cooling needed in step (a).

Description

PROCESS FOR REMOVAL OF CARBON DIOXIDE FROM FLUE GAS WITH AMMONIA COOLED BY VAPORISED LIQUEFIED NATURAL GAS

The invention relates to a process for removal of carbon dioxide from flue gas .

During the last decades there has been a substantial global increase in the amount of CO2 emission to the atmosphere. Emissions of CO2 into the atmosphere are thought to be harmful due to its "greenhouse gas" property, contributing to global warming. Following the Kyoto agreement, CO2 emission has to be reduced in order to prevent or counteract unwanted climate changes. The largest sources of CO2 emission are combustion of fossil fuels, for example coal or natural gas, for electricity generation and the use of petroleum products as a transportation and heating fuel. These combustion processes result in the production of flue gases comprising carbon dioxide.

Processes for removal of carbon dioxide from flue gases are known in the art.

For example, in WO 2004/005818 the use of aqueous monoethanolamine (MEA) for removal of carbon dioxide at elevated temperature is described. However, a severe drawback of this technology is the high energy consumption. The MEA process may consume 10 to even 30% of the steam generated in a boiler heated by combustion of a fossil fuel. In addition, the carbon dioxide released has a relatively low pressure. In order to enable further use of the carbon dioxide in processes like enhanced oil recovery, expensive compression equipment is needed.

There remains therefore a need for a more energy- efficient process for removal of CO2 from gases, wherein CO2 is obtained at high pressure. It has now been found that this can be achieved by a process for removal of CO2 from flue gas, comprising the steps of: (a) removing CO2 from flue gas by contacting said flue gas with cooled ammonia in an absorber operated at low temperature to obtain ammonia enriched in CO2 and a purified flue gas;

(b) regenerating ammonia enriched in CO2 in a regenerator operated at elevated pressure to obtain regenerated ammonia and a gas stream enriched in CO₂;

(c) regasifying liquefied natural gas via heat exchange against a heat transfer fluid, thereby obtaining natural gas and cooled heat transfer fluid; (d) using at least part of the cooled heat transfer fluid is used to provide cooling needed in step (a) .

The process enables removal of CO2 to low levels. This results in the reduction of CO2 emission to low levelsmeeting the environmental standards. The regenerator is operated at elevated pressure, so that the gas stream enriched in CO2 is obtained at elevated pressure. The pressurised gas stream enriched in CO2 can advantageously be used for enhanced oil recovery, with less compression equipment needed. In addition, as at least part of the cooling duty needed for the CO2 absorption step is supplied by evaporating liquefied natural gas, the process has increased energy efficiency.

Suitably, the flue gas comprises in the range of from 1 to 15 % (v/v) of CO₂, or from 3 to 10 % ) of CO₂ (v/v) .

The flue gas usually also comprises oxygen, suitably in the range of from 0.25 to 15 % (v/v), preferably from 5 to 15% ( v/v) .

In step (a), CO2 is removed by contacting the flue gas with ammonia at low temperature in an absorber.

Suitably the absorbing step is performed at temperatures below ambient temperature, preferably below 15 ⁰C, more preferably in the range of from -10 to 15 ⁰C, still more preferably from 0 to 10 ⁰C and most preferably from 0 to 8 ⁰C. In the preferred temperature ranges, removal of CO2 to low levels is achieved while the cooling duty requirements of the absorber are kept to a minimum.

As the temperature of the flue gas will typically be relatively high, preferably the flue gas is cooled prior to entering the absorber. Cooling of the flue gas prior to entering the absorber may be done by means known in the art, for example using a fan, a cooler or a gas-gas exchanger .

Suitably, absorption takes place at a pressure in the range of from 0.8 to 2 bara, preferably from 0.8 to 1.5 bara, more preferably about 1 bara.

Step (a) results in ammonia enriched in CO2 and a purified flue gas. The purified flue gas, now comprising very low concentrations of CO2, may be vented into the atmosphere . In step (b) , ammonia enriched in CO2 is regenerated at elevated pressure in a regenerator operated at elevated pressure.

Preferably, the regenerator is operated at a pressure in the range of from 5 to 50 bara, more preferably from 10 to 50 bara, most preferably from 20 to 50 bara.

The regeneration step is suitably performed at temperatures higher than used in the absorption step.

Step (b) results in regenerated ammonia and a gas stream enriched in CO2. Suitably, regenerated ammonia is led to the absorber to be used in step (a) .

The CC>2-enriched gas stream exiting the regenerator is at elevated pressure. Suitably, the pressure of the CC>2-enriched gas stream is in the range of from 5 to 50 bara, preferably from 10 to 50 bara, more preferably from 20 to 50 bara.

In applications where the CO2~enriched gas stream needs to be at a high pressure, for example when it will be used for injection into a subterranean formation, it is an advantage that the CO2~enriched gas stream is already at an elevated pressure.

In one embodiment, the pressurised CO2~enriched gas stream is used for enhanced oil recovery, suitably by injecting it into an oil reservoir where it tends to dissolve into the oil in place, thereby reducing its viscosity and thus making it more mobile for movement towards the producing well.

In another embodiment, the pressurised CO2~enriched gas stream is pumped into an aquifer reservoir for storage .

In yet another embodiment, the pressurised CO2- enriched gas stream is pumped into an empty oil reservoir for storage. For all the above options, a series of compressors is needed to pressurise the CC>2-enriched gas stream to the desired high pressures. Pressurising the CO2~enriched gas stream to a pressure of about 10 bara generally requires a large and expensive compressor. As the process results in a CO2~enriched gas stream which is already at elevated pressure, suitably above 10 bara, the most extensive compressor is not needed and thus the CC>2-enriched gas stream is easier to further pressurise to the desired pressure for enhanced oil recovery.

In step (c), liquefied natural gas is regasified via heat exchange against a heat transfer fluid, to obtain natural gas and cooled heat transfer fluid.

Regasif ication of liquefied natural gas is suitably done in an evaporator of the intermediate fluid type. Suitable evaporators include an open rack vaporiser or a submerged combustion vaporiser, as for example described by J. H. Cho et al . in the LNG Journal June 2005, pages

24-26. The heat transfer fluid can be any fluid suitable for heat exchange with liquefied natural gas. Preferably, ammonia or water/glycol mixtures are used as heat transfer fluid. In the process, at least part of the cooled heat transfer fluid is used to provide cooling needed for the removal of CO2 by absorption in cooled ammonia (step a) .

Preferably at least 50%, more preferably at least 70%, still more preferably at least 90% of the cooling duty required to operate the absorber at low temperature is provided by the regasif ication of liquefied natural gas.

As the process uses regasif ication of liquefied natural gas to provide at least part of the cooling duty needed for the CO2 removal, the process is advantageously applied at an import terminal for liquefied natural gas, using the regasifying equipment already at hand. Thus, in a preferred embodiment, the CO2 removal steps of absorption and regeneration are integrated with a liquefied natural gas import terminal. In a preferred embodiment, the flue gas is derived from a power plant comprising at least one gas turbine.

Typically, fuel and an oxygen-containing gas are introduced into a combustion section of the gas turbine. In the combustion section of the gas turbine, the fuel is combusted to generate a hot combustion gas . The hot combustion gas is expanded in the gas turbine, usually via a sequence of expander blades arranged in rows, and used to generate power via a generator. Suitable fuels to be combusted in the gas turbine include natural gas and synthesis gas. For improved efficiency, hot exhaust gas exiting the gas turbine can be introduced into to a heat recovery steam generator unit, where heat contained in the hot exhaust gas is used to produce additional steam.

The heat recovery steam generator unit is any unit providing means for recovering heat from the hot exhaust gas and converting this heat to steam. For example, the heat recovery steam generator unit can comprise a plurality of tubes mounted stackwise. Water is pumped and circulated through the tubes and can be held under high pressure at high temperatures. The hot exhaust gas heats up the tubes and is used to produce steam.

The flue gas can be flue gas exiting the heat recovery steam generator unit or can be exhaust gas exiting the gas turbine .

The invention will now be illustrated by means of example only using the following non-limiting embodiment, with reference to the Figure. In figure 1, hot flue gas comprising CO2 having a temperature of 110 ⁰C originating from a gas turbine is led via line 1 to a cooling unit 2, where it is cooled to a temperature of about 28 ⁰C. Optionally, cooling unit 2 is provided with cooled water, supplied via line 3. If the process is applied in areas close to the sea, especially where the ambient conditions are such that the sea water will be at low temperature, the cooling water is preferably derived from sea water. Cooling water is led from cooling unit 2 via line 4. Cooled flue gas at a temperature of 28 ⁰C is led from cooling unit 2 via line 5 to gas-gas exchanger 6, where is cooled to a temperature of 20 ⁰C. Cooled flue gas at a temperature of 20 ⁰C is led from gas-gas exchanger 6 to heat exchanger 9, where it is cooled to a temperature of 5 ⁰C using a cooled heat transfer fluid. Cooled heat transfer fluid is supplied to heat exchanger 9 via line 10 and used to cool the flue gas. Resulting warmed-up heat transfer fluid is led from heat exchanger 9 via line 11. Line 10 is coupled to a liquefied natural gas import terminal (not shown), where liquefied natural gas is regasified to obtain cooled heat transfer fluid. Cooled flue gas at a temperature of 5 ⁰C is led from heat exchanger 9 via line 12 to CC>2 absorber 13. CO2 absorber 13 contains ammonia at a temperature of 5 ⁰C and is operated at a pressure of 1 bara. In CO2 absorber 13, CO2 is transferred from the flue gas to the ammonia to obtain purified flue gas and ammonia enriched in CO2. Ammonia enriched in CO2, at a temperature of 35 ⁰C is led from CO2 absorber 13 via line 14 to heat exchanger 15, where it is heated to a temperature of 105 ⁰C. Heated ammonia enriched in CO2 is led from heat exchanger 15 via line 16 to regenerator 17.

Regenerator 17 is operated at a temperature of 120 ⁰C and a pressure of 30 bara. In regenerator 17, CO2 is released from the ammonia. The resulting gas stream enriched in CO2 is led from regenerator 17 via line 18. This gas stream enriched in CO2 is at a pressure of 30 bara and can be further pressurised and advantageously used for enhanced oil recovery, or pumped into an empty oil reservoir or pumped into an aquifer. Regenerated ammonia at a temperature of 120 ⁰C, depleted in CO2, is led from the regenerator via line 19 to heat exchanger 15 and used to heat up ammonia enriched in CO2. Cooled regenerated ammonia is led from heat exchanger 15 via line 20 to heat exchanger 21. Cooled heat transfer fluid is supplied to heat exchanger 21 via line 10 and used to cool the regenerated ammonia. Resulting cooled ammonia having a temperature of 5 ⁰C is led from heat exchanger 21 to the absorber 13 via line 22. Line 10 is coupled to the liquefied natural gas import terminal (not shown), where liquefied natural gas is regasified to obtain cooled heat transfer fluid. Purified flue gas at a temperature of 5 ⁰C is led from absorber 13 via line 23 to gas-gas exchanger 6 and used to cool flue gas entering the gas- gas exchanger .

Claims

C L A I M S

1. A process for removal of CO2 from flue gas, comprising the steps of:

(a) removing CO2 from flue gas by contacting said flue gas with cooled ammonia in an absorber operated at low temperature to obtain ammonia enriched in CO2 and a purified flue gas;

(b) regenerating ammonia enriched in CO2 in a regenerator operated at elevated pressure to obtain regenerated ammonia and a gas stream enriched in CO2; (c) regasifying liquefied natural gas via heat exchange against a heat transfer fluid, thereby obtaining natural gas and cooled heat transfer fluid;

(d) using at least part of the cooled heat transfer fluid is used to provide cooling needed in step (a) .

2. A process according to claim 1, wherein the heat transfer fluid is a cooling medium, preferably ammonia or a water-glycol mixture.

3. A process according to claim 1 or 2, wherein the ammonia absorber is operated at a temperature below 15 ⁰C, preferably in the range of from -10 to 15 ⁰C, more preferably from 0 to 10 ⁰C, most preferably from 0 to 8⁰C.

4. A process according to any one of claims 1 to 3, wherein at least 50%, preferably at least 70%, more preferably at least 90% of the cooling duty required to operate the absorber at low temperature is provided by the regasification of liquefied natural gas .

5. A process according to any one of claims 1 to 4, wherein the regasification of liquefied natural gas is done at an import terminal for liquefied natural gas .

6. A process according to any one of the preceding claims, wherein the flue gas comprising CO2 is derived from a power plant .

7. A process according to any one of claims 1 to 6, wherein the regenerator is operated at a pressure in the range of from 5 to 50 bara, preferably from 10 to 50 bara, more preferably from 20 to 50 bara.

8. A process according to claim 7, wherein the gas stream enriched in CO2 is at a pressure in the range of from 5 to 50 bara, preferably from 10 to 50 bara, more preferably from 20 to 50 bara.

9. A process according to claim 7 or 8, wherein the gas stream enriched in CO2 is compressed to a pressure in the range of from 60 to 300 bara, more preferably from 80 to 300 bara.

10. A process according to claim 9, wherein the pressurised gas stream enriched in CO2 is injected into a subterranean formation, preferably for use in enhanced oil recovery or for storage into an aquifer reservoir or for storage into an empty oil reservoir.