GB2457950A - Improved process for the capture and disposal of carbon dioxide - Google Patents
Improved process for the capture and disposal of carbon dioxide Download PDFInfo
- Publication number
- GB2457950A GB2457950A GB0803867A GB0803867A GB2457950A GB 2457950 A GB2457950 A GB 2457950A GB 0803867 A GB0803867 A GB 0803867A GB 0803867 A GB0803867 A GB 0803867A GB 2457950 A GB2457950 A GB 2457950A
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- Prior art keywords
- carbon dioxide
- unit
- gas
- solvent
- minus
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- B01D53/34—Chemical or biological purification of waste gases
- B01D53/343—Heat recovery
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Abstract
A hydrogen-containing, high carbon monoxide, low carbon dioxide content gas is mixed with an oxidising gas at high, preferably about 35 bars or above, pressure and fed to a reactor system in which the carbon monoxide is converted, largely or completely, into carbon dioxide. The carbon dioxide-rich product gas stream is cooled and then treated to facilitate cold processing, before being further cooled to condense carbon dioxide, which is removed as a liquid, pumped to pipeline pressure and exported. Cooling temperature is not below carbon dioxide solidification temperature of minus 56, and is preferably between minus 20 to minus 30 degrees Celsius. The remaining carbon dioxide is removed from the product gas, by solvent washing. The resulting carbon dioxide-rich solvent is stripped of carbon dioxide at said high pressure in a counter currently operated column, or columns, by one or other or both reaction gas streams, singly or in partial or complete combination. The carbon dioxide-lean solvent is returned to solvent washing for re-use, and the carbon dioxide-laden reactant or reactants stream or streams fed to the reactor system, to raise the carbon dioxide concentration in the reaction product gas stream such that substantially all net carbon dioxide reaction product is condensed in said further cooling stage and removed as liquid for pumping to pipeline pressure and export. The low carbon dioxide content product gas stream leaving solvent washing is sent on to end-use.
Description
Description
Increasing global concerns over the causative effect of carbon dioxide emissions in world climate change have led to a variety of countermeasures such as increased investment in wind power, nuclear power, and natural gas combined cycle power plants. In both Europe and the USA attention has also been focussed on clean coal technology incorporating coal gasification and the capture of carbon dioxide, followed by its compression to about 155 bars and export to pipeline. Such gas can then be used for enhanced oil recovery by injection into depleting fields or injected into depleted oil or gas reservoirs for safe storage.
There is a major negative impact of carbon dioxide capture and export upon the costs and thermal efficiencies of such clean coal plants. The invention is aimed at reducing this impact significantly.
The increased use of natural gas for power generation is placing pressure on supplies which in turn leads to price increases. This has led to proposals to construct coal-based substitute natural gas (SNG) plants in the USA. Such plants emit large amounts of carbon dioxide to atmosphere and are, like coal-based power plants, sure to be subject to regulations enforcing carbon dioxide capture and safe disposal. The invention is also aimed at significantly reducing the negative impact of carbon dioxide capture and disposal on the costs and thermal efficiencies of such SNG plants.
New build pulverized coal-based steam cycle power plants will suffer especially large negative impacts on costs and thermal efficiencies if, as seems likely, carbon dioxide capture and disposal is mandated. This makes the use of coal gasification as above-mentioned more attractive. The invention can be employed in conjunction with coal gasification to pennit direct combustion of a major portion of the resulting coal gas for steam raising and use in steam turbines, a lesser portion being used in a gas turbine power plant integrated with the steam cycle.
In order that the invention can be better understood three examples of its application will be given: (A) In a coal gasification combined cycle power plant (B) In a coal-based SNG plant (C) In a coal gas fuelled steam power plant integrated with a smaller coal gas-fuelled gas turbine plant.
Example (A)
Reference is made to figure 1.Unit I is coal gasification unit, unit 2 is a carbon monoxide shift conversion unit, unit 3 is a heat recovery and cooling unit, unit 4 is pre-treatment unit which renders shifted cooled gas fit for cold processing, unit 5 is a cold recovery unit using conventional heat exchange art, unit 6 is a cold processing unit, equipped with refrigeration means, which carries out shifted gas cold processing, unit 7 is a solvent wash unit to effect residual carbon dioxide removal from the exit gas of unit 6, unit 8 is a solvent stripping unit to remove carbon dioxide from used (rich) solvent and enable its re-use as regenerated (lean) solvent in unitl, and unit 9 is a product gas fuelled combined cycle power unit.
Unit 1 employs dry coal feed, oxygen-blown gasification to produce a gas, which after suitable treatment, is sulphur free and has the following typical analysis in volume percent: Hydrogen 30 Carbon monoxide 65 Carbon dioxide I Nitrogen 4 Said gas is assumed at a nominal pressure of 35 bars through items 1,2,3,4,5,6,7,and 8.11 is passed to item 8 where it is used to counter-currently strip carbon dioxide from rich solvent in a pressurized stripping column provided with suitable mass transfer means. The resulting carbon dioxide-laden gas is passed to unit 2 in which steam is added by known means e.g. by saturation using hot water in counter-current contact, and subjected to the well known shift reaction in a single or multi-stage reactor system. The hydrogen-rich shifted gas with its content of recycled carbon dioxide from unit 8 is passed to unit 3 for heat recovery and cooling and is then treated in unit 4 to render it fit for cold subsequent cold processing. In particular water vapour is removed to prevent ice fonnation. The treated gas is cooled in unit 5 in heat exchange with exit gas and liquid carbon dioxide from unit 6, and then is passed to unit 6 where the gas is further cooled to condense out liquid carbon dioxide. Such cooling must be limited in order to avoid solid carbon dioxide formation which occurs at minus 56 degrees Celsius. In practice the lower temperature is considerably higher and in the range minus 20 to minus 30 degrees Celsius, such that the carbon dioxide content of the exit gas lies in the range 201040 percent by volume. Liquid carbon dioxide is removed and passed to unit 5 to recover its cold content, before or after being pumped to pipeline pressure of about 155 bars and is then exported to pipeline for disposal.
Hydrogen-rich gas with lowered carbon dioxide content is passed to unit 5 for cold recovery and then passed to unit 7 where its carbon dioxide content is further reduced by solvent washing. The resulting low carbon content hydrogen-rich gas is passed to unit 910 fuel the gas turbine and produce electricity for export. Carbon dioxide-rich solvent from unit 7 is passed to unit 8 to be counter-currently stripped of carbon dioxide by high carbon monoxide, low carbon dioxide content gas from unit 1.Thus only a small amount of carbon dioxide goes forward to unit 9 and is emitted to atmosphere, the major portion being removed as liquid in unit 6 and exported to pipeline.
In order to benefit the shift reaction equilibrium in unit 2, and counteract the effect of the recycled carbon dioxide, hydrogen may be removed from unit I product gas, before it is passed to unit 8, by means of well known hydrogen permeable membrane technology, and used locally as carbon free fuel gas or exported. For local fuel gas use in the gas turbine of unit 9 the hydrogen permeates through the membrane into a counter current inert sweep gas, which is at a pressure appropriate to gas turbine 2) requirements. Such gas is readily available from the oxygen plant contained in unit 1, and is conventionally added to gas turbine fuel gas as a means to suppress nitrogen oxides formation in the gas turbine combustors in coal gasification combined cycle power plant designs. A low calorific value fuel gas at required pressure for the gas turbine of unit 9 is thus produced, which is blended with hydrogen rich fuel gas from unit 7 to yield a medium calorific value fuel gas turbine fuel for use in unit 9. A further benefit of the removal of hydrogen from unit 1 product gas is to reduce the flow of gas through units 2,3,4,5,6,7, and 8.
The power requirement for carbon dioxide removal and disposal in this example of the invention is about 30 Kwh per ton of carbon dioxide, compared with about 150 kwh per ton by conventional means employing solvent wash only and compression of carbon dioxide gas to pipeline pressure. This represents an improvement in overall power generation efficiency of about 3 percentage points.
Example (B)
Reference is made to figure 2. UnitS I,3,4,5,6,7,and 8 are as described in figure 1 of example (A). Unit 2 is a reactor system in which both shift and methanation reactions are performed simultaneously over the same catalyst. The British Gas HICOM process is an example of such a system. Unit 9 is a SNG export facility including dehydration, odonzation, and compression up to pipeline pressure. Units 1,2,3,4,5,6,7 and 8 all are assumed to operate at a nominal pressure of 35 bars.
Cooled and sulphur free gas from unit I having the same composition as in example (A) is split into two streams X and Y. Stream X which may be as low as one third of the total is passed to unit 8 in which it is used to counter-currently strip carbon dioxide from rich solvent transferred in from unit 7. Stream X, laden with carbon dioxide is added to stream Y and the resulting stream is passed to unit 2, where simultaneously occurring shift and methanation reactions are performed to produce a gas which may contain roughly 27 percent of methane and 73 percent of carbon dioxide by volume ( nitrogen-free basis). This composition includes the carbon dioxide recycled in stream X. Said gas is passed via unit 3 to unit 4 for cold processing pre-treatment and then to unit 5 to be cooled by heat exchange with cold methane rich exit gas and liquid carbon dioxide from unit 6. The gas is further cooled in unit 6 to not lower than minus 56 degrees Celsius, and preferably between minus and minus 30 degrees Celsius, and liquid carbon dioxide is removed. Said liquid carbon dioxide is passed through unit 5 to recover its cold content before or after being pumped to pipeline pressure of about 155 bars and is then exported. The methane rich gas with reduced carbon dioxide content is passed through unit 5 to recover its cold content and then passed to unit 7 where its carbon dioxide content is further reduced by solvent wash. The resulting methane rich product gas is passed to unit 9 for conditioning and export as SNO. The rich solvent from unit 7 is passed to unit 8 to be counter-currently stripped of carbon dioxide by stream X, and the resulting lean solvent is returned to unit 7 for re-use. As in example A, only a small portion of carbon dioxide is exported in the final product.
The power requirement for carbon dioxide removal and disposal to pipeline is about 28 Kwh per ton.
In certain cases it may be required to reduce the carbon dioxide content of the SNG to very low levels. This can be done by using a portion of the exit gas from unit 7 as a sweep gas to accept hydrogen permeate in a membrane separation unit. Said hydrogen being transferred across the membrane from cooled and sulphur free gas from unit I flowing counter current to said sweep gas. The sweep gas is recombined with the remaining exit gas from unit 7. Sufficient hydrogen is so transferred into exit gas from unit 7 to enable a fmal methanation stage to convert the unwanted carbon dioxide into methane. The resulting product gas is then passed, as before, to unit 9 for conditioning and export.
Example (C)
Reference is made to figure 3, in which units 1,4,5,6,7,8 and 9 areas described in figure 1 of example A. Unit 2 is a pressurized combustion plant in which fuel gas is burnt with pressurized air and, in which steam is raised, and passed into the steam system of unit 3. Said pressurized air is provided by being extracted from the gas turbine compressor of unit 9, subjected to heat recovery and cooling and to further compression to about 35 bars. Unit 3 is a steam power plant in which hot combustion products from unit 2 are used to raise and superheat steam, which is then used in a steam turbine to generate power for export. The steam raising system of units 2 and 3 is integrated with that of unit 9. Unit 10 isa hydrogen-permeable membrane unit in which hydrogen is removed from unit 1 product gas across a membrane, which is selectively permeable to hydrogen and into a hydrogen-free, inert sweep gas stream P from unit 7, said sweep gas flowing counter-currently to the unit I product gas stream.
Gas pressure in all units is assumed at a nominal value of 35 bars, except for fuel gas pressure to the gas turbine of unit 9, which is as required by gas turbine specifications and to which sweep gas stream P from unit 7 is suitably adjusted.
Cooled and sulphur-free gas from unit 1, having the same composition as that given in example A, is split into two streams X and Y. Stream Y is passed through unit 10, where a significant portion of its hydrogen content flows through the membrane into hydrogen free, low carbon dioxide content, counter-current sweep gas stream P. Stream P leaves unit 10 and is combined with stream X to produce a fuel gas suitable for use in unit 9. Gas stream Y is passed to unit 2 and burnt with pressurized air from unit 9, said air having been previously employed to strip carbon dioxide from carbon dioxide-rich solvent in unit 8. Steam is raised in unit 3 and combined with that from units 2 and 9. Said combined steam is superheated in unit 3 and used to generate power in a steam turbine for export. Cooled combustion product gas from unit 3 is treated in unit 4 and further cooled in unit 5 before passing to unit 6, in which it is further cooled to condense out liquid carbon dioxide. As in previous examples cooling is restricted to avoid carbon dioxide solidification, to not lower than minus 56 and preferably between minus 20 and minus 30 degrees Celsius. Liquid carbon dioxide from unit 6 is passed for cold-recovery to unit 5 before or after being pumped to 155 bars and is then exported. Cold combustion product gas from unit 6 is passed through unitS for cold-recovery and then to unit 7 for removal of the major part of its c remaining carbon dioxide by solvent washing. The carbon dioxide rich solvent from unit 7 is passed to unit 8, where it is stripped of carbon dioxide by a counter-current stream of air from unit 9 as above described. The combustion product gas is then split into two streams P and Q. Stream P is passed, as previously described to unit 10 and stream Q is sent to unit 9 and after suitable pressure reduction, which may include expansion (with or without preheating) for power recovery, is mixed with gas turbine compressor delivery air and used in the gas turbine combustors where it aids in nitrogen oxides suppression. Power is generated in unit 9 for export.
It will be noted by those skilled in the art, that the direct combustion of carbon monoxide in unit 2 avoids the loss in lower heating value associated with carbon monoxide shift conversion to hydrogen, as practised in example A, and the power losses associated with the consumption of steam in the shift reaction.
The percentage of gas from unit I,which is split into stream X, depends upon the required degree of carbon removal, but even with 90 percent removal a split of almost percent is possible. It has been suggested that, in order to achieve parity of carbon emissions (on a tons of carbon dioxide per Mwh basis) with natural gas combined cycle piants, only 60 percent removal is required. Such a target would mean that stream X would amount to almost 40 percent of unit I gas output.
There are many different commercial solvent wash processes for carbon dioxide removal as described in examples A, B and C. In some processes it may be advantageous to add steam, directly or by saturation using hot water, to the stripping gas used in unit 8. Such steam increases the volume of stripping gas, acts as a source of heat, if required, for regeneration of the solvent and, if unused, passes on to be used in the subsequent reaction stage in unit 2 of figures 1,2 and 3.The selection of such processes is made on largely economic grounds.
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GB0803867A GB2457950A (en) | 2008-03-01 | 2008-03-01 | Improved process for the capture and disposal of carbon dioxide |
GB0818778A GB2457970B (en) | 2008-03-01 | 2008-10-14 | Improved process for the capture and disposal of carbon dioxide |
US13/202,946 US8980211B2 (en) | 2008-03-01 | 2009-02-24 | Method for the capture and disposal of carbon dioxide in an energy conversion process |
DK09717231.6T DK2401052T3 (en) | 2008-03-01 | 2009-02-24 | Improved method for the collection and disposal of carbon dioxide in a process for the energy conversion |
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Cited By (4)
Publication number | Priority date | Publication date | Assignee | Title |
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GB2464368A (en) * | 2008-10-14 | 2010-04-21 | Cyril Timmins | A solvent regeneration process |
US8252091B2 (en) | 2008-03-18 | 2012-08-28 | General Electric Company | CO2 recovery from IGCC power plants |
US8585802B2 (en) | 2010-07-09 | 2013-11-19 | Arnold Keller | Carbon dioxide capture and liquefaction |
US8980211B2 (en) | 2008-03-01 | 2015-03-17 | Bryan Christopher Timmins | Method for the capture and disposal of carbon dioxide in an energy conversion process |
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US8445147B2 (en) * | 2009-02-26 | 2013-05-21 | Fuelcell Energy, Inc. | Fuel humidifier assembly for use in high temperature fuel cell systems |
FR2953914A1 (en) * | 2009-12-15 | 2011-06-17 | Air Liquide | Method for separating mixture of main components of carbon dioxide, involves providing refrigeration part for process by refrigerating circuit, where refrigerating circuit circulates mixed cooling agent to cool exchanger |
GB2493400A (en) * | 2011-08-05 | 2013-02-06 | Bp Alternative Energy Internat Ltd | Separation of carbon dioxide and hydrogen |
CN103881766B (en) * | 2014-03-24 | 2015-06-10 | 中石化宁波工程有限公司 | Chilling cyclic CO (carbon monoxide) transformation process |
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US20030022948A1 (en) * | 2001-07-19 | 2003-01-30 | Yoshio Seiki | Method for manufacturing synthesis gas and method for manufacturing methanol |
WO2006037320A1 (en) * | 2004-10-08 | 2006-04-13 | Union Engineering A/S | Method for recovery of carbon dioxide from a gas |
WO2006054008A1 (en) * | 2004-11-16 | 2006-05-26 | L'air Liquide, Societe Anonyme Pour L'etude Et L'exploitation Des Procedes Georges Claude | Method and installation for combined production of hydrogen and carbon dioxide |
WO2006097703A1 (en) * | 2005-03-14 | 2006-09-21 | Geoffrey Gerald Weedon | A process for the production of hydrogen with co-production and capture of carbon dioxide |
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GB2165552A (en) * | 1984-10-11 | 1986-04-16 | British Gas Corp | Methanating synthesis gas |
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Patent Citations (4)
Publication number | Priority date | Publication date | Assignee | Title |
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US20030022948A1 (en) * | 2001-07-19 | 2003-01-30 | Yoshio Seiki | Method for manufacturing synthesis gas and method for manufacturing methanol |
WO2006037320A1 (en) * | 2004-10-08 | 2006-04-13 | Union Engineering A/S | Method for recovery of carbon dioxide from a gas |
WO2006054008A1 (en) * | 2004-11-16 | 2006-05-26 | L'air Liquide, Societe Anonyme Pour L'etude Et L'exploitation Des Procedes Georges Claude | Method and installation for combined production of hydrogen and carbon dioxide |
WO2006097703A1 (en) * | 2005-03-14 | 2006-09-21 | Geoffrey Gerald Weedon | A process for the production of hydrogen with co-production and capture of carbon dioxide |
Cited By (6)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US8980211B2 (en) | 2008-03-01 | 2015-03-17 | Bryan Christopher Timmins | Method for the capture and disposal of carbon dioxide in an energy conversion process |
US8252091B2 (en) | 2008-03-18 | 2012-08-28 | General Electric Company | CO2 recovery from IGCC power plants |
GB2464368A (en) * | 2008-10-14 | 2010-04-21 | Cyril Timmins | A solvent regeneration process |
GB2464368B (en) * | 2008-10-14 | 2011-02-09 | Cyril Timmins | High pressure physical absorption regeneration process |
US8585802B2 (en) | 2010-07-09 | 2013-11-19 | Arnold Keller | Carbon dioxide capture and liquefaction |
US9103584B2 (en) | 2010-07-09 | 2015-08-11 | Arnold Keller | Carbon dioxide capture and liquefaction |
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GB2457970B (en) | 2011-05-18 |
GB0803867D0 (en) | 2008-04-09 |
GB2457970A (en) | 2009-09-02 |
GB0818778D0 (en) | 2008-11-19 |
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