Carbon Capture Technologies for the European Market

Transcription

1 Technologies for the European Market Reprint from VGB PowerTech, July 2008 Authors: Dr. Daniel Hofmann Dr. Tobias Jockenhövel Dr. Georg Rosenbauer Answers for energy.

2 Technologies for the European Market Daniel Hofmann, Tobias Jockenhövel and Georg Rosenbauer Abstract CO 2 -Abscheidungstechnologien für den europäischen Markt Der vorliegende Beitrag beschreibt die Entwicklung der Technologien zur Kohlendioxid-Abscheidung vor und nach der Verbrennung. (Pre- Combustion und Post-Combustion). Bei der Pre-Combustion-Abscheidung liegt der Schwerpunkt in erster Linie auf der Integration und auf konzeptionellen Themen. Bei der Post-Combustion-Abscheidung kommen noch Lösungsmittelcharakterisierung und -auswahl hinzu. Um den aktuellen und in Zukunft noch wachsenden Strombedarf zu decken, wird der Strom auch in Zukunft zum größten Teil aus fossilen Energieträgern erzeugt werden. Da für die neuen kohlebefeuerten Kraftwerke in der EU capture ready, also die Eignung eines Kraftwerks für die CO 2 -Abtrennung, Voraussetzung für die Genehmigung ist, wird der vorliegende Beitrag außerdem darüber informieren, was eine capture ready Ausführung für fossilbefeuerte Kraftwerke aus technischer Sicht bedeutet. Um die weltweiten CO 2 -Minderungsziele zu erreichen, müssen mehrere Maßnahmen gleichzeitig ergriffen werden. Der Energieindustrie wird beim Erreichen dieser ehrgeizigen Ziele eine wichtige Rolle zukommen. In dem Text werden zwei verschiedene Technologien erörtert: Die Pre- und die Post-combustion (CO 2 -Abscheidung), mit denen die Nutzung der fossilen Ressourcen möglich ist, bei gleichzeitiger Begrenzung des damit verbundenen CO 2 -Ausstoßes. Die Pre-Combustion-Technologie beruht auf der bewährten Umwandlung von Kohle oder anderen Brennstoffen in Synthesegas. Das Kohlendioxid kann mit einem physikalischen Abscheidungsprozess aus dem Synthesegas entfernt werden. Dieser Prozess hat sich bereits in großtechnischem Maßstab in der chemischen Industrie bewährt. Hier werden die einzelnen Komponenten besprochen und einige der gemachten Erfahrungen beschrieben. Bei der Post-Combustion-CO 2 -Abtrennung handelt es sich um eine Technologie am Ende des Energieumwandlungsprozesses, die gleichermaßen geeignet ist für Neuanlagen und für Nachrüstungsprojekte. Siemens entwickelt derzeit einen eigenen Prozess auf der Basis eines neuartigen Lösungsmittels. Mit diesem Lösungsmittel lassen sich einige der Schwierigkeiten ausräumen, die andere Lösungsmittel bereiten. Derzeit liegt der Schwerpunkt der technologischen Entwicklung auf der Abtrennung von CO 2 aus den Kohlekraftwerken; aber auch die Abscheidung von CO 2 aus Gaskraftwerken ist in Reichweite. Authors Dr. Daniel Hofmann Dr. Tobias Jockenhövel Dr. Georg Rosenbauer Siemens AG, Energy Sector Erlangen/Germany. Introduction To achieve the target for global carbon reduction of 50 % by 2050, a reduction of emissions by 30 % is required in the European Union by This reduction has to increase further in the time frame up to Legislation currently being debated calls for captureready design of coal-fired power plants in 2015 and mandatory capture in Siemens as an integrated technology company is committed to supporting climate change mitigation measures especially in the field of technology development. Any development has to be technologically feasible but at the same time economically sound. Background The current forecast for energy consumption and power production indicates an increasing use of fossil fuels. Even if there is a relative decrease in the share of fossil fuels amongst energy sources forecast for electricity production, absolute usage will increase by almost 60 % up to 2030 according to an IEA forecast (Figure 1). This usage of fossil fuels with its carbon dioxide emissions is recognised as a major threat to our climate. Siemens is taking this threat seriously and is committed to developing mitigation steps. One of the contributors to carbon dioxide emissions is the use of fossil fuels for power generation. Even though the emissions from power stations are estimated to contribute only about 26 % of the total anthropogenic greenhouse gas (GHG) emissions, power plants are one of the focal areas for mitigation steps as this source is concentrated in a limited number of stationary emitters. All this points to a major role for coal-based power generation and a key role for carbon capture for the mid-term. However, legislative impacts have to be considered in this picture. As an example of the EU s view on global climate efforts, the JRC reference report takes a look into The global climate situation for 2030 and beyond [2]. It compares different scenarios and may have impact on the legislative situation relating to fossil-fueled power plants. The report summarises three scenarios: the base scenario with business as usual, the reference scenario with saving activities to reduce energy import dependencies and the GHG scenario with additional trade mechanisms to reduce carbon footprint. Only the GHG scenario is capable of supporting the EU s 2 C goal with the required 450 ppm atmospheric CO 2 cap. The reference scenario shows a significant decrease in total energy consumption in the developed countries (+7 % vs. +22 % up to 2030 compared to 2005) with an almost constant level for the EU27. This level is achieved without any impact from the action plan for energy efficiency formulated in 2006 that targets a 20 % reduction by This reference scenario shows quite an impact on a global scale by reducing the increase in energy consumption from +131 % to +111 %. However, those reductions alone are not enough to support the 2 C scenario envisioned by the EU. The achieved reductions against the base scenario are about 25 % of what is needed in 2030 and beyond. The report references two major sources for carbon dioxide reduction energy savings and reduced carbon intensity. The latter is mainly impacted by the power sector. The different scenarios have different impacts on power business and particularly on fossilbased power business. Whereas in the base scenario about 50 % of the electricity generation will be fossil-based in 2030, the GHG scenario shows about 34 %. As stated before, a significant portion of the reduction originates from energy saving. The remainder of the changes results from the envisioned reduction in CO 2 emissions in the power sector. Those stem from five different sources: The main driver is power plant efficiency improvement. By 2030, the average efficiency of fossil-fuelled plants is forecast to increase from 35 % to 46 %. This rise in efficiency is contributed to the replacement of aging coal plants with combined-cycle plants. After 2030, a slight reduction is anticipated due to the introduction of carbon capture technologies and the impact those technologies have on plant performance. A second strong driver pinpointed in the report is the switch from coal to gas, an effect that is already described in the first driver. Where coal is seen to more than double up to 2050 in the base scenario compared to 2005, it decreases significantly in the GHG scenario to about 20 % of this base value. The replacement of con- 52 VGB PowerTech 7/2008

3 Power genaration (in TWh1)) Renwables (excl. hydro) in 2005: 400 TWh (2% of total) 2.7% p.a. 35,000 Hydro 15% Renwables (excl. hydro) in 2030: 3,200 TWh (9% of total) Geothermal 16% Wind 28% Solar 1% 55% Biomass 18,000 16% 15% 6% 20% 40% Fossil fuels 66% 62% Nuclear 14% Gas 23% Oil 3% Coal 36% Geothermal Solar 6% 13% Wind 51% Others 1% Biomass 29% Source: Siemens Energy Sector, GS4 base case 1) Terrawatt-hours Copyright Siemens AG All rights reserved Figure 1. Renewables are gaining in importance but fossil fuels will continue to be the mainstay. ventional coal-fired plants with higher efficiency plants (supercritical, IGCC) with the capability for carbon capture is also listed in this category. Almost half of the coal plants in 2030 are seen to be carboncapture plants, with a share of 90 % in This is in line with the current debate on capture readiness in 2015 and mandatory capture in CO 2 capture before combustion (Pre-combustion) IGCC process (coal) or IRCC process (natural gas) 10 m3/s, 40% CO * 2 Fuel O 2 Gasification Integrated CO 2 capture (Oxyfuel) Coal O 2 Syngas cleaning CO shift The third driver in the report is the increased share of renewables that are considered carbon-neutral. Where the strong increase in wind energy is understandable, the usage of biomass on the same order of magnitude (about 7 % of total electricity generation in 2030) is questionable. Parallel targets of 10 % biofuel in the transport sector and an increase in world population CO 2 capture Combined cycle with H 2 turbine CO 2 Steam generator Flue gas cleaning Condensation CO 2 /H 2 O CO 2 capture after combusition (Post-combustion) Conventional PP with CO 2 wash Coal Air 150 m3/s, 70% CO 2 * 1000 m3/s, 14% CO 2 * CO 2 Conventional SPP Flue gas cleaning CO 2 capture CO 2 * typical for 700 MW class Copyright Siemens AG All rights reserved Figure 2. Fundamental Processes for CO 2 Capture. will put increasing pressure on agriculture. Current reports suggest that biofuels will only have a net positive impact if waste biomass can be used. The fourth driver is the resurgence of nuclear power. Even though the current permitting duration may be a hindrance; the strongest influence comes from social acceptability. It will need quite some change in mindset in a large number of countries to see a broad acceptance even in view of the climate change risks. The fifth and last driver is CCS (carbon capture and storage). The GHG scenario foresees that not only more than 90 % of the coal-fired plants will be equipped with carbon capture in 2050, but also some 70 % of the gas-fired units. This would lead to a reduction of about 60 % in carbon emissions from the power sector compared to today. This scenario will entail a significant loss in flexibility due to the need to balance the infeed of renewable energy. Taking half of the hydro part of the foreseen electricity sources as a controllable part (e.g. storage); about 15 % of the overall electricity will have a fast response time to changes in the grid. Compared with the current volatility this margin seems to be far too low. Carbon trading that is the backbone of the GHG scenario requires a carbon price tag in the EU of 37?/t CO 2 eq. in 2020 rising to about 64?/t CO 2 eq. in 2050 to support the reduction targets. VGB PowerTech 7/

4 Fuel Gas island Applications Coal Lignite Petcoke Refinery residues Biomass Fuel preparation Sulphur removal Gasifier Gasifier island Overall the GHG scenario can be seen as a potential path for achieving the 2 C target. Some of the underlying assumptions and targets are very ambitious. The technologies needed for fuel switch and carbon capture are seen as not having entered the market on an industrial scale. Introduction is anticipated to take place in the developed world with a rapid spread into the developing world once proven. The remainder of the paper will deal with those technologies and the developments made by Siemens. Technologies Air separation unit (ASU) CO Shift CO 2 removal Figure 3. The concept of an IGCC power plant. The main basic technological pathways for the capture process are well known and frequently discussed ( F i g u r e 2 ). Post-combustion is what immediately comes to mind. In a quite similar way to desulphurisation the entire flue-gas stream is treated in a CO 2 scrubber, typically based on an amine process. Pre-combustion capture is a method for pre-treating the fuel gas and extracting CO 2 before combustion. Compared to post-combustion capture the treated gas volume is only 1 with more than twice the CO 2 concentration. Scrubbing of a much smaller gas volume under pressure in an oxygen-free environment is far easier and already proven in large-scale chemical industry applications. This can be performed in integrated gasification combined cycle plants (IGCC), where the fuel is converted to synthesis gas before it is fed to the power plant section. Finally, a further alternative is the oxyfuel processes where instead of burning the fuel in air the combustion process uses pure oxygen. This keeps the nitrogen in ambient air out of the process, and the flue gas consists mainly of CO 2 and steam. CO 2 separation is then simply implemented by condensing the steam. Here, the necessary developments are to be seen in the oxygenbased combustion boiler (with air entrainment an issue here), the flue-gas cleaning processes Syngas (CO + H 2 ) Combined cycle FT synthesis Methanol synthesis Ammonia production Power Copyright Siemens AG All rights reserved and finally water condensation from a gas stream of at least two components. Pre-combustion IGCC Transportation fuels Methanol Ammonia / fertiliser Hydrogen Chemicals and Synfuel production Pre-combustion capture with IGCC is a power generation technology that uses proven gasification technology to transform coal and other fuels into a synthesis gas (syngas) which is used in a combined cycle to produce power. The applied processes to capture up to 90 % CO 2 from the syngas are available and well proven in the chemical industry. In addition, IGCC offers the option of polygeneration (where power, steam and high-grade products are produced in parallel) with important advantages. The general benefits of pre-combustion capture are: very low air pollutant emissions proven CO2 capture process fuel flexibility of SFG (Siemens Fuel Gasification) gasifier for a wide range of solid (and liquid) fuels lower water usage and solid waste production can be integrated into polygeneration facilities phased construction possible. The concept of an IGCC power plant ( F i g- u r e 3 ) incorporates an oxygen- or airblown gasifier operating at high pressure and producing raw gas which is cleaned of most pollutants and burned in the combustion chamber of the gas turbine-generator for power generation. The sensible heat of the raw gas and hot exhaust gas from the turbine are used to raise steam which is also used for power generation in the steam turbine-generator. The main system and integration targets are: nearly complete gasification of the feedstock. efficient removal of dust and other pollutants from the gas, meeting the requirements of both gas turbine blading and environmental protection effective integration and coupling of subsystems detailed below in terms of process engineering, plant operations and thermodynamic considerations. If necessary, this concept also offers the possibility of heat generation for process heat and district heat extraction (cogeneration) as well as co-production of chemicals such as hydrogen, ammonia, urea, methanol, etc. or even synthetic gasoline, resulting in a considerable increase in the primary energy utilisation factor. The gasifier feedstock is more or less completely gasified to syngas with the addition of steam and either enriched oxygen or air. The well-known fixed-bed, fluidised-bed and entrained-flow gasifiers for coal are basically suited to integration in the combined cycle, as well as the well-proven entrained-flow systems for refinery residues. The selection of a specific gasifier type to achieve the best cost, efficiency and emissions levels depends on the type of fuel and the particular application, and must be investigated on a case-by-case basis. In most gasifier systems applied to coal, the sensible heat of the hot raw gas is used in a syngas cooler to generate steam for the steam turbine. In some cases, considerable amounts of steam are generated in this way. This also cools the gas sufficiently so that it can be input directly into the gas purification system. In IGCC plants without CO 2 capture the steam production from the raw gas cooler contributes significantly to overall plant efficiency. This is different in processes with pre-combustion capture. In these processes an additional step, so-called CO shift conversion, is included as part of the syngas treatment chain. In this additional step, CO is converted with H 2 O (steam) to CO 2 and H 2 (hydrogen). The CO 2 is then removed and the remaining fuel has a higher hydrogen content than a syngas without CO 2 capture. Most of the generated steam from a raw gas cooler is used for saturation of the syngas upstream to the CO shift. In that case a direct water quench in the gasifier proves to have similar efficiency, while being much more robust and less costly. Dust, soot and heavy metal removal are key issues for initial raw gas purification downstream of syngas cooler and quench system. Subsequently, chemical pollutants such as H 2 S, COS, HCl, HF, NH 3 and HCN are removed, along with the remaining dust. The separated H 2 S-rich gas stream, known as acid gas, is processed to recover saleable elemental sulphur. Downstream of the gas purification system, the clean gas is reheated, saturated 54 VGB PowerTech 7/2008

5 Feedstock preparation Air separation unit Coal feedstock Quench water Oxygen Reaction 1300 to 1800 C Quench Steam Slag Slag discharge system Gasifier island Raw gas cleaning Black water treatment Sludge Raw syngas to gas cleaning Water In addition to air for the combustion chambers, the compressor of the gas turbine-generator also supplies all or part of the air for the ASU. Nitrogen from the ASU is mixed with the purified gas to prevent temperature peaks in the low-no x burners and to increase the mass flow rate in the gas turbine. In the case of air-blown gasification, the extracted air is supplied directly to the gasifier following additional compression. The hot exhaust gases from the gas turbine raise steam for the steam turbine in an unfired heat-recovery steam generator (HRSG) before they are discharged via the stack. The steam turbine is supplied with steam from the gas turbine heat-recovery steam generator. As was already mentioned, the heat from the raw gas is also used to raise steam for the steam turbine when gasifiers with high gas outlet temperatures are implemented. Figure 4. Siemens advanced technology gasifier. Copyright Siemens AG All rights reserved with water if necessary (NO x reduction) and supplied to the gas turbine combustion chamber. In this way, low-level heat can be used and gas turbine mass flow is increased. The air separation unit (ASU) generates the more or less enriched oxygen supply necessary for the gasification process. The inevitably co-produced nitrogen from the ASU is preferably to be used in the gas turbine cycle, and, in case of coal, smaller amounts for transportation of the solid fuels to the gasifier and for inerting purposes. Gasifier The advanced technology of Siemens fuel gasification continues ( F i g u r e 4 ) a longstanding Siemens tradition of satisfying the needs of our customers worldwide. High availability, low life-cycle costs and multi-fuel capability are among the most important factors for being competitive. Siemens fuel gasification technology addresses all of these key competitive drivers. Customers/plant (Location) Hörde Steelworks (Dortmund, Germany) Handan Iron & Steel (Handan, P.R. China) U.S. Steel Corp. (Chicago, USA) STEAG/Kellermann (Lünen, Germany) DOW Chemicals (Plaquemine, USA) Nuon Power Buggenum (Buggenum, the Netherlands HRL (Morwell, Australia) Sydkraft (Värnamo, Sweden) ELCOGAS (Puertollano, Spain) ISAB Energy (Priolo Gargallo, Italy) ELETTRA GLT (Servola, Italy) ARBRE (Eggborough, UK) EniPower (Sannazzaro, Italy) Electrical outout (net) 8 MW VM5 Gas turbine Main Features Start-up Blast-furnace-gas-fired, gas turbine as compressor drive 1960/ MW CW201 Blast-furnance-gas-fired gas turbine MW V93 First CC plant in the world with integrated LURGI coal gasification (hard coal) MW 1 2 x W501D5 CC plant with integrated DOW coal gasification MW V93 10MW Typhoon 6 MW Typhoon 300 MW V MW 2 x V94.2K CC plant with integrated SHELL coal gasification (hard coal and biomass blend) CC plant with integrated drying gasification process (lignite) First CC plant in the world with integrated biomass gasification CC plant with integrated PRENFLO coal gasification (coal and petroleum coke blend) CC plant with integrated TEXACO heavy-oil gasification (asphalt) / / MW V94.2K CC plant with steel-making recovery gas MW Typhoon CC plant with integrated biomass gasification 2002 CC plant fuelled with syngas from SHELL 250 MW V94.2K 2006 heavy-oil gasification MW from syngas and 48 MW from natural gas; 2 Natural gas firing; 3 Oil firing; V94.2K = V94.2 with modified compressor Total experience with gas turbines for syngas/igcc sums up to more than 450,000 operating hours. Including steel mill application the total experience is over 650,000 hours. Figure 5. Syngas GT references. VGB PowerTech 7/

6 This advanced technology (formerly known as GSP technology) was developed in 1975 with a focus on low-grade lignites. Since then, the range of usable feedstocks has been broadened from conventional fuels to include recycled liquid chemical wastes and refinery residues, biomass and other waste materials. With an increasing trend toward clean coal solutions, Siemens gasifiers are equally suited for power generation in IGCC applications, as well as other industrial applications. Starting as low as 200 MWth, Siemens gasifiers are available in sizes up to 500 MWth. During the last year, SFGs has been ordered or pre-selected for a number of projects in China, North America, and other countries. These gasifiers are scheduled to start operation in 2009 and 2010 using a wide range of coals from Chinese anthracite to Illinois bituminous coals. Experience gained at these coal-tochemical projects will provide a strong experience base for future IGCC plants. Gas Turbines With more than 400,000 hours of successful syngas operation, Siemens gas turbines (SGTTM) are particularly suitable for IGCC applications. Siemens state-of-the-art gas turbine systems offer higher output than in their natural gas applications and better efficiency for lower cost of electricity and lower emissions in IGCC applications ( F i g u r e 5 ). Siemens offers a wide range of gas turbines for IGCC applications, with integration options from 0 % to 50 % air integration that enable IGCC plant designs with elevated performance and high reliability. For the 50-Hz market these are: E-class: References for 0 % and 100 % air integration in EU Advanced E-class (0 % 50 % air integration) bid ready recent order in China F-class: Advanced F-class engine under development Based on GT platform only minor modifications Development dedicated to CCS applications 0 % 50 % air integration Ready for bid in short term Other Components Steam Turbines Siemens offers a range of steam turbines for any IGCC application with sub-critical and supercritical steam inlet conditions. IGCC Power Island (SGCC6-5000F 2x1) Siemens can provide the entire power island for large IGCC plants. We have developed an Customer/plant (Location) DOW Chemicals (Plaquemine, USA) Nuon Power Buggenum (Buggenum, The Netherlands) Global Energy/Wabash River (West Terre Haute, USA) Tampa Electric/Polk Country (Mulberry, USA) ELCOGAS (Puertollano, Spain) NPRC/Negishi (Negishi/Japan) Opti/Long Lake (Alberta, Canada) Figure 6. Compressor references. Post-combustion carbon capture process development Piloting and optimisation ASU main air compressor ASU air compressor (for start-up) N 2 compressors, O 2 compressor ASU main air compressor O 2 compressor ASU air compressor N 2 compressors, O 2 compressor IGCC plant Instrumentation & control system Claus gas compressor IGCC plant optimisation and integration study ASU main air compressor N 2 /air compressors, O 2 compressor ASU main air compressor Basic eng. Siemens scope Start-up IGCC power island reference design for a nominal 600-MW plant based on our proven natural-gas-fired 2x1 reference plant. The power island has been upgraded to include a steam bottoming cycle that is fully integrated in the gasification island and a larger steam turbine to maximise plant output. O 2 /N 2 /CO 2 /air Compression Solutions Siemens has provided most of the major compression solutions for the IGCC plants currently in operation around the world. Solutions for IGCC applications are available for the main air compressor of the air separation unit, and O 2, N 2 and CO 2 compression ( F i g - ure 6). IGCC Plant Instrumentation and Controls For IGCC applications, Siemens has combined its new Siemens Power Plant Automation (SPPATM) system with our proven IGCC plant instrumentation and controls experience. The SPPA-T3000 is based on a unique 3-tier IT architecture using server/client networking and information management concepts commonly used today. The SPPA-T3000 is capable of controlling not only the power island but also the entire plant, including the gasification island(s) and the air separation unit(s). IGCC Services Siemens has developed a comprehensive programme of service options to ensure longterm success. This covers not only the power island but also the gasifier island. Maintenance services Service agreements Operation and maintenance services Training and consulting. Integrated Project Approach Siemens offers truly customisable IGCC solutions everything from an equipment-only solution to providing the complete IGCC power island on a turnkey basis. Together with a partner from the process industry we are able to deliver the entire IGCC and provide comprehensive services. Engineering & construcion of post-combustion carbon capture demo plant Detail eng. Process- and modelldevelopment Construction and Installation Comissioning In October 2000 Siemens acquired the Corp. Engineering and the Chemical Process Development activities of former HOECHST AG (company comparable with e.g. Bayer or DOW) Combining the know-how and experiences out of the power generation and chemical processing industries leads to state-of-the-art carbon capture technologies and derived concepts for the integration thereof into the power plants and provides a solid basis for the implementation of the projects Plant support Figure 7. Mastering the whole chain: from process development to implementation of projects. 56 VGB PowerTech 7/2008

7 Siemens process shows major advantages compared to capture processes based on MEA. Stringent environmental requirements are easily met Low degradation (O 2 ) Solvent slip nearly zero Decarbonised gas to stack CO 2 -enriched gas CO 2 compressor (intercooled) Solvent slip nearly zero Lean/rich solvent heat exchanger Scrubber Cooler Stripper CO 2 for sequestration Blower Reboiler Low energy demand Cooler Flue gas from FGD plant MP/LP crossover Steam extraction Condensate preheating Further development with regard to solvent, auxiliary loads and heat demand is ongoing for optimal integration in an SPP. Figure 8. Post Combustion Capture Process Principle Siemens process shows major advantages. Post-combustion Capture Compared to the capture processes based on MEA, we are performing process optimisation with regard to solvent, auxiliary loads and heat demand, and we will optimally integrate the process in an SPP. Since Siemens acquired the Corp. Engineering and Chemical Process Development activities of the former HOECHST AG in October 2000, it masters the whole chain from process development to project implementation because the know-how and experience from power generation and the chemical processing industries can be combined. This synergy enables us to develop state-of-the-art carbon capture technologies and derive concepts for their integration into power plants, and provides a solid basis for project implementation ( F i g u r e 7 ). With the PostCap project, Siemens Energy is pursuing the development of a proprietary postcombustion capture process. The major components of the PostCap process are visualised in Figure 8. The development project includes process validation in a slip-stream pilot plant on an E.ON power plant site. The optimally integrated capture process based on the improved solvent will show major advantages compared to MEA-based processes, e.g. the solvent shows potential for lower plant investment and operating costs. The major advantages of the applied solvent are: No vapour pressure, i.e. near-zero solvent emissions, minimized solvent losses and lower contamination of CO 2 stream Lower solvent degradation, i.e. good O 2 stability and low cost for solvent make-up Lower energy demand, i.e. reduced loss of power plant efficiency Absorption and desorption possible in a wide pressure range, i.e. low-grade steam can be used for desorption In addition, this chemical absorption process for flue-gas cleaning is economically attractive because most costs result from the energy required for absorbent regeneration and by absorbent degradation. As we expect to progress significantly on both points, this- chemical absorption process for flue-gas cleaning is economically attractive. Compared to the classic MEA absorption process, the new process has several advantages: Less energy is required for absorbent regeneration, and the absorbent is more stable. Information on the Absorbent Siemens uses a chemical absorbent because chemical absorbents are characterised by a high selectivity and absorption capacity. In addition, the absorbent used in our process is characterised by the fact that there are very few absorbent emissions caused by absorbent entrained with the flue gas. This significantly reduces equipment complexity. Furthermore, the absorbent itself can easily meet stringent environmental requirements. Test Equipment and Pilot Plant At Hoechst Industrial Park, Siemens has been operating a lab unit that can be used for analysing absorbent properties during CO2 absorption for almost three years, performing long-term stability tests and validating the process. This lab unit is characterised by continuous closed-loop operation of the complete absorption and desorption process within a wide range of operating conditions. The lab unit has been operated several thousands of hours for trials since its initial start-up. In the second project phase, a pilot plant will be installed on one of the E.ON hard coalfired power plant sites. There are some particularly appropriate options which will be evaluated against each other. The project timing schedules the start of pilot plant operation for August VGB PowerTech 7/

8 Focus on Coal-fired Power Plants Since coal-fired power plants globally have a higher potential for reducing CO 2 emissions, the focus will first be on process optimisation for hard-coal and lignite-fired power plants. The process will later be adapted to match the conditions in natural-gas-fired power plants. Capture-ready New steam power plants constructed in the near future are required to have the ability to incorporate a carbon capture plant at a later date. Siemens is currently reviewing the plant layout of the up-to-date steam power plant SSP in order to incorporate the necessary measures to be capture-ready. The capture-ready definition is based on the following topics: enable or facilitate later integration of a carbon capture plant, avoid lock-ins which exclude or hinder use of future capture developments, delete aspects that make retrofit of capture plant impossible. This results mainly in space and access requirements for additional equipment and auxiliaries, necessary energy supplies and provisions for cooling requirements. Influenced power plant areas with a varying degree of impact from capture ready measures are: overall plant layout with rearrangement of components and sufficient space for the whole capture plant (mainly absorption and desorption columns) as well as CO 2 compressor set according to their technological requirements steam turbine building with space for modifications to steam turbine, routing of various large piping as well as space for heat exchangers for low-grade heat utilisation (e.g. from CO 2 compressor intercoolers) steam turbine able to be rebuilt for requirements of future capture plant necessities flue-gas system ready for incorporation of additional/modified blower, additional/enlarged desulphurisation plant and tie-in for the capture plant cooling system with sufficient space for additional coolers or prepared for additional circulating water pump electric auxiliary power supply and cable routing prepared for expansion preparation for enlargement of raw water receiving and treatment, as well as provisions for waste water disposal. Summary To achieve the global carbon dioxide emissions reduction targets, several measures need to be taken simultaneously. The power industry will have to play a major role in achieving these ambitious targets. As none of the current replacement technologies will be adequate to meet today s and tomorrow s increasing electricity needs, the majority of power production will continue to be fossil-based. Two technologies are presented in the paper at hand, pre- and the post-combustion carbon capture that will enable the use of fossil resources while limiting the associated carbon footprint. Pre-combustion technology is based on the proven gasification of coal or other fuels into syngas. The carbon dioxide can be removed from the syngas by a physical removal process proven in large-scale chemical industry applications. The individual components are discussed and some of the Siemens experiences presented. Post-combustion carbon capture is an end-ofpipe technology equally suited for new plants and for retrofits. Siemens is developing a proprietary process based on a new solvent. The solvent chosen will overcome several of the hurdles associated with other solvents. The current focus is on coal-based plants due to the reduced capture costs. However, gas-based power generation is equally accessible. One of the latest EU directives [3] currently under debate calls for capture readiness for all power plants >300 MW. Siemens is studying the needs for a capture-ready design. This will not only entail the space required, but also accessibility, the need to consider tie-in points, optimised layout, oversizing or potential for enlargement of cooling systems and auxiliary power supply to name just a few issues. The developments described cover the capture of carbon dioxide. Equally important, but not treated in this paper are the advances in technology to increase the efficiency of power generation and reduce auxiliary power consumption. Siemens is working extensively in both of those fields. References [1] Intergovernmental Panel on Climate Change (IPCC) final report 4th assessment on climate change, 17. Nov [2] JRC reference report, global climate policy scenarios for 2030 and beyond, [3] Proposal for a DIRECTIVE OF THE EURO- PEAN PARLIAMENT AND OF THE COUN- CIL on the geological storage of carbon dioxide and amending Council Directives, 85/337/ EEC, 96/61/EC, Directives 2000/60/EC, 2001/80/EC, 2004/35/EC, 2006/12/EC and Regulation (EC) No 1013/2006, Brussels, , COMMISSION OF THE EURO- PEAN COMMUNITIES. 58 VGB PowerTech 7/2008

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10 This article appeared in: VGB PowerTech July 2008, Pages Copyright 2008 by VGB PowerTech This reprint is published by: Siemens AG Energy Sector Freyeslebenstrasse Erlangen, Germany Siemens Power Generation, Inc Alafaya Trail Orlando, FL , USA For more information, contact our Customer Support Center. Phone: Fax: (Charges depending on provider) support.energy@siemens.com Fossil Power Generation Division Order No. E50001-G220-A103-X-4A00 Printed in Germany Dispo 05400, c4bs No K SD Printed on elementary chlorine-free bleached paper. All rights reserved. Trademarks mentioned in this document are the property of Siemens AG, its affiliates, or their respective owners. Subject to change without prior notice. The information in this document contains general descriptions of the technical options available, which may not apply in all cases. The required technical options should therefore be specified in the contract.