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PowerClean

FOSSIL FUEL POWER GENERATION

STATE-OF-THE-ART

PowerClean Thematic Network

FOSSIL FUEL POWER GENERATION

STATE-OF-THE-ART

Report prepared by PowerClean R, D&D Thematic Network

30th July 2004 Cover Photograph: Neideraussem Lignite-fired Power Station. Reproduced by permission of RWE Gmbh.

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Acknowledgement This report was prepared by the PowerClean Thematic Network under the European Union Fifth Framework Energy R&D Programme Contract No. ENK5-CT-2002-20625. The PowerClean R, D & D Thematic Network PowerClean is an RTD Thematic Network established under the European Union Fifth Framework Energy R&D Programme with the objectives of encouraging collaboration, co-operation, and exchange between EC supported research projects and researchers, helping to maintain the technical and industrial content of future European energy-related research, and contributing to identifying future research priorities for clean power generation In view of the importance of fossil fuels for the supply of secure and sustainable energy to the enlarged European Union, the second objective takes on a heightened importance, and PowerClean will play its part in trying to ensure that fossil fuels are included in the Seventh R&D Framework programme. It will particularly try to achieve this through the preparation of strategy papers, through workshops and through presentations at international fora. This is the first of several such actions. The members of the PowerClean Steering Committee are: Professor John McMullan (Chairman) NICERT, University of Ulster, Cromore Road, Coleraine, Co Londonderry, BT52 1SA, UK Dr Andrew Minchener IEA Clean Coal Centre Gemini House, 10-18 Putney Hill London, SW15 6AA, UK Professor Klaus Hein Institut fur Verfahrenstechnik und Dampfkesselwesen Universitat Stuttgart Pfaffenwaldring 23, D-70550, Stuttgart, Germany Dr Zdena Zsigraiova IST, Department of Mechanical Engineering A. Rovisco Pais, Pav Mec 1, 2 1049-001 Lisbon, Portugal

Professor Ingo Romey Universitaet Essen FB 12, Technik der Energieversorgung und Energieanlagen PO Box 45117, Universitaetsstrasse 15 45141 Essen, Germany Mr Didier Brudy Thermal Boiler Group, Basic Design Department EDF SEPTEN 12-14 Ave Dutrievoz F69628 Ville Urbanne Cedex, France Dr Sauro Pasini ENEL, Generation and Energy Management Division, Via Andrea Pisano, 120 56122 Pisa, Italy Mr Sven Jansson Svenergy Consultants Tegelbruksvaegen 90, 61242 Finspong, Sweden

How to Join PowerClean Further information and application forms can be obtained through the PowerClean web-site (http://www.cleanpowernet.com or http://www.powercleannet.net), or through the secretariat:

Mrs Barbara Butcher, NICERT, University of Ulster, Coleraine, BT52 1SA, UK Tel: +44 (0)28 703 24469, Fax: +44 (0)28 703 24900, E-mail: [email protected]

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CONTENTS 1 INTRODUCTION...........................................................................................................................1 2 TECHNOLOGY OPTIONS...........................................................................................................2

2.1 Background............................................................................................................................2 2.1.1 Market considerations .............................................................................................2 2.1.2 Economics ...............................................................................................................2 2.1.3 Security of Supply ...................................................................................................3 2.1.4 Environmental protection ........................................................................................3

2.2 Technology classification ......................................................................................................4 3 PULVERISED FUEL (PF) BOILERS ..........................................................................................5

3.1 Background............................................................................................................................5 3.2 Status of the technology.........................................................................................................5

3.2.1 Boiler design............................................................................................................7 3.2.2 Fuel flexibility .........................................................................................................8 3.2.3 Flue gas cleaning .....................................................................................................9 3.2.4 Steam turbines .......................................................................................................10

3.3 Installations world wide.......................................................................................................12 3.3.1 EU situation...........................................................................................................12 3.3.2 US situation ...........................................................................................................12 3.3.3 Japanese situation ..................................................................................................14

3.4 Ultra-Supercritical (USC) R, D&D Status...........................................................................16 3.4.1 R, D&D in Europe.................................................................................................16 3.4.2 R, D&D in US .......................................................................................................19 3.4.3 R, D&D in Japan ...................................................................................................20

3.5 Future R, D & D needs ........................................................................................................20 3.6 References............................................................................................................................22

4 FLUIDISED BED COMBUSTION .............................................................................................24 4.1 Background..........................................................................................................................24

4.1.1 BFBC and CFBC...................................................................................................25 4.1.2 PFBC and PCFBC .................................................................................................27

4.2 Status of the technology.......................................................................................................28 4.2.1 Relative market impacts of the technology variants..............................................28 4.2.2 BFBC.....................................................................................................................28 4.2.3 CFBC.....................................................................................................................29 4.2.4 PFBC .....................................................................................................................31

4.3 Technology installations and associated issues ...................................................................32 4.3.1 CFBC.....................................................................................................................32 4.3.2 PFBC .....................................................................................................................34

4.4 FBC R, D&D Status.............................................................................................................35 4.4.1 R&D in Europe......................................................................................................35 4.4.2 USA R, D & D activities .......................................................................................37 4.4.3 Japanese R, D & D activities .................................................................................38

4.4 Future R, D&D needs ..........................................................................................................39 4.5 References............................................................................................................................40

5. INTEGRATED GASIFICATION COMBINED CYCLES (IGCC).........................................41 5.1 Introduction..........................................................................................................................41 5.2 Fossil fuel gasification technology status ............................................................................41

5.2.1 Feedstock options ..................................................................................................41 5.2.2 Process options ......................................................................................................42 5.2.3 Technology options ...............................................................................................44 5.2.4 Gasification for power generation .........................................................................47 5.2.5 Gasification for non-power applications ...............................................................50

5.3 Gasification R, D&D Status.................................................................................................51 5.3.1 R, D&D in Europe.................................................................................................52 5.3.2 R, D&D in USA ....................................................................................................54

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5.3.3 R, D&D in Japan ...................................................................................................56 5.4 Future R, D&D needs ..........................................................................................................56

5.4.1 Overview ...............................................................................................................56 5.4.2 Gasification R, D&D requirements .......................................................................58

5.5 References............................................................................................................................59 6 ADVANCED & HYBRID CYCLES ...........................................................................................63

6.1 Introduction..........................................................................................................................63 6.2 Development activities in Europe........................................................................................63 6.2.1 Pressurised pulverised coal combustion.................................................................................63

6.2.2 ABGC .........................................................................................................................63 6.2.4 Hybrid PFBC plants operating on coal and natural gas.........................................65

6.3 R,D&D in USA....................................................................................................................68 6.4 R,D&D in Japan...................................................................................................................71 6.5 References............................................................................................................................72

7 APPENDIX COMPARISON OF POWER PLANT THERMAL EFFICIENCIES ...........74 8 MEMBERS OF THE POWERCLEAN NETWORK................................................................75

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1 INTRODUCTION The major challenge facing the power generation industry over the coming decades will be to increase the efficiencies of fossil-fuelled power plants while also meeting more stringent environmental goals. Especially, there is a need to reduce the emissions of CO2 to the atmosphere, with near-to-zero CO2 emissions being the ultimate goal. At the same time, plant reliability, availability, maintainability and operational costs, as well as the cost of electricity (COE), must not be compromised. All energy options should be kept open, but attention must focus on the technologies and fuels that can play the most important role in satisfying the energy demand. In order to support the development of a fossil fuel strategy for Europe, the EC PowerClean Thematic Network has prepared three reports to make the case for coal in a European and global context, to examine the overall state of the art in power generation, and to identify the R, D&D needs in the area. The first report1 “Fossil Fuel Power Generation in the European Research Area” examines the future of energy demand and supply. It shows that if our aspirations in terms of standards of living, environmental protection, security of supply, and resource conservation are to be met, all energy supply options must be vigorously pursued. In particular, there is an urgent need to develop clean coal technologies to increase efficiency and to allow CO2 capture and storage. The second report, this review, has been prepared by to provide a panorama of the international state of the art for new, high efficiency, clean coal generation technologies, to place European developments in the global context, and to identify outstanding technical problems that are limiting development. Finally, arising from this review, the third report “Fossil Fuel Power Generation in Europe – R, D & D Needs” will identify the key R, D&D issues that must be addressed from a European Research Area perspective together with the basis of an appropriate technology development and demonstration programme for Europe. All of these findings are being provided to the European Commission to support their deliberations on the form and content of the future Framework Programmes for Sustainable Energy Systems The present document:

• Identifies the technological options for clean energy production from fossil fuels that are available at a potentially competitive cost, in terms of components, their coupling and their operating conditions;

• Gives indications as to the more promising technologies in terms of reliability, availability, capital cost, and cost of production;

• Explores the potential of the technologies in a “near-to-zero” emissions environment. • Indicates directions for promising long-term R&D.

The terms of reference for this review have been limited to fossil fuel utilisation rather than also including fossil fuel supply. As such, a deliberate decision has been made to exclude underground coal gasification and coal-bed methane recovery. This is not because they are not potentially important, but because they raise issues that are strictly outside the fossil fuel power generation sector, and are more closely related to mining and extraction. Similarly, where near zero emissions issues are considered, this review has focused on the need to optimise overall energy efficiency through the development of fossil fuel technologies that can best be integrated with appropriate CO2 capture and storage techniques. The technical, economic and regulatory issues associated with the actual development and deployment of CO2 capture and storage systems are being addressed through a complementary thematic network, CO2NET. 1 Reports available on PowerClean website or from secretariat (see back of title page)

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2 TECHNOLOGY OPTIONS 2.1 Background 2.1.1 Market considerations A series of high-level forecasts [e.g. IEA, WETO] all suggest that for the foreseeable future coal will continue to provide a major part of the overall global energy mix, particularly for electricity generation. This is especially the case for developing nations in Asia, where coal use is projected to increase very significantly, while in other coal-orientated regions its share will at least be maintained. In the EU-15 at present, the market for new coal fired electricity generation plants is fairly restricted. This is mainly due to the mechanisms of a deregulated energy market (in particular, the pressure for cost reductions), the still increasing utilisation of natural gas on a large scale, and differences in the energy policies of EU member states. However, the market situation in the EU is expected to change. At present more than 50% of the power station capacity of 600 GW is more than 25 years old. Assuming a lifetime of about 40 years, about 50 % of presently available capacity will have to be retired by 2030. In order to maintain at least the present supply situation, about 300 GW has to be replaced. If the expected increase in electricity demand arises, a total capacity of approximately 500 GW new capacity will be needed by that time. The sheer scale of such new plant capacity requirements will have to be met through the use of a range of fuels and as noted above coal will be a part of that energy mix. It is also expected that the gradual succession will be based on the most modern technology with regard to environmental protection and cost effectiveness. Continuous efforts in research and development are therefore necessary in order to achieve these goals. Likewise, the recent enlargement of the EU by 10 new member states with predominantly old installations will offer considerable market opportunities in order that their capacity can approach Western European standards. Because several of the new partner states are coal producers, and so operate coal fired power stations, the latest technologies will need to be installed to replace the present low efficiency, environmentally unacceptable, and cost inefficient plants. Finally the world market, in particular in coal-orientated regions such as China and India with low efficiency industrial plants, offers large additional opportunities for the supply of modern European technology. The need for technological advances in these regions is strongly supported by the increasing awareness of environment pollution and the legislative actions for emission control in line with their national policies. It is important in such overseas markets to adjust best available technology to local economic criteria and local environmental goals, which can differ substantially from European experience. In considering this, and also the effect of cost competition from, for example, the USA, Japan, or even local equipment suppliers, European industry needs to not only offer advanced technology but also to concentrate on the development of standardised and modularised units for site-specific applications. Examples include fuel handling and preparation, optimised conversion processes for industrial and utility use together with integrated emissions control systems. 2.1.2 Economics The supply of heat and electricity at competitive cost is a decisive factor for the market penetration of new coal based conversion concepts in a liberalized energy market. For this reason, future efforts must concentrate on reducing investment expenditure and, in particular, operation costs. Because of the variability of the latter and its predominant dependency on fuel costs, there are three major potential areas for economic improvement:

• Reduction of specific fuel consumption. This can be achieved by increasing the net efficiency of the overall plant and its single components, including the combustion/conversion process.

• Flexibility to burn a wide variety of fuels offered by the market. This requires an extensive knowledge of the fuel properties and their effect on the combustion/conversion process and, in particular, on availability related restrictions during operation.

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• Reduction of maintenance costs. These are strongly influenced by unpredicted erosive, corrosive and excessive temperature effects which, in turn, are associated with combustion/conversion, the fuel properties and their interaction with materials. Minimisation of maintenance cost requires detailed knowledge of such interactions under realistic conditions - including the properties of fuels and materials.

2.1.3 Security of Supply Future coal fired power plants, as a major backbone for the security of electricity supply, will have to provide a maximum of availability and flexibility in order to follow the demands of the customers on the one hand, and to cope with the variety of fuels offered by an international coal market on the other. In a liberated energy market in which costs are the driving force of competition, these are key external issues and will require further optimisation of present practice to reduce the internal costs in investment and operation. Flexibility is also needed in order to incorporate electricity production from the increasing number of new generators based on renewable energy sources which, at present, is predominantly wind power in the EU partner countries. Furthermore, concerning the fuel spectrum, the strategy of utilising biofuels and wastes as part-replacement for solid fossil fuels in industrial plants offers benefits with regard to environment protection and resources preservation, but requires additional flexibility in the combustion/conversion process and for maintaining the required plant availability. 2.1.4 Environmental protection Modern coal fired power plant can achieve very low levels of pollutants, including particulate and acid gas emissions. At the same time, there is a need to continue to optimise the integration of such emissions control systems in order to minimise any operational and capital cost issues. Furthermore, it can be expected that future legislation for the control of emissions other than carbon dioxide will require compliance with more stringent limitations than are applied today. Thus, there will be a need for environmentally more efficient and cost competitive techniques for both the fuel conversion process and for flue gas treatment. In addition, there is a need to comply with the strategic goals of reducing greenhouse gas emissions and conserving resources, and as such the efficiency of coal-based electricity generation plants must be optimised. Technological options have to be developed and implemented for both the total process and for its components. Recent studies have indicated that present best values of about 47% for net efficiencies could be improved to 51% by 2010 and to 53% by 2020 (LHV basis for Northern European locations). This represents a 12.5% improvement over current best practice, and is a 75% improvement over the average efficiency of the present fleet of coal-fired power stations. Such an improvement implies large savings in specific fuel consumption, which will reduce fuel costs, and, because fuel costs contribute up to 70 % to the total operating costs, will lead to lower electricity prices for the consumer market. It also offers the possibility of achieving the desired 60% reduction in CO2 emissions from coal-fired plant purely through performance enhancement. In addition to advances towards CO2-leaner processes, a number of “(near) zero emission processes” are under consideration in the USA, in Japan and in the EU to capture the CO2 from flue gases by various cleaning processes. These techniques can be enhanced considerably by modifying the fuel utilisation process to favour CO2-enrichment in the flue gases prior to capture. In such schemes it will be important to ensure that the other environmental benefits are not affected adversely. At the same time it is essential that such processes are developed in an integrated form to minimise any efficiency penalties for electricity generation.

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2.2 Technology classification A standard way of classifying power generation technologies, based on the characteristics of the environment in which the fuel releases its energy content, is shown in Fig. 2.1 [2].

Fig. 2.1 – Coal power generation options As far as the steam side is concerned, all of these technologies are based on a conventional steam turbine/generator; the problems are similar in each case, and steam turbines will be analysed in the section related to PF technology. In contrast there are differences in the fuel/flue gas path, where each technology has its own peculiarities and technological problems to be solved, as will be shown below. There are also many new processes, at varying stages of development and maturity, gradually moving from the desktop, to laboratory, to demonstration and thereafter to commercialisation. These new concepts will be analysed in the hybrid cycles section. Following the classification of Fig. 2.1 this paper will review the most important coal power generation options with the specific intention of defining the effective status of the technology, showing the fields in which developments are being conducted, and highlighting possible fields in which more research is still needed. It is worth noting that comparison of performance data for different power stations can be difficult because of reporting conventions and different site conditions. A discussion of these issues is presented in the Appendix in Section 8.

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3 PULVERISED FUEL (PF) BOILERS 3.1 Background In pf boilers, coal is ground into fine particles and then injected with air through a number of burners into the lower part of a combustion chamber. The particles burn in suspension and release heat, which is transferred to water tubes in the combustion chamber walls. This generates high pressure, high temperature steam which is fed into turbine/generator sets to produce electricity. PF boilers are termed “subcritical” if the steam generated is below the critical pressure of 221.2 bar. Above this pressure, there is no distinct water-steam phase transition, and the boiler is said to be “supercritical”. The process is shown schematically in Figure 3.1.

Figure 3.1 Schematic diagram of pulverized fuel (pf) power station

There has been great evolution in the design and the performance of this technology since the seminal document written in 1875 by George Babcock and Stephen Wilcox on the “Requirements of a Perfect Steam Boiler” [3]. Today the total world installed capacity of coal fired boilers is of the order of 1000 GW and they generate a large majority of the electricity produced from coal, which itself is used for 38.7% of total global electricity generation [4]. 3.2 Status of the technology The goal of improving the efficiency of PF plants by increasing the temperature and pressure of the steam working fluid has been pursued since the technology first emerged in the early 1900s. The historical evolution of the steam pressure and temperature is shown in Fig. 3.2 and 3.3 [5]. The

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transition to high steam conditions was accomplished in the late fifties and early sixties, with the introduction of numerous supercritical boilers operating at or above 565 °C and 24 MPa steam pressure.

Fig. 3.2 – Historical development of superheated steam pressure [5]

Fig. 3.3 – Historical development of superheated steam temperature [5]

The earliest supercritical steam plant was Eddystone 1 (1959), designed to operate under steam conditions of 34.5 MPa and 650/565/565 °C. The plant has operated under de-rated conditions of 32.4 MPa and 605 °C for most of its service life because of mechanical and metallurgical problems. Most of these were due to high thermal stresses and fatigue cracking of the heavy section components. These problems and the low availability of supercritical plants temporarily dampened the interest of the utilities in supercritical (SC) or ultra-supercritical (USC) plants. As a consequence, most producers reverted to plants with sub-critical conditions of about 525 °C and 17 MPa. Economic considerations were also important because of the low energy prices of the period.

1900 1920 1940 1960 1980 2000

0

50

100

150

200

250

300

350

400SH

Ste

am

pre

ssur

e (b

ar)

Year

Pioneerplants

Eddystone 1

Average trend

1900 1920 1940 1960 1980 2000

200

300

400

Year

Pioneerplants

Eddystone 1

Average trend

SH S

tea

m t e

mp

erat

u re

(deg

C)

500

600

700

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The energy crisis of the mid-70s and the subsequent sharp increase in fuel prices led to renewed interest in the development of more efficient PF power stations. Extensive studies conducted by EPRI [6], [7] showed that plant with 593 °C/31 MPa steam conditions would be feasible with only minor improvements in the already existing technology. Subsequently, falling energy prices, low growth rates and the commitment of investment funds to environmental protection measures prevented the construction of new power stations with high steam parameters for a period during the 1980s. In the early 1990s, in response to the discussion on global warming, the power plant industry increased the cycle conditions and also further optimised various power plant components. Figure 3.4 shows the evolution of SH steam plants over the last 20 years. Today, supercritical technology has completely overcome the earlier problems and offers a more favourable cost of electricity with higher efficiency and lower emissions. The current state-of-the-art pf plants are represented by Avedöre 2 (Denmark), 400 MWe, 305 bar, 582 °C/600 °C and Tachibana-Wan 1 & 2 (Japan), 2x1050 MWe, 250 bar, 600/610 °C, both commissioned in 2001. With lignite, the state-of-the-art is Niederaussem K (Germany), 260 bar/580 °C/600 °C, commissioned in late 2002. Currently, for the historical reasons of lower costs and higher operational availability and reliability, the global installed technology is still dominated by sub-critical steam cycles. However, a recent IEA report [8] indicates that, of the 22.4 GWe of new coal-fired capacity commissioned in OECD countries 1997-2000, 19.4 GWe (i.e. over 85%) is supercritical. In non-OECD countries, the figures for the same period are reversed [9]: only 5% out of new installed capacity was based on SC technology in the second half of last decade.

Fig. 3.4 Best pf installations world-wide (live steam temperatures in oC) 3.2.1 Boiler design Two-pass and tower boiler designs are both in widespread use, with two-pass being the market leader [11]. European bituminous coal-fired plants of both types are common, but Japanese and US plant are normally of the two pass design. All lignite-fired plant utilises a tower boiler principle. The most popular arrangement of tubing in the combustion zone is a spirally-wound membrane wall using smooth-bore tubing. This inclined tubing arrangement reduces the number of parallel paths compared to a vertical wall arrangement and therefore increases the mass flow of fluid (steam/water mixture) through each tube. This high mass flow improves heat transfer between the tube metal and

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the fluid inside, so the tube metal is adequately cooled despite the powerful radiant heat flux from the furnace fireball. The minimum load at which the furnace water flow is just sufficient to maintain adequate cooling of the furnace wall tubes (Benson load) for a once-through boiler with spiral wound furnace is between 35 and 40% of maximum cooling rate (MCR). An alternative design concept is to use vertical tubing with internal fins to improve heat transfer. This design allows low part-loads down to 20 to 25%, and reduces investment and operating costs (with lower pressure losses). It also offers the ease of manufacture and installation of the tube walls that is typical of drum-type steam generators. The adoption of new high-strength ferritic steels has recently enabled steam conditions to be raised above 248 bar/566 °C. As superheater tubes must be designed to operate at temperatures ~35 °C above the live steam temperatures, for steam temperatures up to ~580 °C, the metal temperature will be ~615 °C and low-alloy steel tubes such as T22 may possess adequate creep strength. However, not only do the advanced steam parameters for supercritical plant impose higher stresses on the superheater tubes, they also increase the potential rates of both fireside and steam-side corrosion. Medium-chromium (Cr) steels such as X20 can be used at these temperatures or alternatively, for corrosive coals or higher temperatures, more expensive austenitic steels such as T316 and T347 can be used. The current maximum boiler reheat outlet steam temperature is 610 °C. In thick-sectioned components such as steam pipes and headers, ferritic steels, from carbon steel up to 12% Cr X20Cr.Mo.V121 (Mo: molybdenum; V: vanadium), have been used for steam conditions of 250 bar/560°C. Here, the steam lines are normally now manufactured from X20Cr.Mo.V121. Materials with even higher creep strength will be needed for thick-section components under more advanced steam conditions and P91/T91/F91 are suitable for such use up to ~ 300bar/580-600°C. The layout and design issues for reheater banks are similar in principle to those of the superheater banks, in particular with reference to materials and temperature limits. However, there is more scope with the reheater to increase temperatures or adopt novel designs because the reheater pressure is much lower and so the tubes are under much less stress. In addition, the reheater is normally situated behind the superheater in a region of cooler gas flow. An additional 20 °C is typically achievable in reheater steam temperatures for the same material constraints. In summary, current state-of-the-art boiler outlet steam conditions are up to 300 bar/600-610 °C. 3.2.2 Fuel flexibility Most hard coal boilers are designed to enable the burning of a range of typical coals found on the international market. Mine-mouth plant projects (for a single type of coal) are becoming rarer because the price of coal from opencast mining in Australia, Indonesia, Venezuela, etc. is now so low that it is competitive even when allowing for transport costs. Projects based on single combustion fuels are today only considered for lignite or brown coal fired units, which are always mine positioned. The design characteristics of existing steam generators usually allow a wider range of fuels to be fired than was initially intended, though there are a few precautions to consider. This, together with the availability on the market of renewable combustion fuels (biomass) and high energy content residuals (sewage sludge, RDF, etc.) - in some cases at negative or near zero cost - has favoured their co-utilisation in boilers in substitution for a small fraction of coal (5 - 15% in co-combustion). Today, considerable experience has been gained in this field, though there are still some open questions relating to the use of the ash in cement and concrete. For example, in Europe, rules and regulations are still in evolution and are not consistent throughout the Member States. The possibility of using a not-insignificant percentage of renewable fuels in the existing generating system is certainly an alternative to consider, to achieve a global reduction of CO2 emissions, and to address the problem of disposal of high-energy content wastes.

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3.2.3 Flue gas cleaning Due to their great environmental sensitivity, the emissions limits for conventional pollutants have decreased steadily over the last 20 years as shown in Fig. 3.5. The figure also shows that new coal fired power stations (such as Torre Nord), are required to satisfy local emission limits that are often well below the existing legislation. Typical flue gas cleaning configurations used today in coal-fired units are shown in Fig. 3.6. Configuration b, which includes a cold electrostatic precipitator, is used only in Japan.

Fig. 3.5 – Recent trend of emissions limits

Fig. 3.6 –Typical flue gas cleaning configurations for coal firing Typical emission values (mg/Nm3 at 6% O2) obtained with the above configurations are: NOx = 50-100; SO2 = 75-100 and particulates from 10-20 (a), to <5 (c). Table 3.1 shows the best effective emission values for the main pollutants in coal fired power stations world-wide: the lowest emission values are obtained in Hekinan power station (Japan).

SOxNOxdust

Presentlimitsm

g/N

m3 ,

6%O

2

USA 609/EC USA 81/EC USAHawthorn

Japan3ten

0

200

400

600

800

1000

1200

1400

1600

1979 1988 1999-2000 2001 2001 2002 2010Italy

Torre Nord

Coal fired plants

FGD

Low-NOxburners SCR

COLD ESP FGD

a)

b)

c) Low-NOxburners SCR

FF oCOLD ESP FGD WESP

Low-NOxburners

GGH GGH-

-

-FGD

FF o ESP(*)SCR

10

Table 3.1 - Effective emission values for best reference power plants worldwide

3.2.4 Steam turbines Modern steam turbines for supercritical and ultra supercritical duty are of relatively high capacity, between 300 MWe and 1200 MWe, and with adiabatic efficiencies up to ≈ 95%. In recent years, improvements in computational fluid dynamics (CFD) software has allowed hydrodynamic regime and blade shaping to be developed on the basis of sophisticated 3-dimensional (3-D) or advanced three dimensional (3-DS) analysis. In this way a complete range of new high-efficiency turbine blading has been developed by EU and Japanese equipment manufacturers. With this new design philosophy, Siemens now claims to have developed a new type of 3DV blading (3D blading with variable stage reaction) which allows the reaction of each stage to be set on an individual basis. 3DV combines the benefits of multistage reaction blading and low reaction impulse blading and offers greater design freedom. Up to now, blades and vanes have been based on either an impulse or reaction design philosophy, with the same degree of reaction applied to all stages. This imposes an immediate constraint that sets a limit to the design target when aiming for the highest level of efficiency. However, if a 3-D blade is designed for each specific application, the distinction between impulse and reaction blading is lost. This allows further significant improvements in efficiency. The highest efficiency (gross) of 49% has been claimed by Mitsubishi Heavy Industries (MHI) in their 1050 MWe steam turbine (reportedly the biggest and most efficient USC turbine never built), with the largest low-pressure last stage blade of 46” (1170 mm) [9], [11]. Extending the use of ferritic materials for steam turbine forgings to handle temperatures above 594°C is under development, since they avoid the issues of material expansion and thermal stress that accompany the use of austenitic materials. One way of doing this is to improve the cooling techniques used for turbine rotors, the alternative is to improve materials. In Japan, there is one example of a steam turbine with ceramic coating on the first stage (Hekinan [4], [5]). Because of the severe temperatures and stresses that exist throughout the turbine, alloys have been developed that mitigate creep and creep-fatigue problems. The impact of start-stop cycling is a concern as steam temperatures increase, particularly in the headers, steam lines, and HP and IP rotors.

Fuel MWe NOx SO2 Particulates Year

Mellach (A) Coal (< 1% S) 250 + heat 180 110 10 1986

Hawthorne (USA) Coal (< 1% S) 550 65 150 22 2001

Boxberg (D) Lignite 907 150 350 10 2002

Haramachi (J) Coal (< 1% S) 2x1000 120 200 25 1997

Tomatoh-Atsuma (J) Coal (< 1% S) 2x700 100 143 10 2000

Tachibana-Wan (J) Coal (< 1% S) 2x1050 90 143 10 2002

Hekinan (J) Coal (< 1% S) 2x1000 30 75 5 2001

New Units (Japan) Coal (< 1% S) 700÷1000 50 75 5

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Currently, it is reasonable to view 593°C as a steam temperature for which ferritic steels for boilers and turbines are well established. It is likely that 620°C will be possible with ferritic steels in the near future, and perhaps even 650°C with the addition of tungsten as an alloying element [12]. The use of advanced materials, especially titanium, for lower density LSB (last stage blades) allows for longer blades, and hence, increased exhaust annulus areas: Siemens’ titanium LSB provides an area 10% greater than the longest steel blade [9]. The advanced materials to be used for USC turbine components are of a higher quality grade than for the conventional steam conditions of 538°C. This can be seen, for example in the MHI standards of Table 3.2. Similar results can be found for the other EU and Japanese manufacturers. Alloy 10-12 Cr is also quite common in recent EU steam turbines [13] [14], though additional long-term creep data may be needed for these advanced steels. Above 650°C, it is anticipated that super-alloys will replace the traditional ferritic steels for BP and IP rotors. Nickel-based super-alloys will be required for turbine forgings, superheater tubes, boiler outlet headers, steam piping, valve bodies, and turbine casings. Because of the increased thermal expansion coefficients of these materials compared to ferritic steels, thermal stresses in forgings and castings become an important issue during start-up and load cycling, and rotor axial expansions require new design approaches. For this reason it is felt that such turbine designs might be more suitable for base load duty where thermal stress-caused fatigue damage is limited, than for on-off or load-change operation [12].

Table 3.2 - Comparison of 600°C turbine materials to conventional 538° (MHI)

The turbine configuration depends on the capacity application range, and is approximately as follows:

• 300 – 500 MWe 2 casing • 450 – 700 MWe 3 casing • 650 – 850 MWe 4 casing • 800 - 1050 MWe 4 casing cross-compound, or 5 casing

Solid particle erosion (SPE) is a particular concern with supercritical units, due to the once-through operation of the boiler. SPE is caused by deposits, such as magnetite, that have exfoliated from boiler tube surfaces. The worst erosion is associated with particle impingement on the high pressure control stage and the first reheat stage. Early experience showed that supercritical units required nozzle and bucket repair/replacement about one and half times more frequently than subcritical units, and SPE

Main steam temperature 600 °C 538 °C

Rotor New 12 Cr forging Cr-Mo-V forging

Nozzle chamber 12 Cr cast steel 2 ¼ Cr – 1 Mo cast steel

Inner casing 12 Cr cast steel 1 ¼ Cr – ½ Mo cast steel

N° 1 blade ring 12 Cr cast steel 1 ¼ Cr – ½ Mo cast steel

N° 2 blade ring 2 ¼ Cr – 1 Mo cast steel 1/2 Cr – ½ Mo cast steel

Outer casing 2 ¼ Cr – 1 Mo cast steel 1 ¼ Cr – ½ Mo cast steel

Rotating blade Refractory alloy (R-26) 12 Cr forging

Main steam stop valve 9 Cr forging 2 ¼ Cr – 1 Mo forging

Main steam governing valve 9 Cr forging 2 ¼ Cr – 1 Mo forging

12

was reported as the major cause of heat rate degradation in supercritical turbines. Hard particle erosion is a visible, and often severe consequence of cycling, and is more noticeable in once-through supercritical units in USA, which are not equipped with a steam by-pass [15]. 3.3 Installations world wide 3.3.1 EU situation The EU has a total installed capacity of 600 GW, 30% of which is based on coal. Mainly because of the age profile, only 8% of the existing power plants show an efficiency of 40% (LHV) or higher. Figure 3.7 [16] shows that 63% of the plants in the EU countries are older than 20 years. In the non-EU countries the equivalent number is 66%. This age profile will inevitably lead to a high demand for new capacity over the coming years – first to compensate for the retirement of older units, and then to address the forecast increase in electricity demand. It is expected that the replacement or refitting of some of the old power plants with plant using modern technology with very high steam conditions and very low emissions will be one of the preferred solutions for the utilities.

Fig. 3.7 – Age of coal-fired PP for the EU countries [17]

Power plants representing the latest and highest technological status of supercritical industry have been installed in Denmark and Germany, and a new advanced project is currently at a late stage of development in Italy. Tables 3.3a and 3.3b show the most advanced PF installations in Europe, located in Germany and Denmark, together with data on the boiler and steam turbine supplier. In Italy, Enel is at the final stage of approval of a project for the installation of 3 x 660 MWe PF boilers, designed for 270 bar, 600/610 °C, today the most advanced steam conditions in Europe. 3.3.2 US situation The installed capacity in the US is approximately 833 GWe (UDI/McGraw Hill Energy Database, November 2000), of which 40 % is coal-fired (334 GWe). Of the "black coal" units, 558 are sub-critical, 64 are supercritical and 23 are supercritical with high final superheater and reheater temperatures. Only 14 units have double reheat [17].

13

The age profile shown in Fig. 3.8 indicates that over 80% of the population entered service over 20 years ago, which reflects the trend away from coal-fired power generation in the 1970's and 1980's due to the uptake of nuclear power generation and then a more recent trend to natural gas fired CCGTs. Analysis of the distribution in terms of efficiency (net, HHV basis) reveals that only 2% of the total population has an efficiency greater than 38%, with the most efficient being Tanners Creek #4 (39.8%). This unit employs a supercritical technology with steam conditions of 24.13 MPa, 538/552/566°C. This number, based on HHV, is clearly lower than the best achievable values of the technology, which are above 45% (on LHV).

GERMANY Niederaussem Lippendorf Schwarze Pumpe Staudinger Boxberg Schkopau

Owner RWE Energie Vattenfall Vattenfall Preußen Elektra Vattenfall Kraftwerk

Schkopau

Boiler Supplier Alstom et al. Steinmüller et al. Alsthom Deutsche

Babcock Alstom et

al. Steinmüller et al.

ST Supplier Siemens PG Siemens PG Siemens PG Alstom Alstom Alstom

Main Fuel Lignite Lignite Lignite Bit. coal Lignite Lignite

Output (MWe, Net) 965 930+ heat 2x800 + heat 509 907 2x450

Main Steam (bar) 275 267 267 262 266 285

Main Steam (°C) 580 554 547 545 545 545

Reheat Steam (°C) 600 583 560 562 581 560

Net Efficiency (%LHV) 45.2 42,3 41 43 41,8 40

Year 2002 2000 1997-98 1992 2001 1995

DENMARK Esbjerg 3 Skaerbaek 3 Nordjyllands 3 Avedöre 2

Owner Elsam Elsam Elsam Energy E2

Boiler Supplier Alstom BWE BWE BWE/FLS Miljo

ST Supplier - MAN/Alsthom Alsthom Ansaldo Energia

Main Fuel Bit. Coal Natural Gas Bit. Coal Bit. Coal

Output (MWe, Net) 411 411 411 390

Main Steam (bar) 250 290 290 300

Main Steam (°C) 560 582 582 580

Reheat Steam (°C) 560 580/580 580/580 600

Net Efficiency (%LHV) 45 49 47 48.3

Year 1992 1997 1998 2001

Table 3.3 – Supercritical steam power plants in Germany and Denmark

14

Fig. 3.8 - Unit age distribution of US power plants (Black Coal) In the US, which with Russia, was the first and traditional developer of SC technology, there has been no technological evolution over the last 20 years, in contrast to the rest of the industrialised world, and the few ultrasupercritical boilers built by American manufactures (CE, now Alstom and B&W) were installed in far east countries. Fig. 3.8 also shows that the coal generation fleet has now reached a mature middle age, and so retrofit interventions are foreseen soon. Data derived from EIA 2003 [18] predicts a total of 74 GW of new coal fired capacity to come on line between 2001 and 2025. In addition to this, a substantial demand for retrofit & re-powering of existing capacity is expected. 3.3.3 Japanese situation Japan originally depended on fuel oil (together with hydro, gas and nuclear) for electricity generation. In 1980, of a total installed capacity of 125 GW, only 5 GW of power stations were coal-fired. But, starting from the oil crises (1973 and ’79), the need for diversification of energy sources was recognised, and has given rise to the increase of coal utilisation and a fast development of new more efficient technologies. By 2001, Japan had a total installed capacity for all energy sources of 230 GW, with coal accounting for 13% (30.5 GWe) [19]. Stimulated by and with funding from MITI (Ministry of International Trade and Industry), Japanese utilities and manufacturers have paid considerable attention to improving the performance of power plants, to respond to global environmental issues (greenhouse gases), to reduce the cost of electricity (COE) and to increase the competitiveness of Japanese industry. Fig. 3.9 plots the evolution of turbine steam conditions in Japan since 1945 [20]. The first plant to use supercritical steam conditions (24.1 MPa, 538/566 °C) was built in 1967 and remained the standard for large capacity plants for about twenty years. The first “USC” plant in Japan was built in 1989 (Kawagoe, 700 MWe), employing gas fired boilers with steam conditions of 31 MPa/566°C/566°C/566°C). At the time, the steam turbine was the world’s largest ultrasupercritical pressure turbine. Steam temperatures reached 593 °C in 1993 (Haramachi #1, 1000 MWe). These improvements were largely the result of developing improved component materials to withstand higher temperatures.

1940s 1950s 1960s 1970s 1980s 1990s0

50

100

150

200

250

300

Num

ber

Age

15

Fig. 3.9 – Evolution of turbine steam conditions in Japan

Fig. 3.10 shows the candidate materials for Japanese power plants [21]. The vertical axis shows the allowable stress at 625 °C and the horizontal axis shows the Cr content (which is nearly equal to corrosion resistance and is proportional to the price). Solid symbols show the materials developed in Japan, which are the majority. This is one of the reasons why Japan is in such a strong position to develop and use USC steam conditions. The most advanced steam conditions currently in commercial operation in Japan are 25.0 MPa/600°C/610°C at the Tachibana-Wan boiler (2x1050 MWe), and 26.6 MPa/600°/610 °C at the Isogo unit 1 (600 MWe). What is also impressive is the list of coal fired plants under construction at March 31st, 2001 (Table 3.4).

Fig. 3.10 – Candidate materials for Japanese power plants

0

20

40

60

80

100

120

140

0 10 20 30Cr% (Corrosion resistance)

Allo

wa

ble

str

ess

at 8

98K

(Mp

a) Ferritic Steels Austenitic Steels

P23/T23

P22/T22

P91/T91

P92/T92

F12M

P122/T122

Nf12 Xa704

METI-SUS304J1HTB

METI-SUS310J1TB

METI-SUS321J1HTB

SAVE25

TP347HFG

TP321H

: Developed in Japan

METI-SUS310J1TB

16

*Pressurised fluidised bed combustion combined cycle (PFBC) system (Source: FEPC)

Table 3.4 – Plants under construction in Japan (March 2001) 3.4 Ultra-Supercritical (USC) R, D&D Status In this section, the research activities for the development of ultrasupercritical technology, especially in Europe, will be examined. The results will then be compared with major research projects throughout the world, primarily in the US and Japan. The fundamental problems in achieving ultra-supercritical conditions lie in the availability of suitable materials of construction. As shown in Figure 3.11 (and already referred to indirectly in Section 3.3), there is an upper temperature limit to the use of steels, above which much more expensive nickel alloys will be required. 3.4.1 R, D&D in Europe In Europe, with finance from the EU (Thermie, ECSC) and national research programmes, as well as from industry, intense advanced research has been carried out on the development of USC boiler technologies. The reference project, started in 1998, is the AD700 project, which involved the participation of 38 of the most important industrial and university research centres [22]. The goal of the AD700 project is to demonstrate that it is possible to operate USC steam plants with steam conditions of 700/720 °C, 375 bar. This can lead to efficiencies of 52-55% (LHV), compared to 47% with currently best available PF USC technology. Phase 1 started in 1998. Phase 2 started in 2002. Phase 1 runs for six years and covers material development and feasibility studies. Phase 2 covers material development and preparation for Phase 3, which is planned to include construction and operation of a relatively small test facility, with a test programme starting in 2005 and running for

Name of plant Company Unit capacity (MW) x n° of

units

Steam pressure at turbine inlet (MPa)

Steam temperature at turbine inlet (°C) Fuel Commissioned

Tachibana-Wan EPDC 1050x2 #1 25.6

#2 26.0 600/610 Coal 2000-2001

Tomatoh-Atsuma Hokkaido EPCo 700 25.0 600/600 Coal 2002

Hitachinaka Tokyo EPCo 1000 26.0 600/600 Coal 2003

Hirono Tokyo EPCo 600 24.5 600/600 Coal 2004

Hekinan Chubu EPCo 1000x2 25.0 568/593 Coal 2001-2002

Maizuru Kansai EPCo 900x2 24.5 595/595 Coal 2004-2010

Osaki (PFBC)* Chugoku EPCo 250 16.6 566/593 Coal 2002

Matsuura Kyushu EPCo 1000 25.0 598/596 Coal 2005

Reihoku Kyushu EPCo 700 24.0 593/593 Coal 2003

Karita (PFBC)* Kyushu EPCo 360 24.1 566/593 Coal 2001

Kin Okinawa EPCo 220x2 16.6 566/566 Coal 2002-2003

Isogo EPDC 600 27.0 600/610 Coal 2002

17

three years. The test facility is based on boosting to 700 °C a steam extraction of 50-125 t/h from an existing plant. Candidate AD700 materials are shown in Figure 3.12.

Figure 3.11 The temperature and pressure limits to the use of steel in USC power plants

Another European project, the E-max initiative, aimed towards the same goal, was initiated by VGB in 2001, and is backed by a number of major European utilities (Enel, EDF, Electrabel, E.ON Energie, Vattenfall, EnBw, RWE Power and Elsam). E-max targets the direct demonstration of a 400 MWe AD700 technology power plant. Basic to the E-max project is the wish of the European utilities to have the AD700 technology ready for the boom in construction of new generating capacity expected in the period 2010-2030. Since late 2001, efforts have been made to co-ordinate the objectives and time schedules of AD700 and E-max. This led to a proposal to establish a full-scale test facility, in which the complete HP section of a 400 MW AD700 power plant, including the HP steam turbine, can be demonstrated. This would have the advantage that fabrication and welding of full-scale HP steam lines and bends could also be demonstrated, while other crucial components, such as a 100% HP by-pass can be demonstrated and tested. Long term development of high-strength materials with sufficient fire-side and steam-side corrosion resistance have also been funded by COST programmes (Figure 3.12). In Europe, the COST 501 programme [23], involving steelworks, power plant manufacturers, power station operators and research institutes, has led to the development of materials which allow a live steam temperature of near 600 °C, with reheat temperatures of 620-625 °C. Building on that experience, the COST 522 programme aims at a steam temperature of 650 °C, which for a sea-water cooled plant in Northern Europe, would give a net efficiency of about 50% (LHV). Materials are, without doubt, the most critical components of a boiler under high steam conditions but there are also some other technological aspects related to furnace design that have been analysed in EC funded projects.

18

Standard SC boilers are equipped with spiral wound furnace pipes; however spiral loop is expensive to manufacture. A new design of once-through boiler has been developed by Siemens within USB 2000 and the EU Thermie programme 700. It is based on a horizontal furnace and internally rifled vertical pipes. This considerably increases the cooling effect, and the vertical tubing arrangement involves lower assembly and construction costs. The vertical tubes are self-supporting, so boiler support becomes simpler. Also the furnace corners are easier to form. Based on this activity the world’s first vertical low-mass-flux once-through boiler was supplied by Mitsui Babcock and Siemens to Yaomeng power station in China in 2001.

Figure 3.12 Candidate AD700 materials (adapted from Elsam Engineering A/C data).

USC steam turbine development has also been important subject of research. Finally, considerable research effort has been aimed at improving the environmental compatibility of USC boilers and at extending their fuel flexibility. Extensive efforts have been undertaken to develop low-NOx combustion systems. Examples include the Longannet Gas-over-Coal Reburning and the Vado Ligure Coal-over-Coal Reburning programmes, both financed under the EU Thermie programme. Numerous research projects have been undertaken to develop burners to co-fire coal with other materials: first biomass, then wastes like RDF, sewage sludge, and plastic. Most of these projects have involved utilities and have had the objective of using existing boilers with only minor modifications to burn these secondary combustion fuels. The advantages are in some cases economic (coal is substituted with a secondary fuel of lower or zero cost) or environmental (CO2 emissions are reduced with a renewable fuel). Even in the latter case there is always an economic return (tax reduction, incentives....). Recently, attention has been paid to “new pollutants”, of which mercury is a particular example. Discussions are already taking place after both a United Nations paper [24] and the new rules and

19

regulations in discussion in US (Clear Skies [25]), which foresee that this is an element whose emissions must be strongly reduced. In the EU FP6 programme, attention is nearly completely focused on CO2 sequestration and storage, completely ignoring the industry approach, which first concentrates on increasing plant efficiency and improving plant operation so as to reduce CO2 emission prior to the additional CO2 capture. The most interesting subject in this field, related to USC boilers, is O2 or enriched air combustion. This is a technology which, as well as having important implications for CO2 separation, is also potentially suitable for application in existing boilers. Some industrial examples of the concept have already began to be seen [26] (combustion air enrichment with O2 to improve combustion efficiency) even if, at the moment, costs are greater than the expected gains, due to the high production cost of O2. 3.4.2 R, D&D in US In contrast to Europe and Japan, the US has not invested in the development of USC technology over the last twenty years, mainly due to the lack of any stimulus from the internal market. Today the US has lost its competitiveness in an area it pioneered almost half a century ago, and is staying abreast of foreign developments largely through teaming arrangements with Japanese and European boiler manufacturers. Only recently, in 1999, the USDOE funded a research program to evaluate the high temperature corrosion resistance of different materials. The programme has been performed by Babcock and Wilcox and the Ohio Coal Development Office. Testing has been conducted on metal specimens inserted in the high temperature region of a boiler (Niles, Ohio), firing high sulphur coal (3-3.5%), and with internal steam temperatures ranging from 563° to 593°C. The end of this program is foreseen for December 2004. In a move largely designed to help US manufacturers to compete with their European and Japanese counterparts, USDOE's NETL and the Ohio Coal Development Office (OCDO) have undertaken a 5-year programme for high temperature ultra supercritical materials for coal fired power plants. The launch of this project in the USA is an important indication of the potential and attraction of European AD700 technology. This work is being carried out by a team including the Energy Industries of Ohio as administrative lead, US large boiler manufacturers (Alstom, Babcock Borsig, Babcock & Wilcox/McDermott, and Foster Wheeler) as major contractors and participants, and with EPRI as technical lead organization. The target is to be able to produce, within five years, a family of pipes and components made of advanced steels capable of withstanding operating temperatures up to 760°C. The project also contains provisions for developing advanced alloys suited to 870 °C, if needed. The budgets and the candidate materials are shown in Table 3.5.

Schedule and Funding Candidate Materials Duration Oct 2001 – Sept. 2006 IN 740 47Ni-25Cr-20Co-Nb Funding Alloy 230 55Ni-22Cr-14W-5Co USDOE/NETL $15.2 M HR6W 43Ni-23Cr-6W-Ti & Nb OCDO/OAQDA $ 2.0 M CCA617 45Ni-22Cr-12Co-9Mo Cost Share by members $ 2.7 M S304H 18Cr-9Ni-3Cu-Nb & N Alloy vendors (in kind) $ 0.1 M Save 12 11Cr-3W ferritic

Table 3.5 US high temperature materials R&D programme

As part of a larger collaborative effort, the Albany Research Center (ARC) is examining steam-side oxidation behaviour for ultrasupercritical (USC) steam turbine applications. Initial tests are being done on six alloys identified as candidates for USC steam boiler applications: ferritic alloy SAVE12,

20

austenitic alloy Super 304H, the high Cr-high Ni alloy HR6W, and the nickel-base superalloys Inconel 617, Haynes 230, and Inconel 740. Each of these has very high strength for its alloy type. Three types of experiments are planned: cyclic oxidation in air plus steam at atmospheric pressure, thermogravimetric analysis (TGA) in steam at atmospheric pressure, and exposure tests in supercritical steam up to 650ºC and 34.5 MPa. The atmospheric pressure tests, combined with supercritical exposures at 13.8, 20.7, 24.6, and 34.5 MPa should allow of the effect of pressure on the oxidation process to be determined. An extensive activity is planned on environmental control technologies for NOX, SO2, particulates, VOC and mercury removal and by-product recovery and utilisation. 3.4.3 R, D&D in Japan Most of the really significant advances in new materials for USC conditions appear to have been made in Japan, where substantial government funding continues to be made available by MITI (now Ministry of the Economy, Trade and Industry) The Phase 1 (1981-1993) R&D programme targeted the development of ferritic 9-12 Cr steels for steam conditions of 31.4 MPa, 593°/593°/593°C, and austenitic steels for steam conditions of 34.3 MPa, 649°/649°/649°C.During the period 1994-2001 the Phase 2 programme considered the development of ferritic steels for steam conditions of 30 Mpa, 630°/630°C. Currently (since 1997), the National Institute for Material Science is running Project STX21 for the development of advanced ferritic heat resistant steels for large diameters and thick section boiler components in coal fired USC plants under conditions of 35 MPa, 650°C. 3.5 Future R, D & D needs Future R & D for coal fired industrial and utility processes must aim to significantly improve the currently best available plant technology either in total or in its essential components. Potential benefits with regard to efficiency improvements, and thus, CO2 emission reduction, must be clearly established, and technical concepts with a realistic chance for success must be followed in a stepwise fashion from research through prototype development to large scale demonstration. In parallel. new concepts of CO2-free power generation from coal must be developed despite the associated reduction in plant efficiency. The primary issue is that the goals set by European energy strategy considerations are met in due time, and at economically acceptable costs, by a well balanced mix of available primary energy sources and related processes. Some of the options will require additional efforts in industrial development; others still need fundamental research prior to application. In order to achieve the major goal of a significant reduction of CO2 emissions from coal based conversion there are possible various options. First, an increase in the net efficiency of current best available technology will contribute to lowering specific fuel consumption, with positive consequences for resource preservation, specific local emissions, and plant operation cost. Efficiency improvement can be achieved inter alia through reductions in the internal process losses of various components:

a) during fuel conversion by: − optimisation of the fuel preparation process − improvement of the fuel/air interaction to reduce excess air requirements and

consequently waste heat losses − alternative tail-end utilisation of heat at low temperature

21

− improved knowledge on fuel-dependent ash forming phenomena in order to optimise the energy consumption required for maintaining safe and continuous operation

b) in the water/steam cycle by: − optimisation of the arrangement of gas/steam heat transfer surfaces − higher water side inlet temperatures and improved cold end conditions − detection and elimination of sources for heat and pressure losses

c) by improvements of the steam turbine by: − heat and mass loss reduction − aerodynamically enhanced blade configuration.

Second, total efficiency increases can be achieved by further increasing the steam pressure and temperature. Although research and demonstration is already underway in Europe and elsewhere, there is still a large potential through introducing new materials, in particular from the non-ferrous sector. However, prior to any introduction into large-scale plant, intense research is still required into handling, fabrication, life time considerations, gas-material interactions etc. The CO2 issue can be further addressed by the introduction of so-called “CO2-neutral fuels” such as biomass and wastes with a sufficiently high calorific value. These fuels and their utilisation as part-replacement in coal fired plants have been under investigation for several years, particularly in the EU, where they are fired directly or as their pyrolysis products. However, experience so far shown that, in addition to their relatively small contribution to the total energy supply and their limitations in temporal and spatial availability, there are a number of fuel dependent operating problems. Because of the general strategy to widen the range and increase the utilisation of such fuels, further intensive research is required into their specific properties and their interaction within the combustion process and with the surrounding materials. Finally, new concepts of a “CO2-free” coal fired process which are under research in Japan and in the USA and are also the subject of study under FP6, are considered to be important for mitigation of the CO2-problem. Assuming that these ongoing activities yield the expected outcomes, major questions will still remain prior to large-scale demonstration, and will need further detailed research attention. Areas of concern for coal fired systems may be

• optimal enrichment of CO2 prior to capture • cost effective physical/chemical removal of CO2 • interaction with materials in the combustion process • heat transfer changes and their consequences for the water/steam cycle • alternative CO2 removal concepts as an integral part of a cost-effective emission control

system Apart from the major issue of CO2-reduction, environmental protection also includes other species ranging from “conventional” emissions such as particulate matter and the oxides of sulphur and nitrogen, to trace metals, aerosols and by-products of coal combustion. Because more stringent regulatory limitations are expected in future, there is a need for further development of the presently very effective technologies to ensure compliance with considerably lower permitted concentrations in effluent gases, and at the lowest possible cost. Further restrictions concerning the amount and the quality of solid waste by-products are also envisaged. Thus, further efforts in research and development are urgently required, including:

• more efficient emission control techniques during both the fuel conversion process and the subsequent gas cleaning

• cost effective combinations of available techniques • new concepts based on fundamental knowledge of physical and chemical principles • measures to influence the quality of solid by-products for use as raw materials in other

markets

22

Security of supply, the other major issue of EU strategy, depends directly on having high-availability plant which is flexible with regard to variations in customer demand and is able to make use of the widest range of low cost fuels available on the market. Since coal will remain a major primary fuel for power generation and a vital component of a balanced energy mix for the foreseeable future, research is needed for improvements towards, for example:

• knowledge of the interaction of fuel and construction materials under changing fuel and combustion conditions in order to avoid failures during operation

• measurement and monitoring of fuels and operation for optimal process control • maintaining maximum plant efficiencies under all load conditions • reducing the need for maintenance • operation at lowest cost for competition reasons.

Finally, Europe is a major world leader in power plant technology. It must maintain and extend this position. In view of the strong competition from other nations and cost constraints in potential customer countries such as Eastern Europe and overseas (particularly in areas which are traditional coal producers and users), this must be achieved at minimum life-time cost. Also, in consideration of the local economic situations and environmental strategies in these customer countries, European R & D must also concentrate on offering tailor-made technological solutions and site-dependent specific components for these markets. 3.6 References 1. K. Littewood, “Gasification: Theory and Application”, Progr. Energy Combust. Sci., Vol.3, pp. 35-71, 1977 2. “Cleaner Coal Technologies – Options”, DTI/IEA, 1999 3. S.C. Stultz, J.B. Kitto Editors, “Steam its Generation and Use”, 40th Edition, The Babcock & Wilcox Company,

Barberton, Ohio, 1992 4. “Key World Energy Statistics – 2003”, IEA, 2003 5. A. Kather, G. Helermann, R. Husemann, P. Hougaard, M. Knizia, “Steam Generators with Advanced Steam

Parameters”, Int. Joint Power Generation Conference, Phoenix, AZ, October 2-6, 1994 6. G.M. Yasenchak, R.H. Ladino, R. Waltz, J.M. Prowers, A.T. Sloboda, J. Charter, “Engineering Assessment of an

Advanced Pulverised-Coal Power Plant”, Report CS-2555, EPRI, Palo Alto, 1982 7. R.D. Hottenshine, N.A. Phillips, R.A. Dill, “Developments Plans for Advanced Fossil Fuel Power Plants”, Report

CS-4029, EPRI, Palo Alto, 1985 8. D. Scott, P. Nilsson, “Competitiveness of Future Coal-Fired Units in Different Countries”, IEA Coal Research

Report, January 1999 9. P. Luby, M.R. Susta, “Steam Power Plants - New Wave of Supercriticality”, Power-Gen Europe, Milan, Italy, June

11-13, 2002 10. Supercritical Steam Cycles for Power Generation Applications, DTI/IEA 1999 11. Y. Tanaka, et al., “Advanced Design of Mitsubishi Large Steam Turbines”, Mitsubishi Heavy Industries, PowerGen

Europe 2003, Düsseldorf, May 6-8, 2003 12. A.F. Armor, “Ultrasupercritical Steam Turbines: Design and Material Issue for the Next Generation”, EPRI 1006844,

March, 2002 13. M. Scala, A. Torre, “One of the World's Most Advanced Steam Turbosets For AVEDØRE 2”, Ansaldo Energia,

Power-Gen Europe, Milano, Italy, June 11-13, 2002 14. H. Ruediger, G. Scheffknecht, “Advanced Steam Power Plant Technology: Reliable Technology for High

Efficiencies”, Power-Gen Europe, Milan, Italy, June 11-13, 2002 15. A.F. Armor, R. Viswanathan, S.M. Dalton, H. Annendyck, “Ultrasupercritical Steam Turbines: Design and Materials,

Issues for the Next Generation”, EPRI, Palo Alto, USA, CA; VGB Conference Cologne, March 19-20, 2003 16. G.N. Stamatelopoulos, G. Scheffknecht, E. Sadlon, “Supercritical Boilers and Power Plants: Experience and

Perspectives”, PowerGen Europe 2003, Düsseldorf, May 6-8, 2003 17. Australian Greenhouse Office, “Integrating Consultancy-Efficiency Standards for Power Generation”, Report

January, 2000 18. EIA, “Annual Energy Outloook 2003”, DOE/EIA-0383, January, 2003 19. “The Federation of Power Companies of Japan”, Electricity Review Japan, 2002

www.fepc.or.jp/english/erj/index.html 20. S. Hisa, M. Sasaki, M. Fukuda, M. Hori, “A Vision for Thermal Power-Plant Technology Development in Japan”,

17th World Energy Congress, Houston, USA, September 13-18, 1998 21. K. Yamamoto, I. Kaijgaya, I. Umaki, “Operational Experience of USC Steam Condition Plant and PFBC Combined

Cycle System with Material Performance”, Materials at High Temperatures, 20(1), 15-18, 2003

23

22. S. Kjaer & al., “The Advanced Supercritical 700 °C Pulverised Coal-Fired Power Plant”, Power-Gen Europe 2001, Brussels, Belgium, 29- 31 May, 2001

23. J. E. Oakey, D. H. Allen, M. Staubli, “Power Generation in the 21st Century – The New European COST Action”, Parsons 2000, Cambridge, UK, July 3-7, 2000

24. “Global Mercury Assessment”, United Nations Environmental Programme – Chemicals, December 2002 25. J. Saarinen, “Clear Skies cleans up”, Power Engineering International, June 2003 26. L.E. Bool, J. Bradley, “Demonstration of Oxygen-Enhanced Combustion at the James River Power Station, Unit 3”,

The Mega Symposium, Washington, D.C., May 20, 2003

24

4 FLUIDISED BED COMBUSTION Fluidised bed combustion (FBC) in its various forms offers a technology that can be designed to burn a variety of fuels, efficiently and in an environmentally acceptable manner, for a variety of applications. There are two main derivatives of the technology, namely bubbling (BFBC) and circulating (CFBC), and both of these can be either atmospheric or pressurised in operation. 4.1 Background In an FBC plant, combustion of the solid fuel takes place within a fluidised bed where inert material, fuel and sulphur sorbent are maintained in suspension by an ascending air flow. From a macroscopic viewpoint the bed behaves like a liquid with a fluid dynamic regime that varies depending on the fluidisation type (bubbling fluidised bed, turbulent fluidised bed, circulating fluidised bed). The temperature is around 850°C, which is an optimum for low NOx formation and SOX capture by the sorbent.

Figure 4.1 The different fluidised bed variants, BFBC, CFBC, PFBC and PCFBC [1] The principal advantages of FBC power plants can be summarised as follows [2]: “in situ” desulphurisation is possible during combustion in the fluidised bed through the reaction of sulphur dioxide with limestone or dolomite sulphur sorbent, forming calcium sulphate;

• limited nitrogen oxide emissions thanks to combustion temperatures typically around 850°C, which is below the temperatures where “thermal NOx” can form;

• high heat transfer to immersed boiler tubing, where steam is generated for expansion through a steam turbine, allowing for a compact boiler arrangement;

• high flexibility for use with different ranks of coal, including those with high sulphur and/or ash content;

fuel

AirAsh

BFBA)

fuel

AirAsh

CFBB)

C) PBFB

Fuel

Ash

Air

D) PCFB

FuelAsh

Air

25

• possibility to burn low grade fuels, such as biomass, RDF and other waste substances and to perform “co-combustion” of different types of fuels;

• use of crushed fuel with relatively large particles, leading to reduced milling costs. The combustion may take place at atmospheric pressure in bubbling (BFBC) or circulating (CFBC) fluidised bed plants, or at elevated pressure in PFBC or PCFB plants, as illustrated in Figure 4.1. 4.1.1 BFBC and CFBC Bubbling Fluidised Bed Combustors (BFBCs) operate in a regime in which the speed of the ascending air is sufficiently high to maintain the bed in a state of fluidisation, with a high degree of mixing, but is low enough that solid particles lifted out of the bed will mostly fall back into it again. This results in a dense bed with a uniform temperature, and with rather small over-temperatures for the burning char. The dense part of the fluidised bed in BFBC plants has a voidage near to that which characterises minimum fluidisation. Within it, there is a bubble phase with a low content of solids. The bubbles formed from the excess air supply with respect to that necessary for the fluidisation of solids, rise through the dense phase. As in gas-liquid systems, the bubble flow in the fluidised bed induces solids transport and mixing in the dense region. The upward flow rate for air/combustion gases in BFBC plants is typically 2 – 3 m/s, and bed heights are 0.5 to 1.5 m. As a result, gas residence times within the bed are between 1 and 2 seconds. The solid material mostly stays in the well-stirred bed, although small particles will leave the bubbling bed and be thrown up into the freeboard region. Cyclones and other particulate removal devices are used to collect them before the flue gases continue to further heat recovery systems. Coarse bed material is also withdrawn from the bottom of the bed in order to avoid enrichment of ash components which might cause bed agglomeration, and to maintain the high sulphur capture capacity of the bed.

Figure 4.2 265 MWe CFBC power plant (JEA large scale CFBC project, USA) Circulating Fluidised Bed Combustors (CFBCs) are a development of bubbling bed technology [3, 4]. As with the latter, air is blown through the bed and entrains a percentage of the solid particles from the bed. If the velocity of the fluidising air is increased above a defined level, the entrained particles are carried upwards away from the bed surface and the distinct surface layer that characterised the bubbling bed disappears. The combustion chamber is then filled with a turbulent cloud of particles that no longer remain in close contact with each other. The burning particles are then recovered from

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the air flow and fed back into the lower part of the combustion chamber. Thus, the bed solids may be heated to incandescence and fuel fed into the combustion chamber where it burns in the fluidising air. The turbulent contact between the fuel particles present and the bed solids stabilises the overall temperature. This system is known as a CFBC, an example of which is shown in Figure 4.2. The ability to capture and recirculate elutriated solids back to the combustion chamber is an inherent feature of CFBC design. The solids loading in the gas emerging from the combustion chamber is very high and the hot solids themselves constitute a major heat transfer mechanism. In this respect, the emerging solids carry with them a significant portion of the heat released during combustion in the combustion chamber. This phenomenon has been addressed in a variety of ways by the different CFBC technology developers. CFBC units, whatever their origin, generally include some or all of the following elements: • A furnace/combustion chamber in which the coal or other fuel is injected (often with limestone)

and fluidised together with part of the recycled solids. Approximately 50% of the combustion air is introduced below the grid plate. As a result, combustion in the lower part of the bed is reducing in nature, thus limiting the risk of nitrogen oxide formation. Additional combustion air is injected as secondary air at an appropriate point above the grid plate.

• A solids separation system, such as a cyclone or labyrinth separator, installed at the combustion chamber outlet in the high temperature gases (~750-950°C) which enables most of the solids leaving the chamber to be collected and re-injected into the system, allowing only a very small fraction of the ash produced to be carried by the discharged flue gas.

• An external heat exchanger. This may be fed by fluidised solids from the bottom of the cyclone that are cooled before being fed back into the furnace or other part of the solids recycle loop. The distribution between hot solids and recycled cooled solids keeps the combustion chamber temperature at the desired value.

In CFBC boilers, air staging is commonly used. Except in the lowest part of the boiler, with a bubbling bed region, the upward flow rate of air/combustion gases is typically 5 – 7 m/s. Boiler height varies depending on plant size, but is commonly in the range of 12 to 30 m. The residence time for air and combustion gas is accordingly between 2 and 6 sec. Since finer sulphur sorbent is also used in CFBC boilers than in BFBC boilers, this results in more efficient sulphur capture. Depending on the gas velocity, the bed can produce a phase of dense flow (slug flow) in which large slugs push the solid upwards with big pressure fluctuations, or a phase of dense (non-slugging) flow, characterised by the aggregation of particle bunches and solid traces which break and reform in a rapid succession. The vertical solids concentration profiles typically have a sigmoid form, with a dense area at the bottom of the riser, and a diluted transport area in the upper part. These two parts are connected by a transition area, the extent of which is dependant on the circulating solid flow and gas velocities. The ideal process conditions have a gas velocity slightly above the minimum fluidisation velocity. The radial solid concentration profiles suggest an “annular” flow structure with a central “core” of relatively low concentration and a dense area at the riser walls where the solids flow downwards. The solids are transported upwards with average volumetric concentrations of up to 20% and a rather uneven radial distribution with values typically around 5 - 7% in the central core and above 25 - 30 % at the walls. Combustion occurs in a dilute system with a voidage of 0.8 - 0.9 and is accompanied by particle breakdown (comminution), which reduces the size of fuel particle size (with an average dimension of 3mm) as they transform into char. The release of volatile substances contained in the combustion fuel strongly influences the heat transfer dynamics along the length of the combustor wall, which sometimes needs additional exchange surfaces to absorb the heat released. Although NOx formation is lower in BFBC and CFBC plants than in traditional PF plants, due to the lower process temperatures, N2O formation is greater.

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The residue from the combustion of the char consists of mineral constituents from the fuel, many of which do not fuse at typical bed temperatures of 800°C - 900°C, and also products from the desulphurisation reaction, primarily CaSO4 and partially sulphated limestone. The flue gas typically leaves the cyclone at a temperature of 800 °C and crosses the convective backpass where its enthalpy content is transferred to the water/steam circuit which is integrated with a steam turbine. The flue gas, before reaching the chimney, is also cleaned in an electrostatic precipitator or bag filters. 4.1.2 PFBC and PCFBC The PFBC concept for power generation from coal involves the combustion of the solid fuel in a fluidised bed at pressure, generation of steam in boiler tubes immersed in the fluidised bed and expanded in a steam turbine driving a generator, with expansion of the combustion gases in a gas turbine driving another generator. This results in a combined cycle arrangement, giving higher cycle efficiency than with a steam cycle alone. The potential benefits, when compared to BFB and CFB plants are: • reduced combustor dimensions and greater plant compactness for the same installed capacity; • higher generation efficiency due to the combined cycle arrangement; • heat transfer coefficients over bed tubes are moderately higher; • better utilisation of the sulphur sorbent; • higher combustion efficiency; • lower NOx emissions at comparable excess air levels. The fluidising velocity in a PFBC plant is typically 1 m/s. With a bed height of 3.5 to 4 m, the air/gas residence time within the bed is in the range of 4 seconds - similar to that of CFB plants. The use of dolomite or limestone as bed material added with the fuel allows capture of the sulphur oxides in the fluidised bed during combustion. As in CFB plants the low bed temperature, typically between 850 and 880°C, reduces the formation of nitrogen oxides. Unlike CFB, and BFB systems, however, sulphur capture continues to improve as the temperature is increased above the 850 - 880°C temperature range although other concerns such as bed agglomeration then become more likely dependent on the fuel used. The overall PFBC principle and the major components of a plant (based on ALSTOM technology) are illustrated in Figure 4.3. The key components of a PFBC (or PCFB) plant are the gas turbine, the boiler, the equipment for feeding fuel and sulphur sorbent into the fluidised bed, and for removing ash from the pressurised systems. These are unique systems, which are not employed in other types of power plants. By contrast, the steam cycle can be conventional, with or without reheat, and with subcritical or supercritical steam conditions. In PFBC plants, where fuel and sulphur sorbent need to be crushed, with a mean particle size of about 1 mm, there are two main alternatives for feeding into the pressurised boiler. In one of these, the crushed fuel is mixed with water to form a paste which is then pumped into the hot fluidised bed, with or without admixture of crushed sorbent. Alternatively, a dry feed system can be used. This is generally the preferred solution in power generation applications, especially when the fuel has a low heating value. This requires the use of a lock hopper system to raise the pressure slightly above that of the fluidised bed. An intermediate solution is to feed the fuel as a paste but use a dry feed system for the sulphur sorbent. Ash must be removed from the pressurised fluidised bed and cyclones, and also from the final particulate cleanup device, a fabric filter or an electrostatic filter, operating at atmospheric pressure just upstream of the stack. Depressurisation of the relatively coarse bed ash can be achieved through use of valves, which basically have a "small scale" lock hopper function, at the base of a packed bed of the ash. By comparison, the cyclone ash is best kept in suspension until depressurisation is complete. In both cases, recovery of heat from the ash provides an important contribution to plant efficiency.

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PFBC has inherently very low emissions of air pollutants. Fabric filters are typically used to remove particulates from the flue gas before the stack. Through a proper choice of sorbent to sulphur (Ca/S) ratio, SOx removal with dolomite or limestone can essentially be controlled to any desired levels for most coals. NOx formation is inhibited because of the low combustion temperatures.

Figure 4.3. Schematic illustrating the PFBC principle

Besides pressurised bubbling-bed technology, the other possibility of designing “a CFB alternative”, in the form of PCFBC, has also resulted in significant development efforts. This has been led by Ahlstrom Pyropower/Foster-Wheeler, with pilot-scale tests being performed both in Finland and in the U.S.A., where this technology was chosen to be demonstrated as part of the U.S. DOE’s Clean Coal Technology Demonstration Program. Although a number of potential host utilities were considered, that project never materialised. The technology continues to be of interest particularly in the USA for hybrid cycles applications, as discussed in Section 6. 4.2 Status of the technology 4.2.1 Relative market impacts of the technology variants Figure 4.4 illustrates the introduction and market penetration of different types of FBC plants through to 1996. It is clear that since the mid-1980s, CFBC has dominated both for utility and industrial applications and this trend still continues [5]. 4.2.2 BFBC The possibility of applying fluidised bed combustion (FBC) technology for the generation of electricity from coal first attracted worldwide interest in the 1960s. This was primarily because it promised to be a cost effective alternative to PF plants, while at the same time allowing sulphur capture without the use of add-on scrubbers. As a result, R&D efforts began in the U.S. and in Europe, first with atmospheric bubbling fluid bed (BFB) units. In 1975, European companies installed the first major coal fired BFBC in Renfrew, Scotland. The USA followed with a 30 MWe prototype BFBC plant in Monongahela Power Co. in Rivesville, West Virginia. Development of BFBC continued in the USA with the construction of a 20 MWe pilot plant by TVA in 1982, and a 160 MWe demonstration plant in 1988. A similar development took place in Japan, leading to the re-powering

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of an existing 350 MWe PC plant at EPDC’s Takehara site to BFBC in the early 1990s. This remains the largest BFBC power plant ever built.

Figure 4.4 – Global development of FBC power plants capacity > 50 MWth [5]

However, it has since been shown that the technology is better suited to smaller industrial applications, including units that fire biomass and wastes in conjunction with, or instead of, coal. The capacity of bubbling bed installations manufactured during the past three decades has varied significantly. In the early part of the 1980s, capacities tended to be relatively modest with many BFBC units being built in the range 3-40 MWth. More recently, units in the medium capacity range of 30-100 MWth have been introduced, with a relatively small number in the range 150-280 MWth, the latter being established in Japan, Finland and Thailand. Such large-scale BFBC units continue to be supplied, although not in large numbers, primarily to large northern European pulp and paper mills and power producers. Here, there has been a growing tendency for such users to opt for a single large BFBC unit, with its inherent economies of scale. In the area of pulp and paper mills, Kvaerner remains the market leader with a claimed >100 BFBC units in operation worldwide. Elsewhere, the trend is towards small/medium capacity units. For instance, by the early 1990s, China claimed to have >2000 bubbling fluidised beds in operation while India had ~200 in use. 4.2.3 CFBC In contrast with BFBC, there are currently over 1,200 CFBC plants worldwide with a total installed capacity of some 65 GWth (unit size is normally quoted in terms of boiler thermal rating rather than electrical duty) [2, 6]. The dominant application region to date is Asia with some 52% of installed capacity (34 GWth), while North America accounts for some 26% of worldwide capacity (17 GWth), and Europe has around 22% of capacity (14 GWth). There is a small amount of other capacity, represented by a few units in Latin America and in the Middle East, which together represent less than 1% of total worldwide.

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Almost all of the Asian CFBC capacity is located in China where there are some 900 CFBC plants of average size around 30 MWth. Some 200 further, mostly small, plants are either being commissioned or under construction although recently there has been the introduction of a 300 MWe CFBC demonstration and associated technology transfer from Europe. Within North America, virtually all of the CFBC capacity is in the USA, where coal and lignite are the predominant fuels although a significant proportion of capacity is based on anthracite culm. The latter feedstock was used in some of the earlier plants that took advantage of the ability of CFBC to burn very low calorific value fuels and of the presence of large inventories of culm from coal washing operations, notably in Pennsylvania. Excluding the small plants in China, the cumulative installed capacity in the rest of the world has grown over time from launch of the first unit in 1978 to significant and relatively constant year-on-year growth of capacity additions from the mid 1980s, slowing somewhat in the early and mid 1990s but now displaying an upward trend again (see Figure 4.5). A number of factors has contributed to this pattern, including:

• The relatively successful performance of the first few units • The ability to match the technology to a wide range of plant size requirements • The availability of the technology from a number of licensors • The ability to configure the technology for fuel flexibility • Global trends during the 1980s which generally favoured small plant with rapid build times

and quick entry into revenue generating service, increased attention to environmental performance and the ability to use fuels on an opportunistic basis

• Recession conditions in the mid to late 1990s, particularly in the Far East, may have contributed to the observed slowing in the rate of capacity addition.

Figure 4.5 – Larger CFBC installations world-wide

Figure 4.5 shows the best recent and currently planned projects, including the introduction of advanced steam conditions. In terms of the overall number of individual plants operating, the clear leaders in the field of CFBC technology have now become Foster Wheeler/Ahlstrom, and Lurgi Lentjes Babcock; the former has around ~180 commercial units operational and the latter, probably, around half that number. Significant niche markets also continue to be served by companies such as

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Alstom Power, Kvaerner and Babcock & Wilcox [2]. In terms of individual plant capacity, the situation with CFBC plants has mirrored that of bubbling bed installations in that the capacity range produced by the major manufacturers has been very wide. To date, the CFBC units that are operating range from a few MWth to over 250 MWe but the latest order will see a460 MWe unit established. In terms of the future, on a worldwide basis, the market opportunities appear good, with a potential market up to 2020 of some 150GW (primarily coal-fired) capacity being estimated [2]. This represents some 20% of the likely global capacity increase for coal-fired power generation over that time period. The market proposals are localised with the major opportunities being seen as China (125GW), North America (17GW) and India (6GW). 4.2.4 PFBC Based on the concept of the pressurised bubbling bed, one company, ABB Carbon, (now part of Alstom Power), has supplied all but two installations, most of these initially functioning as demonstration units, although some are now operating on a commercial prototype basis. Overall, the uptake of bubbling bed PFBC technology is progressing slowly, Figure 4.6. On a regional basis, initial exploitation of PFBC technology took place in the country of domicile of the initial monopoly supplier, namely Sweden. It subsequently expanded into other European countries and into North America, and the highest level of current activity is in Asia, specifically in Japan. Figure 4.3 lists a number of the PFBC studies and projects which have taken place since 1980, showing the PFBC units which have been built/ordered. It can be seen that the market penetration is modest. Thus demonstration units were built in Spain, the U.S. and Sweden, based on Alstom's P200 PFBC module with an electrical output of approximately 70 MWe. A further demonstration then took place in Japan to be followed by a 360 MWe PFBC plant based on the P800 module. This was ordered by Kyushu Electric, one of Japans major utilities, from IHI, an Alstom licencee. This plant is now in commercial operation at Kyushu Electric's Karita site [7. 8, 9, 10], and has advanced supercritical steam conditions (24.1 MPa/566°C/593°C) and a net thermal efficiency of near 42% (HHV), corresponding to about 44% (LHV). It represents the state of the art for PFBC technology. Two other Japanese utilities have also introduced PFBC plants in their grids, this time with Japanese PFBC technology.

Figure 4.6 – PFBC plant development [1]

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The apparent lack of uptake of the technology in Europe and North America despite initial applications being supported by public funds suggests a continuation of risk-averse behaviour on the part of utilities as a result of PFBC’s perceived higher costs and complexity compared to competing systems, coupled with an increasing focus on natural gas-fired combined cycle gas turbine plant for environmental, efficiency and capital reasons, in regions where gas is relatively abundant [2]. Japan does not have access to substantial gas reserves and is a net importer of LNG, so these factors do not apply there. It is believed that success in Japan is critical to the success of the technology, and the major potential market is seen to be Japan (3GW) over the time period to 2020. Recently, due to a rationalization of the Alstom resources in view of some market difficulties, PFBC is no longer actively marketed although support is maintained for existing installations. As such it seems that the PFBC technology will only flourish if taken forward by the Japanese licencees and their local competitors or in some form of hybrid cycle, which is being pursued in Japan and the USA rather than Europe. 4.3 Technology installations and associated issues Since it has been shown that BFBC is no longer considered an appropriate technology for power generation applications, this section of the report will concentrate on CFBC and PFBC related issues. 4.3.1 CFBC The CFBC principle was first applied by Kellogg for power generation purposes at the first SASOL plant in South Africa in1955. The European companies Ahlstrom Pyropower (now Foster Wheeler), Lurgi and Alstom later became the leading developers of CFBC. A very important step was Ahlstrom’s development of the technology during the 1970s, originally for use with biomass at one its pulp mills. The development of CFBC technology follows that of USC PC technology. There has been a continuous improvement in efficiency due to economies of scale and the increase in the steam parameters thanks to the introduction of new creep resistant materials. The use of current state-of-the-art USC PF plant steam conditions (about 300bar/600°C) in USC CFB plants, rather than the traditional 250bar/540°C/565°C, is predicted to result in plant efficiency increases of close to 3 percentage points [11, 12, 13]. The new technological innovations introduced by Alstom and Foster Wheeler in the latest plants include: • Cooling system for the recirculating solids • Heat sinks integrated with the fluidised bed • Ash cooling system • Superheated steam by pass systems for temperature control • Cyclone retrofit for the gas/solid separation

Foster Wheeler has licensed Siemens’ Benson vertical technology for use in the design of CFB boilers. This technology offers significant functional and economic advantages for once-through power generation such as: low pressure loss, simple support system, minimum tube temperature unbalance, full variable steam pressure. Using it, Foster Wheeler now has a contract to supply the world’s first supercritical CFB, which will also be the world’s largest CFB unit. It is a 460 MWe boiler island for a power plant in Lagisza, in southern Poland. Built around once-through supercritical technology that plant will provide world-leading levels of efficiency (gross efficiency > 43%) and fuel usage, together with very low emissions. The other advanced CFB plants built recently by Foster Wheeler are:

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• Two CFB units in Northside Power plant JEA, at Jacksonville, Florida, with partial funding from the USDOE, Figure 4.2a and b. The plant has an installed capacity of 2x265 MWe net (297 MWe gross). The old boilers were repowered with CFB, designed to burn different rank coals with high sulphur content (up to 8%) petcoke. Both units were commissioned in 2002 and are, to date, the highest electric output CFB boilers in operation.

• CFBC plant at Turow, Poland. Old pulverised-fuel boilers were replaced by three conventional 235 MWe (gross power) CFB boilers (commissioned in 1999 and 2000) and three 262 MWe (gross power) compact CFB units (under construction, the last unit being commissioned in 2004).

• CFBC plants for National Power Supply Co., in Tha Toom, Thailand. Operating since 1998, these units have an installed capacity of 2x150 MWe and are fed with bituminous coal and anthracite. They are compact boilers and include the FW patented reheat steam by-pass system.

ALSTOM technology is based on a separation system with inlet ducts that are designed to accelerate and pre-separate the particles prior to the cyclone itself. This, in turn, has several favourable consequences [12]: • High heat and mass transfer, thus avoiding the creation of hot spots in the bed that are

detrimental to reducing NOx emissions. • High level of heat pick-up in the furnace. • High level of sulphur capture by the limestone injected in the furnace. • Low level of Ca/S ratio (good level of limestone use). Based on the operational success of existing large CFBs, ALSTOM has developed a conceptual design for the next generation of CFB units, with a rating up to 600 MWe, using supercritical parameters and once-through technology. Experience gained by ALSTOM on a large number of PC once-through units has also been extensively used. The main design features are: • a single furnace of "pant-leg'' type, water walls of vertical tubing type to avoid erosion; • six steam-cooled high efficiency cyclones of circular shape; • external heat exchangers; • one steam cooled cyclone outlet duct for each set of three cyclones; • one tubular air heater for fluidising air, regenerative air heaters for primary & secondary air. The most recent advanced plants built by Alstom world-wide are: • Can-Turkey. The unit has an installed capacity of 2x160 MWe and is fed with lignite. Both

CFBC units have four cyclones, two for each wall, with OMEGA superheaters and reheaters. Effort has concentrated on the cyclone separation efficiency: the sections, lengths and inclinations of the cyclone inlet ducts have been optimised to improve the segregation at the entrance, the descending fluid velocity has been decreased.

• Red Hills-USA. This is a 500 MW power plant, commissioned in 2002, burning lignite, and composed of a single steam turbine fed by two Alstom Power CFB boilers firing Mississippi mined lignite. Each 250 MW boiler is composed of a single furnace, four fabricated steel cyclones and four FBHEs, two for bed temperature control and two for reheat steam temperature control. The whole furnace bottom, main gas ducts to cyclones, and the external heat exchangers, are refractory lined.

• Guayama (Puerto Rico Power Authority, USA) (2002): 2 x250 MWe CFB units burning coal. Very stringent emission limits required the installation of a Urea SNCR deNOx system and a circulating dry scrubber system for deSOx.

• Sulcis-Italy. The CFBC unit has a size of 350 MWe, one of the largest under construction in the world, and a high temperature steam cycle (163 bar, 565°/580°C), which will guarantee plant net efficiency of 40 % (based on LHV).

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It is also worth noting the Alholmens power plant (Pietarsaari, Finland), which is fitted with the largest CFB burning biomass in co-combustion with coal. The 240 MWe CFBC unit was built by Kvaerner. Plant operation started in 2001. The ability of CFBC systems to operate on a wide range of fuel types has been confirmed through extensive operational experience. Most major suppliers have manufactured CFBC units that are capable of operating with the major classes of fuel types. Although many CFBC units currently in commercial operation use a single fuel feedstock, there are many others that regularly co-fire mixtures of fuels. The high degree of fuel flexibility that characterises many designs of CFBC often allows a plant operator to select fuels on the basis of what may be currently available at an economic price and where appropriate, produce a fuel blend that combines several such elements. Often, a premium fuel may be co-fired with a low-grade feedstock such as paper mill or oil refinery wastes. CFBC systems have an inherent advantage in that they are designed to increase solids residence times by allowing for recirculation of particles into and through the high temperature combustion zones. This means that fuels ranging from anthracite to wood can be burnt in appropriately designed CFBC systems at high combustion efficiencies of up to 99%. Many CFBC units have achieved relatively low levels of the primary pollutants, NOx, SO2, CO and particulates. Sorbent is usually added to the system in order to control SO2 emissions. NOx levels are minimized using bed temperature control and other means, while solids passing through the system can be retained using conventional particulate control systems. However, achieving acceptable overall environmental performance has, in practice, often required considerable development effort by the manufacturers. 4.3.2 PFBC For bubbling bed variants the design innovations have arisen from Alstom Power. Thus to enable the necessary degree of airflow control, ALSTOM developed a special type of PFBC gas turbine, which may be regarded as a turbocharged, constant speed gas turbine. The overall gas turbine concept is illustrated in Figure 4.7.

Figure 4.7 Configuration of ALSTOM's PFBC gas turbines

The high-pressure section contains a compressor and a turbine on a shaft connected to the electrical generator. The HP shaft rotates at about 6,100 rpm. A reduction gear is used to reduce this to the appropriate generator speed, 1,500 or 1,800 rpm depending on grid frequency. The LP shaft operates between 3,400 - 5,650 rpm, and the compressor is provided with a variable inlet guide vane for low load operation. The low-pressure turbine (LPT) is provided with a variable inlet guide vane for control of the turbine load. An intercooler is fitted between the two compressors in order to enhance

HP Turbine

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the HPC efficiency and to limit the temperature of the air entering the pressure vessel to 300°C. This allows the use of conventional pressure vessel steel in the combustor vessel, which is an important cost factor. The heat extracted from the intercooler is used for condensate preheating. ALSTOM has developed two sizes of this gas turbine type. The smaller, GT35P, based on components from the well-proven GT35C, was used in the P200 PFBC module. With a turbine inlet temperature of about 850°C, this machine generates about 15 MWe, and the total plant output is 75-85 MWe, depending on coal type and steam conditions. The low temperature allows un-cooled turbine blades and vanes to be used. This is desirable, since with the relatively high dust content in the flue gas it avoids clogging of cooling holes. Following this, the GT140P was developed for use in the larger P800 PFBC module that can give a gas turbine output of 70-80 MWe and a total plant output of 360 to 400 MWe. ALSTOM uses two stages of high efficiency cyclones, located inside the pressure vessel, for particulate cleanup. To obtain the required removal efficiency, the gas velocity in the cyclones is relatively high, and their diameter is small. This arrangement, and the use of wear resistant coatings on selected turbine components, has proven sufficient to control erosion in the GT35P and GT140P gas turbines. A combustion efficiency of 99.5 % or higher can be expected with most coals, which also results in a low content of residual carbon or unburned material in the ashes. A few percent of char can be found in the primary cyclone ash, while for practical purposes unburned char does not exist in bed ash or secondary cyclone ash. The particulate loading in the flue gas leaving the freeboard of a PFBC plant typically will be 10,000 parts per million by weight (ppmw) or more, depending on the nature, size distribution, and properties of fuel and sorbent. The elutriated particles will have a size range of between 300 micrometers (µm) or more down to less than 1 µm. While cyclones can achieve the necessary reduction in particle loading for protection of the gas turbine, there is interest in alternative cleanup methods, primarily for hybrid cycles applications. Some encouraging results exist from tests with ceramic hot gas filters in the TIDD, Wakamatsu and Escatron plants, and at pilot plant scale, such as in ALSTOM's Component Test Facility (CTF) and Process Test Facility (PTF). However, so far, such filters are not judged ready for use in commercial PFBC plants. 4.4 FBC R, D&D Status Although CFBC in particular and to a far lesser extent PFBC have achieved considerable commercial success, there are a number of areas that continue to be the focus of attention. In broad terms, the drivers for technology improvement are:

• Scale-up issues to achieve increased thermal efficiencies and further cost-effective environmental improvements

• Improved component design leading to more compact and cost effective systems • Repowering applications • Development of improved materials of construction for key in bed components • Broadened range of fuels usage • Use as part of advanced cycles

These issues are addressed in a number of research programmes. 4.4.1 R&D in Europe For CFBC, within the European Union, the European Commission provided funding for R, D&D into clean coal technology within the Framework Programmes. Under the Third and Fourth Framework Programs, considerable support was provided for the development and demonstration of CFBC technology, including the 250 MWe CFBC at Gardanne. In each case, multi-partner collaborations from member countries of the EU were encouraged. Under the Fifth Framework Programme, there was no designated funding for either development or demonstration of FBC technology. The structure

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of the programme changed significantly with a harmonization of technical and social-economic requirements having to be met. The funding for any CCT activity has to meet a range of criteria, of which the most pertinent here is improved environmental performance. Thus, funding cannot be sought for technology development as such, but rather for improving the environmental impact of such technologies. Under Framework 6, there is no scope for direct CFBC R&D. Some R&D funding is available via the ECSC for multi-partner activities. There are guidelines for allocation of funding with environmental considerations a major issue, see below. Electricité de France (EdF) has established a very substantial R, D&D programme on CFBC centred on the Carling (125 MWe) and Provence (250 MWe) power stations. The R&D division of EdF is involved in numerous aspects of the programme, and in particular in the use of modelling tools to establish a detailed understanding of the fluid dynamics of large scale CFBC boiler plant. Cold modelling has been used to validate the results from sample and optical probes installed in the furnace at the Provence power station. EdF is also active in investigating issues associated with scale-up of CFBC to 600 MWe in a single boiler unit. Similarly, Lurgi and Foster Wheeler are actively developing advanced designs for larger scale units with more compact systems and infrastructure, including the incorporation of advanced steam conditions, with fuel flexibility as an integral part of the overall concept. Some of this work has received some financial support via the ECSC R&D programme. Since 1992, in the UK, the DTI via the Cleaner Coal Technology R&D Programme has supported some ten FBC related R&D projects, many of which have been concerned with the use of CFBC in advanced combined cycle systems. The International Energy Agency (IEA) Implementing Agreement constitutes another focus for European initiatives in fluidised bed conversion (FBC), and in particular the fluidised bed combustion of coal and/or alternative fuels (biomass, waste). The European States that are presently signatories to the Agreement are: Austria, France, Finland, Italy, Portugal, Spain, Sweden and the United Kingdom. In the past, the most important activity concentrated on the modelling of the various phases of combustion. At the moment a complete coal atmospheric FBC model is being drawn up, and through 3D modelling, useful results have been obtained in two phase gas solid fluid dynamics, yielding significant results on the local distribution/concentration of the solid particles in the bed, and on the thermal exchange. In addition to this activity, other research fields include: • Friction and solid fragmentation studies • The formation and the reduction of the formation of NOx and N2O. • Sorbent reactivity and sulphur capture mechanisms • Agglomeration and sintering problems in the bed • Ash utilisation • Three-dimensional modelling of circulating fluidised bed combustion • Operation of a pilot cfb-reactor under dynamic conditions • Fluid dynamic modulation of air jet penetration in the gas solid suspension in cross flow • Modelling of solids and gas mixing effects in large-scale cfb combustors • Fluidized bed combustion of liquid fuels • The Circulating moving bed (CMBTM) combustion system, in which a heat exchanger will heat

the energy cycle working fluid, steam or air, to the level required for advanced power generation systems. The CMB™ combustion system can also act as an enabling technology for hydrogen production and CO2 capture from combustion systems using innovative chemical looping air-blown gasification and syngas decarbonisation.

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With regard to PFBC, there is at present minimal direct R&D underway in Europe, reflecting the lack of a technology champion and as such the redirection of activities by the research institutes and universities that have traditionally supported such initiatives. 4.4.2 USA R, D & D activities In the USA, the Department of Energy (DOE), through the Federal Energy Technology Center (FETC), is vigorously promoting CFBC technology and has announced a set of technical goals to be pursued. For the near-term, these include: • To improve understanding that FBC technology has a viable, competitive growth potential even

in an era of deregulation • To continue the development of FBC Clean Coal Technology projects • To scale-up atmospheric units to greater than 250 MWe • To increase FETC public dissemination efforts by educating the general public about the

importance of research and development and the benefits derived from an environmental technology such as fluidised bed combustion.

The flagship project has been the Jacksonville Electric Authority (JEA) Large Scale CFBC Demonstration Project, which is designed to demonstrate Foster Wheeler’s CFBC technology at a scale of nominally 300 MWe, representing a scale-up from previously constructed facilities. The total project cost is just over $309 million with DOE contributing 24% and the industrial participants providing the balance. The current plan is to complete design, construction and operation by end 2004. Clean Coal Power Initiative Under this DoE initiative Colorado Springs Utilities (Springs Utilities) and Foster Wheeler are planning a joint demonstration of an advanced coal-fired electric power plant using advanced, low-cost emission control systems to produce exceedingly low emissions. Multi-layered mission controls will be integrated into a circulating fluidized bed (CFB) combustion unit to produce what is predicted to be the cleanest coal-fired unit in the world on a cost effective and reliable basis. Colorado Springs Utilities and Foster Wheeler are planning to demonstrate this new technology at commercial scale in the 150 megawatt generating unit at the Ray D. Nixon Power Plant, located south of Colorado Springs. To control nitrogen oxides (NOx), the system uses advanced staged-combustion that can achieve very-low furnace NOx levels, coupled with an advanced selective non-catalytic reduction (SNCR) system that can reduce stack NOx to levels achievable today only with higher-cost selective catalytic reduction (SCR). To control sulphur oxides (SOx), the design features a three-stage approach to achieve high sulphur capture (96-98%) with low limestone consumption (less than half of conventional CFB systems). In addition to the advanced SOx and NOx control technology, the advanced low-emission combustion system includes a low-cost, integrated trace-metal control system that can remove up to 90% of mercury, lead and other metals, and virtually all acid gases in the flue gas. Vision 21, USA The technological roadmap of the Vision 21 Program will guide development efforts in High-Performance Combustion Systems [14, 15]. One configuration of 21st Century Energy Plants could be based on combustion rather than gasification. As such, for such designs, future research and development will concentrate on advanced technologies such as pressurized fluidised bed combustion (PFBC) and high temperature heat exchangers. Improvements will be needed in materials, catalysts, and instrumentation to make 21st Century Energy Plants a reality, and advanced computation techniques will be necessary to allow for computer simulations for design and testing. The main research topics related to PFBC are summarised in Table 4.1. One interesting area is “Virtual demonstration of Circulating Fluidized Bed performance”, in which Princeton University has been developing a “Coarse-Grid Simulation of Reacting and Non-Reacting Gas-Particle Flows”. This project will develop improved methods for simulating bubbling, spouted, and circulating fluidised beds, including those with chemical reactions. The virtual simulation tool developed in this project

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will be based on the open-domain Computational Fluid Dynamics (CFD) code MFIX that was originally developed at NETL. The computational model developed will permit both cold-flow and reactive-flow simulations. The principal challenge in this effort is to devise and implement sound physical models for rheological characteristics of the gas-solid suspensions. The goal of the project is to develop and demonstrate the capability of a virtual simulation tool model to model the flow of reactive gas- particle mixtures in CFB. Activities in Vision 21 PFBC programme Activities that continue separately

CO2 recycle Carbonizer development Hot particulate removal Combustion with O2 Advanced sorbent development Ultra-high efficiency PFBC Isothermal compressor development PFBC systems analysis and modelling

Feed and ash handling cost reduction Repowering Specific gas turbine development and

adaptation of existing turbines Hot particulate filter reliability and adaptation

to other markets PSDF activities

Table 4.1 Vision 21 programme activities

4.4.3 Japanese R, D & D activities There have been several studies plus experimental work undertaken in recent years. PFBC process development unit test project With government funding, the Center for Coal Utilization, Japan (CCUJ) and NEDO have engaged in the development of fluidised-bed combustion technology and coal gasification technology. The development and practical application of normal pressure fluidised-bed combustion technology is deemed complete, and has been followed by the development and practical application of pressurised fluidised-bed combustion technology with the possibility of high efficiency. This is, in effect, a hybrid cycle through a rise in the gas turbine inlet temperature (from 850ºC in the PFBC to 1300ºC or so in the A-PFBC) by combining a partial gasifier with conventional PFBC technology, see Section 6. Studies on Combustion, Hydrodynamics and Heat Transfer in Advanced Coal Utilisation Technologies. Nagoya University (Japan), Hamburg University (Germany) and the Research Centre for Advanced Energy Conversion (Japan)carried out a joint project (1992-1995) into the development of energy production technologies based mainly on fossil fuel combustion. The results included:

• Effective and economic desulphurisation processes using Ca-based sorbents were developed. The formation behaviour of NOX and N2O via NH3 at high-temperatures in the simulated gas atmosphere were clarified.

• Developments of diagnostic and measurement technologies for hydrodynamics and combustion in multi-solid fluidized beds were carried out, and the fluidization and combustion characteristics in the present system were revealed.

• Ash melting behaviour and inorganic compounds emissions from various ashes under coal combustion and gasification conditions were made clear.

• The combustivities of various coals were estimated and the relation between coal rank and the ignition characteristics were clarified.

Based on the above studies, various environmentally acceptable, low air pollutant emissions, combustion systems were proposed for using various fuels such as low-rank coal, sludge and gas. Computer analysis of PFBC combined-cycle power generation systems. This project by the Central Research Institute of Electric Power Industry (CRIEPI) finished in 1992. It was designed to develop and evaluate software to analyse the thermal efficiency of bubbling-bed and circulating-bed the software showed that PFBC combined-cycle power generation systems, and in particular, the circulating-bed type PFBC system, have high thermal efficiency in comparison to conventional coal-fired power generation systems.

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Effect of fuel type on the formation of agglomerates in a large scale pressurized fluidized bed combustor IHI Heavy Industries and Tokyo University have investigated agglomerate formation in the world’s largest pressurised fluidised bed combustor at Karita Power Station, Japan. It was found that significant amounts of agglomerate were formed at increased boiler load, bringing about a significant decrease of bed density. Agglomerate formation occurred particularly when the unit was fired with a porous Blair Athol coal that was found to produce a porous char. Firing the boiler with other coals (Nanton) that produced less porous char prevented the formation of agglomerates and enabled stable operation of the combustor to be maintained. A model was developed to calculate the horizontal distribution of char surface temperature in the PFBC based on a quasi-steady heat balance for a burning char by taking into consideration the distribution of volatiles above the fuel feeding nozzles, as well as char porosity. In order to consider the effect of porosity on the combustion of a porous char, a completely new expression to estimate the reaction rate was proposed. The results indicated that the agglomerates were mainly formed due to the combustion of highly porous Blair Athol chars in the poorly fluidised areas in the bed, where air-to-fuel ratio became larger. The combustion rate of less porous Nanton char was much slower then that of the Blair Athol. Accordingly, the combustion temperature of its char was lower, bringing about no formation of agglomerates. 4.4 Future R, D&D needs From an EU perspective, the focus of the future for fluidised bed systems would appear to be on CFBC since this technology can be supplied by a large number of EU manufacturers and there is good cooperation with a number of research institutes and universities on an international basis [16]. CFBC systems offer an alternative to PF plants, with the advantage of being able to use low grade, variable quality coal, plus biomass and wastes, and still achieve high environmental performance at lower cost. With these advantages, CFB fulfils the needs of utility operators in deregulated energy markets and improves coal competitiveness, utilization of local resources, employment and EU export opportunities. CFB boilers have been successfully demonstrated at the < 300 MWe scale, and there have been significant efforts by various manufacturers to develop the technology further, to achieve a breakthrough in utility solid fuel power generation by high efficiency CFB technology with supercritical (SC) steam parameters, as evidenced by the first commercial 460 MWe system with advanced steam conditions now being established in Europe. Such plants with supercritical steam parameters can now achieve overall net efficiencies in the 43-45% range depending on fuel and condenser conditions. The driver now must be to propose and implement commercial projects to scale up the technology to 600-800 MWe to satisfy the operators’ future needs. Proposals have been prepared to advance the state of the art by putting together a multi-partner development programme aiming at a highly competitive system. This includes the integration of a 20% substitution of coal by renewables (biomass), which can reduce CO2 emissions by a further 20-25%. As a result, the advantages and new advanced characteristics of CFB technology could be fully utilised, enhanced further and transferred wider to the power generation industry. The technology will also benefit from any development of ultra-supercritical steam conditions for PF plants (e.g. the AD 700 initiative) and an increase in efficiency towards 50 % will also be a target for CFB boilers. As with PF development, such a project by EU industry would represent an ERA type initiative, but under FP6 there is no scope at present to receive funding to mitigate the risk of taking such a development forward. Finally there is a need to consider the CFBC near zero emissions concept. The same issues and technology options apply here as were discussed in Section 3 on PF, with the provision that as yet the commercial units are smaller than state of the art PF and as such the adverse impact on cost and efficiency of power generation will be proportionately greater.

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In addition, the potential for using CFBC as an enabling technology for hydrogen production and CO2 capture from combustion systems using innovative chemical looping air-blown gasification and syngas decarbonisation needs to be considered in some detail in order to ascertain whether it has sufficient benefit to justify ERA type funding under future Framework programmes. 4.5 References [1] IFRF Combustion File No. 87 [2] A J Minchener, “Fluidised bed combustion systems for power generation and other industrial

application”, DTI-Technology status report 011, January 2000 [3] J R Grace (ed) et al, Circulating Fluidized Beds,. Blackie Academic &

Professional,London,1997. [4] L. Reh, “Challenges of circulating fluid-bed reactors in energy and raw materials”, Chem. Eng.

Sci., 54, pp. 5359-5368, 1999 [5] J. P. Jacobs, “The future of fluidised-bed combustion”, Chem. Eng. Sci., 54, pp. 5559-5563,

1999 [6] K Cleve, Latest Developments and Status of Long Term Experience in CFB-Technology, Proc.

15th ASME Conference on Fluidized Bed Combustion, 1999. [7] Yamamoto, Kajigaya and Umaki “Operational experience of USC steam condition plant and

PFBC combined cycle ssystem with material performance”, Materials at high temperature, Vol.20, n.1, pp.15-18

[8] J. Koike, S. Nakamura, H. Watanabe and T. Imaizumi, “Manufacturing and construction, operation of Karita 360 MW unit”, Proc. FBC2003, 17th Int. Fluidized Bed Combustion Conference, Jacksonville, Florida, May 18-21, 2003

[9] D. Veenhuizen “karita P800 supercritical 360 MWe PFBC plant reaches full power” (1999) Modern Power system, November

[10] J M Wheeldon, A Review of PFBC Power Plant Designs, Proc. 13th Pittsburgh Coal Conference, 1996.

[11] S.J. Goidich and R.G. Lundqvist “The utility CFB boiler-Present status, short and long term future with supercritical and ultra-supercritical steam parameters”, Foster Wheeler

[12] R. Hickey, J.C. Semerard and G. Scheffknecht, “Clean solid fuel power generation: circulating fluidised bed technology for the future”…

[13] P. Laffont, J. Barthelemy, B. Scarlin and C. Kervenec “A clean and efficient supercritical circulating fluidised bed power plant” Alstom power

[14] USDoE , Vision 21program plan. Clean energy plants for the 21st century, http://www.fossil.energy.gov/ Washington DC USA (Apr 1998)

[15] USDoE, DoE selects first Vision 21 projects to design the energy plant of the future, http://www.fossil.energy.gov/ Washington DC USA (Mar 2000)

[16] IEA CCC, Competitiveness of future coal-fired units in different countries, IEA publication CC/14, 1999.

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5. INTEGRATED GASIFICATION COMBINED CYCLES (IGCC) 5.1 Introduction This section provides an international “state-of-the-art” review in the field of clean fossil energy conversion through gasification. The terms of reference encompass the following technology and final product variants: • All gasification units that can be fired with coal, coal with biomass and wastes, refinery residues

and natural gas. • Gasification both for power generation and the associated production of chemicals and fuel gases. 5.2 Fossil fuel gasification technology status Gasification is a means to convert a fossil fuel into either a combustible gas or a synthesis gas for subsequent utilisation. The primary products that can be produced in such plants include electricity, ammonia, oxy-chemicals, syngas, methanol, and hydrogen, as summarised in Table 5.1[1]. Worldwide, there are some 160 modern, gasification units in operation (excluding over 8000 low grade and polluting small units in China), and a further 35 at the planning stage (see Tables 5.2 and 5.3).

Table 5.1 Primary products produced through fossil fuel gasification

Primary product Product Operating plant Planned plant Secondary product

Electricity 35 25 6 Hydrogen 11 1 11 Ammonia 34 3 1 Syngas 14 1 2 Methanol 12 1 11 Oxychemicals 22 0 1 Carbon Dioxide 7 0 5 Others (FT liquids, fuel gas) 25 4 0 Total 160 35 37 Source: Derived from the World Gasification Database, U.S. Department of Energy and the Gasification Technology Council 5.2.1 Feedstock options In the context of this review, the feedstocks include coal, natural gas (for reforming applications) [2, 3, 4], refinery residues [5, 6, 7, 8] and biomass/wastes in combination with coal [9]. All coal types can be gasified. However, on economic grounds, low ash content coals are preferred. There is sensitivity to various coal properties depending on the technology used. In some cases, coal with low sulphur and low halogen content is preferred (e.g. to avoid corrosion of syngas coolers/cleaners in entrained flow systems). In addition, the ash fusion temperature can be an important variable (e.g. in fluidised bed and dry moving bed systems). This is considered further in Section 5.2.3. With regard to refinery residues (bottoms), these can take several forms depending on the design of the refineries and their products. The primary bottoms that comprise most of the fuels of interest for energy applications include: • Atmospheric distillation residue • Vacuum distillation residue • Residual tar from solvent deasphalting/visbreaking process • Petroleum coke from the coker Although much attention has been focused on using coal as the primary feedstock, the large majority of gasification projects to date are based upon the use of fuels other than coal, as shown in Table 5.4.

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5.2.2 Process options Some 20% of the gasification projects throughout the world that use coal as the feedstock produce electric power [1]. The rest produce chemicals such as ammonia, methanol, oxychemicals and syngas. The biomass and biofuels gasification projects, which are small scale compared to fossil fuel operations, produce electricity and syngas. The heavy petroleum products and refinery residues projects are used extensively to produce chemicals and gases, although power production has been integrated with the more recent units. Natural gas and naphtha are used to produce chemicals and fuels, primarily carbon monoxide, hydrogen, methanol and oxychemicals.

Table 5.2 Major operating electricity producing gasifiers by country

Country Plant Name Type Feedstock Products Year Australia Whytess Gully Waste to Energy Proj. Unknown Biomass Electricity 1999 Austria Zeltweg Gasification Plant Unknown RFD Electricity 1997 Canada MSW Plant Thermogenics Inc. Biomass Electricity 2000 Canada Toronto MSW Plant Thermogenics Inc. Municipal waste Electricity 2000 China Beijing Town Gas Plant Texaco Coal Town gas & Electricity 1995

Czech Rep. Vresova IGCC Plant Lurgi Dry Ash Lignite Electricity & Steam 1996

Finland Kymijärvi ACFBG Plant FW ACFBG Biofuels Electricity & District heat 1998

Germany Schwarze Pumpe Town Gas Plant Lurgi Dry Ash Municipal waste Electricity & Methanol 1964

Germany Leuna Methanol Anlage Shell Visbreaker residue H2, Methanol & Electricity 1985

Germany Slurry/Oil Gasification Lurgi MPG Oil & Slurry Electricity & Methanol 1968

Germany Schwarze Pumpe Power/Methanol Plant BGL Household waste & Bit. coal Electricity & Methanol 1999

Germany Schwarze Pumpe Gasification Plant GSP Municipal waste Electricity & Methanol 1992 Germany Fondotoce Gasification Plant ThermoSelect MSW Electricity 1999

India Sanghi IGCC Plant GTI (IGT) U-GAS Lignite Electricity & Steam 2002 Italy Project Texaco ROSE asphalt Electricity, H2 & Steam 2000 Italy SARLUX GCC/H2 Plant Texaco Visbreaker residue Electricity, H2 & Steam 2001

Netherlands Pernis Shell Gasif. Hydrogen Plant Shell Visbreaker residue H2 & Electricity 1997 Netherlands Buggenum IGCC Plant Shell Bit. coal Electricity 1994 Netherlands Americentrale Fuel Gas Plant Lurgi CFB Demolition wood Electricity 2000 Singapore Chawan IGCC Plant Texaco Residual oil Electricity, H2 &Steam 2001

Spain Puertollano GCC Plant PRENFLO Coal & petcoke Electricity 1997 Sweden Värnamo IGCC Demonstration Plant FW PCFBG Biofuels Electricity & Distr. heat 1993 Taiwan Kaohsuing Syngas Plant Texaco Bitumen H2, CO & Methanol SG 1984

U K Fife Power BGL Coal & sludge Electricity 2001 U K Fife Electric BGL Coal & sludge Electricity 2002 U K Project ARBRE TPS Biomass Electricity 2000

U S A Wabash River Energy Ltd E-GAS (Destec/Dow)

Petcoke Electricity 1995

U S A Delaware Clean Energy Cogen. Project Texaco Fluid petcoke Electricity & Steam 2001 U S A Polk County IGCC Project Texaco Coal Electricity 1996 U S A Piñon Pine IGCC Power Project KRW Bit. coal Electricity 1998 U S A Commercial Demonstration Facility Brightstar Env. Ltd. Biomass Electricity 1996 U S A New Bern Gasification Plant Chemrec Black Liquour Electricity 1997 U S A McNeil IGCC Project Fut. Ener. Resources Forest residue Electricity 1997 U S A El Dorado IGCC Plant Texaco Petcoke, Ref. Waste & Nat. gas Electricity & HP steam 1996

Source: Derived from the World Gasification Database, U.S. DoE and Gasification Technology Council Note: The Värnamo, ARBRE and Piñon Pine plants are now closed.

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Table 5.3 Major planned electricity producing gasifiers by country

Country Plant Name Type Feedstock Products Year Australia Esperance Gasification Plant Texaco Lignite F-T liquids/Electricity 2007

Brazil Brazilian BIGCC Plant TPS Biomass Electricity 2003 China Caojing Power Plant Shell Coal Electricity & Syngas 2004

Czech Rep. Vrecopower/Vresova IGCC Project

HTW Lignite Electricity 2003

Europe (Unspecified)

Unspecified Plant Shell Residue Electricity 2005

France Normandie IGCC Plant Texaco Fuel oil Electricity, Steam & H2

2005

India Bhatinda IGCC Texaco Petcoke Electricity 2005 Italy Agip IGCC Shell Visbreaker residue Electricity & H2 2003 Italy Sulcis IGCC Project Shell Coal Electricity 2004 Italy Sannazzaro GCC Plant Texaco Visbreaker residue Electricity 2005 Japan Unspecified IGCC Plant ICGRA Coal Electricity 2004 Japan Marifu IGCC Plant Texaco Petcoke Electricity 2004 Japan Yokohama Cogen/B Texaco Vac. residue Electricity 2003

Netherlands Europoort/Pernis IGCC Plant Texaco Waste plastics Electricity & CO 2006 Poland Gdansk IGCC Plant Texaco Visbreaker residue Electricity, H2 &

Steam 2005

Spain Bilbao IGCC Plant Texaco Vac. Residue Electr.& H2 2005 U S A Kentucky Pioneer Energy AFT-

IGCC Plant BGL Coal & MSW Electricity & Diesel 2003

delayed U S A Lima Energy IGCC Plant BGL Coal & MSW Electricity & H2 2003 U S A Gilberton Culm-to-Clean Fuels

Plant Texaco Anthracite culm Diesel & Electricity 2004

U S A Site not yet determined Carbona/Enviropower Biomass Electricity 2004 U S A Site not yet determined U-GAS Biomass Electricity 2004 U S A Calla GCC Plant U-GAS Biomass Electricity 2003 U S A Unspecified Plant Texaco Coal Electricity 2006 U S A Port Arthur GCC Proj E-GAS(Destec/Dow) Petcoke Electricity 2005 U S A Lake Charles IGCC Proj. Texaco Petcoke Electricity, H2 &

Steam 2005

U S A Deer Park GCC Plant Texaco Petcoke Elect., Syngas & Steam 2006 U S A Polk County Gasification Plant Texaco Petcoke Electricity 2005 U S A Kingsport IGCC Plant Texaco Bit. coal Electricity 2007

Source: Derived from the World Gasification Database, U.S. DoE and Gasification Technology Council

Table 5.4 - Feedstocks used in gasification plants

Feedstock Operational plant Planned plant Coal 27 14

Coal / petcoke 3 1 Petcoke 5 7

Natural gas 22 0 Biomass 12 3

Fuel oil / heavy petroleum residues 29 2 Municipal waste 5 0

Naptha 5 0 Vacuum residue 12 2

Unknown 40 6 TOTAL 160 35

Source: Derived from the World Gasification Database, U.S. DoE and Gasification Technology Council

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5.2.3 Technology options There are three technology variants, classified by gasifier configurations according to their flow geometry: • Entrained flow gasifiers, in which pulverised coal particles and gases flow concurrently at high

speed. They are the most commonly used gasifiers for coal gasification. • Fluidised bed gasifiers, in which coal particles are suspended in the gas flow; coal feed particles

are mixed with the particles undergoing gasification, • Moving bed (also called fixed bed) gasifiers, in which gases flow relatively slowly upward

through the bed of coal feed. Both concurrent and countercurrent technologies are available but the former is more common.

Each has advantages and disadvantages together with differing commercial track records. In overall terms, with regard to suppliers, Shell and Texaco entrained flow gasifiers are used in nearly 75% of the 160 projects referred to above [10]. Of the rest, Lurgi moving bed gasification technologies are also used to a significant extent. For the “planned” gasification projects, it is understood that approximately 75% of these will also use either the Texaco or Shell designs. Entrained flow gasifiers Entrained flow gasifiers are the most widely used gasifiers with seven different technologies (BBP, Hitachi, MHI, PRENFLO (see Figure 5.1), SCGP, E-Gas and Texaco) available [11, 12]. In these gasifiers, coal and other solid fuel particles concurrently react with steam and oxygen or air in suspension (i.e. entrained) fluid flow mode. Coal can either be fed dry (commonly using nitrogen as transport gas) or wet (carried in water slurry) into the gasifier. Entrained flow gasifiers usually operate at high temperatures of 1200–1600°C and pressures in the range of 2–8 MPa with most of the large plants operating at around 2.5 MPa. Raw gas exiting the gasifier usually requires significant cooling before being cleaned. There are two main methods of cooling the gas, either by using a high temperature syngas cooler, which can also include recycling a portion of cooled gas to the gasifier, or by quenching the gases with water. Such units, with a gas residence time of a few seconds, have a high load capacity but this requires the solid fuel to be pulverised to <1 mm. That said, rapid changes in fuel for loading are difficult to handle as the fuel:oxidant ratio has to be maintained within a narrow range in order to keep a stable flame close to the injector and maintain the stability of operation. Entrained flow gasifiers are the most versatile type of gasifiers as they can accept both solid and liquid fuels and operate at high temperature (above ash slagging temperatures) to ensure high carbon conversion and a syngas free of tars and phenols. However such high temperatures have an impact on burners and refractory life and require the use of expensive materials of construction as well as the use of sophisticated high temperature heat exchangers to cool the syngas below the ash softening temperature in order to avoid fouling and control corrosion problems. The ash fusion temperature (or melting point) of the coal/solid fuel should preferably be low so that molten ash can flow down the reactor walls and drain from the gasifier. Fluxes like limestone can be added to reduce the coal ash melting point [13]. Even so, the composition of the coal slag can have a major influence on gasifier refractory life. With the high chrome refractory materials usually used in commercial gasifiers, the slag can penetrate deeply into the refractory before solidifying. As a result, changes that occur in the microstructure and the properties of the refractory give rise to cracks that ultimately lead to material loss [14]. Refractories are expensive parts of the equipment of a gasification plant and to be economically advantageous they should last for a minimum of 2–3 years [15]. Coals with a low ash content are preferred for both economical and technical reasons [16, 17 18]. If gasifier operating conditions are kept constant, an increase in coal ash content will lead to a decrease in gasification efficiency and an increase in slag production and disposal. These three factors contribute to an increase of the overall cost of the process. The decrease of gasification efficiency is mainly due to an increase in oxygen consumption necessary to melt the minerals as well as a thermodynamic penalty since the heat in the slag exiting the gasifier cannot be fully recovered. However, each technology has slightly different coal ash requirements depending on their design. There is a minimum ash content required for the SCGP (>8 wt %), the BBP (>1 wt %) and the Hitachi

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gasifiers because of a slag self-coating system on the wall of the gasifiers, which has to be covered by slag to function and minimise heat loss through the wall.

Figure 5.1 The Prenflo Gasifier (Tabberer, 1998)

The tolerance of entrained flow processes to sulphur and halogen species also differs with each process. It depends on the composition and resistance of the material used in the cooling, cleaning and tapping systems but also on the operating conditions of the gasification process (especially gasifier temperature), as well as the processing capacity of the downstream equipment, such as the sulphur recovery plant. Fluidised bed gasifiers There are six types of gasification processes (BHEL, HTW, IDGCC, KRW, Transport reactor, Mitsui Babcock ABGC) using fluidised bed gasifiers although the majority have yet to be developed to the demonstration scale (see below) [11, 12]. Fluidised bed gasifiers can only operate with solid crushed fuels, with the exception of the transport reactor, which is midway between a fluidised bed and an entrained flow gasifier and as such operates with pulverised fuel (i.e. coal: 0.5–5 mm, <50 µm for the Transport Reactor Gasifier) The coal is introduced into an upward flow of gas (either air or oxygen/steam) that fluidises the bed of fuel while the reaction is taking place. The bed is either formed of sand/coke/char/sorbent or ash. Residence time of the feed in the gasifier is typically in the order of 10–100 seconds but can also be much longer, with the feed experiencing a high heating rate on entering the gasifier. High levels of back-mixing ensure a uniform temperature distribution in the gasifier. Fluidised bed gasifiers usually operate at temperatures well below the ash fusion temperatures of the fuels (900–1050°C) to avoid ash melting, thereby avoiding clinker formation and loss of fluidity of the bed. There are both dry ash and agglomerated ash systems. One of the main advantages of these types of gasifier is that they can operate at variable loads which gives them a high turndown flexibility. A consequence of the low operating temperatures is the incomplete carbon conversion in a single stage, leading to lower cold gas efficiency than in the other types. In order to avoid the production of fly ash with high carbon concentration, many of the fluidised bed gasification processes are now

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equipped with a fly ash recirculation unit. Nevertheless, depending on the coal used, this can lead to an increase of the ash content of the bed. Hybrid systems, in which coal is first gasified in a fluidised bed followed by char combustion in a fluidised bed combustor, can solve this problem and increase carbon conversion leading to higher cold gas efficiency (see Section 6) [19]. Because of the low operating temperatures in fluidised bed gasifiers, reactive coals such as lignites and brown coals are the coals of choice [20, 21]. Fluidised bed gasifiers with agglomerated ash operation can however process higher rank coals as they have higher cold gas efficiency than dry ash systems. Sulphur which is found in the gas stream as H2S and COS can be partly retained in the bed (up to 90%) by sorbents such as limestone. This leads to a considerable reduction of the H2S concentration in downstream equipment and hence a decrease in material corrosion. A consequence of the use of sorbents to retain sulphur compounds in beds as well as the low operating temperatures in fluidised bed gasifiers allows the use of cheaper materials for the building of heat exchangers and cleaning devices. Fluidised bed systems are more tolerant to sulphur than entrained flow systems. However very high sulphur coals are not recommended as they would require a further addition of sorbent leading to an increase in the volume of solids discharged by the process and hence in its overall cost. Moving bed gasification processes There are only three types of gasification processes using moving bed gasifiers (BGL, BHEL, Lurgi dry ash) developed at industrial scale though they are the most mature of the three generic types of gasifier [11, 12, 22, 23]. Moving bed gasifiers can be either slagging (BGL, see Figure 5.2)) or dry ash (Lurgi, BHEL) gasifiers. They are only suitable for solid fuels and can process coals with biomass and/or wastes. The major difference between the two types of gasifiers is that dry ash gasifiers use a much higher ratio of steam to oxygen than the BGL gasifier, resulting in a much lower temperature in the combustion zone (1000°C) and making the dry ash system more suited to reactive coals like lignites than the BGL gasifier. Moving bed gasifiers can process coals with relatively high ash content. Coals with ash contents of up to 35% are reported to be currently processed in the Lurgi dry ash gasifiers at Sasol and at the BHEL pilot plant gasifier.

Figure 5.2 The British Gas Lurgi Gasifier (White 2000)

47

Lump coal (5–80 mm) is fed into the top of the gasifier via a lock hopper system. Processing may be needed to achieve this size as a very fine coal feed will tend to blow straight out of the gasifier. A mixture of steam and oxygen is introduced at the bottom of the reactor and runs counter-flow to the coal. Coal residence times in moving bed gasifiers are of the order of 15 to 60 minutes for high pressure steam/oxygen gasifiers and can be several hours for atmospheric steam/air gasifiers. The pressure in the bed is typically 3 MPa for commercial gasifiers with tests realised at up to 10 MPa. Coal enters the top of the gasifier and is preheated, dried, devolatilised/pyrolysed, gasified and combusted while moving towards the bottom of the gasifier. Moisture is first driven off in the drying zone then coal is further heated and devolatilised by the hotter product gas while moving down to the gasification zone where it is gasified by reacting with steam and carbon dioxide. The remaining char is finally completely burnt in the combustion zone where the bed reaches its highest temperature. Maximum temperatures in the combustion zone are typically in the range 1500–1800°C for slagging gasifiers and 1300°C for dry ash gasifiers. As the flow is countercurrent, the gas leaving the gasifier is cooled against the incoming feed and typical gas exit temperatures are 400–500°C. Thus the use of expensive syngas coolers is not required in moving bed gasifiers. Nevertheless, the temperature at the top of the gasifier is usually not high enough to break down the tar, phenols, oils and low boiling point hydrocarbons produced in the pyrolysis zone and carried out with the gasifier product gas. Recent design changes incorporate recycling which helps to consume these by-products to extinction. Ash is removed either as a dry ash or as a slag, depending on the gasifier type. In order to ensure efficient heat and mass transfer between solids and gases, good bed permeability is needed to avoid pressure drops and channel burning that can lead to unstable gas outlet temperatures and composition as well as a risk of a downstream explosion. Bed permeability depends among others, on coal particle size, thermal fragmentation, caking propensity and ash fusion temperature. Depending on the gasifier design and other characteristics of coal, such as caking propensity, the tolerance of the different gasifiers for coal fines varies from 5% at the Dakota Gasification plant to up to 50% fines (30–40% solid fines and slurry of up to 30% fines) in the BGL gasifier. The latter involves cautious screening prior to gasification and possibly briquetting of the fines. Caking coals have to be blended with low caking coals to be processed in the Lurgi dry ash gasifier at Sasol. The BGL gasifier can tolerate strongly caking coals when a stirrer is connected on the coal distributor. Coal ash fusion temperature (AFT) is also a parameter to consider for dry ash and slagging gasifiers. A low ash fusion temperature can result in the formation of fused ash in the ash bed of dry ash gasifiers, hence an ash fusion temperature higher than the maximum operating temperature of the dry ash gasifier is recommended. 5.2.4 Gasification for power generation Figure 5.3 shows a schematic of an IGCC power plant, and Table 5.5 lists the technology suppliers for the major gasification projects worldwide (both for power and chemicals production). As noted above, the majority of the major IGCC projects are based on Shell and Texaco gasification technology [24, 25 26]. There was one IGCC demonstration project using the KRW fluidised bed technology (Piñon Pine) in the USA but this has faced numerous problems since its commissioning and has now been closed [27]. There is also a project in the Czech Republic to develop an IGCC based on the HTW gasification technology to replace old moving bed gasifiers [28]. There is one coal IGCC plant operating with moving bed gasifiers in Germany (Schwarze Pumpe, BGL technology) for the processing of wastes and coal [29]. The ‘flagship’ coal based IGCC projects for Europe and the USA are shown in Table 5.6, which lists the gasifier and gas turbine technology choices. In overall terms, the development of the IGCC market has been driven by the need to gain added value from refinery residues and this is indicated in Figure 5.4, which shows the size and commissioning dates for the major IGCC projects worldwide. This indicates that while the initial IGCC projects were coal-based the more recent units since Puertollano was established have been built to utilise the refinery residues.

48

Figure 5.3 Schematic of IGCC showing key system components

TECHNOLOGY SUPPLIER

GASIFIER TYPE

SOLID FUEL FEED TYPE

OXIDANT INSTALLATIONS

Chevron Texaco, USA

Entrained Flow Water Slurry O2 Tampa Electric IGCC Plant Cool Water IGCC Plant Chevron Texaco Eldorado IGCC Plant, Eastman Chemical, Ube Industries, Motiva Enterprises, Deer Park

Global Energy E-Gas, USA

Entrained Flow Water Slurry O2 Wabash River IGCC Plant and Louisiana Gasification Technology IGCC Plant

Shell, USA/ The Netherlands

Entrained Flow N2 Carrier/Dry O2 Demkolec IGCC Plant (Buggenum, Netherlands) Shell Pernis IGCC Plant, Netherlands, Harburg

Lurgi, Germany Moving Bed Dry Air Sasol Chemical Industries and Great Plains Plants

British Gas/Lurgi Germany, UK

Dry O2 Global Energy Power/ Methanol Plant, Germany

Prenflo/Uhde, Germany

Entrained Flow Dry O2 Elcogas, Puertollano IGCC Plant (Spain), Furstenhausen in Saarland

Noell/GSP, Germany

Entrained Flow Dry O2 Schwarze Pumpe, Germany

HT Winkler (HTW) RWE Rheinbraun/ Uhde, Germany

Fluidised Bed Dry Air or O2 None

KRW, USA Fluidised Bed Dry Air or O2 Sierra Pacific (Nevada, USA)

Table 5.5 Technology suppliers for gasification projects worldwide

49

Project/ Location Combustion Turbine

Gasification Technology

Net Output MW

Start-up Date

Wabash River, IN GE 7 FA Global E-Gas (formerly Destec)

262 Oct 1995

Tampa Electric, FL GE 7 FA Texaco 250 Sept 1996

Demkolec (now NUON), Buggenum, Netherlands

Siemens V 94.2 Shell 253 Jan 1994

Elcogas, Puertollano Spain

Siemens V 94.3 Krupp-Uhde Prenflo

310 Dec 1997

Table 5.6 Details of flagship IGCC projects in Europe and the USA

Figure 5.4 Deployment of IGCC units

A more detailed assessment of IGCC deployment on a geographic basis is provided below. EU situation In the EU, many companies have actively been developing IGCC technology. The following ‘commercial’ power projects are either in operation or under development:

0

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Cool Water (USA)

Buggenum (NL)

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Tampa Electric (USA)

Puertollano (E)

Pernis (NL)

Pinon Pine USA)

ISAB (I)

Sarlux (I)

API (I) Delaware (USA)

Singapore Plaquemine (USA)

Terre Haute (USA)

El Dorado (USA)

Reno (USA)

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Buggenum, Netherlands, firing coal (plus some part biomass trials). This is a 283 MW electric power plant that uses Shell gasification technology. It has been in operation since 1994 [30, 31].

Puertollano, Spain, a 335 MWe IGCC demonstration plant firing a 50:50 blend of petroleum coke and coal (Figure 5.5). The project received a subsidy from European Commission’s Thermie programme with a grant of 50 million ECUs (~$60 m). The project uses a PRENFLO entrained-flow system with dry feeding, supplied by Krupp Uhde [32, 33, 35, 35, 36, 37].

Shell Pernis Refinery, Netherlands. This project uses Shell gasification technology to convert vacuum cracked residue and asphalt to electricity. It has a total capacity of 1,650 t/d residue and produces 130 MW of electricity [24].

Sarlux, Italy. This project gasifies 3,424 t/d (3,771 short-t/d) of visbreaker residue to produce steam, 550 MW of power, and hydrogen in a Texaco gasifier at the Saras refinery in Cagliari [38].

ISAB, Italy, uses a Texaco quench gasifier to convert 130 t/h of de-asphalter bottoms from the ISAB refinery in Priolo Gargallo, Siracusa, Sicily, to produce a nominal 510 MW of power [38].

API, Italy. This project uses a Texaco gasifier to gasify 1,335 t/d (1,470 short-t/d) of visbreaker residue from the API refinery in Falconara to produce steam and 280 MW of power [39].

Schwarze Pumpe, Germany, converts a mix of 450,000 t/annum of solid waste, and 50,000 t/annum of liquid wastes into electricity, steam, and methanol feedstock using four solid-bed gasifiers made by a variety of manufacturers, and firing visbreaker residue [29].

Schwarze Pumpe, Germany, firing plastic, wood, coal, oil wastes, sewage sludge. Sulcis, Italy, in development for a 450 MWe coal-based power plant using the Shell gasification

technology. The plant will be in operation in 2005 [40]. Agip, Italy, in development for use of high-viscous bottom tar from a visbreaking unit and produce

clean syngas for a power generation unit, where it will be co-fired with natural gas. The plant will use Shell gasification technology and is planned to be in operation in 2004.

Piemsa, Spain, commissioning for 2004/2005 is planned for this IGCC complex that will use refinery heavy stocks to produce 784 MW of net power, hydrogen, sulphur and metals concentrate using Texaco gasification technology [41, 42].

USA situation Thirty-eight gasification projects are either in operation or are planned to be built in the USA. Of these, 8 are based on coal (of which it is known that 3 use bituminous coal, 1 uses anthracite culm and 1 uses lignite coal). Half of the projects produce chemicals as their primary products; the others produce electricity. Only four of the 19 plants that produce chemicals use coal as their feedstock. More than one-half of the gasifier projects in the U.S. use the Texaco gasification technology, although almost every gasifier type that has been developed has been tested [10]. Six of the IGCC projects for electric power have received financial incentives from the U.S. government, mostly capital to buy-down the cost of the equipment. These are: • Polk County IGCC project (funded under the U.S. Department of Energy (DOE) Clean Coal

Technology (CCT) Demonstration program) [43], • Wabash River Energy Limited (funded under the CCT program) [44, 45], • Pinon Pine IGCC Power Project (funded under the CCT program) [27], • Kentucky Pioneer Energy AFT-IGCC project (funded under the CCT program) [46], • Calla IGCC plant, • Boise Cascade project. 5.2.5 Gasification for non-power applications Chemical gasification plants based on entrained flow and more especially on moving bed technologies are at present operating all over the world with the biggest plants located in South Africa (Sasol). EU situation In the past, there was considerable interest in Europe in the gasification of coal to produce syngas to be used either as a fuel or as a feedstock (e.g. in chemicals production). However, with the major switch to natural gas, that interest has declined as near-to-medium-term market prospects are limited.

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A variety of technologies have been developed in Europe to either demonstration or commercial scale. Several of these are available on a commercial basis. For example, Lurgi offers a circulating fluidized bed (CFB) gasification technology, which is suitable for the treatment of brown coal/lignite. Also, a commercial CFB gasification unit at the Ruedersdorfer Cement Plant in Berlin is producing gas for firing the cement kiln. Such CFB type gasification technology can also be offered by Foster Wheeler (Finland/USA). The Rheinbraun Winkler/HTW bubbling fluidised bed coal gasification (FBG) technology is established at demonstration scale in Berrenrath, Germany for the production of methanol and synthetic raw gas from brown coal. Recently the emphasis has been on trying to establish the technology for IGCC power production, with EC financial support being offered for a demonstration plant in Eastern Europe [28]. Other suppliers of bubbling FBG technology variants include OSC Process Engineering (UK). Also of relevance is the two-stage atmospheric fixed-bed coal gasification technology which is offered by suppliers in the UK, Italy and France. These suppliers include Wellman (UK) and IGI (Nuova Impianti Gas Internaziuonali SpA) of Italy In addition to coal, there is interest in refinery residues. For example there is a plant at Wesseling, Germany, which uses heavy oil in a Texaco gasifier to produce methanol. USA situation The chemicals-producing gasification projects in the U.S.A. are largely located at petrochemical plants, refineries, gas plants and chemical plants. They produce a range of important products including: acetic anhydride, ammonia, hydrogen, methanol, oxychemicals, synthetic gas, and diesel fuel. Most are located in Texas and Louisiana where many of the refineries and chemical plants in the U.S.A. are located [1]. South African Experience One variant on chemicals production that is well established in South Africa is the use of gasification for the production of syngas as a feedstock for liquefaction. Thus South Africa has an industry that produces 40% of its gasoline and diesel fuel using modern liquefaction technologies. It has had a synthetic fuels industry since the 1950s when Sasol Limited was created by the South African government to reduce the country's dependence on imported oil by making liquid fuels from coal via gasification and subsequent liquefaction of the resulting fuel gas. The gasification technology in use is the Lurgi dry ash system [47, 48, 49]. Sasol has the capacity to produce 150,000 b/d of liquid fuels [47]. In 1987, as part of a complementary initiative, the South African Government approved the Mossgas project for producing synthetic fuels from offshore natural gas [3, 4]. Two years later, Mossgas, (now PetroSA) was established and production began in 1993 [www.mossgas.com]. The Mossgas project involves extracting natural gas and associated condensate from two offshore fields, delivering it to the offshore drilling and production platform and separating the gas from the condensate. PetroSA then delivers both substances to the onshore refinery near Mossel Bay through a 90-kilometer pipeline and converts them to high quality diesel and gasoline, liquid petroleum gas, kerosene and alcohol using the Sasol process (obtained under licence). PetroSA has the capacity to produce 45,000 b/d of liquid fuels. 5.3 Gasification R, D&D Status The activities previously and currently being undertaken to develop and establish gasification in the EU are reviewed. Then work undertaken is then compared to that ongoing elsewhere. This covers not only the use of gasification for direct power generation but also for the supply of gas for other applications, e.g. hydrogen production to support fuel cells and transport.

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5.3.1 R, D&D in Europe Within Europe, there has been significant development, to the large-scale pilot plant phase, of various gasification technologies and overall gasification combined cycle systems, with funding via industry, various nation states and the European Commission. The demonstration at the commercial prototype scale of two variants of the entrained bed concept has been undertaken via Buggenum, The Netherlands, and Puertollano, Spain (with funding from the EC Thermie Programme within earlier Framework Programmes). There has also been significant R&D effort supported by the EC and ECSC for various added-value activities for the various concepts [50, 51, 52]]. In overall terms, such R&D work that has been undertaken splits into several types of activities: • Component development for overall system integration • Supporting R&D for demonstration activities in the EU • Generic activities to characterise fuel behaviour and environmental performance • Techno-economic studies examining system variants. Within the EC FP4, there were several key R&D initiatives. Techno-economic cycle studies based on the Puertollano plant showed that the design efficiency could be readily increased to 46.8% from the 45% design specification. This could be achieved by increasing the turbine inlet temperature (TIT) from 1120 oC to 1190 oC and by improving the heat recovery steam generator and steam cycle. It was also shown that a further raise in TIT to 1250oC, in line with state of the art units as of the mid 1990s, could raise the overall efficiency by a further 1% to ~48%. These studies were continued, modelling the benefits of a major system redesign, and showed that 51.5% (IGCC98) should be readily achievable at a specific plant cost of~1100 US$/kW [53, 54, 55, 56]. It was suggested that a coal based IGCC could attain efficiencies up to ~58% with a TIT of 1400oC ISO, reheating of the gas turbine, optimised humidification, hot gas clean up, supercritical live steam in a bottoming steam cycle, and staged gasification with chemical quench, as shown in Figure 5.5. It was also noted that with a solid oxide fuel cell as a topping cycle, even higher efficiencies should be possible.

Figure 5.5 Possible improvements to IGCC cycle to raise LHV efficiency to ~58%.

Within the APAS initiative during the FP4 period, there was an integrated R&D project, undertaken by various industrial partners and institutes, which examined the practicalities and potential benefits of co-firing biomass and/or wastes with coal in IGCC units [57]. Tests were undertaken at pilot and

50%

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demonstration plant scales, with back up via supporting techno-economic assessment studies. The results were encouraging, indicating that most fuel mixes could be gasified successfully and with environmental benefit. The techno-economic studies showed that under certain situations, co-utilisation could be attractive economically, particularly where the biomass/waste had a negative cost through the charging of a gate fee by the plant operator. Under FP4, there were two extensive integrated R&D projects. The first examined the potential and practicalities of hot gas clean up (HGCU), covering solid particles, sulphur emissions, fuel based nitrogenous species, halides and trace elements. The work included modelling, laboratory, and pilot and commercial plant scale investigations plus techno-economic studies. In overall terms, it showed that for an IGCC fired on coal or coal/biomass/wastes mixtures it should be feasible to achieve improved cycle efficiency, decreased emissions levels and lower costs of electricity, using existing technology within improved designs. The second project, built on the earlier two projects and covered: • Component development and design to improve handling/feeding • Environmental studies to minimise pollutant emissions • Techno-economic studies to determine gasifier sensitivity to feedstock choice A key finding was that the overall performance projections were encouraging, which suggests that there is considerable practical scope to improve on the performance of the EU demonstration units. However, under the environmental regime at the time, it was clear that pulverised coal combustion, although far less clean, would remain the cheaper option unless full financial credit could be given for the superlative environmental performance that could be achieved. The subsequent Framework Programme reflected this finding in its terms of reference. Thus, in FP5, fossil fuel R, D &D activities were included within a broader energy programme for the development of cleaner energy systems. The aim was the deployment of technologies that would permit a 20% reduction of Europe’s CO2 emissions over the next 5-10 years. As such, the objectives included the development and demonstration of a new generation of clean coal technology (CCT) that would improve the ecological and economical acceptability of coal-based power production. The focus was on the improvement of conventional coal technologies, the enhancement of integrated gasification combined cycle (IGCC) plants, research on co-utilisation of biomass and coal, and new processes for the removal of SO2 and NOx from flue gases. In terms of relative priorities, IGCC R&D did not feature strongly in these activities. Following FP5, there was a shift in emphasis by the European Commission. Thus, FP6 is designed to further establish a sustainable energy base for Europe. This is to be achieved with an emphasis on renewable energy sources, to the extent that fossil fuel R, D&D exists only in the context of the capture and storage of CO2. Thus the focus is on the development of near-zero-emissions fossil fuel based energy conversion systems, through low cost pre- and post-combustion CO2 separation systems and safe, cost efficient and environmentally compatible CO2 disposal options. Consequently while there is scope to undertake development of IGCC towards a near zero emissions technology via H2 shift and CO2 capture, there is no scope for support for the very necessary R&D required to improve IGCC efficiency and overall operational performance combined with a reduction in capital costs. Alongside the EC R&D projects, there were several complementary projects part funded by the ECSC (now carried forward under the Research Fund for Coal and Steel) [52]. Thus, in accordance with the ECSC terms of reference, there was R&D to develop individual components of the advanced technologies, pilot plant testing of major aspects of the overall technology concepts, plus supporting studies to give added value to the various demonstrations of these concepts/systems within Europe. In particular, there was the development of innovative systems to introduce coal and remove ash from pressurised systems, particular emphasis on gas particulate removal and gaseous contaminant control including trace elements, low NOx fuel gas combustion, and the definition of materials for advanced

54

components. Examples include the work by Rheinbraun and others to advance their HTW IGCC process, through the development of a hot gas cleaning philosophy and an assessment of the impact on downstream components of gaseous and solid species [58, 59]. The work showed that it should be possible to design a full-scale system at minimised investment and operational costs while meeting the gas turbine inlet conditions. Under another broad based process performance project [60], Rheinbraun pursued the development of a control system for an IGCC power plant on the basis of fuzzy logic. This fitted with the overall aim of improving the performance of a range of coal-fired equipment. In terms of supporting R&D, there has been a considerable amount of work directed towards the Puertollano IGCC demonstration, both by Elcogas and various Spanish Institutes with input from other organisations within Europe. Thus Elcogas, with ENEL and the University of Castilla, have examined the prospects for the valorisation of IGCC solid products as raw materials for construction. The work has included technical and economic studies covering the use of filter cake and slag in a range of industrial applications [61]. There appear to be some promising applications in cement and concrete production, which if realised would improve the overall economics of the Puertollano IGCC process. A further project is designed to improve the overall IGCC plant performance with enhanced coal-petroleum coke co-processing [62]. There is work being undertaken to improve the knowledge and operability of entrained flow coal gasification through the coordinated use of a three-dimensional simulation of the gasification chamber together with the experimental characterisation of the coal, ash and slag. The partners include ENEL and CSM, DMT and ECN. Although originally formulated as a generic study to cover coal gasification only, the work has in part been redirected to study the issues associated with the co-gasification of coal and biomass, since this is of increasing industrial interest both for Buggenum and Puertollano [63]. As well as practical studies there have been several broad based modelling studies to mathematically simulate gasification (and combustion) processes [64]. Here the overall aim was to use modelling to improve the understanding and predictability of coal utilisation processes, leading to the introduction of improvements in efficiency by effective use of process simulation. Thus CRE and others have used sophisticated non-linear programming methods to obtain a dynamic reliable model for coal gasification. They developed the basis of an advanced control system that enabled the study of control strategies including model predictive control and optimisation algorithms. A further interesting research topic, which is attracting increasing attention, is the use of membranes for separation and cleaning of gases in IGCC processes. The focus for much of the initial work, by the Aristotle University of Thessaloniki, was to examine options to improve energy efficiency and the environmental consequences of various coal upgrading processes through the separation, recovery and recycle of gaseous products. The approach followed was to adapt the methods already used in the chemical industry for a variety of gas separations tasks, where the technology of polymer and ceramic membranes offers several advantages such as low size, simplicity of operation and maintenance, compatibility and diversity [65]. Subsequently the University and others worked to develop and produce hydrogen selective membranes for IGCC applications based on both polymer and ceramic membranes [66]. In addition, there have been techno-economic studies examining system variants within the energy and environmental framework of Europe. Such work does continue but, as ECSC (now RFCS) has medium term guidelines, there is less emphasis on IGCC compared to combustion technologies. 5.3.2 R, D&D in USA IGCC system development has been an important component of the US DoE Fossil Energy R, D&D programme for more than twenty years. This has not only represented a long-term investment in coal-

55

fuelled energy options, but now represents an important option in DOE’s Vision 21 programme for the development of advanced power generation systems for commercial applications beyond 2015. Between 1978 and 1999, the USDoE invested more than US$ 2.4 billion on gasification, which was focused primarily on coal as a fuel. Of this, about 50% was committed to demonstration and commercialization of technology, and $600 million was committed in the 1990s to the demonstration of three near-commercial IGCC technologies within the Clean Coal Technology partnerships (see above). Except for an early $13 million investment supporting the commercial-scale Great Plains gasification facility in North Dakota, the remainder was used for basic component research, bench scale and pilot plant testing of process components. The DoE investment in demonstration and commercialisation has amounted to about one-half of the cumulative IGCC budget since 1978. The parallel industrial investment in development of IGCC technology, including the investigation of gasifier options over approximately the same period, is estimated to be about $2.2 billion [67, 68]. This joint DoE/US industry initiative has established modern technology for the gasification of coal and other fossil fuels to produce synthetic gas, a low-cv gas, or high-cv product such that the technology can be offered for commercial applications worldwide. For power generation applications, the concept of thermally efficient and environmentally benign electricity production from different kinds of coal in an IGCC system has been demonstrated at a commercially viable level using three different gasification technologies. Thermal efficiencies of about 40% have been achieved, with air pollution emissions only a small fraction of U.S. New Source Performance Standards, and with recovery of sulphur as a commercial by-product. Emissions of air-toxic compounds is minimal, contaminated water discharges are negligible, and solid wastes are produced as vitrified material impervious to leaching in storage. More recently, the USDoE and others has identified that IGCC plants also offer significant opportunity for the effective capture and sequestration of carbon dioxide, compared to other clean coal technologies [69, 70]. Gasification activities now form part of Vision 21 [71, 72]. This is the U.S. DOE long-term initiative for developing the technology needed for ultra-clean fossil fuel-based energy plants. It is a cost-shared partnership between industry, academia and government, and it is based on three premises:

• The USA will need to rely on fossil fuels for electricity and transportation fuels well into the 21st century.

• It makes sense to rely on a diverse mix of energy resources rather than on a limited subset of resources.

• Better technology can make a difference in meeting environmental needs at acceptable cost. The ultimate aim is to effectively remove all of the environmental concerns traditionally associated with the use of fossil fuels for producing electricity, transport fuels, and chemicals, and to achieve this through an intensive, long-range (15-20 year) research and development effort that stresses innovation and technology commercialisation. The intention is to develop the technology basis for energy plants with unprecedented efficiency and near-zero environmental impact, for a diverse mix of energy resources, and to leapfrog performance improvement. Specific types of plant and plant configurations are not emphasised because it is not known what kinds of plant, feedstocks, and products the market will favour in 15-20 years time. However, a series of technology roadmaps has been produced that provide a breakdown of each key Vision 21 technology into its principal R&D areas, combustion, gasification, air separation, gas purification, gas separation, CO2 sequestration, fuels and chemicals, fuel cells, turbines, advanced materials, systems integration, sensors and controls, and computational modelling and virtual simulation. The Vision 21 approach commits the stakeholders and the DOE to a long-term, focused strategic R&D programme. It removes the environmental barriers to fossil fuel use and so expands the energy options for the USA. In addition, because near-zero emissions will be achieved independently of fuel

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type, the integrated use of energy resources is encouraged to maximise efficiency and minimise environmental impact and cost. Within this activity, a further initiative, FutureGen, has been established [73, 74]. The FutureGen programme is aimed at the development of a 275MWe coal-fuelled IGCC power station, which includes the demonstration of integrated hydrogen production and of CO2 separation and geological sequestration. It has a nominal budget of $1 billion, and the Federal contribution is to be about 80%. The USDoE expect to see a major return on investment through sales and worldwide exports of US power plant equipment. The intention is to design, construct and operate a plant at a scale capable of producing 1 million tonnes of CO2 for validation of the integrated operation of IGCC and the receiving geological formation. At least 90% abatement of CO2 will be required, with the potential for nearly 100% removal. The associated aims include determining the safety and permanence of CO2 sequestration, technologies standardisation together with protocols for CO2 monitoring and verification. The economic targets include: • Electricity costs to be less than 10% greater than for non-sequestered systems • Hydrogen wholesale price to be no greater than 4.00 US$ million Btu, which is equivalent to 0.48

US$/gallon of gasoline. 5.3.3 R, D&D in Japan Japan has been experimenting with gasification for many years with the technology approaching commercial scale. The major coal gasification developments in Japan have been based on fluidised bed and entrained flow technologies [75, 76, 77, 78. 79] For power generation, the most advanced IGCC project is being undertaken by nine Japanese power companies, the Electric Power Development Company Ltd, Clean Coal Power R&D Co. Ltd, and the Central Research Institute of Electric Power Industry. All have agreed to build and operate a 250 MW air-blown dry feed gasification plant by 2009. The project will be part financed by a subsidy from the Agency of Natural Resources and Energy (30% of the cost), with the other named participants providing the balance. In addition to using IGCC for power generation, coal gasification technology is being developed for industrial use. Thus in 1984, UBE Machinery Corporation Ltd. began commercial production of hydrogen for ammonia plants by using petroleum coke from pitch coal as the raw material to feed 4 x 500 t/d Texaco entrained-bed gasifiers. This technology is commercially available today. In addition, Japan has been developing other gasification systems for industrial applications. These include:

• Hydrogen production technology using coal. This technology is in the early stages of development. However, plans are to accelerate development to complete pilot plant testing by around 2010 so that demonstration and commercial machines can be put into place by 2015 and 2020 respectively.

• Hydrogasification technology. Under the New Sunshine Plan, the first phase of this development program was completed in 2000. Plans are to continue research and development aiming at commercialization of the technology before 2020.

• Multi-purpose coal conversion technology (Entrained-Bed Coal Flash Pyrolysis). During 1996-98, design, manufacturing, installation and cold test runs were completed. Plans are to develop a commercial version of this technology by around 2010.

5.4 Future R, D&D needs 5.4.1 Overview It is generally recognised that IGCC represents a primary option for efficient, environmentally compatible electricity production using coal resources [80, 81]. Indeed it is capable of providing the cleanest coal based power production process, to standards well beyond current environmental

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requirements. However, the major problems for coal fuelled IGCC are the capital cost, and the present uncertainty concerning its operational track record. Thus, further R&D and commercial scale demonstrations are required to take forward the commercialisation of the technology. This must include the introduction of more efficient and flexible designs incorporating improved components together with advanced gas turbines. At the same time it is essential to recognise that IGCC offers several strategic opportunities above and beyond the very important prospect of providing the cleanest generation of power from coal. First, there is increasing interest in the option of IGCC as a source of syngas for chemicals production, not just from coal but especially in the petrochemical process industry from opportunity feedstocks such as coke and refinery residues [82]. Within such a framework, for coal, its use as a raw material to produce hydrogen may provide a major impetus to establish the technology, provided that the use of hydrogen as a transport fuel can be fully established. This opens up the prospect of multi-product IGCC systems, producing electricity and hydrogen, fired on coal in conjunction with other opportunity fuels as circumstances permit. From a strategic perspective, in Europe and the USA it is recognised that any transition towards a hydrogen based economy will depend on fossil fuels for the production of hydrogen for some considerable time. At the same time, when hydrogen is produced via IGCC the resulting byproduct is a concentrated stream of CO2. Consequently, IGCC is the technology of choice when CO2 capture is required since, in contrast to combustion applications, the capture step can be integrated within the overall process. As such in the medium to long term, IGCC offers a very significant prospect for the most cost effective means for providing a near zero emissions power generation technology based on coal and other fossil fuels. However, before such a position can be established there is an overwhelming need for the technology to be deployed on a significant basis so that perceived difficulties with gasification plant capital cost and availability can be countered. Overall design concepts have improved in such a way that the capital costs and operational uncertainties can be addressed. With regard to efficiency issues, currently, the few full-scale pilot plants, that are operating worldwide, achieve efficiencies less than 45%. However, it must be stressed that these units were not designed for high efficiency, but rather, represented conservative designs that would allow the overall concept to be demonstrated with high environmental performance. Optimisation studies carried out within Europe under EC non-nuclear energy R&D programmes have demonstrated that efficiency could be increased to ~50% by implementing fairly simple design changes based on established and available technology, including state of the art gas turbines. Beyond this there would need to be significant R&D to achieve the higher efficiencies mooted earlier. At present the leading technology variants are wet and dry feed entrained flow systems, although moving bed and fluidised bed systems show some advantages depending on local requirements. In overall terms, the prime area for development is the integration of the various components to ensure a lower capital cost for the system. With regard to the components themselves, the issues for entrained flow systems include materials to ensure greater reliability, especially refractories, improved dry feeding, particularly for mixed feedstocks, improved firetube cooler designs with regard to minimising deposition and corrosion. For fluidised bed systems, the aim is to establish dry units for dust removal, sulphur removal and alkali/trace metals control. Linked to all of this is the development of gas turbines to fire the various coal derived fuel gases that will arise from the various gasification units. This includes the need to establish turbine combustion systems that can use hydrogen as the fuel.

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Ultimately, if IGCC is to move forward, there is a strong need to establish a state of the art unit that can demonstrate the design and performance improvements that have been established via studies and smaller scale testing. In this way there is scope to show that the problems that dogged the early demonstration units have been overcome. In view of the future vision for gasification technology, as a process to generate both power and syngas, there should be a demonstration of a multi-product IGCC system. The demonstration should use coal, maybe in combination with other low-cost and readily available fuels. It should be designed to produce electricity, heat and synthesis gas. The plant should be located near an industry that could use the synthesis gas to produce high valued chemical by-products, such as hydrogen, ammonia and methanol. The project should also demonstrate the capture and utilisation or sequestration of some of the carbon dioxide that is produced. It is noted that within Europe there is scope to undertake some R&D on some of the issues within FP6, particularly with regard to CO2 capture. However, it is evident that if the case for fossil fuels utilisation R, D&D can be made then a greater technology development, demonstration and deployment programme will be required. 5.4.2 Gasification R, D&D requirements As outlined above, the prime need is to ensure that EU gasification technology for power generation can advance significantly so that Europe can achieve the necessary reductions in greenhouse gas emissions while EU industry can challenge effectively in a global market. At the same time it is essential to recognise the timing implications for market opportunities plus the financial constraints even within a European Research Area. Consequently a phased approach is proposed based on the initial need to move the system optimisation forward via R&D on a 5-10 year timescale. This could include: • Gasifier component development, including improved materials of construction for refractories

and HRSGs, improved feeding and handling systems. • Gas turbine combustor development to ensure the efficient use of hydrogen rich fuels. • Ancillary component development, including lower cost air separation units. • Complementary design and optimisation studies, including full integration of CO2 capture. • Associated level playing field techno-economic studies, taking into account the global market

possibilities. Beyond this, over the 10-15 year period, strong consideration must be given to technology demonstration. For example, the prospect of some form of sidestream activity on either Puertollano or Buggenum should be positively explored. If undertaken at an adequate scale, this would allow CO2 capture to be demonstrated together with hydrogen-rich fuel gas combustion and utilisation such that scale up to full-scale design might be undertaken with confidence. Ultimately, there is a need to establish a commercial prototype demonstration of a European IGCC technology that can achieve the performance required by the market. Such an IGCC will need to demonstrate reduced energy use and capital cost with improved operational flexibility. There will need to be integrated CO2 separation from fuel gas that has undergone a hydrogen shift stage. Alongside this will need to be gas turbines that can utilise hydrogen as the fuel gas while still meeting all necessary performance requirements. It might well be particularly important to demonstrate the multi-function capability of IGCC. Thus the IGCC variant that may be the most appropriate could be for the co-production of hydrogen and power from fossil fuels. This offers the prospect of very clean power plus the provision of a key energy vector, which is seen as a key requirement for the future EU energy economy. The timing for this activity is probably 15-25 years.

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However, for all of the R, D&D aspects, it is important to be alert to opportunities that might arise, which could allow the timings to be advanced or for additional funding to be introduced. For example, it is known that the World Bank/GEF will support the 450 MWe Yantai IGCC demonstration project in China to both accelerate the application of the technology in China (and elsewhere) and also to assist the long-term goal of H2 production/CO2 capture as a first significant step towards zero carbon emissions. Consequently there may be a prospect for some form of international cooperation, perhaps to carry out a side-stream experiment on this plant if the EU options are not available for whatever reason. 5.5 References [1] USDoE and Gasification Technology Council, World Gasification Database (2001) [2] Geertsema, “Gas to Synfuels and Chemicals”, Sasol Technology (pty) Limited, P O Box 1,

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[29] Buttker B, Seifert W (2000) Syngas and fuel gas from gasification of coal and wastes at Schwarze Pumpe (SVZ) - Germany. In: 21st world gas conference, Nice, France, 6-9 Jun 2000. Vevey, Switzerland, International Gas Union, 7 pp (Jul 2000)

[30] U. Sendin, M. Gasc, W. Schellberg, J. Karg, “Design, Construction and Start-Up of the Puertollano 335 MW IGCC Power Plant”, EPRI Gasification Conference, San Francisco, CA, USA, October 1996, 19 pp

[31] Ploeg J E G (2000) Gasification performance of the Demkolec IGCC. In: Gasification 4: the future, proceedings, Noordwijk, The Netherlands, 11-13 Apr 2000. Rugby, UK, Institution of Chemical Engineers, 11 pp (2000)

[32] W. Schellberg, “The Combined Cycle Power Plant in Puertollano/Spain”, 14th Annual International Pittsburgh Coal Conference, Taiyuan, China, 23-27 September, 1997, 11 pp

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[34] S. Green, “Puertollano Prepares for Syngas Operation”, Modern Power Systems; 49-53, November, 1997

[35] Mendez-Vigo, F.G. Peña, J. Karg, G. Haupt, G. Zimmermann, “Puertollano IGCC plant: Operating Experience and Potential for Further Technology Development” Power-Gen Europe 2001, Brussels, Belgium, 29- 31 May 2001, 13 pp

[36] Mendes Vigo I (2002) Operational experience of the Puertollano IGCC plant. International conference on clean coal technologies for our future, Cagliari (Sardinia), Italy, 21-23 Oct 2002. London, UK, IEA Clean Coal Centre, CD-ROM, 25pp (Oct 2002)

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[38] G. Collodi, “Commercial Operation of ISAB Energy and Sarlux IGCC”, Gasification Technologies Conference, San Francisco, CA, USA, 7-10 October, 2001

[39] J. Spence, “API Energia IGCC Plant Status”, Gasification Technologies Conference, San Francisco, CA, USA, 9-11 October, 2000

[40] Cavalli L, Laezza G, Biliato G, Amico F (2000) The Sulcis IGCC project. In: Gasification 4: the future, proceedings, Noordwijk, The Netherlands, 11-13 Apr 2000. Rugby, UK, Institution of Chemical Engineers, 8 pp (2000)

[41] T. Ubis, L. Bressan, L. O’Keefe, “The 800 MW Piemsa IGCC Project”, Gasification Technologies Conference, San Francisco, CA, USA, 9-11 October, 2000

[42] L. Bressan, L. O’Keefe, “Piemsa IGCC Project Environmental and Economical Benefits”, Gasification Technologies Conference, San Francisco, CA, USA, 7-10 October, 2001

[43] McDaniel J E (2000) Polk Power Station IGCC 4th year of commercial operation. In: 2000 gasification technologies conference, San Francisco, CA, USA, 8-11 Oct 2000. Arlington, VA, USA, Gasification Technologies Council, CD-ROM, paper 261, 11 pp (2000)

[44] Dowd R A (2000) Wabash River coal gasification project, final technical report. Available from: http://www.lanl.gov/projects/cctc/resources/pdfswabsh/ Final%20 _Report.pdf. Washington, DC, USA, US DOE, Office of Fossil Energy, vp (Aug 2000)

[45] US DOE (2002a) Wabash River coal gasification repowering project: a DOE assessment. DOE/NETL-2002, Morgantown and Pittsburgh, PA, USA, National Energy Technology Laboratory, 42 pp (Jan 2002)

[46] Bailey R (2000) The Kentucky pioneer energy project. In: Proceedings, seventeenth annual international Pittsburgh coal conference, Pittsburgh, PA, USA, 11-15 Sep 2000. Pittsburgh, PA, USA, Pittsburgh Coal Conference, CD-ROM, session 3.4, 8 pp (2000)

[47] P. van Nierop, H.B. Erasmus, J.W. van Zyl, “Sasol’s Achievements in the 20th Century as Building Block for the 21st”, Gasification Technologies Council, San Francisco, California, USA, October 8-11, 2000.

[48] Van Dyk J C (1999) Proposals for blending coal sources in such a way as to minimise thermal fragmentation within the gasifier. In: Coal Indaba ‘99, final proceedings, Randburg, South Africa, 17-18 Nov 1999. Randburg, South Africa, Mintek, 4 pp (1999)

[49] Van Dyk J C, Keyser M J, van Zyl J W (2001) Suitability of feedstocks for the Sasol-Lurgi fixed bed dry bottom gasification process. In: Gasification technologies 2001, San Francisco, CA, USA, 7-10 Oct 2001. Arlington, VA, USA, Gasification Technologies Council, CD-ROM, session 10.8, 11 pp (2001)

[50] A.J. Minchener, “The Development of Improved Solid Fuel Gasification Systems for Cost Effective Power Generation with Low Environmental Impact, JOF3-CT95-0018

[51] A.J. Minchener, “Integrated Hot Fuel Gas Cleaning for Advanced Gasification Combined Cycle Processes

[52] A J Minchener, Advanced Power Generation Technologies, The International Conference on Technology for Coal Mining, Preparation and Utilisation: Results of the ECSC Coal Research Programme, Luxembourg, 25-27 June 2002

[53] Evans R H, Ye H, Millar S, Mc Mullan J T, Williams B C (1999) Contribution of the Energy Research Centre, University of Ulster. In: Joule III Programme Clean Coal Technology R&D, Vol III. EUR 19285/111EN. Brussels, Belgium, European Commission , v p (1999).

[54] Evans R H, Ye H, Millar S, Mc Mullan J T, Williams B C (2000) The influence of feedstocks properties on the techno-economic performance of coal-fired IGCC. In: Gasification 4: the future, proceedings, Noordwijk, The Netherlands, 11-13 Apr 2000. Rugby, UK, Institution of Chemical Engineers, 10 pp (2000)

[55] R. Pruschek, “Enhancement of Efficiency of IGCC Power Plants”, EC JOF2X [56] R. Pruschek, “Improvement of IGCC Power Plants Starting from the State of Art, JOF3-CT95-

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[61] Elcogas et al, Valorisation of IGCC power plant by-products as secondary raw material in construction, ECSC 7220-ED/072, Final Report, 1999

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6 ADVANCED & HYBRID CYCLES 6.1 Introduction This section describes some alternative power generation technology variants under development, most of which are based on a combination of gasification and combustion systems within some form of hybrid cycle. Activities undertaken in Europe are first presented, followed by those in the USA and Japan. The term hybrid cycle is used here for cycle arrangements where two or more energy conversion processes are used in combination, thereby enhancing thermal efficiency compared to the basic cycles. This can, for example, mean adding a pressurised partial gasifier to a PFBC plant in order to raise the gas turbine inlet temperature, while burning residual char in the PFBC boiler. That arrangement constitutes what is commonly called an APFBC plant. A slightly different arrangement uses a CFBC boiler instead of a PFBC boiler since this reduces the technical complexities. Thermal efficiency levels of 52 to 53 % (LHV) or more are foreseen for such plants, provided state-of-the-art gas high temperature turbines and USC steam conditions are used. There is also interest in hybrid cycles that include IGCC and fuel cells, commonly referred to as IGCC-FC plants. 6.2 Development activities in Europe 6.2.1 Pressurised pulverised coal combustion A combined cycle based on pressurised pulverised coal combustion (PPCC) was conceived as an alternative to PFBC and IGCC, which might take advantage of the gas turbine developments towards higher turbine inlet temperatures. Theoretical calculations have shown that net efficiencies of over 50% on an LHV basis would be possible. Development of the process began in 1989 in Germany, with a cooperative project between German boiler and turbine manufacturers, coal companies and utilities. Tests were performed on a 1 MWth pilot plant at Dorsten, capable of operation at up to 16 bar and 1700oC; these showed that stable flame temperatures could be achieved. Much effort has since been spent on the development and testing of “particle separation” and alkali removal systems between the pressurised combustor and the gas turbine. The ash would be molten at that stage, which represents a significant technical challenge. While these tests suggested that the development of a technically acceptable process might be viable, this still left the problem of alkali separation to levels acceptable for the gas turbine. Consequently with the expected advances in USC PF technology, and the potential of IGCC as well as various other hybrid cycles, there does not appear to be a strong driver to continue the development of PPCC towards commercialisation. 6.2.2 ABGC The ABGC concept, which was initially conceived by the British Coal Corporation, UK, is illustrated in Figure 6.1. This is based on an air blown pressurised fluidised gasifier coupled to a circulating fluidised bed combustor to burn the residual char from the gasifier. Fuel gas from that gasifier is cleaned and burned to produce a high temperature high-pressure gas, which is expanded through a gas turbine. The exhaust gas from the turbine is used to raise steam and augment significantly the steam cycle associated with the fluidised combustor. The fluidised bed components allow in-situ sulphur retention and the use of a wide range of feedstocks including coals, biomass and waste materials. The development of the ABGC was undertaken by an industrial consortium comprising European Gas Turbines (UK), Stein Industrie (France) and EVT (Germany), PowerGen(UK), Mitsui Babcock (UK) and British Coal (UK) [1]. Collaboration on specific work topics also included input from a range of

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other institutes and research organisations. In overall terms, the development approach comprised various members of the consortium developing individual components for the ABGC; to enable the production of a specification of a 90MWe prototype integrated plant. Considerable support was provided under the ECSC R&D and the EC APAS and Joule programmes for individual component development and some systems integration [2,3,4,5,6,7,8].

Figure 6.1. Schematic representation of the ABGC cycle Subsequently, Mitsui Babcock Energy Ltd purchased the ABGC technology and, with EC Thermie support, formed a new industrial collaboration together with GEC Alsthom (subsequently Alstom Power) and Scottish Power plc to produce an advanced design for an ABGC demonstration plant. A comparison of ABGC with other advanced power generation technologies for a 500 MWe plant was performed, with support from the UK Department of Trade and Industry [1]. The results from that study, Table 6.1, for a location in China, with cooling towers and thus a fairly high condenser pressure, showed the ABGC to have the highest cycle efficiency and the second lowest cost of electricity (COE) of the technologies considered. It should be noted that ABGC, CFBC and the two IGCC cycles were all assumed to have sub-critical steam conditions and that for CFBC, a 2 x 250 MWe design was considered.

Table 6.1 Comparison of ABGC with alternative advanced technologies

TECHNOLOGY EFFICIENCY (LHV)

% CAPITAL

INVESTMENT £/kWeCOE, £/MWh

SC PF 41.7 537 20.9 ABGC 46.9 618 24.8 CFBC 39.2 650 26.1

Dry-feed IGCC 43.3 801 27.9 Wet-feed IGCC 41.0 812 28.7

The results of adopting supercritical steam conditions for ABGC and CFBC increased the efficiencies of those plants to 48.0 and 40.6 % (LHV) respectively. The impacts of condenser conditions and of ash and sulphur contents in the coal were also examined. Changing from Chinese to Northern European condenser conditions, gave a 2.9 percentage points boost for the SC PF plant, while the dry-feed IGCC gained 1.2 percentage points. The effect of using a high-ash coal (30% ash) was biggest for the IGCC plants, with a 4.3% percentage points efficiency reduction for wet-feed IGCC.

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However, for a number of reasons, not least the lack of CCT opportunities within Europe at the time plus the rationalisation of technology options by Mitsui Babcock and Alstom Power, the ABGC concept did not progress to the demonstration and commercial prototype stage. 6.2.3 APCFB A 200 kWth test plant was constructed by BTU Cottbus for the purpose of developing a variant of coal conversion based on APCFB. This concept is characterised by a design that combines the two air-blown steps “partial gasification” and “residual char combustion” in a single component (Figure 6.2).

Figure 6.2 The BTU Cottbus APCFB variant.

Thermal efficiency calculations were performed for plants with different gas turbines [9]. The base concept assumed the use of one large heavy-duty Siemens gas turbine V94.3A fired with Lausitz dried lignite (19 % H2O). Further versions considered alternative Siemens gas turbine models (V94.3A and V64.3A). In addition the effect of the water content of the fuel fired (raw lignite with more than 52 % H2O or dried lignite) as well as the method of drying the coal were investigated. Common assumptions for all versions were ISO conditions for the ambient air and a condenser pressure of 0.05 bar. These calculations yielded net efficiencies of almost 50 % (LHV based) for a variant with the small V64.3A gas turbine and up to than 55 % for the large plants with the V94.3A gas turbine. It was further demonstrated that thermodynamic integration of an advanced, innovative coal drying process (e.g. fluidised-bed drying with waste heat utilisation) gives an additional gain in net efficiency of about three percentage points compared with the variant of firing lignite that was first dried externally. However, following the reorganisation of Alstom Power and the rationalisation of its technology options, the lack of a technology champion for PFBC has meant that this concept has not been taken forward. 6.2.4 Hybrid PFBC plants operating on coal and natural gas There are numerous ways hybrid plants can be configured. In one arrangement, a PFBC plant is combined with a gas turbine cycle. The Technical University of Lund (LTH), in cooperation with Alstom Power, investigated such hybrid plants based on a P200 PFBC plant and a natural gas fired gas

66

turbine with a single pressure HRSG. A schematic of that arrangement is shown in Figure 6.3. The power output can vary somewhat depending on the customers’ specification. The plant studied here has a total electrical power output of 112.4 MW (gross).

Figure 6.3 Hybrid PFBC system In this study three natural gas fueled gas turbines with different power outputs, GT10 (24.1 MWe), GTX100 (42 MWe) and GT24 (183 MWe), were selected. The modelling was carried out using IPSEpro and commercial heat balance software from SimTech. The effect of post combustion to increase the exhaust gas temperature from the gas turbine to 700°C was also considered. Generally, post combustion reduces the plant efficiency, but it was considered as an option to produce the minimum steam flow needed for power production with the steam turbine when the PFBC in not running. In this concept, steam from the reheater and the HRSG would be mixed before entering the intermediate pressure turbine. This configuration results in a hybrid plant, where PFBC and the gas turbine can operate independently. When the PFBC plant is not in use, the steam turbine can operate using the steam generated in the HRSG only. This solution requires that the steam flow from the HRSG accounts for at least 25% of the total steam flow through the turbine. Table 6.2, below, summarises the calculation results. The efficiency of the hybrid plant is higher than the stand-alone PFBC plant. Very significantly, the marginal efficiency for the hybrid plant based on the GTX100 gas turbine without post combustion is of same magnitude as the efficiency of the standard combined cycle based on same gas turbine. In the case studied, this was achieved using a simple HRSG with one pressure level instead of the much more complex HRSG used in the standard combined cycle. This is the most important synergetic effect of the hybrid plant. Other synergy effects of this concept are: • Increased availability because of the two independent power generation systems • Reduced CO2 emission due to the coal ratio of the natural gas • Reduced investment costs due to the integration of the already existing steam plant e.g. steam

turbine, condenser and auxiliary machinery. However, in Europe the lack of a technology champion has meant that there has been no industrial interest in exploring this option further.

Air

Gas Turbine

SteamTurbine

E

HRSGBooster

GasTurbineAir

Fuel Gas

PFBCCombustor

Limestone

Filter

Coal

Limestone

Char

PartialGasifier

Coal

67

Table 6.2. Calculated efficiencies for coal and natural gas fired P200 hybrid PFBC plants using different gas turbines.

Ref.

P200 GT10 PC

GT10 PC

GTX100 GTX100 PC

GT24 GT24 PC

PelGT [MW] 0 24.1 24.1 43 43 183 183

PelST [MW] 94.98 114.9 114.9 114.7 124.6 181.2 189.06

�msteam flow [kg/s] 0 16.88 16.88 16.2 25.04 63.7 79.26 �el

LHV [%]* 41.61 43.63 43.63 46.18 45.34 50.84 49.84 �el

HHV [%]* 39.93 41.26 41.26 43.56 43.16 47.03 46.07 �� LHV* 0 2.02 2.02 4.57 3.73 9.22 8.22 �� HHV* 0 1.33 1.33 3.63 3.23 7.1 6.14 Marginal efficiency** [%] 0 50.34 50.34 57.37 53.04 56.34 54.66 * Net value; ** The marginal efficiency is defined as the ratio between the increased electrical output and the

increased fuel input. 6.2.5 Chemical Looping Combustion An innovative concept that is currently being considered within Europe is chemical looping combustion (CLC) [11]. The CLC principle is to stage the traditional combustion into two separate reaction phases involving a solid looping reactant:

• Reduction of metal oxide by the use of fuel (MO + fuel M + CO2 + H2O) and • Oxidation of the resulting metal by the use of air (M + 0.5O2 MO).

Thus, CLC can result in a direct concentration of CO2 during its formation in an enclosed reactor unit, thereby avoiding the penalty of having an air separation process. In principle it should be applicable to boilers and gas turbine power cycles offering a high flexibility in the use of fuels, although, the most suitable fuels appear to be natural gas and coal. Figure 6.4 illustrates the CLC principle and materials transfer processes. In principle, this entirely new combustion technology, with no contact between fuel and combustion air, could result in the inherent separation of CO2 and avoidance of nitrogen oxide formation. To take this forward, reactor concepts and stable reactive materials at acceptable cost must be developed and characterised. CLC could be operated at atmospheric and pressurised conditions. Of particular interest are concepts that apply CFB reactors in which the oxygen carrier is a powder. Thus it offers a further route forward for either atmospheric or pressurised CFB as the reactor vessels, thereby building on existing EU expertise. Laboratory scale experiments on CLC at atmospheric pressure, using methane as the fuel, are underway in Sweden, with Swedish national funding. The EC is also providing support for CLC related work under FP5 (GRACE), as well as in an ECSC project (CCCC) which besides CLC studies also investigates lime carbonation/calcination (LCCC) as a means to separate CO2 from combustion gases. The LCCC cycle is illustrated in Figure 6.5. Within FP6 the Commission is supporting some activities that will include investigations of carrier stability and integration into a CFB CLC concept. The majority of this work is being undertaken by research institutes and universities, which will be followed by technical and economic evaluations by EU industry to identify the technological and economical barriers for the cycle components and the oxygen carriers. Should the research be successful and should the techno-economic assessments be positive, then some form of pilot plant activities would be considered after which larger scale trials and demonstrations might be appropriate.

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Figure 6.4 Principle for a Chemical Looping Combustion cycle

Figure 6.5 Schematic illustration of the proposed LCCC cycle 6.3 R,D&D in USA

Development of Clean Coal Technology in USA, building on past R, D&D programmes and on Vision 21, is now driven by the Clean Coal Power, FutureGen and Clear Skies initiatives. These are, in turn, supported by other USDOE key R&D programmes on Gasification Technologies, Turbines of Tomorrow and Future Fuel Cells. Still another programme, Advanced Research, aims to develop new

CO2H2O

N2 (+ O2)

CH4 (Fuel)N2+O2 (air)

Cyclone

Fuel reactor

Air-reactor

Oxygen carrierMetalOxygen

CO2H2O

N2 (+ O2)

CH4 (Fuel)N2+O2 (air)

Cyclone

Fuel reactor

Air-reactor

Oxygen carrierMetalOxygen

69

materials, catalysts, instrumentation and sensors, as well as advanced computer systems that might be used in future power plants and energy systems. 6.3.1 PCFB/APCFB Foster Wheeler, with support from USDOE, has pursued the continued development of PCFB, based on Ahlstrom Pyropower’s early work, and of APCFB, combining pressurised partial gasification with PCFB. These technologies were also selected for demonstration in two stages at the MacIntosh utility site in Lakeland, Florida under USDOE´s Clean Coal Technology Demonstration Program. The first demonstration, McIntosh Unit 4A, was intended to use Foster Wheeler’s PCFBC technology integrated with Siemens Westinghouse’s hot gas particulate filter system and a 60 MWe gas turbine. The steam turbine would have an output of 200MWe and the steam conditions would be 2400psig/1000°F/1000°F/2.5 ’’Hg. The second McIntosh project, McIntosh Unit 4B, would involve the addition of a carboniser, topping combustor and high-temperature filter to the basic configuration established in McIntosh 4A, Figure 6.6.

Figure 6.6. The planned two-stage demonstration of Foster Wheeler’s PCFB and APCFB in Lakeland, Florida.

The intention was that coal would be partially gasified in the carboniser and the resulting fuel gas would be cooled and cleaned before firing in the topping combustor, raising the gas turbine inlet temperature to 1315ºC compared with 900ºC in the configuration without the carboniser. This would increase the thermal efficiency by 3.9 percentage points, from just over 36 % (HHV) to 40.6 % (HHV). The net plant power output would also be increased by 93 MWe, from 137 to 240 MWe. Unfortunately, it became clear that no suitable gas turbine was available. As a result, a decision was taken towards the end of 2003 to terminate this project. However, continued development of PFBC and APFBC technology remains a part of the USDOE Vision 21 Program. Thus the goals for the FBC development supported by USDOE are:

• To demonstrate the technical and commercial viability of first-generation PFBC technology in U.S. utility applications.

• To develop and demonstrate the necessary technology base for second- generation PFBC (APFBC) systems.

• To achieve the following PFBC system performance targets (Table 6.3) Future research and development will concentrate on advanced technologies such as PFBC/PCFB and high temperature heat exchangers, together with improvements in materials, catalysts, and

70

instrumentation. In addition, advanced computation techniques will be necessary to allow for computer simulations for design and testing.

Table 6.3 USDOE PFBC Performance targets

Second Generation PFBC Power System First Generation Initial Final

Net System Efficiency 40% 45+% 50+% Target Date by 2000 by 2010 by 2015 SO2 Emission Relative to NSPS 1/4 1/5 1/10 NOx Emissions Relative to NSPS 1/3 1/5 1/10 Air Toxic Emissions Relative to 1990 CAAA Meet Meet Meet Capital Cost, $/kW 1300 1100 1000 Cost of Electricity vs. Conventional PCC Power Plant 90% 80% 75%

Note: NSPS -- New Source Performance Standards: CAAA -- Clean Air Act Amendments 6.3.2 CLC GE is carrying out a programme on what was originally called the GE EER Unmixed Fuel Process concept, but is now referred to as the Advanced Gasification-Combustion Technology [12]. This is similar to chemical looping combustion and is illustrated in Figure 6.6.

Figure 6.6 Principle of GE Advanced Gasification-Combustion Technology 6.3.3 IGCC-FC At present, the primary drive is towards a gasification & fuel cell hybrid plant, which is illustrated in Figure 6.7. This is seen as a step towards the development of a zero-emission plant, i.e., one that also includes CO2 capture. The most novel feature is the coupling to a fuel cell operating at high temperature. The figure shows a solid oxide fuel cell (SOFC), but the alternative is a molten carbonate fuel cell (MCFC). USDOE supports a large number of fuel cell development projects aimed at the power generation market, under the umbrella name of Solid State Energy Conversion Alliance (SECA). A Delphi Corporation SECA SOFC was successfully tested in June 2003 at Southern Company’s Power Systems Development Facility (PSDF) in Wilsonville, Alabama. The fuel gas, which consisted of hydrogen, carbon monoxide, methane, carbon dioxide, water and nitrogen, was produced in the PSDF’s transport gasification reactor. Both hot and cold gas cleaning were adopted in order to make the fuel gas free from sulphur and chlorine compounds, as well as tar.

1 2 3

Steam, CoalOpportunityFuels

Pure H2

CarbonTransfer

OxygenTransfer

Air

Hot vitiatedair toturbine

CO2, SO2 torecovery anddisposal

Gasification reactor

CO Release reactor

2 Oxygentransferreactor

71

Originally, plans were to introduce a 2MWe MCFC on a slip stream at the Kentucky Pioneer IGCC plant in Clark County, Kentucky. Delays in the schedule for that project have meant that the SECA FuelCell Energy MCFC fuel cell has been installed instead for testing at the Wabash River IGCC plant in Terre Haute, Indiana.

Figure 6.7. Schematic representation of a possible gasification/fuel cell hybrid plant

arrangement Numerous other R, D&D programmes aiming to result in power generation from coal, with very high thermal efficiency and also capture of CO2 are underway. For example, General Electric, with co-funding from USDOE, is examining the Unmixed Fuel Processor (UFP) concept. This attempts to simultaneously convert coal, steam and air into separate product streams. These are high purity hydrogen, suitable for use in a fuel cell or as gas turbine fuel, sequestration-ready CO2, and vitiated air at high temperature and pressure for expansion in a gas turbine or use in a gas turbine combustor [12]. Sulphur capture is also part of the scheme. In order to achieve these goals, GE is testing a fluid-bed, three-reactor system with a gasifier, an oxidiser and a CO2 regenerator. Solids are transferred between the different reactors. This essentially constitutes a Chemical Looping Combustion system, see above, with CO2 capture in the gasifier and with both CO2 regeneration and reduction of the oxygen transfer metal oxide in the CO2 regenerator. This project began in year 2000. After laboratory and bench-scale testing, a 0.2 MWe pilot plant is now under construction. 6.4 R,D&D in Japan Japan has a long history of strategic development towards more efficient coal-fired power plants. The organisation which has had the specific role of leading Japan’s technology development and demonstration has been EPDC, which is now called J-power. After introducing ABFBC and PFBC technology, they have continued with their original plan towards APFBC and IGCC-FC. 6.4.1 APFBC

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The APFBC [13,14] system is designed to improve power plant efficiency by about 10% compared to the basic PFBC system, through an increase in the gas turbine inlet temperature from 850ºC in the PFBC to 1300ºC or more in the APFBC, by combining a partial gasifier with the conventional PFBC technology. The particular series-type APFBC arrangement of the PFBC and partial gasifier was conceived in Japan. The advantage of it would be that no new topping combustor would need to be developed. The calculated efficiency of an APFBC plant with 420 MWe net output and a gas turbine TIT of 1300ºC is 50.5 % (gross, HHV) and 46.0 % (net, HHV). EPDC/J-power decided to test the concept at a process development scale, in a Process Development Unit (PDU) built at their Wakamatsu site [14]. PDU construction work started at the end of September 1999 and finished in July 2001, and test operation was carried out from August 2001 to June 2003. At that time, and for financial strategic reasons, a decision was taken to stop work on APFBC and to focus instead continued development of IGCC-FC. 6.4.2 IGCC-FC The development of IGCC-FC has been underway as a national project in Japan since 1995, with support form NEDO and METI. This is called the EAGLE project (see Figure 6.8) [15, 16]. The calculated efficiency for a 551 MWe net output EAGLE plant, with a gas turbine TIT of 1300ºC is 59.6 % (gross, HHV) and 53.3 % (net, HHV). The development schedule for the EAGLE project pilot plant testing in a 150 tonne coal per day plant at the Wakamatsu site. By October 2003, 1295 operational hours had been achieved.

Figure 6.8. Schematic cycle diagram for the EAGLE concept

6.5 References [1] Welford, G. B., et al. Gasifier Developments and the Airblown Gasification Cycle, Report No.

COAL R195, DTI/Pub URN 00/968. [2] British Coal, Knowledge-based gasifier control for clean power generation, ECSC 7220-

ED/056, Final Report, 1997 [3] British Coal, Hot gas desulphurisation for advanced power generation, ECSC 7220-ED/027,

Final Report, 1997 [4] British Coal, Environmental optimisation of the air blown gasification cycle, ECSC 7220-

EC/106, Final Report, 1997 [5] British Coal, Hot fuel gas dedusting after sorbent based gas cleaning, ECSC 7220-ED/057,

Final Report, 1999

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[6] British Coal, Materials for gasifier hot gas path components in advanced combined cycle power plants, ECSC 7220-EC/035, Final Report, 1998

[7] British Coal, Development of a LCV gas combustor with very low fuel nitrogen oxidation for gas turbines, ECSC 7220-EC/034, Final Report, 1998

[8] British Coal et al, Removal of H2S and NH3 in coal gasification power generation systems, ECSC 7220-EC/032, Final Report, 1998

[9] Krautz, H.J., et al. (2003), Lignite-Fired Combined Cycle Power Plant with ACPFBC, Proc. 17th Int. (ASME) Fluidized Bed Conference, May,Jacksonville, FL, U.S.A.

[10] Assadi, M., et al. (2002), Increasing Thermal Efficiency of a PFBC Power Plant Using a Natural Gas Fuelled Gas Turbine, ISCAPE Conf., January, Cartagena, Colombia.

[11] Lyngfeldt, A., et al. (2001), A Fluidized Bed Combustion Process with Inherent CO2 Separation; Application of Chemical Looping Combustion", Chemical Engineering Science 2001, 56, 3101.

[12] Rizeq, R.G., et al: Advanced Gasification-Combustion Technology for Production of H2, Power and Sequestration-Ready CO2.

[13] Nakata, H. (2002) Summary of Advanced-PFBC Technology. APEC Meeting November. [14] Iritani, J. EPDC/J-Power (Personal communication). [15] Wasaka, S., et al. (2003), The Development of Coal Energy Applications for Gas, Liquid and

Electricity, EAGLE, Proc. Int. Conf. on Power Engineering (ICOPE-03), November ., Kobe, Japan, p. 3-175.

[16] Wasaka, S,. et al. (2003), Coal Gasification Development for IGFC (EAGLE Project), APEC Meeting, Australia, December 2003.

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7 APPENDIX COMPARISON OF POWER PLANT THERMAL EFFICIENCIES Comparison of published efficiency values for different types of power plant is difficult for several reasons:

• Differences in how the heating value of the fuel is calculated, • Differences in site conditions and especially condenser pressure, • Differences in plant design, such as single or double stage reheat when otherwise the

plants are of similar design, • Whether gross or net efficiencies (and plant output) are considered, and what add-on

equipment such as desulphurisation units are used. The condenser pressure is commonly the most important factor, and going from a condenser pressure of 0.05 bar, which requires a cooling water temperature of 27-28 oC, to 0.02 bar, for a cooling water temperature of 14-15 oC, produces an extra 3 percentage points. Thus, for proper comparisons, all actual plant efficiencies ought to be recalculated to “standard conditions” in order to be meaningful. In Europe, efficiencies are expressed on the basis of lower heating value (LHV), which is defined as the higher heating value (HHV, the total amount of energy contained in the fuel) minus the latent heat of evaporation of the water contained in the products of combustion. In some countries, such as the USA and Japan, power plant generating efficiencies are commonly defined merely in terms of higher heating value. However, the LHV is a more accurate assessment of the “useful” energy of the fuel for plants where this water leaves to the atmosphere in the flue gas stream. The ratio of HHV to LHV for a typical steam coal is approximately 1.05. It will otherwise vary depending of coal composition and heat content. For fuels such as natural gas and biomass, with a higher hydrogen content, this ratio will be much higher. This complicates comparisons between different technologies and fuels. When generating efficiencies are quoted on based on HHV, the electricity output is divided by the HHV of the fuel used. When they are quoted on a LHV basis, the output is instead divided by the LHV value of the fuel. Consequently, HHV generating efficiencies are lower that LHV generating efficiencies. For example, a coal-fired steam plant with a HHV efficiency of 40% has a LHV efficiency of approximately 42%, provided plant design and site conditions are the same. A broad understanding of the current status of coal-based power plant can be gained from a comparison of several state-of-the-art units steam plants around the world, as illustrated below:

Net thermal efficiency, % Plant Steam conditions MPa/ oC/ oC HHV % LHV %

Tachibanawan (Japan) 24.1/600/610 42.1 44 Tanners Creek (USA) 24.1/538/552/566 39.8 42 Nordjylland 3 (Denmark) 29.0/582/580/580 45 47.0 Niederaussem (Germany) 27.5/580/600 42-43 45.2

The Japanese and U.S. plants have relatively high condenser pressures compared to the Danish plant. The Niederaussem plant burns a lower grade lignite, whereas the others are fuelled with bituminous “trading” coals.

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8 MEMBERS OF THE POWERCLEAN NETWORK Alstom Power

Aristotle University of Thessaloniki

Centro Sviluppo Materiali

Chalmers University of Technology

CINAR

Clive Hadfield & Associates Ltd

Deutsche Montan Technologie GmbH

Elcogas

Electricité de France

ELSAM Engineering A/S

EMC Environmental Engineering

ENEL

European Power Plant Suppliers Association

FLS AIRTECH

Foster Wheeler Energie

Future Energy Solutions

Iberdrola Ingenieria Y Consultoria

IEA Coal Research

IFRF Research Station

Imperial College London

Instituto Nacional de Engenharia e Tecnologia

Industrial

Innogy Plc

Instituto Superior Técnico

KEMA Nederland BV

Kungl Tekniska Hogskolan

Mitsui Babcock Energy Ltd

National Technical University of Athens

Polytechnic University of Bucharest

POWERGEN UK Plc

PTJ Juelich

RWE Gmbh

Siemens Gmbh

SimTech Simulation Technology

Societé Nationale d'Electricité et de Thermique

Svenergy Consultants

Tampere University of Technology

Technical Research Centre of Finland

Technical University Delft

Technical University of Silesia

Tech-wise A/S

TECNATOM

TNO

UK Coal Mining plc

Universidad de Zaragoza

Universitaet Essen

Universitat Stuttgart

University of Cranfield

University of Glamorgan

University of Nottingham

University of Ulster

WS Consultant

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