FOSSIL FUEL POWER GENERATION STATE-OF-THE-ART PowerClean Thematic Network

PowerClean

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.

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 Ingo Romey Universitaet Essen FB 12, Technik der Energieversorgung und Energieanlagen PO Box 45117, Universitaetsstrasse 15 45141 Essen, Germany

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 Dampfkesselwesen Universitat Stuttgart Pfaffenwaldring 23, D-70550, Stuttgart, Germany

Mr Didier Brudy Thermal Boiler Group, Basic Design Department EDF SEPTEN 12-14 Ave Dutrievoz F69628 Ville Urbanne Cedex, France und 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

Dr Zdena Zsigraiova IST, Department of Mechanical Engineering A. Rovisco Pais, Pav Mec 1, 2 1049-001 Lisbon, Portugal

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 2

3

4

5.

INTRODUCTION...........................................................................................................................1 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 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 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 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 ii

5.3.3 R, D&D in Japan ...................................................................................................56 Future R, D&D needs ..........................................................................................................56 5.4.1 Overview ...............................................................................................................56 5.4.2 Gasification R, D&D requirements .......................................................................58 5.5 References............................................................................................................................59 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 APPENDIX COMPARISON OF POWER PLANT THERMAL EFFICIENCIES ...........74 MEMBERS OF THE POWERCLEAN NETWORK................................................................75 5.4

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7 8

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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 2.1

TECHNOLOGY OPTIONS 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. 2

•

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 partreplacement 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 5

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. 400

SH Steam pressu re (bar)

350 300 250

Eddystone 1 Pioneer plants

200

Average trend

150 100 50 0 1900

1920

1940

Year

1960

1980

2000

Fig. 3.2 – Historical development of superheated steam pressure [5] 700

SH Steam temperature (deg C)

Eddystone 1 600 Pioneer plants

500

Average trend

400

300

200 1900

1920

1940

Year

1960

1980

2000

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. 6

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 TachibanaWan 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 7

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 coutilisation 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. 1600

mg/Nm3, 6% O2

SOx NOx dust

Coal fired plants

1400 1200 1000 800

Present limits

600 400 200 0 1979

1988

1999-2000

2001

USA

609/EC

USA

81/EC

2010 2001 2002 Italy USA Japan Hawthorn Torre Nord 3ten

Fig. 3.5 – Recent trend of emissions limits

a)

Low-NOx burners

FF o ESP(*)

b)

Low-NOx burners

SCR

GGH

c)

Low-NOx burners

SCR

FF o COLD ESP

SCR

COLD ESP

FGD

FGD

FGD

GGH

WESP

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 = 50100; SO2 = 75-100 and particulates from 10-20 (a), to 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. 29

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-onyear 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.

Gross electrical output/MWe

600 Lagisza (PL)

500 Jacksonville (USA)

400

AES Puerto Rico

Gardanne (F)

Seward (USA) Sulcis (I)

Turow (PL)

300

Gilbert (USA) Turow (PL)

200

Can (Turkey)

Tha Toom (Thailand)

100 0 1994

Red Hills (USA)

Tonghae (Korea)

1996

1998

2000

2002

2004

2006

2008

2010

Year plant commissioned 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. 450 400

Subcritical Supercritical

Karita

Capacity, MWe

350 300

Osaki - 1

Osaki - 2

250 200 150

Tomatoh-Atsuma

Escatron

100

Vartan 50 0 1985

Tidd

Wakamatsu

1990

1995

Cottbus

2000

Commissioning year

Figure 4.6 – PFBC plant development [1] 31

2005

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-theart 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. Air Flue Gas Air

LP Turbine Exhaust

Air

LP Compressor

PFBC Combustor

HP Compressor

Fixed speed shaft

HP Turbine

Variable speed shaft

Intercooler

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 34

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 35

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, lowcost 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 verylow 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 HighPerformance 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 37

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 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

Activities that continue separately 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 coalfired power generation systems. 38

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] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13] [14] [15] [16]

IFRF Combustion File No. 87 A J Minchener, “Fluidised bed combustion systems for power generation and other industrial application”, DTI-Technology status report 011, January 2000 J R Grace (ed) et al, Circulating Fluidized Beds,. Blackie Academic & Professional,London,1997. L. Reh, “Challenges of circulating fluid-bed reactors in energy and raw materials”, Chem. Eng. Sci., 54, pp. 5359-5368, 1999 J. P. Jacobs, “The future of fluidised-bed combustion”, Chem. Eng. Sci., 54, pp. 5559-5563, 1999 K Cleve, Latest Developments and Status of Long Term Experience in CFB-Technology, Proc. 15th ASME Conference on Fluidized Bed Combustion, 1999. 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 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 D. Veenhuizen “karita P800 supercritical 360 MWe PFBC plant reaches full power” (1999) Modern Power system, November J M Wheeldon, A Review of PFBC Power Plant Designs, Proc. 13th Pittsburgh Coal Conference, 1996. 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 R. Hickey, J.C. Semerard and G. Scheffknecht, “Clean solid fuel power generation: circulating fluidised bed technology for the future”… P. Laffont, J. Barthelemy, B. Scarlin and C. Kervenec “A clean and efficient supercritical circulating fluidised bed power plant” Alstom power USDoE , Vision 21program plan. Clean energy plants for the 21st century, http://www.fossil.energy.gov/ Washington DC USA (Apr 1998) 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) 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 Secondary product Operating plant Planned plant 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 Product

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

Australia Austria

Year

Whytess Gully Waste to Energy Proj.

Unknown

Biomass

Electricity

1999

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 1998

Finland

Kymijärvi ACFBG Plant

FW ACFBG

Biofuels

Electricity & District heat

Germany

Schwarze Pumpe Town Gas Plant

Lurgi Dry Ash

Municipal waste

Electricity & Methanol

1964 1985

Leuna Methanol Anlage

Shell

Visbreaker residue

H2, Methanol & Electricity

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

UK

Fife Power

BGL

Coal & sludge

Electricity

2001

UK

Fife Electric

BGL

Coal & sludge

Electricity

2002

UK

Project ARBRE

TPS

Biomass

Electricity

2000

USA

Wabash River Energy Ltd

E-GAS (Destec/Dow)

Petcoke

Electricity

1995

USA

Delaware Clean Energy Cogen. Project

Texaco

Fluid petcoke

Electricity & Steam

2001

USA

Polk County IGCC Project

Texaco

Coal

Electricity

1996

USA

Piñon Pine IGCC Power Project

KRW

Bit. coal

Electricity

1998

USA

Commercial Demonstration Facility

Brightstar Env. Ltd.

Biomass

Electricity

1996

USA

New Bern Gasification Plant

Chemrec

Black Liquour

Electricity

1997

USA

McNeil IGCC Project

Fut. Ener. Resources

Forest residue

Electricity

1997

USA

El Dorado IGCC Plant

Texaco

Petcoke, Ref. Waste & Nat. gas

Electricity & HP steam

1996

Germany

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 Year

Country

Plant Name

Type

Feedstock

Products

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

USA

Kentucky Pioneer Energy AFTIGCC Plant

BGL

Coal & MSW

Electricity & Diesel

2003

delayed

USA

Lima Energy IGCC Plant

BGL

Coal & MSW

Electricity & H2

2003

USA

Gilberton Culm-to-Clean Fuels Plant

Texaco

Anthracite culm

Diesel & Electricity

2004

USA

Site not yet determined

Carbona/Enviropower

Biomass

Electricity

2004

USA

Site not yet determined

U-GAS

Biomass

Electricity

2004

USA

Calla GCC Plant

U-GAS

Biomass

Electricity

2003

USA

Unspecified Plant

Texaco

Coal

Electricity

2006

USA

Port Arthur GCC Proj

E-GAS(Destec/Dow)

Petcoke

Electricity

2005

USA

Lake Charles IGCC Proj.

Texaco

Petcoke

Electricity, H2 & Steam

2005

USA

Deer Park GCC Plant

Texaco

Petcoke

Elect., Syngas & Steam

2006

USA

Polk County Gasification Plant

Texaco

Petcoke

Electricity

2005

USA

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 Coal

Operational plant 27

Planned plant 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 8 wt %), the BBP (>1 wt %) and the Hitachi 44

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,