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COOPERATIVE RESEARCH CENTRE FOR BLACK COAL UTILISATION Established and supported under the Australian Government’s Cooperative Research Centres Program

COAL-BASED POWER GENERATIONIN JAPAN

TECHNOLOGY ASSESSMENT REPORT 18

by

D G Roberts# 

and

T F Wall* 

#CRC for Black Coal Utilisation

Advanced Technology Centre, The University of NewcastleCallaghan, NSW Australia 2308

* Department of Chemical Engineering

The University of NewcastleCallaghan, NSW Australia 2308

August 2001

 

Advanced Technology Centre, The University of NewcastleUniversity Drive Callaghan NSW 2308 AUSTRALIATelephone (02) 4921 7314 Facsimile (02) 4921 7168

Email: black-coal@newcastle.edu.au

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CONTENTS

EXECUTIVE SUMMARY 3 

INTRODUCTION 5 

Background 5 

Japanese Energy 5 

Electricity Supply 7 

The Role for Coal in Japan’s Energy Supply 9 

COAL-BASED GENERATION IN JAPAN 12 

Case Study 1: EPDC Tachibana-wan Thermal Power Station 14 

Description 15 

Coal Testing Regime 16 

Case Study 2: Shikoku EPCO Tachibanawan Thermal Power Station 17 

Case Study 3: Chubu EPCO Hekinan Thermal Power Station 18 

ADVANCED TECHNOLOGIES IN JAPAN 20 

Pressurised Fluidised Bed Combustion 20 

Case Study 1: PFBC Commercial Demonstration Plant, KyEPCO Karita 21 

Case Study 2: PFBC Demonstration Plant, Osaki 22 

Case Study 3: APFBC Development Project, EPDC Wakematsu 23 

Coal Gasification 24 

Case Study 4: EAGLE Gasification Development Project, EPDC Wakematsu 25 

Case Study 5: 250 MW IGCC Demonstration Plant 26 

SUMMARY 28 

Current Generation 28 

Next Generation 29 

ACKNOWLEDGEMENTS 31 

REFERENCES 31 

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FIGURES

Figure 1: Structure of the overall energy supply situation in Japan [after 3]...........................6 

Figure 2: Japanese electric power companies and the regions they service [5].......................7 

Figure 3: Electricity sales by the 10 electric power companies in Japan, with forecasts to2009 [5]. ...............................................................................................................8 

Figure 4: Total generation of electricity in Japan over the last 20 years [5]............................8 

Figure 5: Sources of generated electricity in Japan in 1998 [5]..............................................9 

Figure 6: Breakdown of the electricity sources proposed under a deregulated electricitymarket. Compare this with the current situation in Japan (Figure 5) [9]...............11 

Figure 7: Pollution control systems used on the 59 currently operating coal-fired powerstations in Japan [12]. SCR = selective catalytic reduction; FBC = fluidised bedcombustion (in-bed limestone sorbent); PFBC = Pressurised Fluidised BedCombustion; CY+BF=cyclone + bag filter; ESP = electrostatic precipitation. ......13 

Figure 8: Breakdown of proposed electric output from the EAGLE system.........................26 

Figure 9: The MITI goal for coal utilisation technologies in Japan [3, 16]...........................30 

TABLES

Table 1: Current energy mix for electricity generation compared with the mix from the proposals under a system exposed to competition [9]...........................................11 

Table 2: Coals tested in the EPDC Tachibanawan units. .....................................................17 

Table 3: Operating parameters for the PFBC unit at KyEPCO, Karita.................................21 

Table 4: Conceptual parameters of a Japanese APFBC system............................................24 

Table 5: Summary of coal utilisation technologies in Japan. The numbers used are the bestdata taken from information on the facilities discussed in this report....................29 

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 Gasification-based technologies, however, have been identified as the future for

coal-fired technology in Japan. To this end, the Japanese have been planning anIGCC demonstration facility since the early eighties, which is scheduled for

completion in 2007. Gasification technologies to produce power using fuel cells inconjunction with gas and steam turbines are also the subject of fundamental and

 pilot-scale research, and the government foresees the possibility of a ‘zero-emission’coal utilisation facility in the future, which is likely to be based on a combination ofgasification and combustion technologies.

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INTRODUCTION

Background

Japan is the fourth largest energy consumer in the world, after the US, Russia andChina [1]. Given the desire of Japan to diversify energy sources away from oil andto further its economic growth, the need for coal imports to the country will continueto increase. Australia is the world’s largest exporter of black coal, and of the 167 Mtexported in 1998, 70% was sold to Japan and other Asian markets [2]. Therelationship between Japan and Australia in terms of coal exports and utilisation istherefore very important to both countries.

There is international concern over the role emissions from coal combustion for

 power generation play in air pollution (emissions of oxides of nitrogen and sulphur),water pollution (ash storage leachate contamination from heavy metals) and theenhanced greenhouse effect (emission of CO2). In order to reduce the amount ofthese pollutants and to increase the efficiency of the coal utilisation process, newtechnologies have been developed. The use of these technologies in countries thatare reliant on coal for a significant portion of their energy needs will change the coal

 property requirements of the coal they import.

This document will consider the situation in Japan regarding the use of coal as anenergy source from two perspectives. One will be the current situation in terms ofcoal use and coal utilisation technologies. The second will be the future Japan sees

for the use of coal, and the implications of these choices for Australian coal exportersand researchers—with particular emphasis on the planned technologies to be used.The remainder of this introduction will provide details of the Japanese policyregarding energy and coal utilisation, which directs much of the technologicalchoices discussed later in the report.

Japanese Energy

The breakdown of total energy sources in Japan is given in Figure 1. It can beseen that oil is dominant and the amount of oil used over the last decade hasn’t

changed, although its share of the total energy supply is decreasing as the Japaneseintroduce alternatives based on nuclear and renewables.

Japanese energy policy is the three Es: to ensure security of e nergy supply toachieve e conomic growth without damaging the e nvironment. There are two notableissues that arise from this policy. The first is the Japanese commitment at the 1997Kyoto protocol to reduce their 1990 greenhouse gas emissions by 6% by the period2008–2012. The second is that Japan relies on imports for more than 80% of its

 primary energy supply and in 1995 79% of Japan’s crude oil came from the MiddleEast.

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As a result of this policy, and in response to the associated issues, the Japanesegovernment’s policy is to[4]:

§  Diversify petroleum sources away from the reliance on Middle East oil,and reduce overall oil imports. This means expanding the use of oilalternatives such as nuclear, coal, natural gas and renewables;

§  Implement strict end-use efficiency methods;§  Deregulate the petroleum, natural gas and electric utilities to increase

efficiencies and lower costs; and,§  Prioritise measures that contribute to Japan’s Kyoto commitment – i.e. in

reducing CO2 emissions.

The CO2 emission issue is a major point. The government sees the short-term keysto meeting this obligation in fuel switching (from coal to natural gas and nuclear) andhigher end-use efficiencies. Middle-term future possibilities include fuel-cell

 powered cars and waste heat recovery. Longer-term issues include space-based solar power, CO2 sequestration and biomass-based power generation.

0

20

40

60

80

   S   h  a  r  e  o   f   T  o   t  a   l   S  u  p  p   l  y   (   %

Oil

Coal

Gas

Nuclear 

Other 

 

0

100

200

300

400

500

600

1973 1985 1990 1998

   T  o   t  a   l   S  u  p  p   l  y   (   G   L  o   i   l  e  q .   )

Other 

Nuclear 

Gas

Coal

Oil

 

Figure 1: Structure of the overall energy supply situation in Japan [after 3].

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 CRIEPI have been quoted in the Japanese media, however [in 4], as claiming that

Japan cannot reduce greenhouse gas emissions, and that by 2010 Japan’s CO2 emissions will be 14% greater than 1990 levels. Further to this, they recommend

further introduction of solar and nuclear energy sources, along with the use oftechnologies that favour the ability to sequester CO2 produced.

Japan still sees a role for coal, however, in the generation of power to fuel theirdesired growth, and as an oil alternative in the non-electricity-generation industries.This is discussed in later sections of this report.

Electricity Supply

Most of Japan’s electricity is produced by 10 privately-owned electric power

companies. These companies are responsible for the generation and distribution ofelectricity within their region (Figure 2). From March 2000, sections of theelectricity supply structure were liberalised, introducing competition between someelectric power companies as well as smaller entrants into the electricity industry.This liberalisation of the electricity industry is a direct result of the government

 policies discussed above.

The amount of electricity sold by the major power producing companies in Japanis increasing each year, and is forecast to continue to increase (Figure 3). Thiscompares with an increase in the total amount of electricity generated in Japan overthe last 20 years (Figure 4).

Figure 2: Japanese electric power companies and the regions they service [5]

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 Unlike Australia, which generates 85% of its power [6] from the combustion of

coal (and much of the remainder from the combustion of oil and gas), Japan produces power from a mix of coal, oil and gas combustion, nuclear fission and hydroelectricgeneration (Figure 5). Japan has been using nuclear power since 1966, and currentlyoperates 51 reactors at a combined capacity of 44.9 GW [5]. It uses this nuclear

 power along with inflow type hydroelectric and modern, state-of-the-art pf units asthe base supply sources. Most of the coal, gas and oil combustion plants are used tosupply the mid-range and peak demands (with some contribution from pumpedstorage type hydroelectric power in periods of very high demand). In terms of

0

200

400

600

800

1000

   E   l  e  c   t  r   i  c   i   t  y   S  a   l  e  s   (   T   W   h   )

1965 1975 1985 1995 1999 2004 2009

Electricity Sales - Major Companies

 Figure 3: Electricity sales by the 10 electric power companies in Japan, with forecasts to

2009 [5].

0

200

400

600

800

1000

1200

   E   l  e  c   t  r   i  c   i   t  y   G  e  n  e  r  a   t   i  o  n

   (   T   W   h   )

1980 1985 1990 1995 1998 1999

Electricity Generation - Total Japan

 

Figure 4: Total generation of electricity in Japan over the last 20 years [5].

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generating plant capacity, coal makes up less than 12% of the total (andapproximately 19% of the actual generated electricity).

In addition to the data discussed above is the release of information by TEPCOearly in 2001, regarding the freezing of the plans for 27 thermal plants at 12 powerstations [7, 8]. TEPCO forecasts the growth in power demand over the next 10 yearsto be less than 2%—this is a record low for Japan. The TEPCO informationdiscusses this reduced level of growth in terms of reduced demand and changes in

the way Japan electricity is produced. The economic slowdown of the last 5 years,combined with the increase in the use of air-cooling units with gas and the increasein power generation plants owned and run by non-power-sector companies, are seenas the major contributing factors. Non-power-sector companies, for example, havegenerated a combined annual power output equal to that of two 1000 MW powerstations. Concerns about emissions of greenhouse gases and other pollutants werenot related to any of these decisions.

The Role for Coal in Japan’s Energy Supply

The Japanese are still more dependent on oil than any other energy source, with

coal second. In terms of electricity generation, nuclear power has the largest share,with gas and coal second. Following government policy to move away from thereliance on oil (in particular Middle-Eastern oil) the dependence on oil imports isdecreasing. The result of that is an increase in the reliance on gas and nuclear-basedelectricity generation, as well as a desire to rely more on renewables. Amongst thisis a steady reliance on coal—in both electricity generation and replacement of oil

 products through coal liquefaction. It is on this steady reliance on coal that thediscussion of current and proposed utilisation technologies is based.

An interesting dilemma has arisen for the Japanese government in dealing with the policy of the three Es [9]. As discussed, the aim of significantly reducing the

emissions of CO2 from energy production has meant that they are actively pursuing a

Electricity Generation by Source

Nuclear 33%

Coal

19%

Gas

21%

Oil

16%

Hydro

9%

Others

2%

 

Figure 5: Sources of generated electricity in Japan in 1998 [5].

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move away from a reliance on coal. On the other hand, in order to encourageeconomic growth the government is going through a process of privatising theenergy market, with the associated focus on a ‘more electricity, less cost’ approach.The difficulty of this is the fact that these two situations tend to be mutually

exclusive, since thermal power sources—in particular coal—are the ones that areseen as the most economical.

The result of this privatisation strategy can be seen in the new power generationcapacity that has been contracted (amounting to just less than 6000 MW,representing 3.1% of the power station capacity in March 2000). These generators

 propose to utilise a very different mix of power generation options than the 10 large power companies do at present (Table 1, Figure 6). The pledged power generationfacilities have all chosen thermal power (coal, oil and gas). There are no proposalsfor nuclear, hydro or geothermal. The relative cheapness of coal has seen its

 proportion rise from 20% currently in use to a proposed share of 49% of those proposed. This is entirely a result of the introduction of competition, and is at directodds with many of the Japanese government’s policies [see 9].

The impetus for the planning for future strategies for coal utilisation is the promiseto reduce CO2 emissions. Eventually, it is seen that the supply of oil will be limited,

 perhaps as early as 2020 [3]. For the next 20 or so years, the aim is to producesystems that increase the efficiency of the coal utilisation process. The firstgeneration of these is ultrasupercritical pf and PFBC systems: the former is the basisfor existing state-of-the-art facilities while the latter is at the stage where they are atthe advanced stage of demonstration, soon to be commercialised.

The principle long-term research priorities of the Japanese government’s coalR&D program (which is primarily funded my MITI) are based on the liquefaction (to

 produce a viable oil replacement) and gasification (to produce gas to be used inintegrated turbine/fuel cell systems) of coal [3]. This has led to the development andrecent construction of advanced systems that convert coal (through pressurisedgasification processes) to both electricity and chemicals. These are discussed inmore detail in subsequent sections.

Japan is not a major producer of coal. It is therefore very important that the coalutilisation industry in Japan secures a stable supply of imported coal. It follows that

any such coal needs to be suitable for use in the technologies that are being adoptedfor power generation and other uses. This is an issue since the properties of coalsthat are seen as favourable for use in current technologies (e.g. coal combustion as

 pulverised fuel in utility boilers) are not necessarily the same as the properties thatare seen as useful for coal utilisation in advanced technologies, such as pressurisedfluidised-bed combustion and gasification, and entrained-flow gasification. Thefollowing sections of this report will discuss these technologies as they are used, oras they are forecast to be used, in Japan.

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Current Facilities Pledged Facilities

Coal 20% 49%

Oil 14% 34%

Gas 24% 17%

Hydro 10% None

 Nuclear 32% None

Table 1: Current energy mix for electricity generation compared with the mix from

the proposals under a system exposed to competition [9].

Proposed New Electricity Generation bySource

Gas

17%

Coal

49%

Oil

34%

 

Figure 6: Breakdown of the electricity sources proposed under a deregulated

electricity market. Compare this with the current situation in Japan (Figure 5) [9].

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COAL-BASED GENERATION IN JAPAN

The state-of-the-art in coal utilisation technologies, in particular for powergeneration in Japan, is set to change. This is primarily a response to government

 policies regarding greenhouse gas targets, policy-induced competition in theelectricity-generation markets, and the desire to secure a stable energy supply forJapan’s future.

Of the Japanese power plants that use coal as the primary fuel, pulverised-fuelfired systems are by far the most common. Advanced pf plants are currently beinginstalled to produce power in Japan, e.g. Tachibanawan EPDC Thermal PowerStation. It has two units, each with a capacity of 1050 MW, which came online in2000. It uses ultra-supercritical steam conditions of 259 atm and 605/613°C. This

 particular plant will be discussed in more detail in subsequent sections of the report.(The advanced nature of supercritical [and of course ultrasupercritical] steam and post-boiler gas cleanup technologies, however, have little effect on the technicalrequirements of the coal used—although a recent review by Bèer [10] points to

 possible ash deposition issues arising from the higher surface temperatures of thesuperheater and reheater tubes.)

Most of the coal used for power generation in Japan is burnt as pulverised fuel.These pf plants have a high degree of post-boiler gas cleaning (see Figure 7). Inthese plants primary (i.e. boiler/burner) NOx control strategies are widely used incombination with selective catalytic reduction (SCR). Strict NOx emission limits

less than the national standards, which are already far less than most countries, areagreed to by regional authorities and between plants. Low NOx burners, withoverfire air and sometimes flue gas recirculation or reburning combined with SCR,are typically used. Standard particulate removal systems in Japan are highly-efficient electrostatic precipitators. Such methods are typical of the systems beinginstalled currently in Japan for power generation, and are discussed in more detail inthe case studies.

Reducing pollutants emitted by Japanese power stations is a large issue due to the proximity of the power stations to centres of population. Only the USA (94 GWe)and Germany (30 GWe) have more pf combustion capacity fitted with post-

combustion NOx reduction measures than Japan (15 GWe) [10]. SCR has been usedcommercially in Japan since 1980, usually on power stations burning low to mediumsulphur coal. Japan now has approximately 15 GWe of coal-fired SCR capacity, outof a total of about 53 GWe worldwide. The use of non-catalytic reduction of NOx (SNCR) in Japan seems to be limited to oil and gas fired power stations where it has

 been used as a technology since the mid-70s.

Japanese methods for removal of SO2 are primarily based on a wet scrubbingsystem using limestone or gypsum. Strict waste disposal controls (the space in Japanthat can be used for waste disposal is extremely limited) means that processes

 producing saleable gypsum are favourable. Consequently, chlorine pre-scrubbers are

also used to meet the users’ quality requirements.

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 The strict emission limits on particulates for coal-fired power stations means that

all Japanese units are fitted with some form of particulate control, the most common being highly-efficient electrostatic precipitators. Ash disposal in Japan [11] istypically via ocean reclamation, with leachate concentrations of heavy metals withinguidelines. The decrease in the allowable leachate concentration guidelines,however, has meant that the margin for error is also decreasing. As a result theJapanese are looking for alternatives to ocean disposal of ash. The minimum amountof space available to utilities means that there is an emphasis on ash utilisation, withsome research into the leaching properties.

A consequence of this is the increase (from 56% in 1993 to 70% in 1998) in the proportion of ash generated which is utilised. This is primarily in terms of cementmanufacture, although the maturity of this industry and saturation of the marketmeans that future demand is not likely to increase.

Post-boiler NOx Control

None

SCR Activated

Cokes

SOx Control

None

FBC

Wet

CaSO4

Dry

CaSO4

Wet

MgSO4

Particulate Control

Hot ESP

Dry+wet ESP

Extra Cold ESP

CY+BF (PFBC) Cold ESP

 Figure 7: Pollution control systems used on the 59 currently operating coal-fired power

stations in Japan [12]. SCR = selective catalytic reduction; FBC = fluidised bed

combustion (in-bed limestone sorbent); PFBC = Pressurised Fluidised BedCombustion; CY+BF=cyclone + bag filter; ESP = electrostatic precipitation.

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The large extent to which the power stations in Japan are required to treat the fluegases to remove pollutant species, and the emphasis that is put on efficientoperations, means that the cost of constructing and running pf power stations is muchgreater than in Australia. It is estimated by CRIEPI [13] that the capital cost of an

ultra-supercritical pf unit in Japan is approximately $4800/kW, although utilities areachieving costs substantially less than this (approximately $3200/kW). This isconsistent with IHI’s recent claim to be achieving a 30% cost reduction in theinstallation of the new units at Hekinan Power Station (see case study). These costs

 per unit capacity can be compared with the cost of the latest Australian (Queensland)supercritical pf units of approximately $1000/kW.

Although pf technology is not identified as a clean coal technology for long-termfuture use in Japan, there are active research projects being undertaken to achieve animmediate reduction in pollutants. In terms of NOx emissions, CRIEPI (ChemicalEnergy Engineering Department) has been actively designing pf burners to providelower levels of NOx in the flue gas without the common side-effect of increasedlevels of unburnt carbon in the fly ash. This is through burner designs that promotecoal combustion close to the burner and provide conditions to reduce NOx formationfurther away from the burner.

There is currently a large amount of research activity into the heavy metals that areemitted with the fly ash, in particular the behaviour of these elements in terms ofleaching into waterways. This research work is being performed in closecollaboration with power stations: the nature of this research is therefore highlysensitive and the confidential results are not widely available.

The following two case studies of pf-fired power stations present some detailedinformation regarding facilities that can be considered as Japan’s state-of-the-art pftechnology. They are amongst the most recently commissioned pf facilities in Japan,and are both situated in locations that require an extensive regime of emissionscontrol. Their high capacities and efficiencies make them contributors to the

 baseload electricity supply in their regions. These factors combined make them goodexamples of the state of Japanese pf combustion technology.

Case Study 1: EPDC Tachibana-wan Thermal Power Station

Tachibana-wan is a thermal power producing site comprising of two coal-fired power stations: EPDC (the Electric Power Development Co.) and SEPCO (ShikokuElectric Power Co.). The EPDC plant in particular is a prime example of the current‘state-of-the-art’ of Japanese coal-fired power generation capacity. The EPDCstation has two units (online in July and December 2000) and the SEPCO site has asingle unit, which came online in 2000.

The island on which the site is based is a national park; consequently theconstruction of the power stations and the subsequent operation has a major localenvironmental slant. Moreover, the ocean surrounding the island is a local ‘black

spot’ for pollution—the upshot of which is extraordinary pressures from local

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authorities to reduce environmental impacts of construction and operation. The power stations have been mostly built on reclaimed land surrounding the naturallyexisting island, which left much of the native vegetation intact.

Description

The EPDC Tachibana-wan Thermal Power Station is the largest and (claims to be)the most efficient in Japan. It has two pulverised-coal fired units, each with anoutput of 1050 MW. The number 1 unit was online in July 2000, and the number 2unit was online in December 2000. The plant was originally designed as a

3×700 MW plant; however, the increased efficiencies afforded by the larger-scaleunits meant that two 1050 MW units were built. The size and efficiency of the unitsmeans the electricity produced by the power station is used as baseload supply, and issent to the Kansai region (700 MW), the Chugoku region (150 MW) and the island

of Kyushu (50 MW) as well as local use on Shikoku (150 MW).

The coal used in the power station is brought in by ship, using a dock facility thatis shared by EPDC and SEPCO. The coal for the EPDC units is stored on the EPDCsite using a system of 8 fully enclosed and connected silos (75 m tall and 45 macross, with a total capacity of 70 000 tonnes). This is to prevent contamination ofthe local national park from wind blown coal dust. The silos are fitted with a coalrecirculation system, which is activated if the coal self-heats above a certaintemperature. In such an event, the coal is removed, cooled, and placed back into thesilo. They are also fitted with a water spray system in case that circulation systemisn’t effective. Neither system has been activated to date.

The operation of the power station is almost fully computer-controlled. The onlysystem which is not is the fire alarm and abatement system, by decree from localauthorities. The entire operation is managed from a single control room which is inthree sections: one section for each of the units (each of which is typically run by asingle operator) and a section for the gas cleaning (NOx, SOx, particulates, etc.).

Unit 1 uses IHI low-NOx burners, and unit 2 uses Hitachi (NR type) low-NOx  burners. Both units operate with intermediate and over-fire air with flue-gasrecirculation to decrease the conversion of fuel-N to NOx in the boiler. Both burner

systems have computer-controlled self-diagnostics, which (theoretically) optimisesthe combustion conditions. There is little ongoing fine-tuning of the burners tocontinuously improve NOx emissions, as the effectiveness of the deNOx system is sogood. Startup for both units is light-oil and is quoted to take 140 minutes. Theminimum load on the burners is quoted as 40%. Steam in both units (3000 tonnes/hrfor each unit) is generated at ultrasupercritial conditions of 605/613°C and25.88 MPa. The efficiency of the USC system here is the best in Japan—this isattributed by EPDC to the longer turbine blades used.

Denitrification of the flue gas is performed using conventional selective catalyticreduction techniques. NOx content of the stack gas is quoted as 45 ppm—this is low

compared to older thermal stations in the Yokohama region, which are of the order of

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150 ppm NOx. Desulphurisation is using wet limestone methods to produce saleablegypsum, resulting in quoted levels of SOx in the stack of 50 ppm.

Due to large pressures from local authorities particulates in the exhaust gas are of

 particular concern. The particulate removal systems on the units here areelectrostatic precipitators, a system which is common in most parts of Japan.Particulate content at the exit of the ESP is quoted at 50 mg/m 3 N —and in reality it isoften less than this—typical emissions are usually in the order of 10 mg/m3 N. Dry(fly) ash and wet (clinker) ash are stored temporarily in silos on site. No ash isdisposed of on site, since there is not enough space on the island. It is removed daily

 by ship: 70% of this ash is used in cement manufacture and the rest is disposed of.The carbon content of this ash is consistently less than 5% which gives no problemsfor the cement manufacturers.

Coal Testing Regime

EPDC are currently testing various coals (listed in Table 2) to find a supply that best meets their needs. They are investigating the ease of grindability, the reactivity(i.e. ease of conversion), slagging and fouling characteristics, and the self-heating ofthe coals in their silo storage systems.

Whilst price is their main concern, they are also interested in coals that are lowash, since the removal and disposal of ash is a significant issue for a location such asthis. This ash is ideally one with a high ash fusion temperature. Furthermore, theyindicate that the particle size of the fly ash generated by the coal is important: since

the ash must be handled extensively to store, ship then either sell or use, the handlingcharacteristics are a decisive factor. They have experienced difficulties in handlingfly ash that has particles that are too fine.

Coals that are easy to burn, i.e. have a high reactivity, are also favoured. In termsof indexes used to measure the reactivity of the coals supplied, the sole factor is thefuel ratio. EPDC are not concerned about the levels of N or S in the coal, again

 because the gas cleaning systems for each unit are very efficient. This is notnecessarily the norm in Japan: EPDC’s focus is on technology and developmentwhereas electric power companies are more focussed on compliance and stability.

Of the coals tested, the ones that they are most pleased with are Blair Athol andEncham. The reasons are a combination of low ash, high conversion reactivity andash with a high melting point.

Due to the reliance of the station on high-quality imported coals, there is noincentive to blend coals. Most of the blending is done when they are cleaning outcoal silos. The only routine blending done at EPDC Tachibanawan is with theIndonesian coal, as a test blend. It is a coal with a much lower calorific value—the

 blending is done to raise the heating value to closer to that of the Australian coals.This is consistent with related research being performed in CRIEPI [14] and other

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research organisations, with the aim of developing future utilisation technologies forsub-bituminous coals.

Case Study 2: Shikoku EPCO Tachibanawan Thermal Power Station

Sharing the same Tachibanawan site as the EPDC power station is the SEPCOthermal power station. It has the one unit, rated at 700 MW, which has been onlinesince 2000. Coal shipping facilities are shared with the EPDC site; however, the 8silos discussed above are not shared. The unit has four of its own coal storage silos,similar (but not identical) to the EPDC silos. On average 3 of these 4 silos are full atany time.

The unit is fundamentally very similar to the #2 unit on the EPDC station. That is,Hitachi designed low-NOx burners with OFA and flue gas recirculation. DeNOx anddeSOx systems are similar also, as is the ESP particulate control measures. Whilstthe quoted particulate levels in the stack emissions is 10 mg/m3 N, they claim to beemitting less than 1 mg/m3 N. Ash is stored on site and removed by ship 4 times aweek. There is enough capacity for 20 operating days worth of ash on site in thestorage system. Typical operation is at 95% load which is reduced to 75% in low-demand times.

Whilst the technology used in this unit is fundamentally similar to the #2 unit onthe EPDC site, the philosophy of the operators is somewhat different. Stability ofcoal supply, stability of electricity production and strict compliance with allregulations are the driving factors. When choosing a supply coal the most importantaspect is the price of the coal. The second most important aspects are stability of the

#1 Unit #2 Unit

Blair Athol Australia Blair Athol Australia

Encham Australia Encham Australia

Mt Owen Australia Bulga AustraliaWambo Australia Burton Australia

Macquarie Australia Surat Premium Australia

Bulga Australia Warkworth Australia

Lanoli Bridge Pinann

Burton Australia Peabody

Surat Premium Australia Whitbank South Africa

Warkworth Australia Kidetoroko South Indonesia

Dartbrook Australia

Peabody

Whitbank South Africa

Kidetoroko South Indonesia

Table 2: Coals tested in the EPDC Tachibanawan units.

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supply of the coal, the country of origin and the port through which the coal isshipped.

As with the EPDC units, ash in the coal is of paramount importance, and an upper

limit of 10-13% ash is placed on any coal they want to use. Furthermore, the coalthat they do choose must have S-levels less than 1.0% daf, and N-levels less than1.8% daf. Any coal they use will have a fuel ratio1 of less than 2 and an averagecalorific value of approximately 6000 kcal/kg. The majority of the coals used in theSEPCO unit are Australian coals—the unit was designed using NSW Hunter Valleycoal. Recent times, however, have seen the demand of the unit not met by theAustralian suppliers, which has seen more use of Chinese coal, with the associatedreduction in shipping costs.

Case Study 3: Chubu EPCO Hekinan Thermal Power Station

Hekinan Thermal Power Station is a pf-fired facility owned and operated byChubu Electric Power Company. It is located at Hekinan, on the coast of AichiPrefecture.

There are currently three operational 700 MW units at Hekinan Power Station.The first of these is an MHI boiler, which came online in October 1991. This wasfollowed in June 1992 by the commissioning of the Hitachi number 2 unit, and inApril 1993 by the IHI number 3 unit. These units form part of Japan’s baseloadelectricity supply. In these units steam is produced at 2500 t/h (units 1 and 2) and at2250 t/h (unit 3) at supercritical conditions of 25.5 MPa and 543/569°C (units 1 and2) or 543/596°C (unit 3).

In 1998 construction began on the new Hekinan units, numbers 4 and 5. Thesewill each be 1000 MW pf units, and will be manufactured using state of the arttechnology in Japan. They are manufactured by IHI and will be operational in

 November 2001 (number 4) and November 2002 (number 5). The addition of thesetwo units increases the total capacity of the plant to 4100 MW. These new units each

 produce steam at a maximum of 3050 t/h at conditions of 25.5 MPa and571/596°C—slightly less than the conditions used at Tachibanawan. Efficiency andreliability have been increased through the use of the world’s first 3600 rpm

1000 MW tandem compound type turbine.

 NOx control measures at Hekinan are extensive. Low-NOx burners are used inconjunction with the use of over-fire air to reduce the NOx formed in the boiler.Selective catalytic reduction of the NOx formed removes 90% of the NOx producedin the boiler—this is claimed to be the best facility of its kind in Japan. During theinstallation and commissioning of the new units, the gas cleaning measures on theexisting units were upgraded. This has meant that the NOx output from units 1, 2 and3 has been reduced by 15 ppm to 30 ppm for each unit, with each of the new

1 As with the EPDC facility, the only index used for reactivity assessment is the fuel ratio of the coal

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1000 MW units emitting 15 ppm. (In order to achieve the emission targets of15 ppm from the stack, the NOx levels coming out of the boiler must not exceed50 ppm.) This means that overall the NOx emitted from the power station has beenreduced upon addition of two new units, and is now less than the emissions from

other state-of-the-art facilities such as Tachibanawan.

Desulphurisation of the flue gas is based on a wet limestone-gypsum scrubbing process. This recovers good quality gypsum of a high purity. As with thedenitrification facility, the deSOx equipment on the existing units was upgraded, suchthat the SOx emissions from the existing units was decreased from 50 ppm to28 ppm, and the emissions from each of the two new units will be 25 ppm. As withthe case with denitrification, the addition of the two new units has not increased theamount of SOx emitted by the plant.

Particulates are removed from the flue gas using a somewhat unique two-stage process. Prior to the desulphurisation facilities there is a high-performance dry-typeelectrostatic precipitator system. This system uses a system of moving electrode

 plates to discharge the collected dust. After the deSOx facility is another electrostatic precipitator system—in this case it is a wet-type facility, which reduces the totalemission of particulates to 5 mg m N

3. Previously the existing facilities wereachieving a particulate level of 10 mg m N

3  per unit—as with the other environmental

measures the installation and commissioning of the new units has given theopportunity to increase the performance of the particulate control measures on theexisting units.

The majority of the ash produced at Hekinan Power Station (approximately 80%)is disposed of on site with 20% used in cement manufacture. The ash is disposed inan ash storage pond with an area of 750 000 m2 and a capacity for 10 years worth ofash. Heavy metal leachate and other potential pollutants are kept from escapingthrough the use of submerged steel walls and impermeable plastic sheeting.

The coal used in the facility is all imported coal from Australia, Canada, USA andChina. This coal is shipped to the power station and unloaded using a dedicatedunloading facility. It is stored in an open-air coal storage yard surrounded byspecially designed fences to minimise the spreading of coal to the local environment

 by strong winds. The yard is equipped with a water spray system to aid in the

abatement of coal dust emissions.

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ADVANCED TECHNOLOGIES IN JAPAN

Although the standard pf coal combustion system in Japan is relatively clean andefficient, it is not part of the Japanese government’s long-term plan for coal-based

 power generation. The most recent technical meeting between the Japanese and theUS on coal utilisation2 —which was labelled as a symposium discussing the mostsuitable clean coal technologies for the future—did not present one paper regarding

 pf combustion.

In order to increase efficiencies and eventually work towards a “zero emission”system for chemical production and power generation, advanced coal utilisationtechnologies have been identified by the Japanese Government and generators as thefuture of coal utilisation in Japan. In particular, those based on pressurised fluidised

 bed combustion and pressurised entrained-flow gasification have been the basis forthe future goals for coal utilisation technology (see for example Figure 9 in theSummary section of this report).

The forms of these advanced technologies are varied. Currently, the emergingtechnologies for commercial power generation are primarily coal combustion in

 pressurised fluidised beds. Technologies that have been identified for futureimplementation are gasification systems, usually pressurised entrained flow or

 pressurised fluidised bed (sometimes combined combustion/gasification systems).These are currently the basis of design and large-scale testing for the imminentconstruction of a demonstration plants, which indicates the direction that coal

utilisation technologies will take in the more medium-term future.

Pressurised Fluidised Bed Combustion

The Japanese have been interested in fluidised bed combustion for many years,and have shown further interest in the use of the pressurised version as an advancedclean coal technology. The use of pressurised fluidised beds is seen in Japan as thecurrent ‘advanced’ technology to be implemented. This will, in the longer term,

 possibly give way to the use of gasification-based systems (see below); but, in anycase, will still remain a major part of power generation in Japan, especially through

the use of advanced PFBC.

Currently in Japan there are four PFBC sites, three of which are currentlyoperating. EPDC at Wakematsu (71 MW) was operational in 1994, and providedoperating experiences and design testing and was the basis of the design of theadvanced plant at Karita. The 360 MW Karita plant run by KyEPCO is scheduledfor commercial operation in July 2001, and this has led to the developmentalWakematsu unit’s closure. Hokkaido Electric at Tomatoatsuma (85 MW) has been

2 The 16th Japan/US Joint Technical Meeting.  Hyatt Regency, Fukuoka, Japan. November 7–8,2000.

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operating since 1998 and with Chugoku Electric at Osaki (250 MW × 2) has one unitcurrently operating with the other planned for operation over the next two years.

The Japanese are also developing advanced PFBC (APFBC) which has the added

ability to produce power in combination with fuel cells. APFBC as used in Japan is atechnology that is still under development, and involves a partial gasifier which isfed with coal and air and has a separate limestone furnace used for desulphurisation.Carryover char from this gasifier is sent to a char combustor, and the fuel gasgenerated is used to increase the exit gas temperature. Further description of APFBCwill be given in the case study below.

Three PFBC case studies are examined here to provide a more detailed picture ofthe state of PFBC technology in Japan. The first is the 360 MW facility at Karita,included here since it is a very large unit that utilises Australian coals, and is backed

 by an extensive history of research and technological development. The Osaki PFBCfacility is discussed as it is of a somewhat unique design, in that it uses two fluidised

 bed furnaces in the single unit. The third study is of the development of the next-generation PFBC, based on the Advanced PFBC technology discussed above.

Case Study 1: PFBC Commercial Demonstration Plant, KyEPCO Karita

At their power station in Karita, KyEPCO (Kyushu Electric Power Co.) replacedtheir number 1 (pf) unit with a pressurised fluidised bed combustion system. Thisunit rates at 360 MW, which makes it the largest single PFBC unit in the world. The

 planning of the Karita plant was made using knowledge and experience gainedthrough involvement with the EPDC PFBC unit in Wakematsu. The plant is in part arepowering project, in that some of the infrastructure remaining from the previous220 MW pf boiler is being used in construction of the PFBC unit.

This PFBC system was supplied by Ishikawajima Heavy Industries (IHI), throughlicence agreements with ABB Carbon. The gas turbine was supplied by ALSTOMPower, Sweden. Relevant operating parameters are listed in Table 3.

Bed temperature 870°CBed height 4.2 m

Freeboard height 7.0 m

Superficial velocity 0.9 m s-1

Pressure 1.3 MPa

Steam condition 24.1 MPa, 566/593°C

 Net target efficiency 42.8%

Table 3: Operating parameters for the PFBC unit at KyEPCO, Karita.

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The installation of the pressure vessel began in November 1997. It was first firedin the middle of 1999, and is expected to be ready for commercial operation by mid2001. At the end of July 2000, the unit had been generating power for a cumulative

 period of over 3200 hours, with the longest period of continuous operation being

650 hours.

The efficiency (at the grid) is claimed to be over 2% better than the conventionalcombustion unit, with improvements made also to the emissions of SOx (76 ppm),

 NOx (60 ppm) and particulates (30 mg/m N3). NOx is reduced through the use of low

temperature combustion and SOx is reduced by using in-bed limestone sorbent. Allof the ash produced (approximately 30 000 tons of bed ash and 100 000 tons of flyash per annum) is planned to be used as a raw cement material by cement companiesclose to the power station.

KyEPCO are not willing to discuss the problems—if any—they have beenexperiencing during operation testing. It is understood that the maximum operationalload of the unit has been 90% due to bed agglomeration problems, although somealterations to the material used for the bed has alleviated these.

Case Study 2: PFBC Demonstration Plant, Osaki

The Chugoku Electric Power Company has commissioned a pressurised fluidised bed combustion power generating facility at Osaki, in Hiroshima Prefecture. Thesystem has a planned capacity of 500 MW—250 MW of which are currentlyoperating as the 1-1 unit.

The design of the Osaki PFBC facility is unique in that it uses two fluidised bedfurnaces. The first of these is used as the superheater and the second is used as thereheater. This system of using two separate furnaces inside separate pressure vesselsallows for a much more compact and practical design of the power plant.

In this PFBC system, coal (approximately 6 mm diameter) is fed at approximately185 t/h as a coal-water paste (20-30% water) with approximately 10 t/h limestonesized to 3 mm. This fuel is fed into both furnaces. The furnaces are nominallyoperated at 865°C and approximately 10 atm (although the pressure of operation

during the visit was below 9 atm). Recent operational experience has shown that theoptimum bed height for the A-furnace is 4.0 m, and the optimum height for the B-furnace is 3.8 m. Bed height is maintained during reduced-load period using make-up limestone. Steam is generated at 17.3 MPa and 571°C.

Low-temperature combustion is the means by which direct NOx formation isreduced. Also used is the standard PFBC feature of in-bed limestone sorbent for SOx removal. These systems result in a furnace-exit NOx concentration of 200 ppm and aSOx concentration of 76 ppm. Further NOx removal is achieved using a selectivenon-catalytic denitrification system employed directly after the furnace (injection ofammonia). Dust is collected in a series of cyclone filters prior to the gas turbine.

Further denitrification of the flue gas is achieved through selective catalytic

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reduction after the gas turbine which results in a stack NOx emission of 19 ppm.Compare this with the quoted emissions of NOx from EPDC Tachibanawan pf powerstation which has NOx emissions of approximately 45 ppm and CEPCO Hekinan pf

 power station which has recently reduced the NOx emissions from its units to

15 ppm. SOx emissions at EPDC Tachibanawan are approximately 50 ppm—muchthe same as the current emissions at Hekinan, although the latter is planningdesulphurisation improvements to reduce this further.

The furnace emits particulates at 20 g/m N3, which is reduced to 1 g/m N

3 after thecyclone filters. Following the SCR denitrification system a baghouse filtrationsystem reduces these to a stack emission of 9 mg/m N

3, which is comparable to the10 mg/m N

3 design emissions of Tachibanawan and Hekinan pf plants, although theHekinan ESP modifications are likely to reduce this to 5 mg/m N

3.

Chugoku Electric claim the gross efficiency of this system to be 42.6%. Comparethis with gross efficiencies of the EPDC Tachibanawan units of 42-43%—theTachibanawan units are claimed to be the most efficient pf units in Japan. Based onthese data, and the assumption that the desulphurisation and other peripherals not

 present on the PFBC unit would sacrifice efficiency, one would imagine that thePFBC unit achieves similar or better environmental performance with an increase innet efficiencies. The reluctance of the operators to divulge the exact detailsregarding net efficiencies makes a more detailed comparison impossible.

Case Study 3: APFBC Development Project, EPDC Wakematsu

EPDC, with CCUJ and Chubu Electric Power Company, are investigatingadvanced PFBC, for use in power generation at high efficiencies and with lowemissions. They are confirming the suitability and operability of such a systemthrough the design and operation of a process development unit at their Wakematsusite.

The APFBC system demonstrates a high level of efficiency: the net value is quotedat 43–46%. This is partly due to the increase in temperature of the gas turbineto1300°C, and improvements to the steam turbine section. The system is designed tooperate under a range of gasification conditions, enabling it to be used with a greater

range of coal types—they claim the major issue for coal suitability is the ash fusiontemperature. Low reactivity coals, or those with a low volatile matter, are notforeseen to be a problem. The design coal for the system’s development unit wasWarkworth, and they plan on testing the system with a wide range of coals. The lackof any need to develop a separate topping combustor contributes to the claim that thedevelopment of such a system is indeed low-risk.

A typical system that is conceptualised from such a PDU is summarised inTable 4.

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Generating end output 470 MW

Gross/Net Efficiency 50.5% / 46.0%

Desulphurisation Dry limestone

Emissions SOx: 50 ppm NOx: 45 ppm

Particulates: 10 mg/m N3 

Table 4: Conceptual parameters of a Japanese APFBC system.

Tests of the three furnaces (oxidiser, gasifier, desulfuriser) and analyses ofoperating parameters are scheduled to begin in 2001, using a process developmentunit, a facility currently constructed at EPDC Wakematsu. This facility will operateat 19 atm pressure, with an oxidiser temperature of 900°C and a gasifier temperature

of over 1000°C. Results from these tests are expected to be used in the preparationof a final design for a suitable APFBC facility.

Coal Gasification

Of the 160 gasification plants that are operational, being built or plannedinternationally, 12 are electricity-generating plants. Six of these are coal-fired (fiveusing bituminous coals). The remainder operate on waste or biomass [15]. Thetechnology that the Japanese have identified for coal use in the longer-term future iscoal gasification.

Coal gasification for power generation is still in the demonstration stage.Demonstration facilities exist in the US at Wabash River (Destec entrained-flow),Polk County (Texaco entrained-flow) and Piñion Pine (KRW Agglomeratingfluidised bed); in The Netherlands (Buggenum, Shell entrained-flow); Spain(Puertollano, PRENFLO) and the Czech Republic (Vresova, Lurgi dry ash fixed-

 bed). More are either under construction or in the design phase in the US, UK andJapan.

Gasification is currently used in Japan as a means to produce chemicals fromliquid petroleum or petroleum coke. There are five such plants in operation, four

 based on the Texaco gasifier and one on the Shell gasifier [15]. The predictedefficiency gain over coal combustion technologies (for high-rank coals, of whichJapan imports large amounts) has meant that gasification, in particular entrained-flowgasification, has been identified by Japanese researchers as a ‘future’ for coal-based

 power generation. Furthermore, the Japanese see the reduction in the amount of flyash produced as an important benefit, as the disposal of fines has long been an issue(see previous section). The long term goal of zero-emission power generation(possibly incorporating chemical production) in Japan—similar to the UnitedStates—is based on the gasification (or partial gasification) of coal.

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Gasification for power generation has been developed in Japan using a two-stage,air-blown entrained-flow technology. This was developed by CRIEPI & MHI Ltd.using CRIEPI’s 2 t/day gasifier (process development unit, or PDU) at CRIEPI’sYokosuka Research Laboratories, then demonstrated at MHI’s 200 t/day pilot scale

gasifier located at Nakoso. Australian coals have been involved in this development,with Moura the design coal for the Nakoso plant. Electric utilities, CRIEPI andothers have combined to start the design of a 250 MW IGCC coal-fired powergeneration demonstration plant. This will be based on these technologies, i.e. a two-stage air-blown entrained-flow gasifier with cold gas cleanup.

CRIEPI are also researching the gasification of coal and oil alternatives, in

 particular the use of Orimulsion. Orimulsion is a fine (approximately 20 µm particlesize) bitumen slurry marketed by BITOR (Bitumenes del Orinoco) in Venezuela.The bitumen used in the emulsion is obtained from flash evaporation of light oil fromVenezuela’s Orinoco belt. It is seen as an alternative to heavy crude oil.

A separate gasification-based project, the EAGLE project, aims to develop agasification system to produce gas suitable for use in fuel cells and chemical

 production. This facility, at the EPDC site in Wakematsu, is in the constructionstage, and is further discussed along with the national IGCC demonstration facility inthe case studies below.

Case Study 4: EAGLE Gasification Development Project, EPDC Wakematsu

In 1998, construction began of a pilot plant at EPDC’s Wakematsu site to providedata to assist in the establishment of a coal gasification technology suitable for usewith fuel cell power generation as well as petrochemical production. The EAGLE(coal Energy Application for Gas, Liquid and Electricity) project is centred aroundthe 150 t/d plant that is planned to be operational by 2001/2002. With this gasifierare systems to investigate hot gas cleaning technologies and issues associated withdeveloping the total system to produce gas suitable for use in fuel cells. The fuelcells are being developed in separate research projects within Japan (some of theseare being performed at CRIEPI) and are most likely to be based on a moltencarbonate or solid oxide system.

The project has been in planning since 1995, with construction commencing in1998. The aims are to develop a gasifier that uses an oxygen-blown technology, andcombine this with cleaning systems that provide gas of an acceptable quality for usein fuel cells—this currently has been identified as a cold gas cleanup system.

The gasification unit is an entrained-flow, oxygen-blown gasifier. It will have adual-burner system, with the lower burner combusting coal to provide heat for thegasification reactions that will take place at the upper burner. The swirlcharacteristics of the gasifier have been designed to maximise residence time in thegasification section, leading to high levels of carbon conversion for a wide range offeed coals. It will operate at 26.5 atm using 95% O2 as the feed gas.

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The system will have three power generating stages (these are also shown inFigure 8): the steam turbine (199 MW), the gas turbine (155 MW) and a fuel cell,most probably based on molten carbonates (262 MW). The use of a fuel cell to

 produce power increases the predicted efficiency of the system to 53.3% (net).

Case Study 5: 250 MW IGCC Demonstration Plant

Since the mid 1980s, research has been performed in Japan with the aim ofdeveloping a gasification technology suitable for power generation at efficiencies

greater than, and with levels of pollutants less than, traditional combustiontechnologies. Experiments and modelling were carried out using a 2 t/d gasifier atCRIEPI, and the knowledge and experience gained were applied to the design andconstruction of a larger scale (200 t/d) pilot plant at Nakoso.

The gasifiers in these systems used a two-stage, air-blown entrained-flowtechnology. The first stage (the combustor) combusts the coal in air and providesheat to convert coal mineral matter to a molten slag and for the subsequentgasification reactions. The heat (and some char) from this process travels into thereductor, where further coal is injected and the gasification reactions occur.

Slagging problems in the 200 t/d pilot scale gasifier were identified, andrefinements were made to alleviate these problems. It was found that the surface ofthe molten slag forming in the combustor was corrugated, and this increased thetendency for slag to be entrained in the gas and deposited on the cooler walls of thereductor. Design modifications to the throat section between the combustor and thereductor which altered particle trajectory, velocity and gas residence times alleviatedthese problems. A long term uninterrupted test on the pilot gasifier of 789 hours was

 performed with the final tests at the Nakoso plant completed by 1995.

By 1997 feasibility studies had been performed, and these identified the most

suitable technology for the IGCC facility as air-blown gasification combined with

Fuel Cell

262 MW

Gas

Turbine

55 MW

Steam

Turbine

199 MW

 

Figure 8: Breakdown of proposed electric output from the EAGLE system.

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cold gas cleanup. The Nakoso plant was running a hot gas cleanup system, using afluidised bed of (regenerated) iron oxide to remove H2S and an anthracite-based

 process to reduce the SO2. This process was deemed unsatisfactory for thedemonstration plant in terms of long-term reliability and unspecified “environmental

acceptability” issues. This hot gas system did, however, provide gas for the gasturbine of an acceptable quality.

The demonstration facility will have a power output of approximately 250 MW,utilising approximately 1600 t/d of coal. Original estimates of a 300 MW facilitywere based on a gas turbine inlet temperature of 1300°C; the demonstration plantwill use 1200°C gas turbines (a decision made due to the emphasis being placed onreliability of operation rather than efficiency).

The estimated net efficiency of the demonstration plant is 40.5%. This iscomparable with the current state-of-the-art pf and PFBC power stations. It is

 predicted that at the commercial stage, the system would be using 1500°C classturbines which will provide efficiencies of 46–48%.

In 1999 trial design studies and verification gasification tests began, using fundssourced 30% from the Japanese government and 70% from utilities, and involving

 joint research by 11 organisations, EPDC and CRIEPI. These tests have been carriedout using a 24 t/d pressurised gasification test facility, and aim to verify themodelling of coal performances, gasification characteristics, ash behaviour and stableoperation conditions. The conditions in this test gasifier are somewhat different tothose proposed for the IGCC facility, with the pressure less than 10 atm (c.f. approx

20 atm in the proposed demonstration plant). It is claimed that this will notsignificantly affect the adaptation of the results to the completed demonstration plant.These gasification tests are to be completed in 2001 with construction of thedemonstration facility scheduled for 2004. The demonstration plant is planned to beoperational by 2007–9.

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SUMMARY

The Japanese government’s energy policies will involve a change in the wayenergy and electricity are produced. In particular, the desired economic growth ofJapan needs to be fuelled using a secure energy supply whilst minimising anyundesirable environmental impacts. Within these plans, the use of coal will remainimportant, although the technologies that use this coal are going to change.

Current Generation

The Japanese state-of-the-art facilities have high capacities, and they are efficientand clean. They use premium coals, mainly from Australia, and have extensive post-

 boiler gas cleaning facilities. A result is that emissions from their modern stationsare the lowest in the world.

The most important thing for the operators of the modern facilities in terms of coalquality and supply is the cost and stability. This is followed by the amount of ash inthe coal (maximum allowed level is usually between 10 and 15% by weight).Provided the mineral matter doesn’t cause problems with fouling or erosion, and thecoal has a reactivity that gives ash with a low-enough C-content, these two issues arethe most important.

Some companies (EPDC, for example) are not concerned with the level of N in the

coals. Their in-boiler and post-furnace NOx abatement techniques are good enoughto handle a wide range of NOx levels, and the low-NOx burners used are reasonablyinsensitive to the amount of N in the coal3. This latter point is not agreed uponuniversally amongst the operators. This indicates that the results of research intocoal N and NOx need to be communicated more effectively: at least one Japanese pf

 plant operator will not purchase coal with a coal-N content of 1.8% daf.

3 This point has been recently reinforced using data from CRIEPI’s combustion test furnace fitted witha burner typical of that used in Japanese pf-fired power stations. More information can be found inthe CRC Research Report produced under the same TRA grant as the present report.

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Figure 9: The MITI goal for coal utilisation technologies in Japan [3, 16]

Efficiency increases,1st generation.

§ USC (pf)§ PFBC

Efficiency increases,2nd generation.

§ IGCC, etc§ DIOS, SCOPE 21

Zero emissiongeneration

§ Fuel cells and H2 turbine generation

§ CO2 conversion andutilisation 

Efficiency increases, hybridgeneration

§ Gasification and fuel cells§ Co-generation§ H2 production from coal§ CO2 sequestration

1990 2000 2010 2020 2030

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ACKNOWLEDGEMENTS

The authors would like to acknowledge financial support from the TargetedResearch Alliance (TRA) grant scheme, administered through the TechnologyDiffusion Program of the Commonwealth Government of Australia. Financialsupport was also provided by the Cooperative Research Centre for Coal inSustainable Development (formerly CRC for Black Coal Utilisation), which isfunded in part by the Cooperative Research Centres Program of the CommonwealthGovernment of Australia.

The authors would also like to acknowledge the assistance of the Central ResearchInstitute of the Electric Power Industry (Japan), in particular the members of theGasification Group therein, for helpful discussions and contributions. Dr Chris

Bailey (CRC for Black Coal Utilisation) is to be thanked for his input during thecompilation of this report.

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