lEA COAL RESEARCH

lEA COAL RESEARCH

Advanced power systems and coal quality


David H Scott and Anne M Carpenter

IEACR87 May 1996 lEA Coal Research London

Copyright copy lEA Coal Research 1996

ISBN 92-9029-269-5

This report produced by lEA Coal Research has been reviewed in draft fonn by nominated experts in member countries and their comments have been taken into consideration It has been approved for distribution by the Executive Committee of IEA Coal Research

Whilst every effort has been made to ensure the accuracy of infonnation contained in this report neither lEA Coal Research nor any of its employees nor any supporting country or organisation nor any contractor of lEA Coal Research makes any warranty expressed or implied or assumes any liability or responsibility for the accuracy completeness or usefulness of any information apparatus product or process disclosed or represents that its use would not infringe privately-owned rights

lEA Coal Research

lEA Coal Research is a collaborative project established in 1975 involving member countries of the International Energy Agency (lEA) Its purpose is to provide information about and analysis of coal technology supply and use The project is governed by representatives of member countries and the Commission of the European Communities

The lEA was established in 1974 within the framework of the Organisation for Economic Co-operation and Development (OECD) A basic aim of the lEA is to foster co-operation among the twenty-three lEA participating countries in order to increase energy security through diversification of energy supply cleaner and more efficient use of energy and energy conservation This is achieved in part through a programme of collaborative research and development of which lEA Coal Research is by far the largest and the longest established single project

lEA Coal Research exists to promote a wider understanding of the key issues concerning coal with special emphasis on clean coal technologies and security of supply and in particular

to gather assess and disseminate information about coal to undertake in-depth studies on topics of special interest to its members having due regard to the strategic priorities of the International Energy Agency to assess the technical economic and environmental significance of these topics to identify gaps in international research programmes to report the findings in a balanced and objective way without political or commercial bias

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3

Abstract

The effects of coal quality on the design perfonnance and availability of advanced electric power generating systems (supercritical pulverised coal firing systems tluidised bed combustors and integrated coal gasification combined cycle systems) are discussed Low rank andor low quality coals including coal wastes (anthracite culm and bituminous gob) are among the fuels considered The advanced power systems each have their own set of coal quality requirements As with conventional pulverised coal-fired systems these systems can utilise any coal but the system design may have to be modified to cope with the properties of the selected fuel

4

Contents

List of figures 7

List of tables 9 Acronyms and abbreviations 10

1 Introduction 11

2 Supercritical PC-fired boilers 12

21 Supercritica1 steam conditions and materials of construction 12 22 Design problems 13

221 Load following operation 14

222 Furnace water wall conditions 14

223 Water wall construction 15

224 High temperature corrosion 16

225 Corrosion resistant materials 17

23 Furnace exit gas temperature and coal quality 18

231 Estimation of coal fouling propensity 19

232 The control of furnace exit gas temperature 20

24 Supercritical boiler firing with low rankgrade coal 22

241 Attainment of low FEGT with lignites 22

242 Steam conditions and materials of construction 23

25 Comments 23

3 Atmospheric fluidised bed combustion 24 31 Process description 25

32 Coal rank and boiler design 25

33 Coal and sorbent feeding 26

34 Ash removal and handling 27

35 Ash deposition and bed agglomeration 29 36 Materials wastage 31 37 Practical experience with waste coals 35

38 Air pollution abatement and control 36

381 Sulphur dioxide 36

382 Nitrogen oxides 40 383 Particulates 42

5

39 Residues 43

310 Comments 45

4 Pressurised fluidised bed combustion 47

41 Process description 47

42 Fuel preparation feeding and solids handling 48

43 Ash deposition and bed agglomeration 50

44 Control of particulates before the turbine 51

45 Materials wastage 52



462 Nitrogen oxides 55

463 Particulates 56

47 Residues 56

48 Pressurised circulating fluidised bed combustion 57 49 Comments 57

5 Gasification 59

51 Commercial gasification plants 59

52 Major IGCC demonstration projects 60

53 Entrained flow slagging gasifiers 60

531 Fuel preparation and injection 60

532 Coal mineral matter and slag flow properties 62

533 Refractory lining materials for gasifiers 65

534 Metals wastage in entrained flow gasifiers 66

54 Fixed bed gasifiers 67

541 Bed permeability 68

542 Slag mobility 68

55 Fluidised bed gasification 69

551 Char reactivity and ash fusion 69 552 High Temperature Winkler (HTW) gasification process 70

56 Hybrid systems 71

561 The air blown gasification cycle 73 562 Advanced (or second generation) PFBC 74

6 Economic considerations 75 61 Costs of conventional and supercritical PC power stations 75

611 PC power stations fuelled by high grade bituminous coal 75

612 PC power stations using low rankgrade coal 78 62 Motivating factors for the use of low rankgrade coal 79

63 CFBC power generation 80

631 CFBC boilers economies of scale 80 64 PFBC boilers 81

65 IGCC 82

66 Comments 84

7 Conclusions 85

8 References 88

6

5

10

15

20

25

Figures

Limits on the use of various materials for live steam outlet headers of a 700 MW steam generator 14

2 Configuration of heating sUIiaces in a supercritical tower boiler 14

3 Top eighteen causes of forced full and partial outages for the decade 1971-1980 15

4 Coal corrosion - stable and corrosive zones 16

Sectional side elevation of boiler at Meri-Pori power station 18

6 Characteristic shapes of ash specimens during heating 19

7 Characteristics of fuel ash slagging tendency 20

8 Circulating fluidised bed boiler 25

9 Variations of heat duties of recirculating loop and backpass (percentage of total boiler heat duty) as a function of lower heating value 27

Required ash removal rate as a function of coal heating value 28

II Transformations of the coal inorganic matter in CFBC boilers 30

12 Modifications to CFBC boiler 31

13 Wear on membrane wall tubes in CFBC boilers 32

14 Added CaiS molar ratio required for increasing sulphur capture as a function of coal type 38

Added limestone required for increasing sulphur capture as a function of coal type 38

16 NOx emissions as a function of combustor temperature 40

17 NOx and NzO emissions as a function of coal type 40

18 Bed temperature effects on NOx emissions from slurry and dry coal 42

19 Solid residue generation as a function of coal type 44

PFBC ABB P200 unit 48

21 Single candle filter element 51

22 Entrained flow gasifier 61

23 Calculated and observed values for the slurryability of 20 coals 62

24 Schematic presentation of the variation of viscosity with temperature 63

Slag viscosity as a function of temperature 63

7

26 Basic concept of the CRIEPI pressurised two stage entrained flow coal gasifier 64

27 Acidbase ratio and ash fusion temperature 65

28 BGL fixed bed gasifier 68

29 Simplified diagram of the HTW gasifier 70

30 The air blown gasification cycle 73

31 Simplified process block diagram - second generation PFBC 74

32 Impact of condenser pressure on net efficiency 78

33 Effect of coal grade and boiler size on product selection 80

34 New technology cost curve 81

35 Difference in cost of electricity (COE) between similar sized PFBC and IGCC power plants and its variation with coal sulphur content 83

36 HTW system with fluidised bed dryer 83

8

5

10

15

20

25

Tables

Danish supercritical power stations 13

2 DraxEPRI probe materials compositions 17

3 Comparison of raw brown coals 20

4 Effect of platen superheaters on FEGT 21

Effects of coal properties on CFBC system design and performance 26

6 Coal ash properties (determined by ASTM mineral analysis) 33

7 Typical analysis of anthracite culm 35

8 Sorbent requirement 37

9 Analysis of the coals 38

Operational data for the PFBC plants 49

11 Ash chemical analysis of the Spanish coals 51

12 Environmental performance of PFBC plants 54

13 Coal properties and gas yield 62

14 Normalised composition of four coal slags 63

Ash and slag requirements for major gasification processes 68

16 The effect of coal washing on mineral matter analysis 69

17 Feedstocks tested for HTW gasification 71

18 The saturated vapour pressure of alkali chlorides 71

19 Alkali saturation in coal-derived gas 72

The average properties of peat coal and brown coal used in the tests 72

21 Summary of the measured concentrations of vapour phase alkali metals 73

22 Breakdown of coal-fired investment costs 76

23 Summary of levelised discounted electricity generation costs 77

24 Estimated cost of electricity for PC firing in Victoria Australia 78

The effect of coal quality on PFBC costs 82

26 Operating hours since first firing 82

9

Acronyms and abbreviations

ABGC AFBC AFf ar ASME ASTM BFBC BGL CEGB CFBC CRIEPI daf db EPRI ESP FBC FBHE FEGT FGD HHV HRSG HTW IDT IGCC KRW LHV LLB MWe MWt NOx PC PCFBC PFBC SCC SCR SNCR

air blown gasification cycle atmospheric fluidised bed combustion ash fusion temperature as received American Society of Mechanical Engineers American Society for Testing and Materials bubbling fluidised bed combustion British GasLurgi (process) Central Electricity Generating Board (UK) circulating fluidised bed combustion Central Research Institute of the Electric Power Industry (Japan) dry and ash-free dry basis Electric Power Research Institute (USA) electrostatic precipitator fluidised bed combustion fluidised bed heat exchanger furnace exit gas temperature flue gas desulphurisation higher heating value heat recovery steam generator High Temperature Winkler (process) (ash) initial deformation temperature integrated gasification combined cycle Kellogg Rust Westinghouse lower heating value Lurgi Lentjes Babcock Energietechnik GmbH megawatt electric megawatt thern1al nitrogen oxides (NO + N02) pulverised coal pressurised circulating fluidised bed combustion pressurised bubbling fluidised bed combustion stress corrosion cracking selective catalytic reduction selective non catalytic reduction

10

1 Introduction

This report is concerned with the coal quality requirements for advanced electric power generating systems and the impact that their wider adoption might have on the utilisation of coal resources The systems considered are not yet generally used by utilities but have been demonstrated at or near utility scale for electricity production The rise of the new generation of supercritical pulverised coal-fired power stations is considered because although they are an extension of a long established technology they provide performance parameters against which other developments are judged The technology is also included in its own right because it is evolving with the promise of further performance improvements Although fluidised bed combustion (FBC) and coal gasification are long established processes they have only been deployed for electricity generation as relatively small units in the case of FBC and as subsidised demonstration units in the case of integrated gasification combined cycle (IGCC) Hybrid combustiongasification systems are discussed briefly as extensions to existing IGCC and FBC technology

The commercial evaluation of developing technologies is problematic and potentially contentious Some commercial aspects are discussed in this report because they are inseparable from the question of coal quality requirements TIle low cost of electricity from conventional power stations is partly based on the widespread availability of economically priced coal of acceptable quality It is also based on the reduction of capital and operating costs by a long process of research and development reinforced by accumulated operating experience A detailed knowledge of the coal quality requirements of the process is a fundamental part of that accumulated experience Ideally the facility to use coals of a range of qualities widens the utilities choice of coal suppliers However the delivered price of the coal is only one of the factors affecting its impact on the cost of electricity from the power station Aspects of the quality of a

given coal may militate against clean safe reliable and economical operation of a pulverised coal (PC) fired boiler Coal quality affects boiler efficiency availability and maintenance costs A PC power station can be designed to allow the properties of a difficult coal to be accommodated but this may involve increased capital expenditure as well as increased operating costs Since the cost of transporting coal can be a considerable part of its total delivered cost economic considerations tend to limit the use of coals with less desirable qualities to the locality of the mine In consequence a relatively narrow range of high grade medium rank bituminous coals is traded internationaJly as thermal coal

In some regions legislation designed to protect the environment may preclude the use of locally available low quality low cost coal through a lack of affordable pollution control technology In consequence such fuels and the by-products of coal beneficiation may appear to be worthless although they have appreciable potential heat content At other locations socioeconomic considerations have compelled the use of low ranklow grade coals without adequate environmental control The unpleasant environmental consequences that have resulted have been widely reported Proponents of clean coal technologies such as FBC and IGCC have suggested that the technologies widen the range of usable coals because their coal quality requirements are different from those of PC boilers However these technologies have their own quality requirements and as with PC systems there wiJl be cost and availability implications if inappropriate fuels are used

Opportunities for the more effective utilisation of solid fuel resources are considered in this report together with some of the effects of coal quality on the design performance and availability of advanced power systems

11

2 Supercritical PC-fired boilers

This chapter is concerned with the impact of coal quality on the design and operation of supercritical boilers The design of PC-fired supercritical boilers is strongly int1uenced by the properties of the coals that are commercially available and in future the commercial value of available coals may be int1uenced by their suitability for supercritical boilers

The development of power station technology was driven by the need to reduce the cost of electricity During the first 60 years of the 20th century economies of scale and improved efficiency resulted in a fall in the cost of electricity in the USA from 300 UScentkWh in 1900 to around 5 UScentkWh in 1960 (1986 UScent) By 1960 the average efficiency of US utility power stations had levelled off at around 33 HHV (35 LHV) for the average plants and around 40 HHV (42 LHV) for the best plants (Hirsch 1989) More recently the requirement to minimise the environmental impact of power generation has also been an important consideration Increasing the thermal efficiency of a power station other things being equal can provide more electricity without a corresponding increase in pollution Specifically for a given fuel increased efficiency is the only currently practicable means for increasing power generation without increasing C02 emissions

Comprehensive descriptions of the design and construction of modern power station boilers including supercritical boilers are provided by books such as Steam its generation and use (Stultz and Kitto 1992) Aspects of boiler technology are discussed in this chapter because coal quality impact and boiler design are interrelated topics There is a considerable body of knowledge on the coal quality requirements for conventional PC boilers This knowledge has been incorporated into a number of computer models that allow semi-quantitative estimates to be made of the effect of coal properties on boiler efficiency and operating costs (Carpenter 1995 Couch 1994 Skorupska 1993) Similarly the control of pollution from PC boilers has been thoroughly discussed in other lEA Coal Research reports (Hjalmarsson 1990

Hjalmarsson 1992 Morrison 1986 Soud 1995 Takeshita and Soud 1993) For the purposes of this report the coal quality requirements for subcritical boilers are assumed and the topics discussed relate to the additional requirements of supercritical boilers

21 Supercritical steam conditions and materials of construction

Many factors affect the efficiency of a power station but in later years the main route to higher efficiency was through increased steam temperatures and pressures Increasing the main and reheat steam temperatures by 20 K improves efficiency by about 12 (05 percentage points) and increasing the main steam pressure by 1 MPa improves efficiency by 01-03 (approximately 01 percentage points) (Billingsley 1996) In conventional boilers the water is heated under pressure in the water cooled walls that form the furnace enclosure The heated water passes to a drum that is designed to separate water and steam The water is recirculated and the steam is superheated in the convective section of the boiler before passing to the turbine The boiling point of water increases with increasing pressure up to its critical pressure of 221 MPa If the temperature of water is increased at a pressure in excess of its critical pressure the water does not boil in the conventional sense It acts as a single phase t1uid with a continuous increase of temperature as it passes through the boiler The change in water properties and the high temperatures and pressures involved in supercritical operation have fundamental implications for the design of boilers operating in this region

In the 1950s and the 1960s the first generation of supercritical power stations were built in Germany the UK and the USA Philadelphia Electric Companys 350 MWe Eddystone I plant which was commissioned in 1958 had design steam conditions of 344 MPa main steam pressure 649degC main steam temperature and two reheat stages each to

12

Supercritical PC-fired boilers

566degC (344 MPal694degC566degc566degC) The need for high creep resistance under these conditions led to the use of thick section austenitic stainless steels for pressure containing parts such as the main steam pipelines and valves The radiant boiler surfaces which in modem construction are low alloy steel water walls were also of austenitic stainless steel However austenitic stainless steels are highly susceptible to thcrmal fatigue and progressive damage because of their low thermal conductivity and high thermal expansion in comparison with ferritic steels (Metcalfe and Gooch 1995) The design efficiency of Eddystone was 43 HHV (45 LHV) but due to boiler tube failures the station had to be derated giving an efficiency of 4] HHV (Pace and others ]994) Supercritical power stations built subsequently in the USA had unit capacities up to 760 MWe but generally used less extreme steam conditions (sing]e reheat 24-26 MPa with main and reheat temperatures around 540degC (IEA Coal Research ]995a)

In the 1970s changing economic conditions in the USA resulted in their supercritical power stations designed as base load units being used for load following operation With the high temperatures and pressures already making severe demands on their austenitic components the additional stresses of cyclic operation led to availability problems Negative experiences with the first generation of supercritical power stations in the USA led to a retreat to subcritical power stations with lower thermal efficiency but which through lower capital cost and greater availability appeared to offer a better investment prospect (Scott 1991) German experience with supercritical boilers was more favourable because the units were mostly small laquo500 th of steam) base loaded industrial boilers (Waltenberger ]983)

Research and development work on advanced steam cycles continued With increasing emphasis on environmental protection adding impetus to the drive for increased efficiency it is now recognised that it is necessary to use ferritic alloys for the major thick section components New supercritical power stations have been built taking advantage of advances in metallurgy and parallel improvements in computerised control systems In 1979 utilities in Jutland and Funen western Denmark started a programme of supercritical power station construction Elsam jointly owned by utilities in Jutland and Funen provided overall

Table 1 Danish supercritical power stations (Kjaer 1990)

coordination Table 1 shows the steam conditions for the Jutland supercritical power stations and the efficiencies achieved under Danish conditions (coastal sites with access to cold sea water)

The twin 350 MWe supercritical units Studstrupvrerket 3 and 4 were commissioned in 1984 and 1985 respectively A series of installations followed The construction of the 400 MWe Nordjyllandsvrerket at Alborg is now underway and commissioning is scheduled for 1998 A PC-fired ultra supercritical power station with a net efficiency of 50 LHV might be in operation by the year 2005 (Kjaer 1994) Elsam RampD Committee together with leading boiler and turbine manufacturers and a number of utilities in Europe are supporting an European Union Thermie B action Strategy for the Development of Advanced Pulverised Coal-fired Plants The goal of the project is to prove the technology for the construction of an ultra supercritical plant with a steam temperature of 700degC a steam pressure of 375 MPa and a net electrical efficiency of 52 LHV by the year 2015 (E]sam RampD Committee 1994) Such progress will require a considerable research and development effort Far more research is needed on the boiler side to construct a boiler which can feed steam into the advanced turbines(Blum 1994) However an efficiency of 52 LHV should not be regarded as the ultimate goal for PC-fired power stations Elsam RampD Committee believe that higher efficiencies are achievable (Luxh0i 1996)

22 Design problems The design of the later generation of supercritical units had to provide solutions for the problems of the first generation units and solve new problems Among these problems

load following operation caused failure of thick walled components Thermal cycling and frequent transition from subcritical operation with forced water circulation to supercritical straight through operation caused additional stresses to be imposed on the boiler tubes furnace water wall conditions In early supercritical boilers the heating and gas containment functions were separate Refractory bricks were used to enclose the furnace and water tubes provided the heat exchange In later boilers the functions of heat exchange and

Unit Studstrupvccrket Fynsvrerket 7 Esbjvrerket 3 Nordjyllandsvrerket

3 and 4

Gross generator output MW Net generator output MW Coal flow kgs (LHV 266 MJkg) Net efficiency LHV Final feedwater temperature degC Main steam pressure MPa Main steam temperature DC Condenser pressure kPa

375 352 315 429 260 25 540 27

410 384 324 444 280 25 540 27

407 383 312 461 275 25 560 23

406 382 298 471 300 285sect 580

23~

without flue gas desulphurisation plant (FGD) sect revised from 30 MPa to 285 MPa (Kjaer 1993) t revised from 481 to 47 (Kjaer 1993) ~ revised from 21 kPa to 23 kPa (Kjaer 1993)

13


containment were combined by the use of membrane walls The materials of construction of the fluid cooled membrane wa]]s are barely adequate for supercritical duty high temperature corrosion With some coals ash deposition can cause rapid high temperature corrosion of superheater tubes This problem becomes more severe as superheat temperatures are increased

221 Load following operation

The design of many modem power stations must provide for intermittent operation and for rapid load changes during operation Due to the high steam outputs of modem power stations large diameters are needed for components such as the superheater outlet header Since these components are also subjected to high thermal stress thick walls are required to confer the necessary strength Thick walled components have to be heated and cooled carefully to avoid incurring damaging stress by differential expansion This requirement conflicts with the need for rapid load changes The disadvantages of austenitic stainless steels in such applications led to the retreat in steam conditions to the temperaturepressure limits of the ferritic steel X20CrMoV 12 (F12) The Kawagoe gas-fired supercritical power station of Chubu Electric Co Japan is designed for daily start-up and shut-down It is also designed for an emergency rate of load change of 7minute and a normal rate of 5minute at 50 output or more The design of Kawagoe addressed the problem of temperature limitations of F12 by the pioneering use of XI0CrMoVNb91 (PT91)

PT91 was the first in a new generation of 9-12 Cr ferritic steels which were developed with international cooperation at Oak Ridge National Laboratories in the USA Figure 1 shows the design temperature strength relationship for P91 (ASTMASME standard for XI0CrMoVNb91 piping) in comparison with F12 and an austenitic steel (Rukes and others 1994)

The P91 properties are adequate to cope with the steam conditions that can be produced by current PC-fired boiler technology a steam pressure of 25 MPa and a steam temperature of 590degC or a steam pressure of 35 MPa and a steam temperature of 565degC or any combination of

CIl 0 E ID c 15 2 0 ] c

1il i [lgt J () () Q)

0 E 25 -t----- --- -----_---CIl Q)

(jj __---L ----__------__-----__----L L-_

525 550 575 600 625 650 Steam temperature at inlet of turbine degC

Figure 1 Limits on the use of various materialS for live steam outlet headers of a 700 MW steam generator (Rukes and others 1994)

temperature and pressure on the straight line between those two points Although the ferritic steels cannot match the creep resistance of austenitics at the highest temperatures their fatigue resistance at lower temperatures makes them preferable for the construction of thick walled components outside the boiler enclosure Any further development in steam conditions would require one of the successors of P91 that are currently being proved It would also require the development of new materials of construction for the boiler because of the coal quality related problems of the furnace water walls and the high temperature superheater tubes

222 Furnace water wall conditions

The furnace and convection sections of modern boilers are contained by continuous membrane walls that form a gas-tight enclosure The walls in the furnace section of the boiler are cooled by boiling water (subcritical operation) or by high velocity supercritical water They absorb radiant energy from the flames and cool the gases before they enter the convective section of the boiler Figure 2 shows the configuration of the heating surfaces in a supercritical tower boiler

The service conditions of the water walls are particularly arduous in the middle region immediately above the burners At this point the flue gases are at their hottest and the rate of

economiser

reheater 1

superheater 2

reheater 2

superheater 3

superheater 1support tubing

vertical tubing tube 318 mm x 63 mm

spiral-wound or vertical tubing tubes 38 mm x 63 mm

Figure 2 Configuration of heating surfaces in a supercritical tower boiler (Rukes and others 1994)

14


1 Waterwalls

Superheater

Pulveriser

4 Boiler feed pump

Boiler general

Reheater first

7 Vibration of turbine generator

8 Buckets or blades

9 Feeder water heater leak

Economiser

Induced draft fan

Forced draft fan

Lube oil system turbine generator

Generating tubes

Stator windings

Furnace slagging

Main turbine generator

Control turbine amp slop valves

o 100 200 300

Lost power production GWh (shaded areas are possibly coal related)

Figure 3 Top eighteen causes of forced full and partial outages for the decade 1971middot1980 (Folsom and others 1986)

12

13

14

15

17

18

heat transfer to the walls is of the order of 270 kWm2 (Stultz and Kitto 1992) The walls are attacked by corrosive flue gas from the fire side and by the cooling water from the water side The flue gases also contain erosive particulates derived from the mineral matter in the coal and these may damage the water walls as well as downstream convective surfaces In view of their arduous conditions of service and their considerable area it is not surprising that a survey mainly of subcritical boilers and using 1970s data from US boilers found that water wall tube failures were the greatest single cause of boiler downtime (see Figure 3)

The relevance of these data to modern practice has been reduced by advances in quality control during manufacturing and improved understanding of feed water chemistry However they do serve to illustrate the arduous and critical role of the furnace water walls

223 Water wall construction

The water walls are made by welding tubes together with flat bars to form continuous panels that are gas-tight and rigid If

high alloy steels were used for these assemblies it would be necessary to anneal them after fabrication or repair If this were not done the stresses created by welding would encourage cracking and early failure The practical impossibility of annealing such large assemblies has effectively limited the materials of construction to carbon steel or low alloy steel The temperature of the flue gas leaving the furnace and entering the convective section of the boiler must be controlled to mitigate fouling problems with the first convective heating surfaces (see Section 23) The desire to design a steam generator to fire a wide range of different coals leads to the specification of a relatively low furnace exit gas temperature (FEGT) (Lemoine and others 1993)

The maximum service temperature of the low alloy steels used in waterwall construction places an upper design limit on the temperature of the fluid cooling the membrane walls The best steel that is currently proven for boiler waterwall construction is the low alloy steel 13CrM044 If this is used conventional design codes allow a maximum design fluid temperature of 435degC for 38 mm outside diameter tubing

15


with a wall thickness of 63 mm (Lemoine and others 1993) The design temperature incorporates an allowance for a small temperature rise in service With correctly conditioned boiler feedwater a protective layer of magnetite scale forms on the waterside surfaces of the tubes The formation and slow growth of this scale prevents more rapid corrosion but it hinders the removal of heat from the tubes by the cooling water As a result the metal temperature slowly increases during operation of the boiler For clean tubes if the maximum watersteam temperature at the outlet of the water walls is 420degC the tube wall material is subjected to a mid-wall temperature of about 450degC After 100000 h of service the mid-wall temperature will have increased to about 455degC (Blum 1994) As the operating pressure of a boiler is increased a number of factors combine to expose the limitations of the materials currently available for waterwall construction

for maximum thermodynamic efficiency the temperature of the feedwater to the walls should increase with increasing pressure (Eichholz and others 1994 Horlock 1992) the rate of growth of the waterside scale increases with increasing temperature the maximum design temperature of the metal decreases with increasing pressure the specific heat of water decreases with increasing pressure

As steam conditions are increased the net effect is to reduce the proportion of the heat that can be absorbed in the furnace section without shortening the service life of the boiler through overheating the water walls Research continues to develop higher specification materials for water walls (see

Section 232) but parallel advances in other materials will permit higher steam conditions

224 High temperature corrosion

The tubes in the boiler that operate at the highest metal temperatures are the superheat tubes and the reheat tubes These tubes are subjected to corrosion from the inside by the steamsupercritical water and from the outside by corrosive species in the flue gas and by corrosive fouling deposits The naturally coarse grained nature of austenitic stainless steel makes it vulnerable to attack from hot water by intergranular corrosion However the grain structure can be modified by heat treatment or by work hardening Shot blasting is said to be particularly effective (Ishida and others 1993)

High temperature corrosion of the outside of the tubes is related to properties of the coal and its mineral matter content Serious external wastage or corrosion of high temperature superheater and reheater tubes was first encountered in coal-fired boilers in 1955 The boilers concerned were burning coals from Central and Southern Illinois USA that contained high concentrations of alkali chlorine and sulphur They were also among the first boilers to be designed for 565degC main and reheat temperatures with platen superheaters Early investigations showed that the corrosion was found on tube surfaces beneath bulky layers of ash and slag The deposits largely consist of Na3Fe(S04)3

and KAI(S04h although other complex sulphates were thought to be present At first it appeared that coal ash corrosion might be confined to boilers burning high alkali coals but a similar pattern of corrosion occurred on superheaters and reheaters of several boilers burning low to medium alkali coals Where there was no corrosion the complex sulphates were either absent or the tube metal temperatures were moderate (less than 593degC) The general conclusions drawn from the survey were that

all bituminous coals contain enough sulphur and alkali to produce corrosive ash deposits on superheaters and reheaters and those containing more than 35 sulphur and 025 chlorine may be particularly troublesome and the corrosion rate is affected by both tube metal temperature and gas temperature Figure 4 shows the stable and corrosive zones of fuel ash corrosion as a function of gas and metal temperatures (Stultz and Kitto 1992)

Laboratory studies showed that when dry the complex sulphates were relatively innocuous but when semi-molten (593-732degC) they corroded most of the alloy steels that might be used in superheater construction The rate of corrosion followed a bell shaped curve reaching a maximum at a metal temperature of approximately 680-730degC and then declining (Stultz and Kitto 1992) The elements of the complex sulphates are derived from the mineral matter present in the coal The elements cited as contributing to high temperature corrosion were iron chlorine sulphur sodium potassium and aluminium (Heap and others 1986)

1400

1300

Corrosive zone

1200

1100

Stable 1000 zone

900

600

Metal temperature degC

500 550

Figure 4 Coal corrosion - stable and corrosive zones (Stultz and Kitto 1992)

650

16


The contribution of all the listed elements except chlorine is evident from the formulae of the corrosive complex sulphates Various theories have been advanced about the state of existence of chlorine in coal and its interaction with sodium and potassium There is a broad consensus that when the coal is heated chlorine is released as gaseous HCI (Chou 1991 McNallan 1991 Sethi 1991) Latham and others (1991) suggest that HCI releases sodium and potassium from the coal ash and under oxidising conditions with S03 present sodium and potassium chlorides are converted to the sulphates Research reported by McNallan (1991) suggests that chlorine may also have a more direct effect on high alloy components The critical difference between chlorine and most other oxidising species is that chloride and oxychloride corrosion products are usually volatile or liquid at high temperatures The stable oxide layer that passivates refractory alloys can be attacked by chlorine and this attack is accelerated by the presence of C02 Hence many alloys fail to form protective scales in the presence of chlorine and cOITode rapidly with linear kinetics Because the corrosion products are volatile chlorine may be undetectable on the corroded specimens and so its contribution to the corrosion mechanism may not be apparent

UK experience with high chlorine British coals led to the conclusion that there was a positive linear correlation between increasing coal chlorine content and the rate of high temperature corrosion (Gibb and Angus 1983 Latham and others 1991) However the interpretation of these data and their widespread application to non UK coals has been questioned In a report from the Chlorine Subcommittee of the Illinois Coal Association Abbott and others (1994) argued that the positive correlation established for British coals is not necessarily valid for other coals Wright and others (1995) recommended a three point plan to improve understanding of the relative effects of chlorine sulphur and alkali metal species on the potential of a coal to cause fireside corrosion namely to

revisit CEGB experience to determine the conditions under which the reported effects of chlorine on corrosion occurred examine field exposures in US boilers to measure the

relative corrosion rates for a range of US chlorine containing coals perform tests in small scale burner rigs to examine the influence of chlorine sulphur and alkali metal species under more tightly controlled conditions than is possible in an operating boiler

225 Corrosion resistant materials

Since the 1960s the UK CEGB and more recently National Power have been conducting corrosion probe trials at a number of subcritical power stations in the UK In the 1970s and early 1980s tests carried out at Drax power station in Yorkshire UK (now owned by National Power) identified improved superheater materials to extend tube lifetimes up to 250000 h Drax comprises six 660 MWe units with main steam conditions of 167 MPal568degC and reheat conditions of 4 MPal568degC Both the platen and final superheaters were made originally of austenitic stainless steel (Esshete 1250) (CEGB 1986) Samples of various materials were exposed for 2000-3000 h at 600-700degC in the boiler flue gas adjacent to final superheaters and reheaters The data from the tests were partly responsible for the installation of substantial quantities of co-extruded tubing into final stage superheaters and reheaters of 500-660 MWe units operating in the UK Esshete1 250 was used as the inner load bearing alloy which provided the requisite high temperature creep resistance The corrosion resistant cladding was either 25Cr20Ni steel (T310) or 50Cr50Ni alloy (Incoloy 67) (Latham and Chamberlain 1992) The T31 0 material reduced the corrosion rate by a factor of approximately three Incoloy 67 gave a more than tenfold reduction but high initial cost is a deterrent to its more general use (Latham and others 1991)

In November 1988 a new set of tests commenced at Drax in a cooperative programme with the Electric Power Research Institute (EPRI) USA EPRI were planning a programme of tests in the USA to cover a range of coal compositions but no high chlorine coal was included Since it was planned to burn a coal at Drax with a mean chlorine content of approximately 04 the UK programme effectively extended the range of the US programme Table 2 shows the range of alloys assessed in the joint programme

Table 2 DraxiEPRI probe materials compositions (Latham and Chamberlain 1992)

Alloy Cr Ni Fe Mn Mo Nb N Al Ti V

Incoloy 67 48 52 05

Cr35At 35 45 bal 01

Cr30Asect 30 48 bal 20 03 03

T310 25 20 bal 10 HR3q 25 20 bal 10 05 03 4002 20 33 bal 35 05

NF7091 20 25 bal 15 03 02 Esshetc 1250 IS 10 bal 6 10 10 03

T91 9 bal 03 10 01 005 02

well characterised control alloys ~I a high strength version of T310 -1shy corrosion resistant cladding alloy for co-extruded tubing a cladding alloy for tluidised bed combustors sect potential superheater tubing material t a high strength 20Cr25Ni developed in Japan

17


The corrosion resistance ranking order for the materials was consistent throughout the tests Incoloy67 Cr35A Cr30A T310 HR3C Esshete 1250 T91 The tests demonstrated the importance of forming and maintaining a chromium oxide film to prevent the onset of fireside corrosion of superheater materials Of the materials subjected to the full 10000 h test exposure only those with the highest chromium contents gave low corrosion rates throughout The alloy 4002 perfomJed well but was only exposed for 5000 h Confirmation of its initially promising performance would require further tests The other alloys with a chromium content of 20-30 initially fomJed a protective film but when this broke down the layer did not re-fom and pitting attack with sulphide penetration occurred The alloys with less than 20 chromium did not appear to form a protective film at all and general attack around the fireside front was present in all the test specimens It was concluded from these tests using a subcritical boiler firing high chlorine coal that the best material for coal-fired supercritical boilers appeared to be a co-extruded tube with an outer layer of 5000Cr50Ni or 35Cr45Ni (Latham and Chamberlain 1992)

Experience has shown that it is possible to operate boilers with main and reheat temperatures below 566degC with little if any high temperature corrosion from most coals It has also been found that for the present generation of supercritical boilers (560degC main steam 649degC reheat) austenitic stainless steel can give adequate high temperature corrosion resistance where the coal specification is for a maximum sulphur content of I and a maximum chlorine content of O 1 (Ishida and others 1993) However these quality constraints would exclude many coals and the developments in steam conditions envisaged for supercritical boilers take superheater conditions into the corrosive zone and up the bell curve towards the maximum rate of cOlTosion The highest metal temperatures envisaged are for the 325 MPal625degC ultra supercritical boiler which would have a metal temperature in the superheaters of about 660degC (Blum 1994) Boiler designers have only limited data on the high temperature corrosion resistance of the new high temperature boiler alloys in supercritical boilers Elsams 25 MPal560degC supercritical plants use TP347H (18 Crll 0 Ni) steel for their superheaters The improved fine grained TP374HFG version will be used for their new 29 MPal580degC units to meet the need for increased water side corrosion resistance It has been argued that correlations suggesting a role for chlorine in high temperature corrosion have been largely derived from UK CEGB experience The CEGB units were firing British coals with an analysis atypical of internationally traded coals (Abbott and others 1994) Re-examination of the UK work and further basic research on the role of chlorine in high temperature corrosion might help to resolve these problems (Abbott 1995)

23 Furnace exit gas temperature and coal quality

FEGT is an important parameter because it strongly influences the condition of the fly ash entering the convective section of the boiler The convective zone begins where the

heat exchange surfaces are effectively screened from direct radiation from the furnace fireball By convention the location of the border between radiant zone and convective zone is decided by the geometry of the boiler Figure 2 shows the arrangement of surfaces in a typical single pass tower boiler The other main category of boilers is the two pass boiler Figure 5 is a sectional side elevation of the supercritical two pass boiler at Meri-Pori power station Finland

In the case of the tower boiler the furnace exit is the horizontal plane through the support tubes For the two pass boiler the furnace exit is conventionally taken to be the vertical plane from the tip of the boiler nose the projection which narrows the cross section of the furnace as the gases tum to meet the final superheater It should be noted that by these definitions the platen superheater (secondary reheat) is in the radiant section of a two pass boiler while the secondary reheat surface of a tower boiler is in the convective section However tower boilers may also be equipped with pendant superheat surfaces suspended from the support tubing

During combustion the coal particles reach temperatures in the region of 1400degC to 1700degC At these temperatures most of the ash species present melt or soften (Boni and Helble 1991) If the molten ash particles stick to the water walls the resulting slag deposits may seriously interfere with the operation of the boiler For this reason the furnace enclosure is an empty box designed to avoid particle impingement on

Separator vessel

Outlet reheater

Final superheater Platen superheate

Circulating pump

Over air ports

Primary superheater

Over air ports

B

duct ---H=lt- Gas recirculation

Figure 5 Sectional side elevation of boiler at Meri-Pori power station (Jesson 1995)

18


the walls The height cross section and heat exchange area of this box are sized to ensure that combustion is essentially complete and the gas is sufficiently cooled before it enters the convective section The convective section of the furnace is crossed by heat exchange tubes If the gas temperature at the beginning of the convective section is too high the fly ash particles will still be molten and sticky when they encounter the tubes Sticky particles forming an initial deposit on clean tubes may create a surface that favours further deposition As the deposit thickens the temperature of its outer surface increases by some 30-100degClmm depending on its thermal conductivity and the local heat flux With increasing temperature the viscosity of any liquid phase decreases This increases the stickiness so that more fly ash particles are retained when they impinge The deposit tends to consolidate by sintering and sulphation (Couch 1994) Because of the location where this effect occurs it is usually referred to as fouling (the accumulation of deposits in the convective sections of a boiler) However because the softening point of the ash is an important factor affecting formation of the deposit the high temperature fouling propensity of coals is related to their slagging propensity Some of the undesirable effects of fouling are

reduction of heat transfer compared with a clean tube heat transfer can be reduced to a half in one hour and to a quarter in 24 hours Reduction of heat transfer in one part of the furnace leads to increased temperature in subsequent parts of the furnace and can result in sintering and consolidation of deposits there increased rates of corrosion or erosion These can either be direct effects of ash deposition or due to increased

soot blowing operations aimed to remove the ash The subject of high temperature corrosion of convective surfaces is discussed further in Section 224

An excessive FEGT is clearly detrimental but the definition of excessive depends on furnace conditions and the properties of the coal

231 Estimation of coal fouling propensity

Measurements of ash fusibility are widely used as an aid to assessing the maximum FEGT The preferred method for determining ash fusibility in the USA is described in ASTM Standard D 1857 Fusibility of coal and coke ash The ISO Standard 540 Solid mineral fuels - Determination of fusibility ofash - High temperature tube method and the German DIN 51 730 Bestimmung des Asche-Schmelzverhaltens are essentially similar A sample of ash is moulded into shape having sharp edges (ISO and DIN) or a sharp point (ASTM) and heated in a furnace The atmosphere in which the specimen is heated may be oxidising or reducing The temperature at which the ash softens sufficiently for the point or an edge to become visibly rounded is recorded as the initial deformation temperature (IT) As the temperature is further increased slumping of the specimen is observed and the hemisphere temperature and the flow temperature give an indication of the viscositytemperature characteristics of the ash (see Figure 6)

In addition to the shapes recorded in the ISO and DIN tests the American standard recognises a point between the IT and the hemispherical temperature This point where the cone

Height Height Height = width = width2 lt16 mm

o Initial Softening Hemispherical Flow deformation point temperature temperature

ASTM test

Height =width2

ISO and DIN tests Initial Hemispherical Flow deformation temperature temperature

Height =D D 13 original height

Increasing temperature

Figure 6 Characteristic shapes of ash specimens during heating

19


has slumped to a hemispherical lump in which the height is equal to the width of the base is called the softening temperature When not otherwise specified an ash softening point quoted in the USA usually refers to the temperature detennined under reducing conditions (Stultz and Kitto 1992) The temperatures dete~ined under oxidising conditions are appreciably higher As a rule the ffiGT is selected so that it is approximately 50degC below the ash softening point of any coal to be used in the furnace (Heie~ann and others 1993 Lemoine and others 1993) However Rukes and others (1994) argued that the use of 10w-NOx combustion systems in association with finer grinding and improved combustion control reduced fouling in the high flue gas temperature areas For the coals they used the customary temperature of 1300degC for the flue gas immediately upstream of the support tubing can be increased to l350degC

Although ash fusion temperature has been widely used for many years as a guide to specifying FEGT it is not the sole indicator The ash fusion test is essentially an empirical indication of slaggingfouling propensity The laboratory processes for preparing and testing ash samples are fundamentally different from the processes that take place within a boiler More recently investigators have recognised the importance of mineral matter composition and distribution within the parent coal particles as a better indicator of a coals slagging and fouling behaviour (Skorupska 1993) In addition to the results of laboratory tests the choice of an optimum ffiGT may be strongly influenced by practical experience of the behaviour of the coals in question in similar applications This is illustrated by the account by Schuster and others (1994) of the selection of ffiGT for a new series of supcrcritical brown coal-fired boilers to be built for Vereinigte Energiewerke AG (VEAG) in central and eastern Germany (see Section 24) The new units will use the medium to highly slagging brown coals from HalleLeipzig and lower Lausatia Planning of the new supercritical power stations involved careful assessment of the combustion fouling and slagging properties of the local brown coals Table I presents outline data on these coals together with the properties of Rhenish brown coal

The design team had the advantage of practical experience with the east German and Rhenish brown coals It is known that some east Ge~an brown coals show a high propensity for causing slagging This is ascribed to the presence of ironsulphur compounds and high CaO content which can lead to the formation of low melting eutectics A triangular diagram was used to give an approximate assessment of the slagging propensity of the coals based on their silica-free ash analysis (see Figure 7)

Test burns using existing 210 MWe units provided further info~ation on the performance of the brown coals This comprehensive process of assessment of the slagging qualities of the brown coals led to the recommendation that the design ffiGT for the new boilers should be 950 to 980degC (Schuster and others 1994)

For power stations burning the more widely used bituminous

~~SffimiSOO~~IY~OOdl~O_O_C__T_h_e~d_e_Si_g_n_ffi_G_T bo

Table 3 Comparison of raw brown coals (Schuster and others 1994)

Rhineland Lower Lausatia Leipzig area

LHV MJkg 69-97 80-85 105-115 Ash 3-12 5-12 6~1O

Water content 50-62 51-57 50-52 SUlphur content 02-09 05- 15 17-21

0406

06

02

Figure 7 Characteristics of fuel ash slagging tendency (Schuster and others 1994)

for the new 700 MWe VEBA power station in Gelsenkirchen-Hessler Ge~any is l250degC to correspond with the ash softening point of the coal (Eichholz and others 1994) Raising the outlet temperature of the flue gas from 1250degC to 1300degC drops the water wall temperature by approximately 15degC but involves having to accept a substantial reduction in the range of usable coals (Weinzierl 1994)

232 The control of furnace exit gas temperature

Current state of the art steam conditions are determined by the ASTMASME P9l piping specification and the corresponding T9l tube specification Both of these are specifications are based on the performance of X1OCrMoVNb 91 Hence the abbreviations P9l and T9l which properly refer to the standards are used in the literature to refer to the metal Construction of thick walled components outside the boiler from PT9l allows steam conditions of 325 MPal571 dc The development of water wall materials has been overtaken by these conditions Maximum water wall temperature conditions determined by the limitations of 13CrM044 require compromises to be made in boiler design to control FEGT A number of measures can be taken to reduce FEGT but they can have

a_tt_ffi_d_a_n_t_d_is_a_d_~_n_t_~~e_s_ _

08 06 04 CaO+MgO+S03

08


Superheater panels can be hung in the hot furnace gas These pendant panels can be supported from the top of a two pass boiler or from support tubing in a tower boiler Wide spacing between the panels encourages self cleaning but the panels are exposed to high gas temperatures corrosive sticky ash and erosion by refractory particles in the ash However there is a considerable body of experience in the use of pendant panels As the steam conditions in subcritical two pass boilers in the USA and UK approached supercritical steam conditions it was necessary to use pendant superheat surface known as platen superheaters to satisfy the increasing proportion of heat exchange required for superheat Experience gained from these applications was used in the design by Babcock now Mitsui Babcock Energy Limited (MBEL) of the platen superheaters for Meri-Pori supercritical power station Table 4 lists some of the later power stations where this technology has been used

Keeping the tubes clean depends on giving sootblower steam jets good access to the deposits and detailed design is important in this respect With some types of ash special measures are needed to control tube alignment Membraned platen tips were first introduced in 1983 at the Matala power station in the Republic of South Africa This feature was needed because a particularly difficult coal ash led to uncontrolled deposits which caused platen tube distortion In view of the operating temperature and parent tube material a 225 chrome membrane material was specified and in consequence post weld heat treatment was required Only a limited number of the outer tubes in each clement are actually joined by membrane but the technique was totally successful at Matala and has now become part of MBELs current standard for platen superheaters (Jesson 1995)

FEGT may also be controlled by recirculating gas from a cooler part of the boiler The recirculation of flue gas may not detract from the thennodynamic efficiency of the boiler but the considerable energy consumption of the recirculation fan may reduce net electricity output The 400 MWe Nordjyllandsvierket supercritical units are equipped for flue gas recirculation Flue gases are removed after the electrostatic precipitators and returned to the boiler through a

separate duct in the regenerative air heater Flue gases can enter the boiler through the over burner air ports immediately above each burner or through the over fire air openings above the combustion zone The main purposes of the recirculation system are to control the outlet temperatures of the intennediate pressure steam during part load conditions and to protect the water walls in the combustion chamber during oil-firing However it is also possible to use this system to cool the flue gas when firing coal of low ash softening temperature (Kjaer 1994)

If producing a requisitely low FEGT results in an excessively high water wall temperature the water wall temperature may be reduced by reducing the feedwater temperature Unfortunately optimum thernl0dynamic efficiency requires the reverse as steam temperature and pressure increase the feedwater temperature should also increase For the earlier supercritical power stations the feedwater temperature was around 275dege For the more advanced steam conditions of 275 MPal580degc580degC Eichholtz and others (1994) found that the highest thermodynamic efficiency was obtained by preheating the feedwater to 31 Odege Taking account of the limitations of the water walls with a required FEGT of 1250degC they were obliged to limit the feedwater preheat to 300dege On the basis of past experience the maximum FEGT for boilers in the Saar area of Germany had been set at 1150dege The design study for the new Bexbach II supercritical boiler showed that the FEGT would have to be increased to 1200degC although this involved the abandoning of existing safety margins It was estimated that for the Bexbach unit if the FEGT was 1200degC the maximum feedwater temperature would have to be limited to 290degC (Bi1Iotet and ]ohanntgen 1995) However the additional preheating of the feedwater for supercritical conditions is obtained by extracting heat from the high pressure turbine This results in some costly additions to the unit including increased high temperaturehigh pressure heat exchange surface Rukes and others (1994) have suggested the saving in operating costs through higher efficiency may be insufficient to justify the additional capital expenditure (see Section 61) They concluded that a feedwater temperature of approximately 275degC would give the lowest cost of electricity

Table 4 Effect of platen superheaters on FEGT (Jesson 1995)

Boiler start-up Number and Platen inlet FEGToC Ash lOT degC date size of units MWe temperature DC

Mcri-Pori Finland 1993 I x 600 1329 1070 1100 Hemweg The Netherlands 1993 I x 650 1414 1136 1080 to 1200 Lethabo South Africa 1987 to 1992 6 x 600 1398 1099 1190 Yue Yang China 1991 2 x 362 1518 1162 1400 to 1500 Castle Peak B UK 1985 to 1989 4 x 680 1480 1147 1050 to 1200 Hwange Zimbabwe 1987 2 x 200 1490 1159 1380 to 1380 Drax UK 1972 to 1986 6 x 660 1477 1107 1020 to 1200 Castle Pcak A UK 1982 to 1985 4 x 350 1483 1152 1230 to 1350 Matala South Africa 1978 to 1983 6 x 600 1473 1143 1170 Nijmegen Netherlands 1981 1 x 580 1500 1128 1075 Enstedvrerket B3 Denmark 1979 I x 630 1509 1160 1180 to 1200 Tahkoluto Finland 1976 I x 220 1426 1152 900 Sierza Poland 1971 to 1972 2 x 120 1332 1054 980 Didcot UK 1970 to 1972 4 x 500 1466 1071 1020 to 1200

21


Clearly limitations on the tolerable service conditions for water wall steel are already imposing unwelcome constraints on advanced boiler design If the anticipated improvements in the specifications for components outside the boiler are to be exploited there will be a need for improved water wall steels European Japanese and US steel makers boiler manufacturers and utilities are participating in the EPRI RP 1403-50 project to develop new steels for a PT92 specification It is anticipated that this will allow main steam conditions of 325 MPal610degC (Blum 1994) Professor T Fujita of Tokyo University has released information about a new steel that may allow steam conditions of 325 MPal630degC Even the adoption of PT92 would render 13CrM044 inadequate as a water wall material Several new alloys are being evaluated to assess their potential for use as water wall materials In Japan Sumitomo Metals and Mitsubishi Heavy Industries have developed new steels (HMCI2 and HCM2S) Design calculations indicate that if service trials prove these materials to be satisfactory it will be possible improve the water walls sufficiently to provide for main steam conditions of 325 MPal625degC (Blum 1994)

24 Supercritical boiler firing with low rankgrade coal

The flexibility of PC technology has been demonstrated by subcritical boilers designed to operate using fuels with apparently unpromising characteristics Breucker (1990) described the design commissioning and modification of modern (commissioned 1983-1989) boilers firing indigenous fuels in Germany South Australia and Turkey Fuel characteristics were

LHV below 4 MJkg moisture content up to 60 ash content up to 25 of which up to 55 is CaO

Key features of the design of the boilers included ample furnace size to minimise slagging and fouling and the recycle of 20 of the flue gas to control flue gas temperature Both these measures have the additional merit of facilitating the control of NO and N02 (NOx) After the usual settling down period the availability of the boilers at 90-95 compares favourably with availabilities for boilers using normal fuels However there are a number of locations where older unreliable and highly polluting power stations are still in operation

VEAG was founded in 1990 with the responsibility for supplying electric power and district heat to the 14 regional utility companies in Eastern Germany In 1994 brown coal-fired power stations accounted for more than 95 of the 142 GWe of utility electric power generation in the region For political and macroeconomic reasons it is necessary to continue using brown coal in Germany (Kehr and others 1993) The design state of repair and environmental emissions of the existing generating units installed under the former GDR regime are unacceptable by modern Gernlan standards (Eitz and others 1994) The units had an availability of around 80 partly because of the nature of the fuel and a net efficiency of around 36 LHV (Schuster

and others 1994) Measures for remedying this situation include the

progressive shut-down of 8500 MWe of uneconomic high emission power stations upgrading of eight 500 MWe units and the fitting of modern flue gas cleaning plants installation of 2000 MWe of bituminous coal-fired power stations and a 1060 MWe pumped storage station the construction of new efficient brown coal-fired power stations

The new power stations designed specifically for east German brown coals are expected to have an availability of around 90 and an efficiency of 39 to 40 LHV VEAG entrusted a working group composed of representatives from RWE Energie AG and VEBA Kraftwerk Ruhr AG with the task of assessing the relative merits of subcritical and supercritical steamwater processes The comparative merits of several combined cycle processes were also evaluated As a result of the studies the new units will be powered by 800 MWe (2300 th steam) supercritical boilers (Schuster and others 1994)

241 Attainment of low FEGT with lignites

The high fouling propensity of the brown coals led to the specification of a low FEGT (950-980degC) for the new VEAG 800 MWe units For a furnace firing bituminous coal that might require considerable design compromises (see

Section 232) For brown coal firing a number of the properties of brown coals facilitate the reduction of FEGT

in comparison with bituminous coals the temperature of the products of combustion tends to be lower flue gas recirculation through the pulverisers is a normal feature of brown coal-fired boiler operation the high reactivity and pyrolysis behaviour of brown coals make it possible to achieve NOx emission standards of 200 mgmJ by primary combustion methods

Compared with bituminous coal firing the flue gas in a brown coal or lignite-fired boiler contains a higher percentage of water because the hydrogen content of the fuel is higher and the fuel tends to have a higher water content Consequently for a given heat output the mass and specific heat of the flue gas is greater and the flue gas temperature is lower In comparison with a bituminous coal with 4 moisture a lignite with 40 moisture would be expected to produce a FEGT 150degC lower (Couch 1989)

Because of their high moisture content the drying of lignites requires a considerable heat input and because of the explosive properties of lignite dustair mixtures drying is usually done in a low oxygen atmosphere (less than 12 oxygen) Lignite pulverisers act as fans and dryers as well as mills Flue gas is extracted from upstream of the furnace outlet cooled by contact with the wet lignite passes through the mills with the entrained lignite and is blown back into the furnace (Scott 1995)

When firing bituminous coal post combustion NOx reduction

22


methods are used to ensure that NOx emissions are consistently below 200 mgm3 The large combustion chambers that are characteristic of lignite-fired boilers and the high reactivity of lignite allow effective primary NOx control measures to be combined with satisfactory carbon burnout These measures including staged combustion and gas recirculation reduce the high heat flux to the water walls in the region of the bumers (Reidick 1993)

242 Steam conditions and materials of construction

The steam conditions chosen for the VEAG 800 MWe units are 26 MPalS4SdegcS60degC For these brown coal boilers the conditions can be achieved without using high alloy steels Data in Figure 4 indicate that the flue gas temperature of 9SQ-980degC entering the convective section is outside the range where the possibility of high temperature corrosion is predicted The fouling that does occur consists largely of oxides rather than complex alkali sulphates The use of staged combustion for NOx control produces a beneficial change in the nature of the fouling deposits Under high excess air firing the deposits are a strongly adherent material composed mainly of haematite Under staged combustion conditions the deposits form as a loosely bonded silicate material that is readily dislodged by soot blowing (Reidick 1993) The highest grade steel used for the new boilers will be F12 a thoroughly proven boiler material (Schuster and others 1994)

Design studies indicated that higher steam conditions offered poorer commercial prospects This was partly because the need to change from ferritic steel to austenitic steel for the superheater but the limitations of the water wall materials was also a factor For optimum efficiency a further increase in steam pressure would require a corresponding increase in steam temperature This combination would result in the safe operating characteristic of the 13CrM044 water wall being

exceeded or the FEGT increasing (Schuster and others 1994)

Although the required FEGT for the brown coals considered was approximately 200degC lower other properties mitigate the effect on the water walls The sum effect of the different properties and utilisation of bituminous coal and brown coal appears to be that in both cases the fuel limits steam conditions because of the interrelation between the need to limit FEGT and the design limitations of the water wall material However the lower FEGT for brown coals puts superheater conditions outside the range where high temperature corrosion would be expected and allows less costly material to be used

25 Comments The development of new metals for waterwall construction continues but it appears that the improvements in water wall metallurgy will barely be adequate to keep up with the improvements outside the boiler Hence it seems unlikely that the conflict between optimum efficiency FEGT and maximum waterwall temperature will soon be resolved The ash fusion aspect of coal quality will continue to be an issue affecting the design and operation of state of the art PC-fired supercritical power stations

High temperature corrosion is also a coal quality linked problem which may be exacerbated by increasing steam temperatures According to experience in Japan the imposition of limits on coal sulphur and chlorine content appear to be sufficient conditions to avoid excessive high temperature corrosion in their present generation of supercritical boilers However it is difficult to assess whether these are necessary conditions Conversely for more advanced conditions the present empirical levels might conceivably prove too high Re-examination of existing data and further basic research on the role of chlorine in high temperature corrosion might help to resolve these questions

23

3 Atmospheric fluidised bed combustion

The idea of burning solid fuel particles in a bed of hot incombustible particles that is kept fluid by passing air up through it has been known for over 50 years However it was not until about the 1970s that tluidised bed combustion (FBC) technology was introduced into the power sector

The early industrial units were small atmospheric bubbling FBC (BFBC) boilers Coal and limestone are injected into the fluidised bed The bed contains the coals ash pyrolysed limestone sulphated limestone and in some cases inert material at a temperature of around 800-950degC The coal size and vertical air velocity (the tluidising velocity) are controlled so that the bed has a definable upper surface With bed material of a given size distribution there was found to be an upper limit of tluidising velocity Beyond this limit excessive amounts of bed material tended to be entrained and removed from the combustion chamber in the outlet gases This entrainment and consequent carry-over of bed material (known as elutriation) is regarded as a disadvantage in BFBC systems that use tubes immersed in the bed for heat transfer High combustion efficiency cannot be obtained when high rates of elutriation result in the loss of unburned carbon and unused limestone In order to obtain satisfactory combustion efficiency and limestone utilisation this material therefore needs to be captured and recycled to the bed

In the mid 1970s a new technology was developed which takes advantage of this elutriation phenomenon the atmospheric circulating FBC (CFBC) system In these systems higher tluidising velocities are used to ensure that a substantial proportion of the bed material is carried over with the combustion gases This material is collected in a cyclone and recycled to the tluidised bed providing a high combustion efficiency As described in the next section CFBC is the predominant FBC technology in commercial applications with capacity greater than 50 MWt Since utility power producers are usually interested in units having a

capacity considerably greater than 50 MWt and the coal quality requirements for both technologies are similar the characteristics of atmospheric FBC systems have been described by citing data from CFBC systems

A survey in 1988 listed I 12 CFBC plants of which 89 had capacities over 50 MWt and 14 had capacities over 200 MWt (Leithner 1989) CFBC units up to about 400 MWe in size are now being offered with full commercial guarantees (Simbeck and others 1994) With the scale-up in unit capacity CFBC systems are now being demonstrated in utility applications Larger units that are in operation include

the 110 MWe Nucla demonstration project in Nucla CO USA that started up in 1987 (Bush and others 1994 EPRI I991) a 125 MWe combustor at the Emile Huchet Power Station Carling France burning coal washery residues (Lucat and others 1991) Texas-New Mexico Power Cos two lignite-fired 150 MWe units at Robertson TX USA that went into commercial operation in 1990 and 1991 respectively (Maitland and others 1994) a high sulphur high chlorine coal-fired 165 MWe unit at Point Aconi Nova Scotia Canada that was commissioned in 1993 (Campbell 1995 Salaff 1994) a 250 MWe unit at the Provence Power Station Gardanne France burning local low grade coal (Jacquet and Delot 1994) Engineers recently began firing the boiler (Coal amp Synfuels Technology 1995)

Several other projects that employ 150--250 MWe CFBC units are in various stages of planning and construction in Asia Europe Puerto Rico and the USA (Simbeck and others 1994) The CFBC unit at the Provence Power Station has been built with two combustor zones (a design known as the pant-leg) as a precursor for the next generation of 400--600 MWe boilers

24

Atmospheric fluidised bed combustion

31 Process description In CFBC systems crushed coal and limestone (or dolomite) are fed mechanically or pumped as slurry to the lower portion of the combustor (see Figure 8) Primary air is supplied to the bottom of the combustor through an air distributor and staged air is fed through one or more elevations of air ports in the side to control NOx formation Nitrogen oxide reduction efficiency is typically over 90 Combustion takes place throughout the combustor the gas fluidising velocity (generally 5-10 ms) is such that the bed completely fills the combustor There is no distinct bed as there is in BFBC boilers although the density of material in the lower section of the combustor is greater than the density in other parts of the boiler The solids entrained in the flue gas are separated in refractory-lined cyclones and recycled to the bottom of the combustor through a seal (to overcome the pressure differential between the cyclone and the fluidised bottom) Instead of a cyclone separator a Babcock and Wilcox design uses a U-beam as the primary particle collector Recirculation of the coal particles and limestone extends the contact time of the solids and gases and ensures good gassolids contact thus promoting good carbon burnout and efficient sulphur capture with high calcium utilisation Sulphur reduction in excess of 90 (often around 98) can be attained in the fluidised bed The hot flue gases leaving the cyclone flow through a conventional heat recovery section often called the back-pass or convection pass which contains a series of heat exchanger tube banks (such as superheaters and economisers) They then pass through the air heaters and the particulate collecting system before being discharged at the stack

Bed temperature in the combustor is essentially uniform and its optimum temperature is typically around 850degC It is maintained at an optimum level for sulphur capture and

convective pass

cyclone

CFB combustor

staged air

l~i --+ to baghouse

coal and 11 iFi i f1d bod limestone pm~y ~ hIohao9

air h as secondary

air

Figure 8 Circulating fluidised bed boiler (Boyd and others 1989)

combustion efficiency by heat exchange To avoid erosion problems heat exchange tube bundles as used in bubbling fluidised beds me not generally used in the combustion section Heat is absorbed by the steam generating membrane water walls forming the enclosure of the combustion chamber and in some designs by additional heat exchange tubing installed at the top of the combustor or in part of the cyclone wall The Ahlstrom (now Foster Wheeler) Pyroflow system is one example using this design it incorporates Omega secondary superheaters at the top of the combustor In several other proprietary designs the bed temperature is additionally controlled by extracting heat from the recycled solids by an external fluidised bed heat exchanger (FBHE) This unit is incorporated into the return loop between the foot of the cyclone and the combustor It is a characteristic feature of systems designed by Lurgi Lentjes Babcock Energietechnik GmbH (LLB) Foster-Wheeler and others The Provence power plant (Gardanne France) will test FBHEs installed inside the combustor as well as external ones (Jacquet and Delot 1994)

The thermal and environmental performance and operating costs of CFBC are functions of operating conditions design parameters and fuel properties A summary of the effects of coal properties on CFBC system design and performance is given in Table 5

The impact of coal quality on various aspects of the operation of a CFBC unit is discussed in the following sections

32 Coal rank and boiler design As with conventional boilers the size and configuration of a CFBC boiler is affected by the rank of the design coal There are strong correlations between the rank heating value and moisture content of the coal For CFBC the need to obtain efficient sulphur capture and low NOx emissions dictates bed temperatures in the range 85Q-900degC Fluidising velocities are normally around 5 ms The requirements for boiler safety and efficient combustion indicate that excess air should be around 20 With the bed temperature and excess air fixed the amount of heat leaving the furnace to be absorbed in the back pass will vary with fuel heating value and moisture Lafanechere and others (1995) devised an expert system for assessing the effect of coal rank on the size and configuration of CFBC boilers Figure 9 shows the effect of lower heating value (LHV) on the heat distribution between the circulating loop and the backpass

CFBC is credited with good fuel flexibility but this is only possible if the heat duty distribution of the boiler can be modified to accommodate the properties of different fuels This can be done by designing the boiler to operate with high excess air for low moisture coals Excess air can then be reduced for higher moisture coals without falling below 20 Unfortunately this requires the boiler to be over designed reduces overall boiler efficiency and adds to construction cost (Lafanechere and others 1995) Alternatively the same result can be achieved by recirculating flue gas from the induced draft fan outlet back to the combustor

25


Table 5 Effects of coal properties on CFBC system design and performance (Hajicek and others 1993)

Coal property Effect on system requirements Effect on system Effect on system and design thennal performance environmental perfonnance

Heating value

Moisture content

Ash content

Volatile matter content

Sulphur content

Nitrogen content

Chlorine content

Alkaline ash content

Sodium and potassium content

Ash fusibility

Determines size of feed system combustor particulates collection system and hot duct

Affects feed system design size of convective pass and distribution of heat transfer surface

Affects size and type of particulate control equipment and size of ash handling equipment

Affects fuel feed method

Affects required capacity of sorbent system and capacity of ash handling system

None with common designs and typical regulationssect

Can influence selection of materials for cool end components May cause higher corrosion rates for in-bed tubes

May reduce size of sorbent injection system

High alkali metal content may cause fouling problems Preventative measures such as soot blowing and more frequent bed draining may be required

Low fusion temperatures may require allowance for the possibility of fouling and agglomeration

Efficiency affected by moisture and ash content

Higher moisture lowers thermal efficiency

Lowers thennal efficiency through heat loss from hot ash removal

Lower thermal efficiency for higher volatile matter carbon content

Higher sulphur results in higher heat losses because of increased sorbent needs and ash removal

None with common designssect

Typically none Exceptionally high chloride levels can lower thermal efficiency by requiring higher exhaust temperatures

None

Tube fouling and more frequent bed draining can lead to loss of thermal efficiency

Lower fusion temperatures have implications similar to those of high sodium

Size of particulate collection devices

High moisture may increase CO emissions

None with proper design


None or proportional t if site and system size are regulated Determines SOz emissions (in conjunction with alkaline ash) if uncontrolled

Affects NO emissions

Affects HCI emissions

High ash alkalinity contributes to achievement of low SOz emission levels

Higher sodium lowers uncontrolled SOz emissions and tends to improve ESP efficiency through lower fly ash resistivity Fabric filter performance may also be enhanced

Typically none

the form in which sulphur occurs can be important High pyrite requires a longer residence time in the bed This in tum may require increased operating pressure and increased blower capacity

t sulphur content may determine allowable level of S02 emissions if emission standards are defined in terms of fractional removal (eg US New Source Performance Standards)

sect for compliance with low NO regulations staged combustion or post combustion treatment of the flue gas may be needed Staged combustion may give rise to higher CO emissions Post combustion systems may impose an efficiency penalty

given useful heat output depends mainly on the heating value33 Coal and sorbent feeding of the fuel its moisture and its ash content High moisture

In order to maintain a constant inventory of solids within the and high ash tend to lower the thermal efficiency of the combustor a dynamic balance has to be maintained between boiler The necessary rate of sorbent input depends on the coal and sorbent added the material removed by combustion characteristics of the fuel and the required percentage sulphur and the solid material rejected The required fuel input for a capture

26


70

65

60

~ 0

c-o

3 0

1il is a Ql r

55

50

45

40

35

30

0

- D

co bull

~ bull circulating loop

D

bullD

bull D backpass

I

bull D DCO OIJ D

CJJ

5 10 15 20 25 30

Coal heating value (LHV) MJkg

Figure 9 Variations of heat duties of recirculating loop and backpass (percentage of total boiler heat duty) as a function of lower heating value (Lafanechere and others 1995)

The amount of sulphur capture is determined by the total alkali to sulphur ratio In addition to any sorbent added deliberately alkali is provided by the mineral matter contained within the coal Although theoretically a sulphur capture approaching 100 can be achieved (see Section 381) this may result in excessive sorbent requirements For modern CFBC a CaiS molar ratio of 2-4 typically gives 80 to 95 sulphur capture This means that the calcium utilisation efficiency is only 25-50 The rest remains unreacted Thus if the coal has a high sulphur content and a low SOl emission is specified a large amount of sorbent may be required resulting in the generation of large quantities of solid residue (Takeshita 1994) The ash generated from combustion of the coal and the partially sulphated sorbent is removed as fly ash from the baghouse or as bottom ash from the bottom of the combustor The solids handling system has to be sized to cope with the maximum designed loading and the need to dispose of the residue can be an important economic consideration (Mann and others 1992d)

As well as the total quantity of coal and sorbent injected into the bed the particle size distribution is an important consideration FBC boilers burn crushed rather than pulverised coals it is neither necessary nor desirable to crush the fuel to a fine powder However even for CFBC achieving the optimum grind size of the coal is an important parameter for proper coal feeding and subsequent combustion The required coal particle size is a function of coal type reactivity and associated moisture and ash contents If the fuel to be ground is too wet drying may also be required adding to the cost of preparation Generally crushing the coal to -12 mm is sufficient Particles near the top end of this size range are retained in the denser phase in the lower part of the combustor There they decrepitate and attrite until they are small enough to pass into the upper regions of the boiler and be carried to the cyclone (Maitland and others 1994) This general rule does not apply for all

fuels As described later in this Chapter some may need more careful treatment

A key decision in utilising low grade coals and coal wastes is whether to handle them as a dilute slurry (gt40 water) a dense slurry laquo40 water) or as a nominally dry material (-12 water) The dense slurry option appears to be specially suitable for fine washery wastes It simplifies the handling and feeding systems and removes the costly necessity for drying The most serious disadvantage of the technique is its potential for causing bed agglomeration (Anthony 1995) Thus the moisture and ash content of the fuel influence the design of the fuel feed system

34 Ash removal and handling The bottom or bed ash handling system removes ash from the bottom of the boiler cools and stores it for transport to the disposal site The material described as ash is actually a mixture of coal ash spent sorbent lime and unreacted carbon Removal of bottom ash is required to control bed inventory and to remove oversize bed material Before disposal to storage the bottom ash is cooled from its discharge temperature of about 60o-800degC to a manageable 200degC This heat may be recovered to improve the heat rate of the plant In several plants deficiencies in the bottom ash removal system are a major source of forced shut-downs or reduced load operation (Modrak and others 1993)

The performance of the bottom ash system is directly related to the amount of bottom ash which is a function of fuel mineral matter content ash split fuel feed size limestone feed size and limestone consumption (Modrak and others 1993) It is also affected by boiler design and operation The amount of solid residue generated increases with the amount of mineral matter in the fuel and the amount of limestone added (Mann and others 1993) Limestone requirements are highest for high sulphur coals and high percentage sulphur

35

27


capture (see Section 381) Thus using high ash and high sulphur coal can result in the production of large quantities of solid residues The need to dispose of the residues may have a significant effect on the economics of the process (see Section 39) The residues requiring disposal also include the fly ash from the particulate collecting system

The sizing of the solids handling system is an important aspect of CFBC design The heating value and mineral matter content of the fuel are generally used to size the solids handling equipment (as well as the fuel feeding system) Figure 10 shows the required ash removal rate as a function of the coal heating value

Plants are usually designed for a certain ash split The Gilberton plant (PA USA) was designed for a 70 bottom ash30 fly ash split When the ash content of the anthracite culm increased from 37 to about 45 the bottom ashfly ash split increased to a 901 0 split This higher split overloaded the ash removal system decreasing plant capacity increasing system erosion and causing plant outages (Wert 1993) At the Nucla plant (CO USA) full load could not be achieved when higher ash or higher sulphur coals than the design coal were introduced this was due to bottom ash removal capacity limitations (Friedman and others 1990) Major changes were made to the bottom ash system to increase its capacity Thus design restrictions could limit the utilisation of some coals and coal wastes

The handling characteristics of FBC ash can be substantially different from PC or stoker furnace ash Therefore equipment suitable for these latter ashes may lead to problems with FBC ash In addition ash from a FBC boiler can vary widely depending upon the fuel and bed material Problems have resulted primarily from the quantity of ash handled at facilities burning high ash coal wastes Two basic types of system are in common use for removing and cooling bottom ash screw coolers and fluidised bed ash coolers (also called stripper coolers) Modrak and others (1993) review problems experienced at several FBC units using these systems and

bull Ash production

150

Coal heating value (HHV) GJt

Figure 10 Required ash removal rate as a function of coal heating value (Modrak and others 1993)

discuss solutions The use of fluidised bed ash coolers in CFBC plants is described by Abdulally and Burzynski (1993) Pneumatic systems for handling bottom ash recycle ash and fly ash are discussed by Slavik and Bolumen (1993) The following will summarise some of the problems that have occurred in these systems which can be related to the fuel used and hence how coal quality requirements will be affected

The bottom ash is a highly abrasive product causing erosion of screw coolers At the Ebensburg plant (PA USA) high wear of the screw coolers was found in the first 12 m of the trough after six months of operation The erosion was severe enough to allow water leakage onto the conveyor Various hard facing materials have been installed to improve wear resistance in this area Erosion of the screw near the outlet end has also been reported (Belin and others 1991 Modrak and others 1993) Pluggage of the screw coolers and bottom ash lines occurred at the lignite-fired TNP plant (TX USA) The torque on two of the screw conveyors at each unit was not sufficient to move the ash under all conditions Consequently they plugged with ash and tripped off While the screw coolers were not running the ash in the drain line solidified and had to be chipped out The drain lines plugged with resultant ash solidification if they were not used every 2 to 3 hours (Riley and Thimsen 1993)

Problems that have been reported in plants with fluidised bed ash coolers (Modrak and others 1993) include

agglomeration of material due to combustion in the cooler or because of the nature of the fuel Clinker fOffiJation in the classifiers and classifier drains has been a periodic problem at the Nucla plant (CO USA) firing high ash bituminous coal (Friedman and others 1990) pluggage of hot air vents because of high fines loading and inadequate freeboard for particle disengagement in-bed tube erosion as a result of high local velocity andor ash erosiveness In these cases where water cooled in-bed surface is installed in the cooler tube erosion has been minimised by using wear resistant coatings on the tubes low fluid ising velocities and tube geometry changes

Bottom ash and fly ash can be pneumatically conveyed to the ash storage silos Since ash is a highly abrasive material a low velocity is required to minimise pipe erosion However pluggage can result if the velocity is too low Pipeline bends are the primary targets for wear (Slavik and Bolumen 1993) At the Nucla (CO USA) wear occurred mainly on the inlet to the cyclone separators and around the valves on each side of the transfer hopper (EPRI 1991 Friedman and others 1990) The use of pneumatic conveying pumps in some of the first Lurgi-designed CFBC units resulted in high abrasionerosion rates in the conveying screws A new design has minimised the erosion rates (Anders and Wechsler 1990)

Thus the design and performance of the ash removal and handling systems are directly affected by the ash content of the coal and are indirectly affected by the sulphur and moisture content

28


35 Ash deposition and bed agglomeration

Evidence from pilot-scale and utility boilers have shown that certain ash components derived from the coal can cause problems Ash-related problems include agglomeration and sintering of bed material and deposition on heat transfer surfaces and refractory walls This section addresses agglomeration and deposition (particularly fouling) problems in CFBC units the part coal ash components play and the prediction of potential problems from a coal

Bed material agglomeration decreases the fluidisation quality of the bed resulting in poor bed mixing increased temperature gradients poor combustion efficiency and less efficient heat transfer As agglomeration proceeds it can cause the bed to defluidise block air distribution ports hinder the removal of bed material from the furnace floor and hinder solid circulation from the loop seal All this adversely affects the control of the unit and in some cases may cause the shut down of the boiler Agglomerates have formed for example in the bottom of the combustor (on the refractory) and in the loop seal return lines at the CFBC boiler at Stockton (CA USA) However it did not in this case limit boiler operation (Slusser and others 1990) Agglomeration can be more of a problem during part load operation when tluidising velocities are lower (Makansi and Schwieger 1987) Generally because of the low combustor temperature there are no large slag accumulations typical of PC units (Gaglia and others 1993)

Certain ash components can lead to deposition (fouling) in the convection pass These deposits decrease the heat transfer efficiency may cause corrosion and can be difficult to remove Inspection of the backpass during a scheduled turbine outage in December 1993 at the Point Aconi power station (Nova Scotia Canada) showed severe fouling on the convection surfaces (Campbell 1995 Johnk and others 1995) A high sulphur high chlorine (05) subbituminous coal was used The ash buildup on the economiser and air heater was in the form of loose deposits easily dislodged by the sootblowers but the steam-cooled superheater and reheaters were severely fouled by a hard ash deposit Additional sootblowers were installed and a more aggressive blowing schedule was introduced to control the fouling In addition changes in the furnace operating conditions have helped to control fouling Ash accumulations in the superheater sections has also led to failures of the superheater sootblower lances at the Westwood power station (PA USA) The cleanup of the ash accumulation in the superheater and generating bank involved a long forced outage because of the requirement to cool the units down Cleaning with air lances was hazardous because of the re-ignition of unburned carbon Tube failure began to affect unit availability and capacity factors Cleanup after the tube failures was difficult because the released water mixed with the ash and unreacted lime to quickly form a cement-like deposit (Jones 1995b)

Bed agglomeration and ash deposition are closely tied to the abundance and association of inorganic components in the

coal and system conditions (such as bed temperature fluidisation velocity and coal particle size) Coals with a low ash fusion temperature (AFf) particularly the softening temperature can promote agglomeration and deposition In CFBC systems it is important that the sodium and potassium accumulation in the recycled ash do not exceed the limit that could cause a significant drop in the softening temperature resulting in bed agglomeration (Tang and Lee 1988) Usually the fluidised bed is operated below the AFf of the coal Research however has indicated that agglomeration and deposition can occur at temperatures well below the AFf determined by standard methods Peeler and others (1990) report that the problems of ash fusion (agglomeration deposition and fouling) can exist in FBC boilers at temperatures of between 30 and 285degC lower than those indicated by the standard Australian AFf method (AS 103815) with nitrogen purge They also found that the maximum temperature experienced by an individual particle may be significantly above the average bed temperature the particle surface temperature was generally up to 200degC higher than the nominal bed temperature Localised hot spots in the bed will also raise the temperature above the average value Thus the AFf of a coal may not be a reliable indicator of potential agglomeration and deposition problems

Bituminous coals with a high iron content and subbituminous coals and lignites with a high sodium content have been found to promote agglomeration (Atakiil and Ekinci 1989 Hainley and others 1986 Mann and others I992b) Coals with a high calcium content also show a potential for fouling in the convection and reheat sections of a boiler (Hajicek and others 1993 Howe and others 1993 Mann and others 1992b 1993) However agglomeration and deposition are not just a matter of the total concentration of these elements in the coal but depend on their form of occurrence in the coal and their subsequent behaviour in the boiler (as well as operating conditions) At the relatively low temperatures in FBC systems only the organically bound inorganic elements and low melting compounds are likely to undergo major transformations In low rank coals the organically bound alkali and alkaline-earth elements have been found to be the main precursors for agglomeration and deposition (Benson and others 1995)

Temperatures capable of melting various ash species can be attained even during relatively stable operation of the FBC boiler Elements of the coal ash interacting with bed material form the substance that acts as the binder allowing particles to stick to each other and agglomerate These ash-related interactions can occur under normal FBC operating conditions and for low rank coals include the formation of low melting eutectics between sodium- potassium- calcium- and sulphate-rich components and some solid-solid reactions (Benson and others 1995 Mann and others 1992a) The sulphate-rich phases can sinter over time to form strongly bonded deposits Agglomeration can also occur as a result of localised hot spots of bed material where temperatures in the combustor can exceed the typical 950degC limit andor where localised reducing conditions are present Agglomeration under these conditions is via a silicate (aluminosilicate) matrix and typically occurs with bituminous coals (Dawson and Brown 1992 Mann and

29


others 1992a) Figure II gives a schematic of the transformations of the coal inorganic matter in CFBC boilers

During combustion ash forms on the char surface Scanning electron microscopy of the ash formed from a lignite with high sodium and sulphur contents showed it consisted of a molten matrix rich in sodium calcium and sulphur solid phases rich in magnesium and aluminium were embedded in the matrix (Manzoori and Agarwal 1993 Manzoori and others 1992) The ash is then deposited on the bed particle surfaces by a physical process possibly caused by the collision of bed particles with molten ash-coated char particles by a vaporisationcondensation mechanism (whereby organically bound Na K Mg and Ca are vaporised during combustion and subsequently condense onto the cooler bed particles) andor random collisions between the ash-coated bed particles (Galbreath and others 1995 Mann and others 1992a Manzoori and others 1992) These particles are then capable of sintering and agglomerating

Work by Skrifvars and others (1994) has indicated that sintering of coal ashes during CFBC can proceed by at least three different mechanisms These are partial melting of low melting compounds such as alkali sulphates (low rank coals) viscous flow sintering for ashes with a high silica content (bituminous coals and anthracite) and gas-solid reactions between the ash and flue gas compounds Sulphur dioxide in the atmosphere increased sintering for a high calcium low ash brown coal Agglomeration is more prevalent when S02 is present in the gas

A hard fine-grained calcium sulphate-based deposit formed on the ash fouling probes and the refractory walls of the primary flue gas heat exchanger during test burns of lignites with added limestone in a I MWt pilot-scale CFBC facility This was believed to be caused by sulphation of the deposited calcium oxide and subsequent sintering of particles (Mann and others I992b) The primary cause of fouling in the backpass at the Point Aconi station Nova Scotia Canada

Ash agglomerates (recycled)

~Volatiles

Agglomeration Moisture Char Coalescence of

burnin~ inorganic --- Ash ~ ~constituents bullbullpartlcles ~ I

I Gassolid ~ Solidsolid reaction Precipitator interaction (fly) ash

Release of Coal and NaCIS species Inorganic matter ~

Q

l Gassolid Inert bed 0 0 interaction matenal shy

Gas phase Agglomeration reactions and

~ condensation~Emission of 00 HCISOx NOx

Bed agglomerates and aerosols (recycled)

Figure 11 Transformations of the coal inorganic matter in CFBC boilers (Manzoori and others 1992)

burning subbituminous coal is also believed to be due to finely dispersed calcium products originating from the bed material or coal ash The bonding between particles was caused by pore filling and through the sulphation process and low melting point eutectic phases from potassium or sodium (Campbell 1995) Tests in a laboratory rig confirmed the effect of process temperature on fouling When burning a Thailand lignite in a I MWt pilot-scale facility deposition occurred at a flue gas temperature of about 760degC the metal temperature was estimated to be in the range 540-760degC (Howe and others 1993)

A laboratory sintering test method based on compression strength measurements of heat treated ash pellets has been proposed by Skrifvars and others (1992) for predicting bed agglomeration problems in CFBC boilers Sintering can start well below the temperature of any detected melting of the ash The ash sintering tendencies of the different coals tested correlated fairly well with the sintering problems experienced in pilot- and full-scale CFBC boilers

The agglomeration potential of coals (and how operating conditions can be modified to minimise agglomeration) can be evaluated in bench-scale FBC combustors This has been reviewed in a separate IEA Coal Research report (Carpenter and Skorupska 1993)

The utilisation of coal tailings in CFBC units could in some cases cause agglomeration problems Montmorillinite clays are known to have a strong tendency to agglomerate burning coal tailings with a high concentration of these clays could therefore lead to bed agglomeration However the agglomerates remained relatively small in size and did not adversely affect fluidisation when a coal tailings slurry with a high content of montmorillinite clays was burnt in a pilot-scale combustor (Peeler and Lane 1993) The agglomerates were probably fOimed as a result of the slurry injection method

To conclude the utilisation of certain coals could lead to bed agglomeration and ash deposition and fouling in CFBC units For example low rank coals with more than about 4 sodium in the ash could potentially give agglomeration problems (Mann and others 1992b) the organically bound alkali and alkaline-earth elements are the main precursors to agglomeration and ash deposition However competing reactions with other coal inorganic components can reduce the alkali availability (Benson and others 1995) and so decrease their agglomerating and fouling potential For example naturally occurring kaolinite in coal mineral matter reduces the release of sodium The fate of the deposit- and agglomerate-forming minerals ultimately influences the extent of deposition and agglomeration It is therefore important to understand the nature of the inorganic components in the original coal and the mechanisms of agglomeration and deposition so that improvements can be made in predicting FBC performance Bed agglomeration and ash deposition and fouling mechanisms are still not fully understood The use of a given coal is not necessarily precluded by a high alkali content These coals have been used successfully by modifying operating conditions and using additives such as kaolinite Alternatively the alkali content can be reduced by pre-treatment but this adds to the cost of the fuel

30


36 Materials wastage All combustion systems suffer from material problems in that some parts of the different environments within the system are aggressive to the materials of construction Compromises must be made between the combustion conditions component lifetimes and reliability and the component costs It was thought that CFBC boilers would be less prone to materials problems than BFBC where in-bed tube erosion can be a problem A major design feature of some variations of CFBC boilers is either the effective separation of the combustion process (where most of the undesirable materials problems occur) from the high-temperature heat transfer section or at least the elimination of heat transfer tubes that intersect the nominal flow direction of the solids (Stringer and others 1991) However some specific materials issues in CFBC boilers have emerged These can be broadly divided into

refractory systems and metallic component issues

Among the early operating difficulties with CFBC boilers were those associated with the refractory systems Refractory lining problems have been reported in three major areas although their significance varies among units (Heard 1993 Snyder and Ehrlich 1993 Stringer and others 1991) These areas are

the lower part of the combustor Since this part of the combustor operates under reducing conditions the water walls in this area are protected against corrosion by a refractory lining Spalling cracking erosion and anchoring difficulties of the linings have occurred the particle separation systems particularly the entrance to and within the cyclones This has been listed as the major concern for successful CFBC boiler operation (Snyder and Ehrlich 1993) and the recycle down comer and transfer lines for recycling the solids to the combustor Problems here often appear to be related to faults in installation (Stringer and others 1991)

In designs that include external systems with refractory linings such as FBHEs lining anchoring spalling cracking and erosion problems have also been reported (Snyder and Ehrlich 1993)

Developments in refractories and changes in design have helped to eliminate some of the problems For example in the Nucla power station (CO USA) which was commissioned in 1987 most of the refractories have had to be replaced with new materials (Bush and others 1994) These include those in the lower part of the combustor chamber in the cyclone cyclone downcomer and loop seal but not the lining in the cyclone outlet duct To correct the problems in the lower combustor a thinner high strength low cement gunnite was applied to a height of 9 m above the air distributor to the new kick-out tube location (see

Figure 12) The boiler upgrade was completed in 1993

Todays CFBC refractory lining systems are generally

custom designed to meet the requirements of the purchaser and the particular demands of the environment created by the primary and secondary fuel sources the composition of the bed medium and the circulation rate of the proposed facility (Heard 1993) The use of thinner refractory linings has allowed faster start-ups and shut-downs with less concern for refractory damage due to thermal shock In a survey of North American CFBC boilers lining problems have been reduced but not completely eliminated in the newer units (Snyder and Ehrlich 1993) An EPRI report provides guidelines on using refractories in CFBC boilers (Crowley 1991)

The major issue for metallic components in CFBC boilers is wastage by which is meant the loss of section due to mechanical erosion or abrasion by the particulate material in the unit this may be modified by chemical interactions such as oxidation and corrosion Fatigue as a result of forces arising from the dense particle flows may be an issue in for example FBHEs where these are used Fretting as a result of small relative motion between the tubes and tube supports in FBHEs have also been reported (Stringer and others 1991) Certainly boiler tube failures account for the majority of the forced outages at CFBC installations Even after the major upgrade and repairs at the Nucla power station boiler problems continued to be the primary cause of unit unavailability accounting for 74 of the total Leading causes include tube leaks which account for 60 of boiler-related unavailability and boiler internals which

Upgrade design

Kick-out tubes ----shy

Original design

Water wall

tubes

8-10mm thickness

Water wall

refractory interlace

600mm thickness at base

Refractory step

~ Lower water ~ ~ wall header amp

floor tubes

Figure 12 Modifications to CFBC boiler (Bush and others 1994)

31


account for 27 Total forced outages arising from tube failures in CFBC boilers are comparable with those of PC units (Jones I995b) corrosion and fouling of boiler tubes are however substantially reduced in CFBC units

Metal wastage problems have been reported (EPRI 1990 Stringer and others 1991) in

the combustion chamber especiany the membrane water wall tubes immediately above the termination of the refractory lining in the lower part of the combustor (see

Figure 13) Wear at the comers of the combustor or between wing panels and the wans general wear of the water walls and wear at irregularities of various sorts including weld beads and tube bends have occurred the convection pass such as superheater tubes and economiser section the superheater panels attached to the top of the water walls in the combustor where these are included in some CFBC designs FBHEs if used and on the distributor plate especially the air nozzles in the immediate vicinity of the recycle inlet

Anders and Wechsler (1990) report that fewer material wastage problems have been found for German and other European-designed units than for the US units They attribute this to differences in design arising from different environmental requirements Units in Germany have longer reducing zones These are primarily designed to achieve better NOx removal but also result in lower solids densities in the exposed water wa]] area Longer primary zones also ensure better gas solids mixing and complete combustion thus minimising potential wastage in the unprotected water wa]] area

The rates and mechanisms of material wastage are complex functions of the characteristics of the bed material particles and the conditions occurring in the combustor as well as the design The use of fast fluid ising velocities the fine particle size and the high level of recirculation lend themselves to an erosive environment (Kalmanovitch and Dixit 1991) Protection by oxide formation on the carbon steels or low alloyed fenitic steels used in the heat exchangers is questionable especially where local high angle impacts can occur (for instance above the refractory lining) It should be noted that coal as such forms only a sma]] part of the bed The majority of the bed material consists of coal ash incompletely combusted coal or char raw limestone calcined limestone and sulphated lime or anhydrite Sand or another inert material may also be present in some units added to maintain load

There are few if any correlations between bed material properties and material wastage The ability to correlate material wastage with coal constituents has been questioned it has been suggested that both design and operating factors are more important and cannot be ignored For example particle size shape velocity and suspension density a]] of which affect wastage of heat exchanger tubes depend more on hydrodynamics than on fuel components Furthermore tube metal thickness and skin temperatures are major factors

Walerwall tube

Wastage

~

Refractory lining

Water wall tubes

Refractory lining

Figure 13 Wear on membrane wall tubes in CFBC boilers (Stringer and others 1991)

in boiler tube failure (Stallings 1991) Increasing the temperature can increase metal wastage However units of identical design and operated under apparently similar conditions have been found to have a different wastage history For example at the Pyroflow-designed Stockton plant (CA USA) water wall thickness losses of 15-40 occurred requiring their replacement after six weeks of operation (Farrar and others 1991) Similar problems were not reported at the sister Mt Poso plant (CA USA) Different coal feedstocks were used Reported experience elsewhere also suggests that certain coal constituents can have a significant influence on the wear potential of CFBC bed material although operating conditions do play an important part A survey of North American CFBC boilers found that refractory perfomlance was influenced by the fuel source (Snyder and Ehrlich 1993) The rest of this section win examine the coal properties which affect the wear of refractory and metallic components and thus the coal quality requirements for CFBC units

The coal constituents ancVor properties that can influence the material wastage potential of the bed materials include its

mineralogical composition which affects the particle size shape hardness and size distribution of the bed material alkali content and chlorine content

32


Other coal properties can also have an indirect affect on material erosion For instance when the sulphur and ash content of the coal are low it may be necessary to add inert material to maintain the bed Sand is commonly used but it can increase the erosivity by increasing the proportion of hard mineral particles in the bed (Wright and Sethi (990) Using a lower heating value coal than the design value while maintaining or increasing steam generating capacity can mean higher particle and gas velocities and ash flows This could lead to increased erosion At the Westwood power station (PA USA) high tube erosion in the top half of the superheater generating bank and the north side of all economiser sections occurred when a coal with a lower heating value than the design value was introduced and additional operational changes made (Jones 1995b)

Coal mineralogy composition can influence material wastage in a number of ways The coal ash constituent (minerals) of the bed material from one coal may be more angular than those from another coal Since angular particles are more likely to cause erosive or abrasive wear the wear potential of the bed material increases Similarly the coal ash constituent from one coal may be harder than those from another coal The abrasive wear of a surface increases as the hardness of the abrasive increases beyond that of the surface Therefore as the concentration of harder particles increases in a bcd the wear potential of the bed is also likely to increase Since hard minerals m-e likely to be less rapidly attrited than the sorbent and softer ash pm-ticles they probably have a longer residence time in the system Hence the mineral content of the bed (and recycle stream) will increase with time (Sethi and Wright 1991) Particle composition varies with particle size the amount of silicon and aluminium compounds increase and the calcium and sulphur compounds decrease with increasing particle size (Lindsley and others 1993) Particle size is influenced by the presence of partings in the coal friability of the coal ash and by agglomeration Coals that cause agglomeration (see Section 35) can increase the wear potential of a bed by increasing the average particle size Wem- damage generaJly increases with increasing particle size (Bakker and others 1993 Farrar and others 1991 Lindsley and others 1993) although size alone does not determine the wem- propensity of the bed material

In addition to these physical changes in the make-up of the bed material chemical interactions m-e also possible which can cause changes in the angularity hardness and size of the bed particles Surface coatings can develop on the coal ash constituents and sorbent-based constituents of the bed material If hard coatings develop on softer particles the wear potential of the bed material increases Conversely if softer coatings develop then the wear potential may decrease Surface coatings can cause blunting of angular particles again causing a reduction in the wear potential of bed material Small angular and hard particles could be incorporated into the surface coatings increasing the wear characteristics of the bed ash (Sethi and Wright 1991) Efficient bed ash classification (Hotta 1991) and changes in design or operating conditions have helped reduce material wastage problems

Although the angularity and hardness of particles are

important in material wear angularity is difficult to quantify In addition laboratory tests of hardness at room temperature can be misleading since it is the hardness at bed temperature that matters When deposits or coatings exist it is their hardness and not that of the underlying substrate that must be considered In assessing hardness simple tests indicating the mineralogy of the ash particles in the bed have proved a useful tool (StaJlings 1991)

Quartz is the hardest common mineral found in coal It does not fracture upon impact and is probably the primm-y coal constituent contributing to metal and refractory wear However no simple correlations relating quartz content to wear rate have been found Other hard minerals present in coal such as pyrite and alumina will also contribute to material wear Thus Korean anthracites could potentially cause erosion problems since they contain large quantities of silica (quartz) alumina and pyrites (Rhee 1994) Although Indian coals are high ash coals the ash is generally soft and their abrasivity index is low (Sen and Joshi 1991) Therefore these coals would not be expected to pose a problem in respect to material wastage

Data from the Pyroflow-designed Stockton and Mt Poso units indicated that the bed materials should give reasonably similar erosion rates for identically sized particles at identical angles and the same impact velocity (Bixler 1991) However the units had different wastage histories with the Stockton unit suffering water waJl tube erosion The wear difference can be partly attributed to differences in the physical properties and chemical interactions of the bed material and hence to the coal feedstock Although the Andalex coal used at the Mt Poso unit had the highest quartz content it gave fewer erosion problems (see Table 6)

Examination of the bed materials showed that the Stockton material contained a larger concentration of uncoated quartz pm-ticles in the size range that is typically recycled in a

Table 6 Coal ash properties (determined by ASTM mineral analysis) (Farrar and others 1991)

Mineral oxide SUFCo Andalex Skyline wt (Stockton) (Mt Poso) (Stockton)

SiOz 5321 6170 5579

AbOJ 1098 1646 1352

Fe20J 583 299 700

CaO 1715 665 1151 MgO 253 108 190

NazO 226 051 162

Alkalis as NazO 236 094 219

KzO 015 066 086

TiOz 087 082 068

MnOz 004 003

PzOs 034 SrO 016 011 011

BaO 010 014 007

SOJ 578 655 574 Free quartz 3674 3701 3551

calculated free quartz = SiOz-15Ab03

33


CFBC unit The recycle loop of the unit acts as a concentrator for particles that do not readily attrite This suggests that it is not the total quartz content of the coal that is important but its occurrence in a narrow size range Bench-scale experiments on the coal used at the Stockton unit showed that quartz particles in such a size range were present (Sethi and Wright 1991) The Mt Poso bed material contained coal ash particles including quartz particles that were coated with a surface layer The formation of coatings on bed materials generally mitigates the wear potential However the sorbent particles in the Stockton bed material deve loped a hard Ca and SiAl containing surface layer unlike the sorbent particles in the Mt Poso bed This can affect the wear potential in two ways harder than normal particles are formed and coated particles do not attrite as readily as uncoated particles and are less likely to protect a surface from damage by other harder and angular particles The calcium in the coating could have come from the inherent calcium in the coal (Sethi and Wright 1991) the calcium content of the Stockton coal was 2-3 times greater than the Mt Poso coal

The sorbent particles can also contribute to the wear potential of the bed material Limestone contains a small amount of other inorganic constituents besides calcium which can affect the hardness of the particles CCSEM analysis has shown that the limestone and sulphated limestone in the bed can be quite angular (Kalmanovitch and Dixit 1991) This is important as although the sulphated limestone has a lower hardness number than quartz the material comprises a large fraction of the bed inventory

Bench-sca1c experiments have shown that scaledeposit formation on the metal surfaces can help protect the heat exchanger tubes As the layer on the metal surface changes its character (that is thickness composition morphology and continuity) the substrate wastage rate changes The formation of deposit layers is a complex process involving chemical and mechanical actions Calcium and sulphur constituents in the bed material can help form a protective layer on the metal surface (Lindsley and others 1993) CaS04 and CaO can act as a cement to bond the layer together making it more protective However CaS04 can also have a negative effect on corrosion Tests showed that after 50 h of exposure CaS04 exerted a harmful effect on the steel resulting in increased wastage The metal wastage in the first 50 h was less than that which occurred when the sulphate was not on the exposed metal surface (Levy and others 1991 Wang and others 1991) The contribution of calcium (which can come from the coal as well as from the limestone) to deposit fOimation is discussed further in Section 35

It has been suspected that a possible contributor to material wastage in the combustor might be the alkali content of the fuel The units experiencing the highest wear rates have had the highest content of alkalis in their fuels (Hotta 1991) The chemistry of alkalis in the combustion of coals is extremely complex While potassium is generally bound with illite clays sodium is often found with the organic material (Stallings 1991) As part of the organic material sodium generally volatilises Thermal decomposition of alkali carboxylates in low rank coals starts at relatively low

temperatures well under 500degC (Sondreal and others 1993) The sodium is substantially vaporised and distributed throughout the reactor system primarily as a surface coating on particles or as discrete particles (with enrichment in the finer particle size fractions) condensation of volatile sodium species on the boiler tubes could enhance corrosion As a clay constituent sodium (and potassium) tend to be retained in the bulk aluminosilicate ash Thus the chemical association of sodium in the coals will affect its reactions and products and hence material wastage

The sodium content can influence ash fusion temperatures (agglomeration) and post-combustion mineral composition which affects slag development particle size and mineral hardness (Farrar and others 1991) While the coatings on bed materials are generally caused by alkali-induced low melting point eutectics the use of limestone increases the complexity of the chemistry (Stallings 1991) The impact of sodium on the formation of Na-AI-silicate agglomerates was postulated as a cause of the high rates of wastage in the Stockton plant The Stockton bituminous coal had appreciably more sodium than the Mt Poso bituminous coal (see Table 6) Na-AI-silicate particles were found in the Stockton bed material whereas no sodium-rich particles were found in the Mt Poso bed material These sodium-rich particles were harder than the aluminosilicate particles in the Mt Poso material (Slusser 1991) Farrar and others (1991) found similar levels of sodium in the bed and loop seal ashes from all three coal feedstocks at the Stockton and Mt Poso plants This indicates that sodium compounds are preferentially associated with elutriated materials or are lost as volatile species Sodium levels in the coal did not seem to determine the sodium concentration in the bed as all the bed and loop seal ash samples had approximately the same Na20 levels

Alkali attack may be a factor in refractory failures in the combustor and cyclone separators as alkalis have been shown to weaken refractories in laboratory tests (Stringer and others 1991) Weakening of refractory by alkali penetration followed by accelerated corrosion has been proposed to explain the unexpected changes in lining deterioration especially following a change in feedstock However Bakker and others (1993) found no increase in erosivity attributable to alkali In fact some refractories (the phosphate bonded plastics) became more erosion resistant when heated with alkali-containing bed materials In the tests the refractories were packed in bed materials with up to 15 alkali added and heated at 982degC for 24 h This temperature may not have been high enough as alkali attack on refractories is temperature dependent OCCUlTing at 1100-1 400degC (Sondreal and others 1993) Since FBC systems operate below these temperatures alkali attack on refractories should not be a problem

Chlorine in coal is generally released as HCl gas during combustion Little sorbent capture occurs in the bed due to unfavourable thermodynamics (Stallings 1991) Corrosion of boiler tubes could therefore occur when burning high chlorine coals Early operating experience at the recently commissioned Pt Aconi station (Nova Scotia Canada) has shown evidence of corrosion in the superheater tubes A high sulphur subbituminous coal with a chlorine content of about 05 was used Analysis of the deposits suggested that the

34


tubes were suffering from chlorine attack This problem although not critical at this stage could become severe (Campbell 1995) However Stencel and others (1991) found that of the coals tested the coal with the lowest chlorine content produced the highest wastage of the in-bed heat exchanger tubes The tests were carried out in a 12 MWt BFBC combustor using bituminous coals with chlorine contents of 021 and 06 and in addition with HCI gas added to the 06 coal Higb chlorine Illinois coals have been used in PC-fired units without causing corrosion problems although corrosion has been reported in some plants burning high chlorine British coals It has been suggested that other factors such as how the chlorine occurs in the coal or the influence of other substances such as the alkali metals and sulphur may be important when evaluating the potential corrosiveness of a coal (Chou and others 1995)

To conclude there may be some limitations in coal use in CFBC units The properties of a coal can influence both refractory and metal wastage However the rates and mechanisms of material wastage are complex functions of the characteristics of the bed material particles and the conditions occurring in the combustor as well as the design A coal that causes material wastage in one unit may not create problems in another unit with a different design More needs to be known about the impact of bed material constituents on metal wastage in order to better select coals or to take their properties into account when designing the CFBC boiler At present the wear potential of a bed consisting of a mixture of different types of particles (derived from the coal and limestone) cannot be deduced from the wear potential of the individual particles

37 Practical experience with waste coals

Circulating f1uidised bed boilers have been commended for their ability to cope with fuels that might be described as high grade dirt By 1993 two dozen or so CFBC power plants were in operation in Pennsylvania and West Virginia USA firing coal mining wastes (Makansi 1993) However experience has shown that careful engineering in the areas of fuel preparation fuel feed and ash removal is required The reliability of the coal handling and feed system can have a major impact on both plant availability and profitability (Jones I995b) The f1exibility of CFBC boilers to bum a variety of fuels is largely dependent on the design and capacity of the solids feed and ash removal systems (Friedman and others 1990) To illustrate these points some experience of operators using particularly difficult fuels is discussed

In Pennsylvania USA a long history of mining bituminous coal and anthracite has resulted in the accumulation of more than a billion tonnes of coal wastes (Kavidass 1994) Anthracite coal has been mined in Schuylkill County PA for over 100 years As a by-product of this activity millions of tonnes of mining wastes called anthracite culm have been deposited in piles resembling small mountains The other major coal waste in Pennsylvania is bituminous gob an accumulation of middlings from the washing of bituminous coal Projects were conceived

to use these wastes as a direct result of the US Public Utilities Regulatory Policies Act (Thies and Heina 1990) The Act confers a number of benefits on small independent power producers (Schorr 1992) and has provided an incentive to use the low grade coal wastes in small CFBC units Four of these Pennsylvania project~ are described

The Gilberton Power Facility in Frackville PA began commercial operation in 1988 The plant has a capacity of 80 MWe from two circulating fluidised bed boilers operating in parallel The culm is beneficiated before use Heavy media washing reduces the mineral matter content of the fuel and increases the heating value to approximately 18 MJkg The fuel is not thermally dried and can contain up to 18 water after draining A number of difficulties were encountered in preparing and feeding this highly corrosive and erosive material The carbon steel fuel silos suffered an unacceptable rate of wear and had to be fitted with stainless steel liners The coal was fed to the combustor using drag chain conveyors and these suffered higher than anticipated forced outage rates because of abrasive wear Front wall feed pluggage and pluggage in other fuel feed system components occurred due to the high fuel moisture Clearing the pluggages proved to be labour intensive (Wert 1993) Another CFBC power plant the Panther Creek Energy Project located in Nesquehong PA is a duplicate of the Gilberton plant with modifications based on Gilbertons operating experience Belt feeders were specified instead of the drag chain conveyors Jig washers were specified to improve the quality of the fuel and it was decided to control the moisture content of the fuel feed at 12 maximum by improved drainage (Wert 1993)

The St Nicholas Project located near Mahanoy PA was designed to exploit a reserve of approximately 37 Mt of culm (Thies and Heina 1990) The steam generator for this 80 MWe unit is a single CFBC boiler designed for fuel having a higher heating value of 65 MJkg Initial firing using anthracite culm began in October 1989 The culm as recovered contains approximately 15 of coarse rock and the first stage of preparing the material for combustion is the removal of the rock using a 100 mm scalping screen The -100 mm material is then crushed to -25 mm and dried to a moisture content of 9 or less before feeding to the CFBC storage bunkers For a more reactive fuel a single stage of size reduction to -6 mm would have been adequate In the case of the culm however secondary crushing to - 16 mm was found necessary to give satisfactory carbon utilisation A typical analysis of the fuel to the boiler is shown in Table 7

Table 7 Typical analysis of anthracite culm (Thies and Heina 1990)

HHV MJkg 65

Moisture 9

Analysis wt db

Ash 735

Carbon 22

Hydrogen I Oxygen 25

Sulphur 05 Nitrogen 05

35


The Ebensburg cogeneration plant at Ebensburg PA was designed to exploit bituminous gob (33-46 ash 75-12 moisture) The second largest contributor to forced outages at the Ebensburg was fuel injection screw repairs (Kavidass 1994) The bituminous gob is erosive and caused the original stainless steel material of the injection screw to wear out after only 2-3 months in service The screws have been modified using a new weld material and this has allowed them to operate between scheduled outages with minimal maintenance The mineral matter in the waste coal contains fine clay particles which especially during inclement weather collect moisture causing the coal to become sticky This has caused a variety of handling problems such as pluggage in the coal crusher inlet and outlet chutes When coal moisture was high stalling of the fuel feed occurred due to a crust of coal forming on the screw housing at the back half of the 4 m long screw Replacement with a shorter injection screw has eliminated stalling (Belin and others 1991 )

The Cambria cogeneration facility near Ebensburg PA was designed with the benefit of the experience that other operators have accumulated in dealing with bituminous gob The fuel handling and feeding system includes a weather-protected six day supply of bituminous gob equipment for separating out oversized materials (oversize material has contributed to pluggage problems in feed lines) and fuel drying to improve the flow ability and handling characteristics (Jones 1995b)

An 80 MWe CFBC plant located near Grant Town WV USA has achieved high availability by using a carefully prepared bituminous gob Waste coal and silt type fuels are received separately TIley are blended to achieve a consistent heating value screened crushed washed and centrifuged to produce a dry material sized -6 mm The fuel processing operation rejects approximately 20 of the incoming material from the gob piles Screening rejects pyritics over 100 mm and bottoms less than 500 11m Washing the mixture removes clay and clay-like material (Castleman and Mills 1995 Makansi 1993)

The combustion of coal wastes using BFBC and CFBC boilers in several countries has recently been reviewed by Anthony (1995) The 1200 MWe PC-fired Emil Buchet power station Carling France uses fine material laquo1 mm) rejected from the washing of bituminous coal (schlamms) The rejects are pumped to the power station as a black liquid concentrated vacuum filtered and dried to about 8 water before being pulverised for firing Since 1950 rejects have also been sent to settling ponds and a total of around eight million tonnes has now accumulated The material in the ponds is unsuitable for PC firing because of its high clay content it induces severe slagging The new 125 MWe CFBC plant was selected because it was able to use both freshly produced schlamms and recovered pond material while complying with new stricter regulations on S02 and NOx emissions Fresh schlamms are mixed with dried wastes to produce a slurry with a solids content of about 70 After final preparation the slurry is pumped to storage where it is kept in suspension by air injected into the base of the storage tanks The slurry is fed into the CFBC through six

independent feed systems Each system has two piston pumps and a pipeline which leads to an injection lance at the base of the reactor TIlere is provision for removing the lance and isolating the injection port in case of blockage TIle unit is capable of operating with fuel mixtures ranging from a slurry with 33 water content to dry schlamms Unit availability was 83 in 1991 and 938 in 1992 (Anthony 1995 Lucat and others 1991)

38 Air pollution abatement and control

CFBC boilers are capable of achieving relatively low levels of the primary pollutants S02 and NOx (defined as N02 + NO) without the need to add expensive pollution control equipment S02 emissions are controlled in situ through the injection of sorbent into the furnace section of the boiler The low combustion temperature of around 800-900degC limits the formation of NOx Despite these low temperatures CO and unburned hydrocarbon emissions are also low as the result of good solids and gas mixing and long residence times in the bed (Friedman and others 1993) Particulate emissions can be controlled effectively using conventional fabric filters (baghouses) or electrostatic precipitators The emission of air toxics (mercury lead and other metallic components) are lower in AFBC and PFBC plants than conventional PC-fired boilers (Lyons 1994) however N20 emissions are higher N20 plays a major role in ozone depletion in the stratosphere and is a potent greenhouse gas

Most countries have legislation restricting S02 NOx and particulate emissions from coal-fired plants These standards are addressed in another report (Soud 1991) and are updated on an lEA Coal Research database (lEA Coal Research 1995b) The actual emission limits from FBC plants are generally set by negotiation between the plant owner and local authority they are usually much lower than national emission standards N20 emissions have not yet been regulated Emissions from CFBC plants have generally met the designated limits For instance coals with up to 34 sulphur have been fired in CFBC boilers in Japan whilst meeting the required emission limits (Nowak 1994) Takeshita (1994) has tabulated emissions from commercial FBC plants in a number of countries whilst Nowak (1994) gives S02 and NOx emissions from CFBC boilers in Japan

Emissions from CFBC boilers vary with coal type operating conditions (such as temperature and excess air level) and combustor design The effects of coal properties on S02 NOx N20 and particulate emissions and results from commercial CFBC boilers will be discussed in the following sections Emission control strategies have been covered in other lEA Coal Research reports (Bjalmarsson 1990 1992 Takeshita 1994)

381 Sulphur dioxide

Most of the sulphur in the coal is converted to sulphur dioxide and absorbed by the sorbent (limestone or dolomite) The sulphur capture mechanism occurs predominantly via calcination of the sorbent to fornl calcium oxide (CaO)

36


followed by sulphation of the CaO The resultant product calcium sulphate (CaS04) becomes mixed with the fly ash and bottom ash It is removed from the boiler in a dry form for disposal (see Section 39)

Sulphur capture performance is generally measured by the molar ratio of calcium in the sorbent to sulphur in the fuel (CaS molar ratio) Another measure is calcium utilisation this is a measure of the moles of calcium in the sorbent that are converted to CaS04 divided by the moles of calcium initially present A disadvantage of in situ desulphurisation in FBC is the higher sorbent consumption required to meet the same environmental standards as PC-fired plants A CaS molar ratio of 2-4 for 80-95 S02 removal in FBC only gives a calcium utilisation efficiency of 25-50 (Takeshita 1994) The rest remains unreacted Table 8 provides an indication of the amount of dolomite that would be required for coals with various sulphur contents As can be seen a large amount of sorbent is required for S02 control creating a large amount of residue for disposal It is therefore important to reduce the sorbent consumption in order to minimise the costs for sorbent and residue management

The sulphur content of the coal primarily determines the amount of sorbent required to achieve a given S02 removal limit and thus the required capacity of the sorbent and ash handling systems Lower sulphur content coals result in lower sorbent and ash disposal costs and a cOlTespondingly lower cost of electricity Higher sulphur coals also lower the thermal efficiency via heat losses from the removal of greater quantities of hot solids (Hajicek and others 1993) Some coals such as western US low rank coals contain a substantial amount of alkali and alkaline earth metal oxides (CaO MgO Na20 K20) in their ash Combustion studies have shown that these coals can achieve high percentages of sulphur retention (S02 and S03) in the ash thus influencing the limestone requirement However the extent of this inherent sulphur capture depends not only on the amount of these elements (particularly calcium) but also on their form of occunence in the coal (as well as combustor operating conditions) A detailed characterisation of the forms of these elements in the coal can help optimise sorbent selection preparation and consumption However this information cannot be obtained from conventional ash chemical analyses

Table 8 Sorbent requirement

Coal sulphur

06 15 2 6

CaS molar ratio Sorbent required as of coal feed weight

11 345 575 863 I 15 345 15 1 518 863 1294 1725 5176 2 1 690 1150 1725 2300 6901 251 863 1438 2157 2875 8626 3 I 1053 1725 2588 3450 10351

Laboratory techniques are being developed that can quantify the forms of the elements in coals thus providing a means of predicting inherent sulphur capture in fuJI-scale boilers A chemical fractionation technique was used by Conn and others (1993) to quantify the reactive and inert forms of calcium in different lignites The reactive forms of calcium are the organically bound calcium (which is released as fine particulates that are reactive with other minerals and S02) and the carbonate calcium Calcium contained in clay structures remains bound at CFBC temperatures and can therefore be considered inert If the mineral debris (which can be a major component of coal washery rejects) is partly limestone or shale then this can additionally contribute to sulphur capture (Anthony 1995) Coal washery rejects are fired in a number of CFBC plants

Desulphurisation efficiencies of over 90 have been achieved without the addition of limestone at the 93 MWt Pyroflow-designed CFBC boiler at the Aluminium Pechiney Gardanne plant France (Seguin and Tabaries 1992) The high sulphur high ash lignites contain 42-59 wt CaO in their ash providing a high inherent sulphur capture Large fluctuations in the 48 h averages of S02 emissions were observed that could not be COlTelated to variations in the load of the boilers Examination of the two different seam coals used showed that the Estaque lignite contained a much lower proportion of reactive calcium than the Eguilles lignite For the former S02 and S03 produced during combustion cannot be totally removed without adding limestone These authors define an index for the inherent sulphur capturing ability of a coal (self-refining capacity R) as

R = CarSr

where Car is the number of reactive calcium moles in the coal and Sr is the number of reactive sulphur moles in the coal

Sulphur emissions from coals ranging in rank from lignite to bituminous have been investigated in a 1 MWt CFBC test facility (Hajicek and others 1993 Mann and others 1992b) The composition of the coals is given in Table 9

Results from these investigations can be extrapolated to full-scale operation since S02 NOx and CO emissions were found to be similar to those from the Nucla station CO USA (when using the same coal and limestone) However N20 emissions were higher The amount of sulphur capture was primarily determined by the total alkalisulphur ratio (basically the total CaS molar ratio) The total alkali is provided by the mineral matter and cations contained within the coal and the alkali in the added sorbent (in this case Ca in the limestone) The forms of alkali in the coal as well as various combustor operating conditions especially temperature were also important The amount of sorbent addition required to meet a given S02 level varied greatly with coal and sorbent type The CaS ratio required to retain 90 of the coal sulphur ranged from 14 to 49 depending on coal type (see Figure 14)

A survey of commercial CFBC boilers in Japan also found assuming that the sorbent is pure dolomite (CaCOMgCO) that the amount of sulphur capture was primarily determined

37


Table 9 Analysis of the coals (Hajicek and others 1993)

Asian Center Black Thunder Salt Creek Blacksville lignite lignite subbituminous bituminous bituminous

Higher heating value ar MJkg 9051 16112 20085 23856 30822

Proximate analysis ar wt Moisture 170 371 276 77 29 Volatile matter 374 290 332 310 351 Fixed carbon 76 289 346 427 538 Ash 380 51 46 186 82

Ultimate analysis ar wt Carbon 250 409 499 588 744 Hydrogen 43 70 66 50 53 Nitrogen 07 05 06 11 13 Sulphur 61 07 03 04 24 Oxygen 261 458 380 160 84

Ash composition ar wt CaO 199 226 244 15 56 MgO 33 102 79 15 12 Na20 03 37 05 02 07 Si02 306 145 285 599 436 Ah03 124 97 164 309 227 Fe203 137 161 64 30 166 Ti02 02 03 14 ll 07 P20S 05 07 13 04 04 K20 ll 04 09 10 17 S03 181 219 124 10 68

7

6

o

70 sulphur retention

IlIl 90 sulphur retention

bull 95 sulphur retention

NA NA


Coal type

Bed temperature 843degC

NA Not applicable

Figure 14 Added CaS molar ratio required for increasing sulphur capture as a function of coal type (Mann and others 1992b)

by the CalS molar ratio which varied greatly with coal and sorbent types (Nowak 1994) But looking only at the CalS ratio to detelmine how much sorbent addition is required can be misleading For example although a CalS molar of 49 is required to meet 90 sulphur retention for the Salt Creek bituminous coal versus 14 for the Asian lignite the total amount of sorbent addition required is much less for the Salt


IlIl 90 su Iph ur retentio n 25

- ~20 0

oi c ~ 15 ltll

S as 10 0 0 ltl

5

NA



NA Not applicable


Coal type

Figure 15 Added limestone required for increasing sulphur capture as a function of coal type (Mann and others 1992b)

Creek coal (see Figure 15) A sorbent addition rate of about 17 gMJ of Salt Creek coal input is required versus 267 gMJ for the Asian coal due to differences in the sulphur and alkali contents in the coals as well as differences

in heating value

The optimum bed temperature resulting in maximum sulphur capture varies with coal type The bituminous coals investigated showed optimal sulphur capture at combustor

38

temperatures of about 843degC (1550degF) whereas the temperature was about 38degC (100degF) lower for the low rank coals Properties of the coal that are most likely influencing this optimal temperature include the forms of the sulphur and alkali as well as the moisture content (Hajicek and others 1993 Mann and others 1992b 1993) The optimum temperature is also a function of design and so would need to be determined for each CFBC boiler (Friedman and others 1993) TIle quality and size of the limestone also affects sulphur capture

As well as coal type the operating conditions (and boiler design) influence sulphur capture efficiency Thus the operating parameters require optimisation for each plant in order to keep emissions within the required limits For example gaseous emissions from the Pyroflow-designed 110 MWe CFBC boiler at the Nucla station CO USA have been investigated over a wide range of operating conditions (Basak and others 1991 EPRI 1991) Two low sulphur (04 and 07) US western bituminous coals were fired The maximum allowable S02 emission limit for the station is 170 mgMJ and a 70 sulphur retention A correlation was developed for sulphur retention with CaS molar ratio for bed temperatures below 882degC TIle high temperature tests did not fit this correlation since limestone utilisation decreased at clevated temperatures The CaS molar ratio necessary to attain 70 90 and 95 sulphur retention were 16 31 and 40 respectively The CaS molar ratio only includes the calcium from the injected limestone At bed temperatures from 882 to 927degC the CaS molar ratio nearly doubled to achieve 70 sulphur retention

TIle coal feed distribution also affected the CaS molar ratio requirement Excess air alone had little impact on sulphur retention However with lower excess air bed temperature increased and limestone utilisation decreased Thus in this unit from a sulphur capture standpoint the excess air needs to be kept at higher levels primarily to control bed temperature Takeshita (1994) discusses other findings that show that as oxygen concentration decreases S02 emissions increase The ratio of secondary air to primary air also had a minimal effect on sulphur retention at the Nucla station The effect of air staging on sulphur retention is complex because both reducing and oxidising zones occur in a CFBC boiler Air staging (for controlling NOx emissions) may adversely affect S02 removal (Takeshita 1994)

At the ACE 108 MWe CFBC boiler CA USA reduced loads were found to increase sulphur capture A low sulphur (03-05) bituminous coal is fired It is estimated that the inherent sulphur capture by the calcium in the coal ash is between 50 and 70 When this is taken into account the full load peIformance of this unit is similar to the performance of the Nucla plant (Melvin and others 1993)

Recirculation of fly ash collected by cyclones or baghouseselectrostatic precipitators into the combustor can increase sulphur retention calcium utilisation and carbon burnout The reduction of S02 emissions through fly ash recirculation enabled the limestone feed rate to be reduced by 30 at the 50 MWe Mt Poso CFBC boiler CA USA (Beacon and Lundqvist 1991) A low sulphur subbituminous


coal was used The effect of operating conditions on S02 emissions has been more fully reviewed by Takeshita (1994)

The following will discuss S02 emission from plants burning low quality coals or waste coals The 250 MWe boiler at the Provence power plant Gardanne France has recently been fired (end of 1995) A high sulphur (37) high ash (28-32) subbituminous coal (HHV 1557 MJkg) is used The coal has a high calcium content (ash 57 CaO) giving a natural CaS molar ratio of 15-25 Some limestone from mine waste is added to achieve 97 S02 removal at a total CaS molar ratio of less than 3 This percentage removal satisfies the requirement to limit S02 emissions below 400 mgm3 (laud and others 1995)

The two Tampella-designed CFBC boilers producing 80 MWe at the Scrubgrass plant PA USA burn high ash waste coal (bituminous gob) The plant is required to keep sulphur retention above 95 and its S02 emission rate to below 194 mgMJ The fuel comes from a number of mines and processing sources which has created problems The fuel characteristics varied considerably depending upon the mine and fuel processing Full load was readily achieved with some blends but not with others even though the fuels used generally fell within the contract limits fuel sources mixing and processing were critical for consistent and reliable operation The fuel ash split of bottom ash to fly ash was not the expected 40 to 60 based on pilot plant testing but was instead 10 bottom ash to 90 fly ash This resulted in low solids recirculation rates and consequently lower heat transfer rates and higher operating temperatures The high combustor operating temperatures of 900 to 940degC resulted in excessive limestone consumption rates and elevated NOx levels In addition the fuel sulphur levels were at or below the fuel contract range which made achieving 95 sulphur retention difficult while maintaining NOx levels at or below the permitted 130 mgMJ The possibility of fuel selection as a solution was unacceptable to the operator Therefore process optimisation and equipment modifications were introduced in order to obtain full load with emission compliances for the full range of fuels (Sinn and Wu 1994)

Emissions from the Scrubgrass and Nucla plants have been compared by Jones (1994) The relationship between CaS molar ratio and temperature demonstrated for the low sulphur bituminous coal at Nucla parallels that which is seen at Scrubgrass The flue gas S02 concentrations were roughly the same This suggests that temperature and flue gas S02 concentration are the most significant factors influencing limestone requirements In addition coal slurries from preparation plants have been shown to compare favourably with dry coal in temlS of CaS molar ratio requirements (Rajan and others 1993)

Coal water slurries (comprising coal washery residues and schlamms that is fine washery residues) or dry schJamms are fired at the 125 MWe Lurgi-designed CFBC boiler at the Emile Huchet power station Carling France These fuels have a relatively low sulphur content of about 06 and 075 respectively S02 emissions of 285 mgm3 were achieved with CaS molar ratios close to 25 Again S02 emissions decreased as CaS molar ratios increased (Joos and

39

---


Masniere 1993) It has been suggested that desulphurisation may additionally occur in the baghouse filter where unreacted CaO has collected However this was not observed at this plant (although the margin of error of 10 may be obscuring this trend)

Thus CFBC units can burn coals of high sulphur content andor low quality while meeting the required S02 emission limit if the plant is designed for the fuel and the operating parameters are optimised The high calcium content of some low rank coals can reduce the amount of sorbent require to achieve a given S02 capture efficiency

382 Nitrogen oxides

NOx emissions from CFBC boilers are inherently low because the contribution from thermal NOx (from nitrogen contained in the combustion air) is negligible due to the low combustion temperature in the combustor Emissions are also controlled by the staged addition of air which creates substoichiometric conditions in the lower part of the combustor However appreciable amounts of N20 are produced at these temperatures Both NOx and N20 emissions are thus dependent on the fuel properties generally being highest for coals with the highest nitrogen contents (under the same operating conditions) The nitrogen content of the coal determines the theoretical maximum emission of NOx for a given coal and operating conditions (Tang and Lee 1988) However prediction of final NOx and N20 emissions is much more complicated as yields are also influenced by the coal type and rank and the homogeneous and heterogeneous reactions occurring within the combustor as well as its design The chemistry of NOx and N20 formation and reduction during coal combustion is complex and still not fully understood and will not be covered Hayhurst and Lawrence (1992) Johnsson (1994) Mann and others (1992c) and W6jtowicz and others (1993) have reviewed this topic This section will discuss the influence of the properties of coal on NOx and N20 emissions and summarise the effects of operating parameters before

350 Excess air 20-25 Salt Creek bituminous Velocity 5ms

Alkali-to-sulphur ratio 15-251300 Center lignite - -Igt --

Blacksville bituminous 0middotmiddotmiddotmiddot0-middotmiddotmiddot250

Black Thunder subbituminous

200 Asian lignite --0-shy

150

100

50

Or------------------------ 700 750 800 850 900 950

Average combustor temperature degC

discussing results from some commercial plants burning different coals and coal wastes

NOx emissions from five coals of different rank (see Table 9) have been investigated in a 1 MWt CFBC facility (Hajicek and others 1993 Mann and others 1992b 1993) In Figure 16 their NOx emissions as a function of temperature are compared

The different NOx levels are caused by inherent differences in the nitrogen associations in the coals The nitrogen in the bituminous coals is released as CN while the lower rank coals release more of the nitrogen as ammonia The distribution of the nitrogen between the volatiles and char influences fuel NOx (and N20) emissions it varied significantly between the coal ranks and was partly responsible for the trends shown in Figure 16 Not only does the total amount of NOx emitted vary with coal type the correlation between the rate of NOx emission and the operating temperature also varies with the coal type The lignites had the smallest rate of increase of NO x emission with temperature and the bituminous coals the greatest The results indicate that lignites emit higher concentrations of NOx than bituminous coals at lower temperatures (843degC) but emit less NOx at higher temperatures Since CaO can catalyse the oxidation of volatile nitrogen to NOx the emissions of these species increase with increasing CaiS molar ratio (Hjalmarsson 1992) Hence S02 emission targets requiring higher CaiS molar ratios may have an adverse affect on NOx emissions Increasing the airfuel ratio also leads to higher NOx emissions A small decrease in NOx

(and S02) yields occurred when finer brown coal particles were burned at a 12 MWt CFBC pilot-scale facility this also resulted in a better burnout of the particles (Kakaras and Vourliotis 1995)

Data from the 1 MWt facility indicate that N20 emissions increase in the following order subbituminous lt lignite lt bituminous (Hajicek and others 1993 Mann and others 1992b 1993) as indicated in Figure 17

Asian lignite No limestone addition

--

~15 E

c o (jj (f)

E10 agt c agt Ol

-~ Z 5

Center lignite Bed temperature 843degCE 26degcm Black Thunder sUbbituminous Vx~es ~r deg

III Salt Creek bituminous e OCI y m s

III Blacksville bituminous

Figure 16 NOx emissions as a function of combustor Figure 17 NOx and N20 emissions as a function of coal temperature (Mann and others 1992b) type (Mann and others 1992b)

40


This same trend is reported for seven coals (an additional bituminous and subbituminous coal) tested at the same facility by Collings and others (1993) However the effect of rank has been queried (Davidson 1994) since their bituminous coals had higher nitrogen contents than their lower rank coals Nevertheless a rank effect might be inferred when the percentage conversion of fuel nitrogen to N20 is considered Boemer and others (1993) also found that the brown coals investigated gave much lower N20 emissions than the bituminous coals The distribution of the nitrogen between the volatiles and char appears to be an important coal property affecting N20 emissions during devolatilisation brown coal releases fuel nitrogen mainly as ammonia an important precursor of N20 As the volatile and moisture contents of the coals increase and the fixed carbon and heating value decrease N20 yields decrease All these properties are indicative of the rank and may be predicting the rank-dependent function of coal on N20 emissions (Collings and others 1993) N20 emissions show an opposite trend found for NOx decreasing with increasing temperature and sorbent addition rate but a similar trend for excess air (Boemer and others 1993 Collings and others 1993 Mann and others 1992b) The effect of excess air is stronger at lower temperatures than at higher temperatures for N20 Limestone feed rate was observed to have little influence on N20 emissions in a number of commercial plants but bench-scale tests have shown an effect (Takeshita 1994) The influence of air staging on N20 is not clear However air staging outside certain limits may reduce the sulphur capture performance (Friedman and others 1993)

NOx and N20 emissions also vary with boiler load In boiler designs where temperatures are lower at partial load NOx emissions increase while N20 emissions decrease with increasing load (Boemer and others 1993 Nowak 1994) However in a Circofluid boiler although lower freeboard temperatures occurred N20 and CO emissions remained approximately constant due to the longer gas residence time In a boiler with an external FBHE combustion temperatures were similar over the range of boiler loads investigated the NOx levels decreased as the load increased whereas N20 emissions were mostly unaffected

N20 emissions from a I MWt facility were higher than those from the Nucla plant CO USA using the same coal and limestone however NOx emissions were similar (Mann and others I992b) This trend is also consistent with that found by other researchers It may be due to wall effects and other features associated with the smaller scale Thus N20 emissions derived from bench- or pilot-scale tests will overestimate those from fun-scale units NOx emissions from bench-scale units were lower than those from operating CFBC boilers (Nowak 1994) By accurately predicting NOx yields the appropriate method of additional NOx reduction (if required) can be assessed

NOx emissions from CFBC power plants have been within their regulated limits For instance at the I 10 MWe Nucla plant CO USA the maximum allowable emission limit for NOx (220 mgMJ) was easily met actual emissions did not exceed 150 mgMJ The bituminous coal had a nitrogen

content of 09-11 wt As expected NOx emissions increased with increasing bed temperature excess air and limestone feed rate In addition the coal feed distribution affected NOx levels The 100 front wall coal feed test produced significantly higher NOx yields than all the other feed configurations (there is an additional coal feed port in the bottom of the loopseal) However the lowest limestone utilisation occurred when all the coal was fed through the two front wall feed ports (Basak and others 1991 EPRI 1991) N20 emissions decreased linearly with increasing temperature and increased with increasing excess air There is thus a tradeoff between the optimum bed temperature and excess air level for S02 NOx and N20 emissions Sorbent feed rate had no effect on N20 (Brown and Muzio 1991)

The 250 MWe No4 unit of Provence power plant Gardanne France is being repowered using a CFBC boiler The guaranteed NOx emission limit is 250 mgm3 (laud and others 1995 Thermie Newsletter 1994) A high sulphur high ash subbituminous coal with a nitrogen content of 097 (ar) is used

The Scrubgrass power plant PA USA burns bituminous gob (supplied from a number of different sources) in two CFBC boilers to produce about 80 MW electrical power Higher than expected combustion temperatures resulted in increased NOx emissions Testing demonstrated that with the range of supplied fuels (higher heating values 116-209 MJkg) NOx emissions increased with increasing temperature excess air and limestone flow The primary limiting factor for fuJI load boiler operation was maintaining the NOx levels below the regulated 130 mgMJ After process optimisation was exhausted equipment modifications (additional combustor surface) was introduced so that fuJI load with fuJI emission compliance could be achieved Performance testing showed NOx emissions of less than 86 mgMJ (Sinn and Wu 1994)

Jones (1994) compared NOx emissions from the Nucla plant (bituminous coal nitrogen content 12 wt dry) with those from the Scrubgrass plant (bituminous gob nitrogen content 08 wt dry) While NOx emissions were sensitive to temperature when burning both types of fuel they were more sensitive to temperature at the Nucla plant Concentrations of oxygen in the flue gas and limestone feed rates may additionally be intluencing the formation of NOx at Scrubgrass

NOx emissions from the Ebensburg cogeneration plant PA USA which burns low volatile bituminous gob were consistently low being 22-30 mgMJ (Belin and others 1991) They were lower than the NOx emissions from the Lauhoff Grain CFBC boiler IL USA which burns high volatile bituminous coal A possible contributing factor may be the effect of NOx reduction due to the continuing combustion of char throughout the furnace and U-beam particle collector region Another contributing factor could be lower calcium concentration in the bed material (higher CaO in the bed leads to greater NOx formation) The nitrogen contents of the fuels are not given

NOx emissions from a coal-water slurry and a standard dry

41


run-of-mine coal (moisture content 676 wt ar) have been compared using a bench-scale CFBC facility (see Figure 18)

The run-of-mine coal was originally used in the coal preparation plant from which the coal-water slurry comes The run-of-mine coal has a higher nitrogen content (189 wt dat) than the slurry coal (182 wt dat) This could increase its NOx emissions However this is offset by the higher slurry coal feed rates necessitated by its lower heating value (22 MJkg dry compared to 27 MJkg dry for the run-of-mine coal) This is further accentuated by the necessity of providing the latent heat of evaporation and sensible enthalpy for the 54 wt water present in the slurry Slurry coal feed rates under these circumstances are therefore actually higher than the run-of-mine coal feed rates and fuel nitrogen feed rates follow this trend Thus the lower NOx levels seen in Figure 18 are the result of the lower temperatures experienced by the slurry droplets during their tenure in the bed The NOx emissions from the run-of-mine coal are twice that from the slurry coal and result from the generally higher reaction temperatures around the coal particles during the devolatilisation and char combustion phases In addition the combustion efficiency of the coal slurry was higher than the run-of-mine coal due to the longer residence time of the slurry droplets in the bed and the smaller particle size distribution of the coal comprising the slurry droplet (Rajan and others 1993)

Coal-water slurries and dry schlamms are fired at the 125 MWe Emile Huchet power plant France For a 85 coal-water slurry measurements showed that the NO concentration effectively tripled (from 30 to 90 ppmv) when the excess air was increased from 7 to 30 For dry schlamms NO concentrations were higher 70 to 110 ppmv when the excess air was increased from 15 to 30 The difference probably stems from the different fuel nitrogen contents 065 and 08 for the coal-water slurry and dry schlamms respectively With dry schlamms as the fuel N20 emissions more than trebled over a 35degC interval (temperature range was about 865-830degC) and increased threefold when excess air was increased from 15 to 40 (Joos and Masniere 1993) This gives some indication of the importance of effective control of operating parameters as a means of minimising NOx and N20 emissions

400

~ 0

300 o

E en Dry run-ai-mine coal c ~ 200 (J

E Coal-water slurry ~ (J)

OX 100 z

O-----------r-------~--__r--____

750 775 800 825 850 875 900 Temperature degC

Figure 18 Bed temperature effects on NOx emissions from slurry and dry coal (Rajan and others 1993)

As discussed the effects of operating conditions on NOx

yields have generally been found to be opposite to the effects on N20 (with one notable exception excess air) This complicates any measures taken to control these emissions The effects of operating conditions on S02 is a further complication Therefore the final selection of operating parameters must consider the interrelationships between all the air pollutants as well as combustion efficiency

Apart from optimising operating parameters additional measures for further reducing NOx are available Nearly all plants use primary measures to minimise NOx emissions Where NOx emissions are stringent selective non-catalytic reduction (SNCR) or selective catalytic reduction (SCR) techniques can be used in addition In SNCR a reagent (ammonia or urea) is injected into the combustor cyclone or after the cyclone With SCR a catalyst is included SNCR is used at the 108 MWe ACE cogeneration facility CA USA The ammonia is injected at the cyclone inlet ducts to reduce NOx levels to the permitted 65 ppmv (404 mgMJ) at full load A low sulphur western US bituminous coal (nitrogen content 119-143 wt) is used Tests have shown that emissions of ammonia (ammonia slip) were not significant stack ammonia emissions averaged less than 4 ppmv (corrected to 3 vol dry 02) (Melvin and others 1993) At the 50 MWe Mt Poso plant CA USA a reduction of 70 was achieved with a NH3NOx molar ratio of 25 Increasing the combustor temperatures reduced ammonia consumption but often at the expense of calcium utilisation (Beacon and Lundqvist 1991) Gustavsson and Leckner (1995) have suggested that N20 emissions might be reduced through afterburning in the cyclone without affecting S02 NOx and CO emissions

A detached white plume is occasionally generated at the Stockton cogeneration plant PA USA (Jones 1995b) The plume is formed when excess ammonia reacts with the chlorides present in the fly ash to form ammonium chloride Although the plume rapidly dissipates at times it causes the plant to exceed its 20 opacity limit In addition when the load drops below 65 the facility is not able to meet its NOx requirements This is because operating temperatures which affect NOx removal by SNCR are lower The use of ammonia can also increase N20 and CO emissions (Brown and Muzio 1991) The advantages of SCR over SNCR involve low ammonia slip and a less adverse effect on CO and N20 emissions (Takeshita 1994) However utilisation of SNCR and SCR means another area requiring process optimisation to meet performance goals and minimise operating expense

383 Particulates

The particulates produced by FBC boilers have characteristics different from those of the particulates produced by PC boilers These differences have implications for the performance of particle collection devices (electrostatic precipitators andor fabric filters) AFBC boilers are operated below the ash fusion temperature of the coal This results in irregularly shaped fly ash particles compared to the spherical PC fly ash particles that form from operation at temperatures above the ash fusion temperature Since

42


CFBC involves separating the larger fly ash particles in cyclones for recycling back to the combustor the mean diameter of the fly ash particles to be collected are smaller than in PC plants Fine particles tend to be more cohesive as they are collected on the filter bag surfaces making dust cakes more difficult to remove Depending on the fabric they can also make the bag more susceptible to blinding In addition the use of a sorbent for S02 removal yields a fly ash with a chemistry distinctly different from PC ash The high alkalinity of the FBC ash alters the cohesivity and consequently the porosity andor thickness of the dust cake Although the higher porosity of the FBC ash helps to compensate for the smaller particle size and higher surface area the net effect is a higher pressure drop across fabric filters This is caused by the small pore diameters within the dust cake caused by the small irregularly shaped particles (Boyd and others 1991) With sorbent injection ash loading will also be much greater These considerations affect the choice of fabric for the bags and the expected pressure drop Many CFBC plants originally supplied with acid-resistant woven fibreglass bags are being replaced with synthetic felted materials to handle sticky abrasive fly ash (Makansi 1991) Erosion protection may also be needed regardless of the bag material

The quantity of fly ash generated is primarily a function of the quantity of ash and sulphur in the coal and the collection efficiency of the primary cyclone Coal with higher ash and higher sulphur will typically generate more fly ash The amount of coal ash ending up as fly ash will to a lesser extent be a function of the fineness of the coal and sorbent and the friability of the sorbent finer grinds and friable sorbents will generate a higher percentage of fly ash than bottom ash As expected the dust loading into the baghouse for the high ash high sulphur Asian lignite was the highest for the coals tested in the 1 MWt facility (Hajicek and others 1993 Mann and others 1992b 1993) It was 49 gm3

compared with dust loadings of 14-2 gm3 for the other coals For all the coals collection efficiencies using woven fibreglass bags in a pulse jet baghouse were above 999 The composition of the coals investigated is given in Table 9

Fabric filtration is the most widely used particulate control system on FBC boilers (Friedman and others 1993) With a properly designed system emission regulations have been met with low to moderate pressure drops and good bag life (Boyd and others 199]) However problems have occurred For instance erosion of baghouses has been reported at the I 10 MWe Nucla plant CO USA This facility has four baghouses three of which were installed as retrofits and the fourth was installed to accommodate the additional gas flow generated by the CFBC boiler All four baghouses use shakedeflate cleaning A limited number of bag failures (78 in over 11000 coal service hours) has occurred The majority of these were the result of fly ash abrasion occurring where the bag was exposed to the direct impingement from the fly ash laden flue gas as it passes into it The problem was compounded by over deflation of the bag during cleaning Modifications introduced to reduce the likelihood of abrasion occurring in this region of the bag have solved the problem (EPRI 1991) The ash content of the western US bituminous coal ranged from 98 to 428

and its sulphur content from 039 to 275 The collection efficiency was 999 with an average inlet particulate concentration of 20 gm3 and an average outlet value of 85 mgm3 The average emission rate was 31 mgMI well below the New Source Performance Standard of 13 mgMI (Heller and others 1990)

FBC fly ash is more difficult to collect than PC fly ash using ESPs because of the higher electrical resistivity and smaller particle size of the FBC fly ash For S02 control systems that do not produce low outlet gas temperatures the resistivity of the ashsorbent particulate may be four orders of magnitude higher than a high sulphur coal ash (Altman and Landham 1993) ESPs are typically used in retrofit applications (Friedman and others 1993) or on small installations BFBC fly ash may contain high levels of unburned carbon If this fly ash is allowed to build-up in hoppers it may create a fire hazard (Makansi 1991)

The utilisation of flue gas conditioning agents (S03 and water) to reduce the electrical resistivity of particulates has been investigated on a small slipstream of flue gas at the Nucla plant During the test programme a subbituminous coal with an ash content of 25 moisture content of 71 and sulphur content of 089 was burned The CaS ratio ranged from 176 to 272 with a S02 removal efficiency of about 80 The average resistivity of the particulates was 45 x 1012 ohm-cm at 149degC with values as high as 1 x 10 13

ohm-cm measured Conditioning the particulates with S03 vapour was successful in lowering the resistivity However higher addition rates were required than are typical for ESPs and the resistivity was not lowered as much as desired With 80 and 100 ppm addition the resistivity was reduced to only 1 x 1011 ohm-cm despite 10-15 ppm of S03 vapour in the gas The difficulty in conditioning the particulates is probably related to the remaining calcium sorbent and the high particle surface areas Flue gas cooling using a water spray was a more successful technique for reducing resistivity it provided an additional benefit to ESP performance by decreasing the flue gas volume Flue gas cooling to 104degC reduced resistivity to approximately the same value as 100 ppm S03 addition but slightly better performance results from the lower gas viscosity at the lower temperature Using water sprays it should be possible to meet the legislated emission limits with a smaller ESP However water addition has to be carefully controlled to avoid creating wet duct deposits and may be technically more difficult than S03 conditioning (Altman and Landham 1993)

39 Residues Although FBC can utilise coals with a high sulphur content whilst meeting S02 emission limits a drawback is the large quantity of residues (spent bed material and fly ash) that are produced As an illustration for 90 S02 removal FBC units require CaS molar ratios of 2 I to 5 1 whilst wet limelimestone scrubbers and spray dry scrubbers at PC-fired plants require CaS molar ratios of around 10 and 12 to 15 respectively (Makansi 1991) As the unit size increases the amount of solid residue generated also increases For typical UK low ash bituminous coals with 1 to J5 sulphur content industrial FBC boilers (20-100 MWt) would need to

43


consume between 1500 and 6000 t of limestone sorbent per year generating between 3000 and 15000 t of ash per year Larger units (200-500 MWt) with more stringent control of emissions would need to consume between 12000 and 35000 t of limestone per annum producing between 30000 and 120000 t of ash per year (Colclough and Carr 1994) The 165 MWe Point Aconi plant Nova Scotia Canada will consume about 400000 t of coal and 150000 t of limestone per year generating about 188000 t of residues This volume is about 25 times that produced by a 165 MWe conventional PC-fired plant burning the same coal with no S02 control The coal has a high sulphur (average 35) and high ash (10-12 average) content In the future when higher sulphur (up to 53) and higher ash (up to 20 or more) coals are used the amount of residues generated is expected to increase to about 280000 t annually (Salaff 1994) Thus the management of the residues is an important economic consideration and could pose a major obstacle to the widespread introduction of FBC into the power generation market

The irony of FBC technology providing a beneficial outlet for the use of coals that are difficult to utilise in conventional PC-fired plants but at the same time producing large amounts of solid residues that require disposal in an environmentally acceptable manner is illustrated by the waste coal-fired CFBC plants These units are probably discharging more material than is fed to the combustor as fuel However they are generating hundreds of megawatts of electric power from what were once mountainous blights on the landscape The acidity of the CFBC discharge is less than the original anthracite culm or bituminous gob due to the lime content of the residues (Makansi 1991)

The amount of residues produced from an AFBC unit will depend on the coal any addition of sorbent and the technology used The quantity increases with the sulphur and ash contents of the coal TIle need for efficient S02 removal comes in a large part at the expense of increased solid residues This is illustrated in Figure 19

The composition of the coals investigated in the I MWt pilot-scale CFBC unit is given in Table 9 The combination of high ash and high sulphur in the Asian lignite resulted in the generation of the highest amount of residue For the other coals tested the amount of residue generated increased with the amount of ash in the coal and the amount of limestone added The limestone requirement is highest for the high sulphur low alkali coals and increased with increasing sulphur capture As discussed in Section 381 the use of coals with a high calcium mineral content will reduce the amount of sorbent required and hence the quantity of residues produced this will result in some cost savings The baseline (no sorbent added) and 70 sulphur capture for the Salt Creek bituminous coal were performed at a different temperature from the other tests This shift away from the optimum temperature for sulphur capture resulted in the higher residues for these tests seen in Figure 19 (Hajicek and others 1993 Mann and others 1992b 1993) Fly ash reinjection can help reduce the amount of sorbent needed and hence the amount of residues produced (see Section 381)

70 baseline (no sorbent)

f 70 sulphur retention

60 l1li 90 sulphur retention

10



Coal type

Figure 19 Solid residue generation as a function of coal type (Mann and others 1992b)

The physical and chemical properties of FBC residues are different from the ash (bottom ash and fly ash) produced in PC-fired plants the use of sorbent for S02 control in FBC results in residues with higher amounts of calcium (and magnesium if dolomite is used) and sulphate CFBC residues are generally less carbonaceous (1-10 organic carbon) than BFBC fines (20-40 organic carbon) and contain between 7 and 74 sorbent-derived materials (Colclough and Carr 1994) principally unreacted lime (CaO) and calcium sulphate There is some evidence for the presence of calcium sulphide Lyngfelt and others (1995) report substantial levels of calcium sulphide in the bed material of a stationary small-scale FBC boiler under conditions where S02 emissions were high (2860 mgm3) This indicates that large amounts of calcium sulphide may be initiated as the S02 concentration exceeds some critical level A low primary air ratio in conjunction with high S02 concentrations may cause calcium sulphide fomlation in CFBC boilers

The presence of lime and calcium sulphate increases the alkalinity of the residues and can pose problems in their utilisation and disposal However the alkalinity may be beneficial for some uses For example the high calcium oxide content could make it useful as a liming agent for acid soils in agriculture and for reducing acid water run-off from old mine workings Calcium oxide also exhibits cementation behaviour and so can be used in concrete applications The calcium sulphate content will then serve as an aggregate However slow hydration of residual CaO thought to be caused by inadequate prehydration may result in the material eventually swelling and cracking A process that permits effectively complete hydration of CaO has been developed by CERCHAR in France Its application to the residues produced from the coal and limestone which will be used at the Point Aconi plant is discussed by Blondin and others (1993) Outlets for the utilisation of FBC residues are being developed the additional revenues from their sale will help to offset operating and disposal costs The 75000 t of fly ash produced each year at the waste coal-fired Emile Huchet

44


plant Carling France are used in cement manufacture (25000 t) and for restoring the settling ponds from which the fuel was origina11y taken to supply the CFBC boiler (Gobi11ot and others 1995) The management of AFBC residues including their utilisation is reviewed in another lEA Coal Research report (Smith 1990) Svendsen (1994) discusses some uses for AFBC residues in agriculture reclamation construction materials and waste stabilisation

Although the utilisation of the residues has been investigated it is mostly disposed of in landfi11s or ponds For example residues from the 110 MWe Nucla plant CO USA and the 160 MWe TNP-One plant TX USA are landfi11ed (Sta11ings and others 1991) Tests have shown that AFBC residues can genera11y be safely deposited in landfi11s although concern has been expressed over the presence of water-soluble sulphates CFBC leachates contain higher concentrations of soluble compounds such as S042- Ca2+ and Cl- than PC ash due to their high lime and calcium sulphate contents The trace element contents are similar in CFBC residues and PC ash However the concentration of trace clements in leachates from the CFBC residues is less than those from PC ash (Lecuyer and others 1994) The residues investigated came from the 125 MWe Emile Huchet plant and a pilot plant burning Gardanne lignite Colclough and Carr ( 994) also found that leachates from both BFBC and CFBC residues (obtained from commercial and experimental facilities in Europe and the USA) were highly alkaline The trace element concentrations in the leachates were genera11y below the limits set for UK drinking water standards

Residue disposal in landfi11s and ponds can be expensive when stringent environmental precautions are required For example the cost of residue disposal at the Point Aconi plant was higher than expected due to the precautions needed to prevent leachate from entering the ground water The design of the disposal site includes a composite (compacted soil and polyethylene sheet) liner for the entire site surface water co11ection and underdrain system and extensive dust control features A11 leachates not recycled wi11 be discharged to settling ponds and treated chemica11y if necessary for ocean discharge (Salaff 1994)

310 Comments The generalisation that FBC boilers wi11 burn just about anything with little or no preparation does come with certain caveats The utilisation of low quality coals and coal wastes for example has led to problems during fuel preparation handling and feeding and in the ash removal and handling system These have primarily been a result of their high moisture andor high ash contents However fuel feed and ash handling systems have significantly improved over the last few years as lessons have been learnt Provided these systems are properly designed and sized for the fuel they now provide relatively trouble free operation low grade coals and coal wastes are being used successfully It is when off-design coals are used that problems can occur

Bed agglomeration and ash deposition and fouling problems have been experienced in some CFBC units Bituminous coals with a high iron content and subbituminous coals and

lignites with a high sodium content have been found to promote agglomeration while coals with a high calcium content could potentia11y cause fouling in the convection and reheat sections of the combustor However agglomeration and deposition are not just a matter of the total concentration of these elements in the coal but depend on their form of occurrence and subsequent behaviour in the combustor (as well as the operating conditions) It is therefore important to understand the nature of the inorganic components in the original coal and the mechanisms of agglomeration and deposition so that improvements can be made in predicting FBC performance

The hard minerals such as quartz alumina and pyrite and the alkali and chlorine in the coal can contribute to material wastage (wear erosion andor corrosion) However the rates and mechanisms of material wastage are complex functions of the characteristics of the bed material particles and the conditions occurring in the combustor as we11 as the design More needs to be known about the impact of bed material constituents on material wastage in order to better select coals or to take their properties into account when designing the CFBC boiler At present the wear potential of a bed consisting of a mixture of different types of particles (derived from the coal and sorbent) cannot be deduced from the wear potential of the individual particles

The sulphur content ash content and chemical composition of the ash determine the potential S02 emissions from the coal and the amount of limestone required to reduce these emissions Coals with a high calcium content need less added sorbent to achieve the required S02 capture efficiency Experience in large-scale (over 100 MWe in size) CFBC boilers have demonstrated that current S02 emission regulations can be met A S02 removal efficiency of 80-95 can generally be achieved at CaiS molar ratios of 2-4 depending on the limestone characteristics and combustion conditions Optimising operating parameters such as temperature can reduce the required Cal5 molar ratio However there is a tradeoff between the optimal conditions for S02 NOx and N20 emissions For example 502 emissions and NOx emissions increase with increasing temperature whereas N20 emissions decrease The design of the plant also influences these emissions and so the operating parameters require optimising at each plant The main limitation to achieving the desired level of sulphur capture is the economic penalty associated with high feed rates of limestone and the associated residue disposal costs

NOx and N20 emissions are dependent on the nitrogen content and to some extent the rank of the coal They can be reduced by primary measures such as air staging but stringent emissions limits may require additional measures for NOx control adding to costs N20 emissions may become a major limitation to the use of FBC N20 is not currently regulated but this may change in the future due to its role in ozone depletion in the stratosphere and because it is a greenhouse gas There is currently no satisfactory way of reducing N20 emissions although afterburning in the cyclone may be a promising technique

Particulate emissions are less influenced by fuel properties

45


They can be effectively controlled by using fabric filters or ESPs Fabric filters appear to be more popular because the high electrical resistivity and small particle size of the fly ash can lead to poor ESP performance

The disposal of the residues in landfills can have a considerable impact on the economic performance of FBC The disposal costs can represent 1-2 of the cost of electricity produced from AFBC combustion of low sulphur coals (Takeshita 1994) The disposal costs are site-specific depending on the availability (and cost) of the land for disposal Selling the residues for utilisation in different

applications will help offset the cost The use of low sulphur coal can reduce costs (less sorbent required and hence a lower amount of residues for disposal) improving the economics of FBC

Experience has shown that CFBC boilers need to be designed for a specific coal and that top performance is likely to be had only for that coal Fuel flexibility can be built into the design but this may reduce overall boiler efficiency and will add to the construction costs It is crucial to the success of CFBC boilers that the fuel characteristics are properly related to the design and operation of the plant

46

4 Pressurised fluidised bed combustion

In AFBC as with PC combustion the heat released is used to raise steam which drives a steam turbine Because their heat losses are higher and because the steam conditions are modest CFBC power stations are generally less efficient than PC-fired stations Development of CFBC boilers is leading to larger unit sizes and to steam conditions suitable for more efficient turbines However although they may close the efficiency gap with PC they do not appear to offer the prospect of surpassing Pc Currently the most efficient steam cycles use a turbine inlet temperature approaching 600degC The bed temperature for FBC is around 850degC Potentially a cycle with this upper temperature could be more efficient than available steam cycles These considerations have led to the design of pressurised bubbling fluidised bed combustion (PFBC) systems in which the heat in the flue gases leaving the bed is exploited directly by using them to drive an expansion turbine The size of the combustor is inversely proportional to the pressure Consequently a PFBC unit is more compact than an AFBC unit or a conventional PC boiler of comparable output Thus PFBC could be suitable for repowering power plants

Although pressurised circulating fluidised bed combustion (PCFBC) is under development no installations beyond the pilot scale have yet been built There are several demonstrationcommercial PFBC units in operation around the world Therefore PCFBC is only covered briefly in this chapter Hybrid systems that incorporate PCFBC boilers are discussed in Section 562

41 Process description In a PFBC plant coal is combusted with added sorbent under pressure (typically between I and 2 MPa) in a fluidised bed boiler providing steam and gas for a combined cycle At these pressure levels combustion efficiency is generally high (over 99) even at low excess air levels The first commercial scale PFBC unit (2 x ABB P200 PFBC modules supplying a single steam turbine) was built at the combined

heat and power plant at Viirtan in Sweden Figure 20 shows the arrangement of the P200 module

The steam is superheated in tubes immersed in the fluidised bed which typically operates at a temperature of around 850degC At full boiler load the tube bundle is fully immersed As the load is decreased the bed level is lowered by withdrawing material into the bed reinjection vessel exposing some of the tubes Since the rate of heat exchange with the gas above the bed is much lower than the rate of exchange with the solid particles in the bed lowering the bed level effectively reduces the rate of steam generation The flue gases from the fluidised bed are cleaned of particulates using cyclones before expansion in a gas turbine which drives the air compressors and a generator The degree to which the flue gas must be cleaned depends on the design of the turbine Commercial PFBC plants currently use special turbines designed to tolerate low concentrations of fine particles because the cyclones only remove about 98 of the particulates Trials using barrier filters to remove the particulates have not been wholly successful (Dennis 1995 Sakanishi 1995)

The Vartan plant designed for back pressure operation has a net electrical output of 135 MW and a maximum output to district heating in excess of 224 MW It can be used solely for district heating at an output corresponding to 50 of the boiler rating but there is no provision for pure condensing operation of the turbine (Hedar 1994) Hence the plant is only operated during the heating season (approximately October through to April)

Following the installation of the first unit plants based on the P200 module were built in the USA (Tidd) Spain (Escatr6n) and Japan (Wakamatsu) Details of these plants are given in Table 10 The Tidd demonstration plant has now ceased operation after completing its planned test programme

A number of PFBC and advanced PFBC including

47

--

Pressurised fluidised bed combustion

pressurised fluidised bed boiler

steam turbine

15MWe

ash

dolomite

steam

gas turbine condenser

~ t coal and

economiser

Figure 20 PFBC ABB P200 unit (Pillai and others 1989)

pressurised CFBC (PCFBC) projects are currently in the construction or planning stage These include an 80 MWe PFBC unit at Tomato-azuma Japan (start-up 1996) a 360 MWe PFBC unit at Karita Japan (start-up 1999) and the Four Rivers Modernization Project consisting of a 95 MW Hybrid-PCFBC unit at Calvert City KY USA (start-up 1997)

42 Fuel preparation feeding and solids handling

The coal and sorbent are injected into the fluidised bed either as a water-mixed paste using concrete pumps or pneumatically as a dry suspension in air via lock hoppers The Vartan Tidd and Wakamatsu plants use paste injection At Vartan the coal is crushed using roll crushers to a clearly specified size distribution with a top size of 6 mm The sorbent is crushed in hammer mills and has a top size of 3 mm (Hedar 1994) The crushed fuel and sorbent are mixed with water to form a pumpable slurry The ratio of water to solids required for a pumpable slurry is a function of the surface properties of the solids and the particle size distribution It is important to minimise the water content of the slurry because the addition of water to the fuel lowers the efficiency of the boiler With suitable sizing of the fuel and solids a paste moisture content of 20-30 was found to be optimal An early study of paste feeding for PFBC indicated that the net effect of paste feeding at this moisture was to decrease the combined cycle electrical output by approximately 08 This penalty was judged to be acceptable in comparison with the engineering and environmental disadvantages of dry preparation and feeding into the pressurised boiler (Thambimuthu 1994) However although slurry feeding was selected as the simpler alternative a number of particle agglomeration problems have arisen associated with the dispersion of the wet material within the bed (see Section 43)

Tests carried out at the Grimethorpe PFBC facility have shown that the viscosity of a coal-water mixture is strongly dependent on the nature of the coal and its particle size distribution as well as the water content of the mixture TIle addition of limestonedolomite can significantly modify the rheological behaviour of the slurry It should be noted that most of the tests were carried out with coal-water mixtures containing more than 25 wt water An increased clay content of the coal appears to increase the viscosity of the slurries (Wright and others 1991) Variations in the type and concentration of clay present can also alter the handling characteristics of the coal (Wardell 1995) Thus introducing a coal with different clay properties could lead to fuel feeding problems Fuel feeding systems for PFBC plants have recently been reviewed by Wardell (1995)

At the Tidd plant the coal paste nominally contained 25 wt water The dolomite sorbent was fed separately into the combustor via a pneumatic transport system However early testing suggested that the addition or sorbent to the coal paste improved sorbent utilisation Problems occurred with plugging of the coal feed system and cyclone ash removal system and fires at the cyclone gas inlets and in the ash dip legs (lower portions of the cyclone) Plugging or the cyclone ash removal system can lead to increased erosion of the gas turbine blades Despite modifications to the cyclone ash removal system plugging of the primary cyclone ash removal lines at unit start-up still led to unit outages (Marrocco and Bauer 1994) No plugging of the fuel feeding system has occurred at the Vartan plant but plugging of the cyclone and ash discharge lines and cyclone fires have occurred Various modifications have reduced these problems (Hedar 1994) Blocking of the fuel feeding lines and nozzles and of the cyclones has been reported at the Wakamatsu plant Improving the particle size distribution of the coal and modifications to the equipment have helped to solve these problems (Sakanishi 1995) The CaS molar ratio has also been increased from 43 to 76 (way above the requirements

48

Pressurised f1uidised bed combustion

Table 10 Operational data for the PFBC plants (after Nilsson and Clarke 1994)

Vartan Tidd Escatr6n Wakamatsu

Site Stockholm Sweden Brilliant OH USA Escatr6n Spain Wakamatsu Japan

Utility Stockholm Energi American Electric Power Endesa Electric Power Development Co

Supplier ABB Carbon ASEA Babcock ABB Carbon + ABB Carbon +

Babcock Wilcox Espanola Ishikawajima Harima Heavy Industries

Purpose commercial cogeneration demonstration demonstration demonstration

Output 135 MWe + 224 MWt 73MWe 79MWe 71 MWe

Unit 2 x P200 I x P200 I x P200 I x P200

Steam turbine new existing existing new

Start-up date 19891990 1990 1990 1993

Coal Polish bituminous Ohio bituminous Spanish black lignite Australian bituminous (subbituminous)

Higher heating 224--290 233-285 85-190 242-290 value MJkg

Coal sulphur 01-15 34--40 29-90 03-12

Coal ash 8-21 12-20 23-47 2-18

Coal moisture 6-15 5-15 14--20 8-26

Sorbent dolomite dolomite limestone limestone

Coal feed paste paste dry paste

Sorbent feed mixed with coal paste dry dry mixed with coal paste (+ dry injection)

Feed points 6 6 16 6

Bed height at 35 35 35 35 full load m

Vessel pressure MPa 12 12 12 12

Excess air 20 25 15 20

Steam data 137 MPal530degC 90 MPal496degC 95 MPal51OdegC 102 MPal593degC593degC

Cyclones 7x2 7x2 9x2 7x2

Filter baghouse ESP ESP ceramic filter (+ baghouse)

Coal feed rate kgs 2 x 84 72 180 79

Sorbent feed rate kgs 2 x 05 25 70 05

Ash now rate kgs 2 x 16 35 150 13

for S02 control) to reduce the stickiness of the t1y ash and so combustion within the bed The fuel nozzle plugs at Tidd prevent blocking of the cyclone ash discharge system (and Wakamatsu) were induced by coal paste preparation

problems Upsets in coal paste preparation have additionally Experience has emphasized the importance of proper coal given bed sintering problems (see Section 43) and have led

preparation to achieve reliable coal injection and proper coal to post bed combustion Combustion occurring beyond the

49


bed results in excessively high temperatures of the gas in the cyclones and of the ash in the primary cyclone dip legs The dip leg combustion was attributed to excessive unburned carbon carryover whereas the gas stream combustion was attributed to carryover of unburned volatiles Both of these phenomena were due to high localised fuel release combined with rapid fuel breakup and devolatilisation Insufficient oxygen in these localised regions resulted in plumes of low oxygen gas with unburned volatiles and fine char at each of the six fuel nozzle discharge points The unburned gases then ignited upon mixing with the oxygen-rich gases in the cyclone inlets Although modifications to the system reduced the problem improvements in the coal paste quality had the greatest impact on reducing the degree of post bed combustion Later runs at the unit showed little sign of post bed combustion However excessive water addition to the coal paste can still result in upward swings in freeboard gas temperature Such swings pose a potential trip risk at full bed height due to excessive gas turbine temperatures (Marrocco and Bauer 1994)

Local black lignite (subbituminous according to ASTM classification criteria) is used at the Escatr6n plant and this has necessitated a different fuel feeding system As the coal already has a high moisture content (14-20) adding further moisture to produce a coal feed paste would have an adverse effect on thermal performance Consequently the coal is fed dry The crushed coal is mixed with finely ground limestone (to give a CaiS molar ratio of about 2) and pneumatically pressure fed through 16 injection lines into the boiler using a lock hopper system An advantage with this mixing process is that the limestone coats the moist coal so that it behaves as a dry solid This allows the coal to flow freely obviating the need for a dryer (Wheeldon and others 1993a) The coal used at Escatr6n is high ash (2G-50) and high sulphur (3-9) In consequence larger solids handling equipment is required for managing the increased ash flow rate and increased limestone consumption For the same energy output as the Viirtan and Tidd plants coal consumption is twice as high the amount of limestone used is between four and twelve times higher and the amount of ash to be removed is about ten times higher (Martinez Crespo and Menendez Perez 1994)

The major problems that have been experienced at Escatr6n are again related to the fuel feeding system and blockages in the cyclone ash extraction system The coal is highly reactive and spontaneous combustion has occurred Therefore the nitrogen content of the transport air including that in the fuel feeding system has been increased Initially plugging of the fuel feeding lines was a problem especially at low boiler loads Changes in the design have solved most of the problems although erroneous coal and limestone particle size distribution and excess moisture can still block the fuel injection system Malfunctions of the fuel injection system have contributed to agglomeration and sintering problems in the f1uidised bed (Martinez Crespo and Menendez Perez 1994 1995)

The major cause of nonavailability of the Escatr6n plant has been blockages in the cyclone ash extraction system Deposits form on the cyclone walls and in the ash removal

system The deposits consist of sintered material or agglomerates Increasing the coal feed flow to produce more steam increases the bed height and the flow of particles towards the cyclone this has led to more agglomeration and blocking in the cyclones The complex design of the cyclones with a large number of conduits and changes in direction has contributed to the formation of blockages Modifications to the cyclones and ash removal systems have reduced the problem (Martinez Crespo and Menendez Perez 1994 1995) The performance of the cyclone ash extraction system is critical to ensure that the exhaust gas is sufficiently clean for gas turbine survivability


A significant operating issue at PFBC units has been the formation of egg-shaped sinters (25-5 em in size) in the bed These sinters consist of bed particles fused together around a hollow core that are believed to originate as lumps of coal paste (Zando and Bauer 1994) At Tidd sintering only posed a major problem when the bed was operated at full bed height and over 815degC Pittsburgh coal and dolomite were used When limestone sorbent was introduced the bed sintered so rapidly and extensively that the unit had to be removed from service Uneven bed temperatures decaying bed density and a reduction in heat absorption were the common symptoms of bed sintering

Potential causes for sinter formation are believed to be poor fuel splitting or drips resulting in large paste lumps in the bed along with localised concentrations of fuel feed at full bed height and low fluid ising velocity (Zando and Bauer 1994) Fuel feeding systems incorporate a method for breaking the paste into small droplets (fuel splitting) Paste can anive as a dense plug of solids and if it is not effectively dispersed throughout the f1uidised bed sintered ash and fused agglomerates can be produced One way of mitigating the problem is to increase the paste moisture content to obtain finer fuel splitting (although this will have an adverse effect on thermal performance) Investigations into the chemistry of the sinters have shown that the likely cause is calcium from the sorbent fluxing the potassium-alumina-silicate clays in the coal ash The nuclei of the sinters appear to be coal paste lumps which become sticky and cause adherence of bed ash on their surface The coal then burns away leaving the coal ash to react with the bed material The less aggressive sintering with dolomite is due to the increased quantities of MgO which tend to raise the melting (fusion) temperatures of CaO-MgO-Ah03 mixtures The low ash fusion temperature of the Pittsburgh coal was probably a major contributing factor to the sintering (Marrocco and Bauer 1994) This has implications in the coal quality requirements for PFBC units By using finer dolomite sorbents (with a top size of 168 mm) bed mixing and f1uidisation were improved and operation at the bed design temperature (860degC) was achieved with little bed sintering

Limestone was used successfully for a 3 week test period at the Viirtan plant when burning the main fuel a Polish bituminous coal with ash and sulphur contents of 9-13 and

50


Table 11 Ash chemical analysis of the Spanish coals (Menendez 1992)

Ash analysis wt Teruel Basin coal Mequinenza Basin coal

Si02 423 314 Ah03 239 85 Fe203 188 44 CaO 51 236 MgO O~ 16 Na20 03 06 K20 15 13 Ti02 08 05 P20S 02 02 S03 62 279

05-10 respectively However when a new coal with a lower ash content and a higher heating value was introduced problems with sintering and segregation of the bed occuned with the limestone sorbent A return to the dolomite sorbent was necessary (Hedar 1994) Thus the sorbent properties need to be considered along with the coal properties (and operating conditions) to mitigate sintering problems Bed agglomeration has also been observed at Wakamatsu which utilises Australian bituminous coal and limestone (Sakanishi 1995)

Certain low rank coals have contributed to problems in CFBC units (see Section 35) Although the high combustion reactivity of these coals ensures high combustion efficiencies their high alkali content can cause bed agglomeration and fouling problems (Sondreal and others 1993) One might therefore expect similar problems if these coals are used in PFBC plants Teruel Basin and Mequinenza Basin coals are used at the Escatr6n plant Table II gives the ash chemical analysis of these two coals

Bed sintering problems caused 16 of the stoppages at Escatr6n in 1993 The sintering was always related to the appearance of a vitreous double sulphate of calcium and magnesium that bonds together solid particles of other minerals The presence of alkalis favours the formation of sintered material as does pressure and the presence of steam Hot spots in the bed can start the formation of sintered material By keeping the bed temperature below 800D C (against the 850degC design temperature) bed sintering has been avoided However this gives a lower gas turbine power level since the gas entry temperature is lower than the design value (Martinez Crespo and Menendez Perez 1994 1995)

44 Control of particulates before the turbine

In order to protect gas turbine blades from erosion and corrosion particulates (fly ash) are removed from the hot combustion gas stream The fly ash is a mixture of coal ash char and sorbent reaction products and may be reactive erosive corrosive cohesive and adhesive The fly ash properties are important because they determine the behaviour of particle collection and rejection in the particulate collection system The fly ash is widely

distributed in particle size shape composition and density These distributions depend on the properties of the coal and sorbent the relative feed rates of the coal and sorbent and the combustor design and operating conditions It is not cunently possible to predict accurately the fly ash properties produced in PFBC although process models have been developed for this purpose (Lippert and Newby 1995)

At the Viirtan Tidd and Escatr6n plants the particulates are collected using a cyclone system involving sets of primary and secondary cyclones The cyclones are enclosed with the combustor in the pressure vessel Ash plugging of the cyclone ash discharge lines has occuned at these plants (see

Section 42) High efficiency cyclones only remove particulates down to a particle size of 5-10 11m (Sondreal and others 1993) and typically up to 98 of particulates Special robust gas turbines that are designed to tolerate low levels of particulates are used at all of the PFBC demonstration plants Recent research has increasingly been directed to more efficient particle removal systems that can remove particulates down to smaller particle sizes The use of candle ceramic filters for this purpose was tested at Tidd Escatr6n will be testing silicon carbide candle filters (installed outside the pressure vessel) in 1996 and 1997 (Martinez Crespo and Menendez Perez 1994) while the recently built Wakamatsu plant is equipped with ceramic tube filters The following will discuss coal and sorbent related problems that have resulted when utilising ceramic filters A separate lEA Coal Research report provides more information on hot gas cleaning systems for advanced power generating systems (Thambimuthu 1993)

There have been a number of problems with ceramic filters related to their cleanability and durability Pulsed-cleaned candle ceramic filters have been tested at the Grimethorpe PFBC facility (80 MWt coal heat input design capacity) in the UK A single candle element is shown in Figure 21

Figure 21 Single candle filter element

51


The feed materials included Glenn Brook coal with Plum Run dolomite and Kiveton Park coal with Middleton limestone The fly ash proved difficult to clean in some cases and ash bridges formed between the candles causing them to fail The c1eanability appears to be associated with the coal and sorbent feedstock For example difficulty was encountered in removing the ash cake layer formed along the candle filter surfaces when Kiveton Park coal and Middleton limestone were used It has been suggested that the acidic nature of the coal-limestone ash may have had an impact on the overall cohesion adhesion characteristics of the ash fines which deposited along the filter surfaces and subsequently on their removal characteristics during pulse gas cleaning (Alvin 1995) Particulates from systems where dolomite has been used appear to be more cleanable than those from systems using limestone (Stringer 1994) However ash deposits containing high concentrations of calcium and magnesium (from dolomite) can promote deposition as well as bridging when sulphation of the sorbent continues for extended periods of time (Alvin 1995)

Another factor affecting filter cleanability and ash bridging between the candles is the fly ash particle size the coarser the particle size delivered to the filter system the easier the filter is to clean at process operating conditions At Tidd initial slip stream tests with the pulse-cleaned candle ceramic filters operated with the primary cyclones in place This resulted in a relatively low inlet dust loading of fine fly ash particles These fine fly ash particles (1-3 11m) were cohesive with a high tendency to sinter or agglomerate particularly at temperatures above 760degC Ash bridging resulted and the ash was difficult to remove from the vessel When the primary cyclone was out of service the filter inlet particle loading increased 20-fold over initial testing while the average inlet particle size increased nearly JO-fold Under these conditions there was stable filter operation (Dennis 1995 Newby and others 1995)

By increasing the particle size of the fines the rate and extent of sintering calcium-containing particles together are projected to decrease (Alvin 1995) This has implications in the utilisation of coals which produce large amounts of fine fly ash particles such as certain low rank coals that contain inorganic constituents primarily in organical1y associated form These coals will require special attention in designing hot gas filtration systems (Sondreal and others 1993)

Sintering of the fly ash and sorbent fines is influenced by the process operating temperature By operating at temperatures below about 650degC the filter unit at Tidd was operated successfully with the primary cyclone in place (Newby and others 1995) Dennis (1995) describes the tests carried out at Tidd to try and operate the filters at the design temperature of 840degC Other factors which have been identified to reduce sintering include decreased carbon dioxide and steam content in the process gas stream and decreased concentration of CaC03 and CaS04 versus CaO and MgO in the sorbent fines (Alvin 1995)

Extensive sulphation of the sorbent fines and condensation of alkali species in the deposited ash cake can additional1y contribute to ash bridging (Alvin 1995) The alkali species

can come from the coal The effect of alkalis on deposition and corrosion wiJI be discussed in Section 45 Alvin (1995) provides a recent study of the morphology and composition of the ash char and sorbent fines which form deposits in ceramic filter systems The deposits were taken from commercial plants and test facilities

45 Materials wastage Coal properties have been found to influence both refractory and metal wastage in CFBC units (see Section 36) However their effect on material wastage in PFBC units is less clear Little information has been given in the open literature on material wastage experience in commercial plants especial1y on the effect of coal properties The main material problems influencing plant operation and availability that have been reported have occurred in the

coal feeding lines combustor (in-bed tube erosion corrosion and abrasion and wal1 wastage) particle removal systems (cyclones and ceramic filters) gas turbines

Corrosion and wear of the fuel transport lines have been encountered At Tidd rapid corrosion of the carbon steel surfaces was experienced When mixed with water the nominally 35 sulphur Pittsburgh coal produces a paste with a pH as low as 3 This resulted in significant corrosion damage to the coal paste mixer and coal paste pumps Replacing the carbon steel surfaces in the autumn of 1991 with austenitic stainless steels solved the problem (Hafer and others 1993) Wear inside the carbon steel transport pipes at Escatr6n suggests that a more resistant material should be used in future designs (Martinez Crespo and Menendez Perez 1994 1995)

The first important materials issue that emerged in BFBC systems was wastage of the in-bed heat exchanger tubes The occurrence of tube wastage in some BFBC systems and not in others suggests that erosion is not intrinsic to FBC but arises predominantly because of variations in design features and operating parameters (such as fluidisation velocity and temperature) Coal and sorbent characteristics such as particle size size distribution hardness and chemical composition can also contribute

A significant difference between BFBC and PFBC systems is the depth of the bed and hence the size of the heat exchangers In BFBC units the wastage is usual1y worst on the bottom tube row less on the second row and little or none on the third and higher rows if present (Stringer 1994) The use of wear-resistant coatings and the design of tube bundles which avoid high velocity paths for solids have mitigated in-bed tube erosion in BFBC systems In-bed tube wastage was observed in the early experimental PFBC systems but the majority of the experience in larger-scale units that have been published relates to the Grimethorpe PFBC facility commissioned in 1980 Severe wastage of the in-bed tube bank occurred resulting in radical tube design changes and changes in operating conditions mainly a lower fluidisation velocity (Meadowcroft and others 1991

52


Stringer 1994) Some details of the new tube design have been released but some results have still not been fully disclosed (Stringer 1994) Part of the tube bundle was designed to operate with metal temperatures more typical of those experienced within utility boilers The results indicated that with an appropriate selection of tube alloys fluidisation conditions operating temperature and steam cycle conditions tube bank wastage should not be a life-limiting problem for PFBC in-bed heat exchangers (Meadowcroft and others 1991 Stringer 1994) Meadowcroft and others (1991) also report that major changes in coal (including a large change in the chlorine and ash contents) and sorbent properties had a minimal effect on the wastage rates

There is little information in the public domain on in-bed tube wastage experience in the demonstration plants apart from a general comment that wastage is not a problem However it is reported that at least some of the in-bed tubes have been coated for protection (Stringer 1994) Zando and Bauer (1994) for instance report that after 5500 h of operation at Tidd in-bed tube erosion was not an issue Only minor tube erosion due to local flow disturbances occurred in localised areas near the bottom of the tube bundle However the boilers at Vartan have had five different tube leak incidents so far twice in the tube bundles and three times in the bed vessel (membrane walls) The shut-down period varied from a week to a month depending on the secondary damage The cleaning and removal of bed material in the tube bundle and bed ash system was often troublesome and time-consuming Some erosion of tube bends occurred and these are now protected During the overhaul period in 1992 some excessive wear was noticed in the space between the tube bundle and the back wall This space was subject to higher velocities A shelf has been added to protect the area Experience so far indicates that better materials or better protection devices are required for longer trouble free operation periods (Hedar 1994) There was no evidence of erosion or corrosion of in-bed tubes at Escatron during 1993 the results suggest that the initial estimate of 20000 h useful life of the tubes will be met (Martinez Crespo and Menendez Perez 1994 1995)

The experience gained at these demonstration plants is on a few different types of coal Problems may occur when introducing coals which have caused material wastage problems in CFBC units (see Section 36) or BFBC units

At the Vartan Tidd and Escatron plants the particulates are collected using a cyclone system Some wear and corrosion of the cyclones at these plants has been reported and plugging of the cyclone ash extraction systems has been a recurrent problem (see Section 42) Although the abrasive nature of the Escatron ashes was a source of concern erosion has only been a minor problem after more than 15404 h of operation (Alvarez Cuenca and others 1995)

The use of ceramic filters for removing particulates was tested at Tidd and testing continues at Wakamatsu Availability of the filters is a major issue For instance frequent ash bridging (see Section 44) has caused candle element damage or failure Breakage due to thermal shock

has been experienced at Wakamatsu The problems with the ceramic tube filters have resulted in the Wakamatsu plant being operated with two-stage cyclones while the filters are out of service (Sakanishi 1995) Demonstration tests with new ceramic filters were due to restart at the end of 1995

There has been concerns about possible erosion and corrosion of gas turbine blades Some erosion of the ruggedised gas turbine blades has been reported at Viirtan Tidd and Escatron although it did not influence plant availability at Vartan (Hafer and others 1993 Hedar 1994 Martinez Crespo and Menendez Perez 1994 1995) The erosion rate increased significantly when the cyclone ash removal lines were plugged Maintenance costs will increase if the service life of the blades is shortened

The major concern about corrosion especially of the gas turbines and the ducts leading to the turbine relates to the fact that measurements have indicated that the concentration of volatile alkali compounds in the gas leaving the combustor is substantially higher than would normally be accepted for gas turbines burning gaseous or liquid fuels (Jansson I994a) The concentration of alkali species in the gas is dependent on the feed coal chlorine sodium and potassium contents as well as the process operating temperature and pressure In general increases in the chlorine content of the coal and SOz sorbent increases the release of alkali metals into the vapour phase since the chlorine serves as a carrier anion (CRE Group Ltd 1995) The chlorine in the combustion gas can be present as alkali chlorides andor HCI Alkali release is enhanced by increased bed temperature and by lower operating pressure Other corrosive elements that may derive from the fuel are vanadium and lead (Jones I995a Stringer 1994)

The ruggedised gas turbines in the demonstration PFBC plants are not reported to have suffered from corrosion problems but results from the last series of tests at Grimethorpe indicated that corrosion is indeed possible for alloys typical of those used in industrial gas turbines Corrosion of CoCrAIY coatings used on turbine blades has occurred at temperatures around 750degC The molten species responsible is believed to be a cobalt-alkali metal sulphate Its formation requires a significant partial pressure of S03 (Stringer 1994)

The coal used at Tidd has a low chlorine and alkali metal content However the utilisation of high chlorine andor high alkali coals could create corrosion problems in PFBC units limiting the use of these coals Certain low rank coals can contain high eoncentrations of alkali metal compounds and some UK coals can have a high chlorine content There is currently no fully proven method for removing corrosive alkali salt vapours from the combustion gas making this a key issue to be resolved in using high alkali low rank coals in PFBC units particularly in Hybrid-PFBC systems (Sondreal and others 1993) The significance of alkali compounds in Hybrid-PFBC systems is discussed in Section 562

53



An advantage of PFBC over CFBC is a better environmental perfomlance as well as a higher thermal efficiency This section will discuss S02 NOx (NO + N02) N20 and particulate emissions from PFBC demonstration plants and the impact of coal properties

461 SUlphur dioxide

Emissions from FBC vary widely with design coal composition nature of sorbent and operating conditions The higher sulphur capture efficiency of PFBC over AFBC systems is primarily a consequence of the effect of pressure on the process chemistry (Anthony and Preto 1995 Podolski and others 1995 Takeshita 1994) At atmospheric pressure CaC03 (in limestone and dolomite) and MgC03 (in dolomite) calcine to CaO and MgO respectively These compounds then react with the S02 At PFBC conditions the CaC03 does not calcine since the C02 partial pressure in the bed is above the decomposition temperature only the MgC03 component in the dolomite calcines As a consequence CaC03 reacts with S02 to form calcium sulphate (CaS04) The direct sulphation of CaC03 results in higher sulphur capture efficiencies at lower CaiS molar ratios

The capture of S02 in PFBC is influenced by the temperature of the bed the CaiS molar ratio the residence time of the gas in the bed (a function of bed height and f1uidising velocity) and load Sulphur retention generally increases (and hence S02 emissions decrease) with increasing bed temperature higher CaiS molar ratios longer gas residence times and increasing load (Podolski and others 1995 Yrjas and others 1993) For AFBC the optimum sorbent perfomlance is

usually achieved in a temperature window between 800 and 900degC typically at about 850degC However there appears to be no pronounced maxima for sulphur capture as a function of temperature in PFBC (Anthony and Preto 1995) The CaiS molar ratio depends on the sulphur content of the coal and the required sulphur dioxide removal level Unlike AFBC excess air appears to have little or no effect on the sulphur retention (Podolski and others 1995) S02 emissions generally increase at part load due to the reduced bed height and consequent lower gas residence time in the bed

A high sorbent utilisation is extremely important as it reduces the quantity of sorbent required to achieve a given reduction in S02 emissions This not only saves on sorbent costs but reduces the size of the solids handling equipment required and the amount of solid residues for disposal Dolomites and limestones vary markedly in their effectiveness for sulphur removal (Yrjas and others 1993) Generally in PFBC dolomites are more reactive on a molar basis than limestone (Podolski and others 1995) However the choice of sorbent depends on a number of factors including the properties of the coal feedstock For example using limestone has led to bed agglomeration problems at Vartan and Tidd but has been successful at Escatr6n (see Section 43)

Results from the PFBC demonstration plants have shown that sorbents can perfoml significantly better under pressurised conditions than at atmospheric pressure Table 12 gives the environmental performance of the four PFBC demonstration plants

Emission limits at Vartan are stringent (30 mgMJ for S02 as sulphur) due to its urban location (Dahl 1993 Hedar 1994) A low sulphur bituminous coal (sulphur content usually less than 1 wt) is fired The average annual S02 emissions from both units were below 16 mgMJ during 1992 to 1994 A

Table 12 Environmental performance of PFBC plants (Jansson and Anderson 1995 Takeshita 1994)

Vartan

Coal sulphur content

S02 emission mgMJ S02 removal efficiency

CaS molar ratio CaS molar ratio

at 90 S02 removal Sorbent feed Sorbent

Coal nitrogen content NO emissions mgMJ

without SNCR NO emissions mgMJ

with SNCR andor SCR NO control method N20 emissions mgMJ

Particulates mgMJ Particulates control method

~l

5-10 96-98 33 about 2

mixed with coal paste dolomite

13 125-145

15-25

SNCR + SCR 20

5 baghouse

NA not available

54


CaiS molar ratio of about 2 was required for 90 sulphur retention The Polish bituminous coal used in the tests (1992) had a high calcium content corresponding to a CaiS molar ratio of 07

A high sulphur (36) bituminous US coal (Pittsburgh no 8) was used at Tidd Early data (1992) have shown 926-931 S0 2 capture for CaiS molar ratios of 205-2 17 giving a calcium utilisation ranging from 42-45 (Anthony and Preto 1995 Marrocco and Bauer 1994 Zando and Bauer 1994) The sorbent feed size was found to affect sorbent utilisation decreasing the size resulted in increased sorbent sulphation and therefore reduced sorbent feeds to achieve a predetermined level of sulphur capture A sulphur capture efficiency of 90 for a CaiS molar ratio of 13 was obtained with 168 mm dolomite sorbent This was achieved under part load conditions (bed height 29 m) with a bed temperature of 860degC Data extrapolation indicate CaiS molar ratios of 11 and 15 for 90 and 95 sulphur capture respectively at full load This would be equivalent to a limestone utilisation of up to 82 The finer sorbent size also reduced sintering in the bed (see Section 43) Although 90 sulphur removal at a CaiS molar ratio of 2 was acceptable when this programme was conceived it is now considered that 95 sulphur removal at a much lower CaiS molar ratio will be necessary for PFBC technology to be competitive in the utility marketplace at the turn of the century (Zando and Bauer 1994)

During one of the tests at Tidd with the ceramic filter in place the S02 concentration across the filter unit was measured The data showed that a 40--50 removal of the remaining S02 had occurred after almost 90 of the initial S02 content of the gas had been removed in the combustor unit Apparently the hot gas filter unit can playa role in reducing sorbent consumption lowering operating costs and enhancing S02 capture (Newby and others 1995)

The Spanish Teruel and Mequinenza black lignites used at Escatr6n (see Table 10) have sulphur contents in the range 3-9 (and ash contents of 20-50) The sulphur content is higher than the coals used at Vartan Tidd and Wakamatsu The Mequinenza coal was fired during the first year of tests (Menendez 1992) This coal contains high amounts of CaO (236) in its ash which assists in the sulphur retention process the sulphur is mainly organic The Teruel coal has a CaO ash content of only 51 its sulphur is mainly pyritic Sulphur removal efficiencies of more than 90 with CaiS molar ratio of about 2 have been achieved at full load (Martinez Crespo and Menendez Perez 1994 1995) This CaiS molar ratio includes the CaO in the coal ash S02 emission levels of about 350 mgMJ have been achieved (see Table 12) As at Tidd sulphur retention decreased with load For load levels lower than 70 sulphur retention with a CaiS molar ratio of 2 fell to 80-85 Consequently if the plant is operated at low loads (which occurs during start-up) a CaiS molar ratio greater than 2 would be required for 90 sulphur retention Using a finer limestone was also found to improve sulphur retention with levels of 95 being reached at full load (Martinez Crespo and Menendez Perez 1994 1995)

High levels of S03 in the exhaust gas can give rise to smoke plumes from condensation of the S03 In PFBC a greater S02 to S03 transformation ratio is found than in AFBC Anthony and Preto (1995) quote work which showed S02 to S03 conversions ranging from about 10 at 1 MPa and 30 excess air to about 25 at 2 MPa and 65 excess air in small-scale PFBC In general S03 decreases with increasing freeboard temperature and a finer dolomite sorbent size and increases with system pressure excess air and S02 emissions (Podolski and others 1995) S03 levels are also higher at partial loads Because of concerns with smoke plume visibility efforts have been made at Escatr6n to maintain the S02 to S03 transformation to less than 4 To achieve this the oxygen level in the combustion gases is being controlled to keep it below 5 when exiting the flue (Martinez Crespo and Menendez Perez 1995) Elevated levels of S03 could in addition cause acid condensation and corrosion in the low temperature region of the exhaust gas path (such as the economiser) At present there is little evidence of this in the demonstration plants (Anthony and Preto 1995)

The Wakamatsu plant is still undergoing trials Initial results have shown slightly higher S02 emissions than the planned value Boiler combustion is currently being optimised to reduce the emissions (Sakanishi 1995) Jansson and Anderson (1995) quote a preliminary sulphur retention of 90 at a CaiS molar ratio of 5 However higher CaiS molar ratios (of up to 76) have been used to try and reduce the stickiness of the fly ash and so prevent blocking of the cyclone ash discharge system Low sulphur (03-12) Australian bituminous coal is used

462 Nitrogen oxides

Like CFBC the major source of NOx (over 90) is from the coal nitrogen (fuel nitrogen) rather than nitrogen from the air (thermal nitrogen) This is due to the relatively low combustion temperature The amount of NOx formed during PFBC coal combustion does not correlate well with fuel nitrogen content (Podolski and others 1995) In general the higher the coal nitrogen content the more NOx and N20 is produced although the degree of conversion depends on the coal reactivity and characteristics as well as the operating conditions (Anthony and Preto 1995)

It has been reported that coals of low rank or high volatile contents are associated with low N20 emissions (Anthony and Preto 1995) Utilisation of these coals could therefore help reduce N20 emissions since there are not as yet any methods that have been commercially proven for controlling N20 emissions

Research on the effects of operating conditions on NOx and N20 emissions from PFBC recently reviewed by Anthony and Preto (1995) have shown that

although temperature has a significant effect on NOx emissions at atmospheric pressure the same is not true of pressurised operation However temperature is the most important single factor in determining N20 emissions in PFBC with N20 decreasing rapidly with increasing temperature

55


opinion on the effect of pressure on NOx emissions is divided Many workers have failed to find a significant effect of pressure on NOx emissions whilst others have reported a decrease in NOx with increasing pressure for coals with a moderate or high volatile content One reason for this divergence in opinion may be because volatile nitrogen and char nitrogen conversions are influenced differently by pressure Pressure does not significantly affect N20 emissions but work reviewed by Takeshita (1994) showed that these emissions are generally lower from PFBC installations compared to AFBC NOx emissions increase rapidly with excess air similarly to AFBC Although excess air can increase N20 the effect is relatively small in PFBC Similarly air staging has a relatively small effect on N20 emissions opinion on the effect of limestone on NOx emissions is also divided with some workers finding that increasing CalS ratio decreases NOx whilst others report no effect or an increase in NOxbull The presence of limestone can cause a drop in N20 levels and reduced load increases NOx and N20 emissions This is probably a consequence of the combined effects of lower temperatures and shorter gas residence times at reduced loads

Typical NO x and N20 emissions from PFBC demonstration plants are included in Table 12 Although PFBC technology exhibits inherently low NOx emissions strict emission standards may dictate the use of selective catalytic reaction (SCR) andor selective non catalytic reaction (SNCR) processes At Vartan a SCR plant was installed immediately after the gas turbine in order to meet the stringent 50 mgMJ NO x emission limit Ammonia is additionally injected into the freeboard or cyclones in order to maximise the SNCR effect Ammonia slip from the SNCR is neutralised in the SCR plant although it can occur when the particulates in the baghouse filters become saturated with ammonia However ammonia injection has an adverse effect on N20 emissions which have doubled since ammonia injection started (Dahl 1993 Hedar 1994)

At Tidd (in June 1992) NO x emissions of 774 mgMJ or lower were achieved without the use of ammonia or SCR processes (Hafer and others 1993) The bituminous coal had a nitrogen content of 13

The black lignite used at Escatr6n has a nitrogen content of 06 When the bed oxygen excess air was increased in order to avoid bed sintering problems NOx emissions increased slightly However the emissions were still below the NO x emission limit NOx emissions have been consistently below about 110 mgMJ without the use of ammonia or SNCR processes (Martinez Crespo and Menendez Perez 1994 1995) Increased emissions of NOx were found under reduced loads at the Tidd Vartan and Escatr6n plants (Takeshita 1994)

Preliminary results from Wakamatsu indicate that NOx emissions (72 mgMJ) are lower than the design value (Jansson and Anderson 1995) This plant utilises dry

ammonia SCR to control NOx emissions (Goto 1995 Sakanishi 1995)

463 Particulates

Particulates emitted from the stack consist of fly ash (from the coal) and spent sorbent The quantity of fly ash generated is primarily a function of the ash and sulphur contents in the coal and the collection efficiency of the cyclones Coal with high ash andor high sulphur contents will typically generate more fly ash than those with lower ash and sulphur contents The particulates can be controlled using conventional fabric filters (Vartan) or ESPs (Tidd and Escatr6n) Problems that can occur with fabric filters and ESPs and the effect of coal properties wi]] probably be similar to those for CFBC boilers (see Section 383) The average monthly particulate emissions at Vartan were well below 10 mgMJ during normal operation (Hedar 1994) and below 10 mgMJ at Tidd Escatr6n and Wakamatsu (see Table 12)

The use of ceramic filters for removing particulates before they reach the gas turbines is expected to eliminate the need for further cleaning of the gas between the turbines and stacks that is the use of fabric filters and ESPs The Wakamatsu plant was designed to operate with ceramic filters but due to problems these have currently been removed from service (see Section 44) Fabric filters have been installed (Goto 1995)

47 Residues PFBC plants produce large quantities of solid residues (bed ash cyclone ash and fly ash from the fabric filters and ESPs) that require disposal The amount of residues produced depends on the coal (sulphur and ash contents) the CalS molar ratio and the sorbent type (limestone or dolomite) An increase in the sulphur content of the coal from 1 to 4 can be expected to result in a 2-3 fold increase in the quantity of residues produced (Nilsson and Clarke 1994) Higher coal ash contents and a higher sulphur retention (higher CalS molar ratio) will also increase the amount of residues produced The use of dolomite produces a greater amount of residues than limestone for similar CalS molar ratios

Solid residues from PFBC consist of coal ash unbumt carbon desulphurisation products and unreacted sorbent Their characteristics are quite different to those from conventional PC combustion residues because of the sorbent-derived components The physical and chemical properties of PFBC residues are also different to those of AFBC residues In AFBC the limestone completely calcines resulting in a large amount of free lime (CaO) in the ash In PFBC limestone sulphation proceeds without calcination This results in a residue with a low free lime content typically less than a few weight percent with most of the residual limestone remaining as calcium carbonate The lower free lime makes cement products made from PFBC residues less prone to the secondary reactions and cracking that has plagued AFBC cement products This is expected to make PFBC residues a more valuable by-product than AFBC residues The magnesium carbonate in dolomite calcines during desulphurisation to magnesium oxide Magnesium

56


oxide promotes secondary reactions in cements and so could limit the utilisation of residues from PFBC plants that use dolomite as the sorbent (Wheeldon and others 1993a)

The unburnt carbon content of the residues can affect its use in cement production The content of unburnt carbon in cyclone ash is affected by the reactivity of the coal and operating conditions especially the load and excess air (Nilsson and Clarke 1994) At Vartan the unburnt carbon in cyclone ash was 1-3 at high loads increasing to 6-8 at 60 load (Hedar 1994) A bituminous coal was used

Residues from Vartan and Escatr6n are currently sent to waste disposal sites (Hedar 1994 Nilsson and Clarke 1994) If PFBC residues could be marketed then the cost of ash disposal and the cost of electricity would be reduced Residues from Tidd (which uses dolomite as the sorbent) were evaluated for use in land application for agriculture mine spoil reclamation soil stabilisation and road embankment construction (Beeghly and others 1995) The beneficial use for agriculture and mine reclamation as a soil amendment material is primarily due to the high acid neutral ising capacity and gypsum content of the residues Despite their high alkalinity results from various leaching studies indicate that the environmental effects associated with disposal or utilisation of PFBC residues should be no greater than those for fly ash from PC or for AFBC residues (Nilsson and Clarke 1994) The self-hardening properties of PFBC residues would additionally serve to reduce the production of leachates These self-hardening properties can also contribute to its use as a building material In Wakamatsu a land reclamation project has been started using solidified PFBC ash (Jansson and Anderson 1995)

Recent reviews on PFBC residues include Carr and Colclough (1995) covering residues from the Grimethorpe PFBC facility and Nilsson and Clarke (1994) The conclusions of these latter authors that more work is needed on the effect of different coals on the characteristics of the residues still remains valid

48 Pressurised circulating fluidised bed combustion

Pressurised circulating tluidised combustion (PCFBC) processes are at an earlier stage of development than PFBC As implied by the title the essential difference from the PFBC design is the use of a circulating fluidised bed boiler instead of a bubbling fluidised bed boiler In practice a different gas cleaning system is also employed The ABB bubbling fluidised bed process uses cyclones to clean the hot gas stream Although these remove most of the particulates the hot gas expander is subjected to levels of particulates and alkalis that would be detrimental to the availability of a conventional combustion turbine Proprietary ruggedised turbines have been specially developed by ABB for the P200 and P800 modules and are an essential feature of the process It has been suggested that the service life of the blades of these turbines is in the region of 25000 h and they must be regarded as items needing regular replacement (Renz 1994) If the cyclones fail to operate efficiently more rapid wear can

occur The developers of PCFBC processes have designed their process to use conventional industrial turbines and have accepted the need for the higher standard of particulate filtration provided by barrier filters Barrier filters are currently being developed for PFBC systems but their reliability at or near PFBC bed temperature has still to be established (Jansson 1994b) During an exchange of opinions at a PFBC symposium a leading authority gave a positive appraisal of the commercial prospects of PFBC but was pessimistic about the feasibility of high temperature barrier filtration (Ehrlich 1994) In the course of the same meeting Meier (1994) expressed confidence that the problems could be solved Assuming that the problems will eventually be resolved the barrier filter configuration lends itself to the development of more efficient advanced cycles (see

Section 562)

49 Comments There is less experience and infomlation on the effect of coal properties on PFBC units than for CFBC as there are only four demonstration units currently in operation Three of these units utilise bituminous coal and one local Spanish black lignite (subbituminous coal) Different coals are being investigated in bench- and pilot-scale facilities At the present time PFBC is not under consideration for waste coals (anthracite culm or bituminous gob) Anthony (1995) considers that there is no prospect of PFBC becoming attractive for these fuels within the foreseeable future

Preparation of the coal is important as a consistent quality is required to avoid post bed combustion and excess moisture can block the fuel feed system Initial problems reported at all four demonstration units include plugging of the fuel feed and cyclone ash removal systems Problems in the fuel feed system can lead to bed agglomeration and sintering problems The presence of alkali compounds in the coal can contribute to the formation of sintered material The choice of sorbent is also important For instance rapid bed sintering occurred at Tidd when Pittsburgh no 8 bituminous coal was used with a limestone sorbent Sintering was much less of a problem with dolomite The low ash fusion temperature of the coal contributed to the sintering and agglomeration

Plugging of the cyclone ash removal systems can also create problems further downstream such as erosion of the gas turbine blades Efficient removal of particulates from the gas stream is therefore essential for gas turbine availability and is a critical area for commercialisation of PFBC The four demonstration units currently use ruggedised gas turbines For more efficient particulate removal ceramic filters are being tested However problems have occurred particularly from the deposition of fly ash on the filters causing ash bridging and failure of filter elements The properties and composition of the fly ash are dependent on the properties of the coal and sorbent as well as the design of the combustor and operating conditions It is not currently possible to accurately predict the fly ash properties produced in PFBC although process models have been developed for this purpose

A major concern about corrosion especially of gas turbines

57


is that measurements have indicated that the concentration of volatile alkali species in the gas leaving the combustor is substantial1y higher than would normal1y be accepted for gas turbines burning gaseous or liquid fuels The concentration of alkali species in the gas is dependent on the feed coal chlorine sodium and potassium contents as well as the operating temperature and pressure In general increases in the chlorine content of the coal increases the release of alkali metals into the gas The utilisation of coals with a high alkali metal content (such as certain low rank coals) or a high chlorine content (such as some British coals) could potential1y lead to corrosion problems There is currently no fully proven method for removing alkali compounds from the combustion gas making this a key issue to be resolved in using high alkali andor high chlorine coals in PFBC or Hybrid-PFBC units

Little information has been published on material wastage in PFBC units There appears to be some concern over erosion of the in-bed tubes with at least parts of them being coated for protection Most of the concern has centred on the gas turbine blades

PFBC units have shown a higher SOz capture efficiency over AFBC units primarily a consequence of the effect of pressure on the process chemistry A high sorbent utilisation is important for the commercialisation of PFBC (and for CFBC) as it will reduce the quantity of the sorbent required and the amount of residues for disposal

Like CFBC units NOx emissions are inherently low and if required can be further reduced by SCR andor SNCR methods However ammonia injection can increase NzO emissions Although NzO emissions are not currently regulated they may be in the future because of concerns about its role in ozone depletion in the stratosphere and as a greenhouse gas NzO emissions from PFBC units are higher than those from PC power plants but are generally lower

compared to AFBC units There is as yet no fully proven method for reducing NzO emissions However low rank or high volatile coals are associated with low NzO emissions Particulate emission limits can be met with the use of baghouses or ESPs

The amount of solid residues produced depends primarily on the coal sulphur and ash contents An increase in the sulphur content from I to 4 can be expected to result in a 2-3 fold increase in the quantity of solid residues produced Calculations have suggested that PFBC power plants can burn low sulphur coals more economical1y than local high sulphur coals The utilisation of the residues will help to offset the cost of electricity from PFBC plants

Although much is known about FBC many of the fundamentals of combustion have not yet been fully elucidated for AFBC and this applies to an even greater degree for PFBC and PCFBC where the basic reaction chemistry may not be the same as that seen with atmospheric systems In particular the fundamentals of the combustion process itself nitrogen oxide chemistry and the sulphur capture reaction require further study (Anthony and Preto 1995) The effect of different coals in PFBC units and on the characteristics of the residues produced also requires more work

In terms of coal quality requirements it has been suggested that PCFBC may be less susceptible to bed agglomeration problems Initial problems with agglomeration have been reported for all the operating PFBC units Agglomeration has been control1able using dolomite as the sulphur sorbent but has made the use of lime or limestone problematic It has been postulated that sintering occurs in localised regions of high heat release and the occurrence of such inhomogeneity is thought to be less likely for PCFBC Hence PCFBC may be more appropriate than PFBC for some coals having low ash fusion temperatures

58

5 Gasification

Coal gasifiers are used in many countries for the commercial production of gas and chemicals The high efficiency and clean operation of natural gas-fired combined cycle power stations has lead to their use by an increasing number of utilities and the conversion of coal into a clean fuel gas has been proposed as the route to clean and efficient coal based electricity generation Industrial-scale gasification and use of the gas in power generation have been demonstrated but a number of coal quality and energy utilisation issues are described in this chapter The cost of electricity produced in this way is also an issue and some cost considerations are discussed in Section 65

51 Commercial gasification plants Coal gasification for chemicals production is a we]] proven technology Three families of gasifiers have been commercia]]y exploited for several decades They are fixed bed gasifiers fluidised bed gasifiers and entrained flow gasifiers Most commercial gasifiers use the Lurgi fixed bed dry ash process which was developed in Germany and used from the 1930s for the large-scale production of synthesis gas The gas consisting mainly of carbon monoxide and hydrogen is used for ammonia synthesis and to a lesser extent for methanol synthesis or hydrogenation The gasifying medium is steam and oxygen Gases pass up through the bed which has to be permeable for the proper functioning of this type of gasifier Because the bed is maintained in a dynamic equilibrium by continuously adding suitably sized coal at the top and removing ash at the bottom these gasifiers are known as fixed bed gasifiers However because the solid material moves down the bed as it is consumed they are also known as moving bed gasifiers In this report the former term is favoured because it is preferred by the developers of the technology The largest concentration of fixed bed gasifiers is in South Africa with a total of 97 gasifiers installed at SASOL I II and III The entire SASOL complex consumes around 36 million tonnes of

coal a year (Takematsu and Maude 1991) A further 18 Lurgi gasifiers are in operation at the Great Plains complex in ND USA and four in Beijing China There are also Lurgi type gasifiers of Eastern European and Russian design in Germany China and in the former Yugoslavia

The next most widely distributed members of the gasifier family are the entrained flow gasifiers The Koppers-Totzek (KT) process was developed by Heinrich Koppers GmbH of Essen Germany The first commercial KT gasification plant was built in France in 1949 and since then 50 gasifiers have been installed around the world (GIBB Environmental 1994) Five KT flow plants were known to be in operation in 1993 comprising a total of 26 gasifiers (Simbeck and others 1993) They are used for gasifying a wide range of pulverised coals from high rank bituminous coal to anthracite Texaco entrained flow coal gasifiers are currently in commercial use in the Germany Japan and the USA for the production of synthesis gas for chemicals Texaco plants have also been built in China A recent report suggests that there are currently over 70 plants using the Texaco process worldwide (GIBB Environmental 1994)

Commercial fluidised bed gasifiers are now a rarity There were around 70 Winkler fluidised bed gasifiers in operation but the process has now largely fa]]en into disuse Conventional atmospheric pressure bubbling fluidised bed Winkler gasifiers were superseded by the Koppers-Totzek and the Lurgi gasifiers (Simbeck and others 1993) However Rheinische Braunkohlenwerke AG (Rheinbraun) in Germany have improved the original Winkler process and adapted it for power generation The IGCC version of the High Temperature Winkler process (HTW) would operate at up to 3 MPa and feature a circulating bed (see Section 552) A commercial scale HTW based IGCC demonstration plant was planned for 1997 but this has been deferred for further development work aimed at improving the efficiency reliability and costs of the process (Adlhoch 1996)

59

Gasification

52 Major IGCC demonstration projects

Three large scale IGCC demonstration projects were underway in the USA in 1995

I) The Wabash River coal gasification repowering project is a 262 MWe repowering at PSI Energys Wabash River generating station West Terre Haute IN USA The project features Destecs two stage coal water slurry fuelled oxygen blown entrained flow slagging gasifier The gasifier is based on the Dow gasifier technology used for the Louisiana Gasification Technology Inc (LGTI) 160 MWe facility in Plaquemine LA USA The new gasifier has a designed power generation efficiency of 38 HHV and will use locally mined high sulphur coal The total estimated installed cost of the project is quoted as US$362 million including escalation permitting and commissioning costs On this basis the total installed cost is approximately $1 380kW of net generating capacity The usc of the existing steam turbine generator auxiliaries and electrical interconnections saved approximately $35 million in comparison with a green field installation Partial funding is provided by the US DOEs clean coal technology program (round 4) which will reduce the cost to the operators to approximately $900kW (Cook and Lednicky 1995 Cook and Maurer 1994) Construction was 70 complete in April 1995 Final commissioning was scheduled for September 1995 (DOE 1995)

2) The Tampa Electric IGCC project will demonstrate a 260 MWe IGCC power generating unit situated at Tampa Electric Companys Polk power station Lakeland FL USA The project will feature Texacos coal water slurry fuelled oxygen blown entrained flow slagging gasifier The designed power generation efficiency of the unit is 39 HHV The current expected cost is approximately $500 million ($2oo0kW of installed capacity) US DOE funding will reduce the cost to the operators to approximately $1600kW (Pless 1994) Construction is underway and was 75 complete at the end of 1994 and commissioning is scheduled for October 1996 (DOE 1995)

3) The Pinon Pine IGCC power project is planned to be a 99 MWe IGCC demonstration at Sierra Pacific Power Companys Tracy station Reno NV USA The project will feature the Kellogg Rust Westinghouse (KRW) air blown pressurised f1uidised bed gasifier Initial construction commenced in early 1995 The US DOE undertook to provide 50 of the estimated project cost of $270 million (DOE 1995)

In Europe there are currently two major IGCC demonstration projects featuring gasifiers based on development of the Koppers-Totzek design Demcolec is operating a 250 MWe

2000 tid coal plant at Buggenum in the Netherlands It is based on the Shell entrained flow oxygen blown slagging gasifier A 335 MWe gasifier designed to use a feedstock of 50 coal 50 petroleum coke is being built in Puertollano Spain This unit is being built by Elcogas with participation from II companies and 8 European countries The project is being subsidised by the European Commission (Thermie Programme) and by Ocicarbon (Spain) It will demonstrate the Prenflo entrained flow oxygen blown slagging gasifier process in conjunction with an advanced gas turbine (Siemens V843) The Spanish plant will be the largest IGCC plant based on coal and is expected to have an efficiency of 45 LHV (43 HHV) Anticipated atmospheric emissions concentrations are S02 lt25 mgm3 NOx lt150 mgm3

particulates lt75 mgm3 Commissioning is scheduled for 1997 and there will be a demonstration period of three years for testing various fuels and technology improvements (Sendin 1996)

53 Entrained flow slagging gasifiers Entrained flow systems have been identified as the type most likely to be used widely throughout the world and so have the greatest potential to affect the world coal trade (Harris and Smith 1994) The oxygen blown version is currently commanding most of the IGCC development effort Four of the five major development projects in the USA and Europe feature oxygen blown entrained flow slagging gasifiers

Figure 22 shows the arrangement of an entrained flow oxygen blown slagging gasifier Pulverised coal and oxygen are injected into the gasifier vessel The fuel may be injected as a dry powder or in the form of a slurry with water The coal is gasified in a flame similar to that in a PC furnace except the process takes place at high pressure (around 3 MPa for the Shell gasifier) and the oxygencoal ratio is substoichiometric The oxygencoal ratio is selected to give the required gasification temperature which is normally in the range 1500-1 600degC Mineral matter present in the coal is converted into molten slag and into volatile species such as H2S HCI and ammonia Most of the mineral matter content of the coal leaves the gasification zone in the form of molten slag The high gasifier temperature ensures that the slag flows freely down the inner wall of the gasification vessel into a water filled compartment at the bottom of the vessel

531 Fuel preparation and injection

The fuel for an entrained flow gasifier has to be reduced to a size range similar to that used for conventional PC combustion In consequence the grindability and heating value of the coal are quality issues for entrained flow gasifiers as they are for conventional power stations The Shell gasifier uses dry powder injection and requires a powder sizing of 90 passing through a 100 11m mesh (Koopmann and others 1993) The powder is prepared using a conventional indirect PC preparation system with rotary classification (Phillips and others 1993) The operation of such systems is potentially hazardous but the requirements for safe and reliable operation are well know and are fully discussed in other publications (Scott 1995) The difference from conventional practice arises in the injection stage The

60

Gasification

Coal grinding and Gasification andOxidant slurry preparation

--~------------~~ Gas scrubbing TIi

synthesis gas

Fine slag and char to disposal-----

Particulate free ------shy

I~---l-_L~p~urgewater

Particulate scrubber

Convective cooler

High r shy - - - - - - - - - - - - ~ pressure

steam Texaco I gasifier I r--I I I

Boiler feedwater

Slag sumPL-__---

Radiant cooler

Coal grinding mill

Recycle (optional)

t I I I I I I I I I Coarse

I slag to --------------~---------J I disposal

I Recycle (optional)

Water

Coal feed

I

Figure 22 Entrained flow gasifier (Simbeck and others 1994)

gasifiers operate at high pressure and a system of lock hoppers is needed to overcome the pressure differential The fuel may then be metered from the final lock hopper and injected into the gasifier by dense phase pneumatic transport The mechanical complications that this imposes may be avoided by preparing and injecting the fuel as a coal-water slurry As well as being mechanically simpler slurry systems demand less power for fuel injection because water is virtually incompressible However the slurry alternative introduces a different set of opportunities and constraints The water content of the slurry effectively reduces the lower heating value of the fuel This is particularly detrimental for fuels that already have a low heating value and it is desirable to minimise the water content as far as is consistent with reliable handling

The Destec Energy Inc gasification plant at Plaquemine LA USA which was commissioned in April 1987 uses 2200 tJd of Wyoming subbituminous coal The coal is prepared at the reception facility which is located 12 km from the gasifier The coal is wet ground using a rod mill to form a pumpable slurry (52-54 wt of solids) which is transfelTed to the gasifier by pipeline A higher solids loading is said to be possible through the use of additives aneVor a more sophisticated grinding process (Webb and Moser 1989)

The design coal for the Cool Water Texaco gasifiers was Southern Utah Fuel Co (SUFCo) low chlorine low sulphur bituminous coal from Utah According to Phillips and others (1993) this coal typically has a moisture free gross heating value of 293 MJkg The coal was fed to the gasifiers as a slurry containing 60 solids Heat rate data indicate that increasing the solids content of the feed slurry from 60 to 665 would increase the efficiency of combined cycle

---------------------~

power generation by one percentage point (from 37 HHV to 38 HHV) (Watts and Dinkel 1989)

The minimum water content for a pumpable slurry depends on the system the coal quality and the particle size distribution of the fuel A relatively coarse grind with a wide distribution of particle sizes such as is used for PFBC gives the lowest water content The PFBC power plants in Sweden and the USA use a coarse paste with a water content of only 20-30 (Thambimuthu 1994) However coarser particles are more difficult to gasify and this consideration dictates the use of a finer grind for entrained flow gasifiers (Curran 1989) For a given size distribution the maximum solids content for a pumpable slurry depends on the properties of the coal A considerable amount of research has been dedicated to the development of techniques for the dispersion of coal in water to form a heavy fuel oil substitute This technology developed for the production of coalwater mixtures (CWM) is relevant to the preparation of aqueous coal suspensions for feeding gasifiers Dooher and others (1990) studied the slurryability of six bituminous coals and one subbituminous coal to develop a methodology for assessing the suitability of coals for slurry fed gasifiers Kanamori and others (1990) performed tests on twenty coals ranging from subbituminous to medium volatile bituminous Investigation of the properties of the coals included proximate analysis ultimate analysis ash analysis and the determination of organic functional groups Dooher and others (1990) found that the most important coal properties affecting slurryability were equilibrium moisture fixed carbon surface carbonoxygen bonding as determined by electron spectroscopy and free swelling index Kanamori and others (1990) found that the slulTyability of a coal its solids content at a given viscosity was strongly related to its

61

Gasification

inherent moisture content and its fuel ratio (the ratio of fixed carbon to volatile matter) The presence of clay minerals tends to reduce slurryability The presence of soluble calcium and magnesium compounds in the coal also tends to reduce slurryability because solvated metallic cations cause the coal particles to form agglomerates Oxygen containing functional groups in the coal were found to reduce the slurryability This finding was confirmed by Ji and Sun (1992) Kanamori and others (1990) claimed that from the results of multiple regression analysis of the data slurryability oa coal and the stability of the coalwater mixture could be predicted from the analytical tests (correlation coefficients gt09) Figure 23 demonstrates the correlation found between calculated and

80

Correlation coefficient r = 0961

75 bull

(1) 70 ~

Ol gt 0 (1)

~ (1) 65 (]

Q o bull

60

55 -----------------r--------- shy55 60 65 70 75 80

Calculated value wt

Figure 23 Calculated and observed values for the slurryability of 20 coals (Kanamori and others 1990)

Table 13 Coal properties and gas yield

observed slurryability and shows that depending on coal qualities solids content at a given viscosity can range from less than 60 to more than 70

Table 13 shows how the detrimental effects of low heating value increased moisture content and reduced solids loading can combine in coals used to prepare slurries The data relate to the performance of the Destec oxygen blown two stage entrained flow slagging gasifier The original data were presented in terms of energy yield for an input of 454 kg of coal (Simbeck and others 1993) In the lower part of the table data have been calculated showing the coal requirements for the production of a given amount of chemical energy in gas In comparison with the bituminous coal the production of gas of the same heat content from the lignite requires more than twice as much coal and produces more than three times as much ash The oxygen requirement is also substantially increased Fluidised bed combustion with dry feeding has been advocated as a more suitable alternative for low rank coals

Some of the factors that have been shown to affect coal slurryability are related to coal rank Intrinsic moisture and oxygen containing functional group content tend to be greater for lower rank coals (subbituminous and lignite coals) Bituminous coals with their low inherent moisture content and hydrophobic nature have been the coals of choice for the commercial preparation of high solids content coalwater fuels and similar properties may be desirable for entrained flow gasifiers using slurry injection

532 Coal mineral matter and slag flow properties

In the past optimistic statements have been made concerning the versatility of slagging gasifiers for converting all types of coal However promoters of the technology (Texaco Syngas Inc) while confirming that no coal has been found to be

Appalachian Wyoming Texas bituminous subbituminous lignite

HHV MJkg (daf) 3521 3052 2921

Coal water slurry solids content 66 53 50 Energy input MJkg of daf coal Raw coal 3521 1312 1256

Power for oxygen production 295 291 333 Total 3816 1603 1589

Energy output Fuel gas 294 2368 2058 High pressure steam 437 509 553

Calculated data for the production of 294 MJ of fuel gas kg of daf coal I 124 143 kg of as received coal 114 187 263 Oxygen kg 0895 109 144 Energy for oxygen production MJ 295 361 476 Slag production (ash + carbon) 0083 0093 0288

Data from Simbeck and others (1993)

62

Gasification

ungasifiable have also said In addition to the ash content mentioned previously the chemical and physical properties of the ash or ash quality are also of interest In actual operation the ash quality impacts upon the gasifier operating temperature refractory wear plant materials selection and water system fouling One of the primary measures ofash quality is the ash fusion temperature (or ash fluid point temperature) It is preferable to have an ash with a low fluid point temperature (less than 1370degC) and a rheology that avoids problems with slag removal from the gasifier (Curran 1989) The successful design and operation of a coal gasification process depends as much on a detailed knowledge of the inorganic matter in coal and the ability to control and mitigate its problems as on the behaviour of its carbonaceous content

The fluidity of the slag at the taphole has been identified as one of the critical factors in the operation of slagging gasifiers Most coal ash slags exhibit Newtonian flow at the high temperature end of their liquid region As the temperature is decreased viscosity increases Two extreme types of slag behaviour have been described At one extreme the slag remains homogenous exhibiting glass-like behaviour As these slags cool the viscosity of the slag increases in a predictable continuous manner At the other extreme for some slags a crystalline phase separates from the cooling fluid and the viscosity of the slag increases suddenly Typically they behave in a predictable manner at high temperature but as they are cooled a temperature of critical viscosity (TcY) is eventually reached where the flow characteristic becomes non-Newtonian and the viscosity increases sharply Figure 24 shows a typical temperature viscosity relationship for a cooling crystalline slag (Benson and others 1990)

In the region of Tcy crystallisation begins to have a significant effect on the viscosity of the slag with the attendant danger that the taphole may become blocked by crystalline deposits Hence for slags that exhibit crystalline rather than glassy behaviour Tcy is the minimum temperature for safe operation In practice the tapping temperature must

C iii o o (J)

gt Cooling

~====~--

t Temperature

Temperature of critical viscosity (T )ev

Figure 24 Schematic presentation of the variation of viscosity with temperature (Benson and others 1990)

be high enough to maintain the slag in the Newtonian flow region at a temperature safely in excess of Tcy Oh and others (1995) examined the characteristics of slags from US coals used in the Texaco gasifier Table 14 shows the analysis of the slags and Figure 25 shows the results of viscositytemperature measurements

The viscosity of the SUFCo and PMB slags exhibit glassy slag behaviour while the viscosity curves of Pittsburgh seam coal and PMA are typical of crystalline slag The SUFCo slag contains high concentrations of Si02 and CaO and low concentrations of Ah03 The high concentration of Si02 in the SUFCo causes the slag to have a higher viscosity than the others at high temperature and to act as a glassy slag showing a gradual increase in viscosity as the temperature decreases In comparison with the SUFCo slag the Pittsburgh coal slag has less Si02 and CaO but more Ah03 and Fe203 Although it exhibits crystalline slag behaviour it has a low Tcy the slag is the most fluid of the four slags at temperatures above 1290degC

Screening tests are needed for assessing the suitability of coals for use in slagging gasifiers Ash fusion tests are relatively quickly and easily performed and are widely used to assess the likely suitability of coals for use in various

Table 14 Normalised composition of four coal slags (Oh and others 1995)

Oxides w SUFCo Pillsburgh No8 PMA PMB

Si02 6021 4677 4379 4337

Ah03 156 2467 2604 2928

Fe203 585 1726 2101 1657

CaO 1157 55 258 351

MgO 214 107 106 1l9

Na20 267 I 045 051

Ti02 088 102 14 152

K20 043 184 222 208

P20S 026 032 07 098

BaO 008 011 015 02

srO 012 018 026 046

PbO 0 005 008 008

Cr203 019 022 026 03

3000 --SufCo

- - Pittsburgh2500

bullbull NO8

Powell 3l 2000 Mountain A 8shy bullbullbullbull - - - Powell bull~ 1500 Mountain B 8 5 1000

~ bullbullbullbullbullbull 500

o+-------------r---_________--=-=-o=-=_r_=_---r 1200 1250 1300 1350 1400 1450 1500

Temperature degC

Figure 25 Slag viscosity as a function of temperature (Oh and others 1995)

63

Gasification

processes For slagging gasifiers the ash flow temperature under reducing conditions is a widely accepted indication of the likelihood of the slag being tappable at practicable temperatures Early work showed that the viscosity of US bituminous coal ashes was in the region of 10 Pas at the ASTM flow temperature This is safely below the viscosity of 25 Pas that has been proposed as the upper limit for successful slag tapping However for some Australian coals viscosities in excess of 25 Pas were found at the flow temperature (Patterson and Hurst 1994)

Although ash fusion temperatures are widely used as a guide to slag behaviour the standard methods for preparing coal ash samples subject the coal to conditions totally different from those present during commercial gasification In the standard methods the coal is ashed by slow heating in air During gasification the inorganic components are transformed by a rapid and complex series of chemical and physical processes The composition of the resulting slag also depends on the partitioning of inorganic components between the gas fly ash and slag Hence the ash fusion data are only a guide and it is necessary either to make measurements using slag samples or to rely on methods of prediction based on the chemical composition of the ash The chemical composition of the ash can be used to estimate liquidus temperatures Equilibrium phase diagrams for the ternary SiOzA1203CaO or SiOzA1203FeO systems can be used for ashes with appropriate compositions but for many ash compositions it is better to use the quaternary SiOzA1203CaOFeO phase diagram (Ashizawa and others 1990) The liquidus temperatures may be changed by the addition of flux and the phase diagrams can be used to make predictions of the amount of flux required to achieve a given liquidus temperature The prediction of melting point for the fluxed mixture is more accurate than the prediction for an un-fluxed mixture because the addition of the fluxing agent tends to reduce the large effect that minor components can have on the fusion temperature (Hurst and others 1994)

The Japanese government and electric power industries are actively promoting the development of IGCe The adoption of IGCC by Japan on any significant scale would have important long term coal supply implications for Japan and for Australia In 1990 Australia supplied approximately 70 of Japans imported thermal coal Approximately 80 of the imported Australian coal had a high ash fusion temperature (ASTM flow temperature in excess of 1500degC) This characteristic is highly desirable for the operation of the conventional and supercritical PC-fired power stations currently used in Japan However it does present problems for slagging gasifier operation In principle the gasification temperature can be increased until the slag becomes sufficiently fluid to run freely from the taphole but if the required temperature is excessive the operating life and overall efficiency of the gasifier are adversely affected These considerations motivated the inauguration of a research programme at Japans Central Research Institute of the Electric Power Industry (CRIEP) (Inumaru and others 1991 )

Ashizawa and others (1990) at CRIEPI researched the topic of slag mobility in an air blown entrained flow two stage

slagging gasifier Figure 26 shows the operating principles of

the CRIEPI gasifier

The design of this gasifier which is similar in principle to the DowlDestec gasifier is described more fully by Inumaru and others (1991) The results from the CRIEPI bench-scale (2 tday) gasifier were used in the design of the 200 tday gasifier which was built at Nakoso Iwaki City Japan and commenced operation in 1993 (Abe 1993) The Nakoso unit is intended as the precursor for a 250 MWe demonstration plant to be built by the tum of the century

Air blown gasifiers produce low heating value gas because of dilution of the gasification products by nitrogen This is mitigated by the secondary gasification stage but the gas heating value is still low in comparison with oxygen blown gasifiers A high operating temperature dictated by a high slag fusion temperature requires an increase in the air to coal ratio with a consequent decrease in gas heating value and gasifier efficiency CRIEPI investigated the relationship between ash fusion temperature and ash composition for approximately 30 different coals from Australia China Canada South Africa and the USA Some coals marketed as a single brand proved to have different properties from sample to sample In general good correlation was found between ash fusion temperature and ash acid base ratio The ratio is defined as the sum of the acidic components divided by the sum of the basic components

(Si02 + A1201)Acidbase ratio =

Fe203 + CaO + MgO + Na20 + K20

Gasification of char

Pyrolysis of coal

Combustion of coal and char

Discharge of ash as molten slag

~ Air for transportation bull

Coal rzd~

Slag Air for combustion

bullFigure 26 Basic concept of the CRIEPI pressurised two

stage entrained flow coal gasifier (Inumaru

and others 1991)

64

Gasification

Figure 27 shows the results of plotting calculated ash acidbase ratio for the range of coals against ash fusion temperature Some coal blends and some fluxed coals were also included as well as points for pure fluxes

Regression analysis of the points on the rectilinear portion of the curve gave the relationship

Tf= 13545X-2 + 2908X + 1232

where Tf is the ash fusion temperature and X is the acidbase ratio

In the course of the trial runs the effectiveness of several fluxes was assessed CaO was found to be widely effective but MgO was found to be effective only within a narrow range of concentrations Fe203 was found to be effective but relatively large amounts were needed Hence in Japan the most effective commercially available flux was limestone (991 CaC03) which decomposed in the gasifier to form CaO and C02 (Ashizawa and others 1991) For the un-fluxed coals the two extremes of slag mobility were represented by an Australian coal with an estimated ash fusion temperature of 1750degC and a Chinese coal with an ash fusion temperature of 1275degC Prolonged operation with the Australian coal was problematic because of difficulties with discharging the slag The mineral matter of the Chinese coal contains 332 CaO The slag discharge properties were excellent but the high lime content caused significant deterioration of the refractory lining of the gasifier It was found that blending the Australian coal with the Chinese coal in the ratio 8020 gave an acceptable ash fusion temperature of I 405degC (Ashizawa and others 1994)

Where a suitable coal is available the reduction of fusion point by coal blending may be preferable to flux addition because it is possible to modify the slagging behaviour without increasing the total ash yield The possible effect of lime on refractory in the gasifier must also be considered As reported by Ashizawa and others (1994) CaO can have detrimental effects on refractory linings As well as increasing ash flux addition also imposes additional cost

2825degC

2600degC

2000

~ 1800 [l

til ~

Qi 1600 0shyE 2 c 14000

[jj

-2 c () 1200 bull laquo bull

1000 0 5 10 15 20

Acidbase ratio

The quantity of flux required depends on the mineral matter content of the coal as well as the mineral matter composition The actual cost would be site specific but for example an addition to the coal of 10 CaO by weight might increase the cost of the fuel by 5-15 In a competitive market the increase in cost would presumably be borne by the coal producer as a reduced coal realisation (Patterson and Hurst 1994)

533 Refractory lining materials for gasifiers

The gasifier has to contain a corrosive atmosphere at normal working pressure of 3 MPa and a temperature around I600degC Hot raw synthesis gas is particularly aggressive because of the presence of H2S and HCI under reducing conditions The pressure is contained by an outer steel shell In the gasifier itself metal components are not directly exposed to the gasifier environment they are covered by a layer of refractory The shell may be protected by a combination of insulating and abrasion resistant refractories or by a water cooled membrane wall which in tum is protected by a thin layer of refractory

The operating life of the refractory is a key factor determining the availability and economics of an IGCC power plant Refractories based on alumina have been found unsatisfactory for slagging gasifiers because slag dissolves alumina High alumina refractories (90 alumina 10 chromia) and impure refractories based on chrome (commercial FeCf204) were found to be heavily damaged at I500degC It was also found that free magnesium oxide in refractories is rapidly dissolved by high silicate slags High purity high chromia refractories (gt70 chromia) were found to be undamaged at temperatures up to 1650degC The rate of attack on refractories was also found to be a function of the velocity of the slag across the refractory surface Increased slag velocities were required to produce detectable rates of wear in high chromia samples at 1500degC (Bloem 1990) However Kuster and others (1990) report that the resistance of high chromia refractory is strongly affected by the composition of the slag Silicate slags with a high CaO content cause a significantly increased rate of wear at temperatures in excess of I450degC Wear is moderate for a CaO content of 14 but at 28 the rate of wear increases asymptotically as the temperature approaches 1600degC

The detailed conditions of service of the refractory depend on the design of the gasifier The Texaco gasifier uses a thick inner layer of refractory to protect the outer shell of the pressure vessel Development work with the Texaco gasifier at Cool Water FL USA showed that the main causes of refractory failure were slag penetration thermal shock crack propagation and spalling The effects progress from the hot face of the refractory and the rate of deterioration increases with time (Bakker 1992) Similar observations were made on the pertormance of refractory in the Dow entrained flow slagging gasifier Factors identified as important for the extension of refractory life were

Figure 27 Acidbase ratio and ash fusion temperature improved gasifier operation with lower temperature and (Ashizawa and others 1994) less thermal cycling

65

Gasification

better quality control of refractory manufacture and installation and the development of new refractory materials

It was predicted that refractory life in the Dow gasifier could be extended beyond three years when processing a coal with ash properties similar to those of the SUFCo Western USA subbituminous coal that was the primary feed of the Destec plant (low sulphur low chlorine low ash fusion temperature) An ash mineral analysis of this coal indicated a CaO conttnt of 17 (Phillips and others 1993) Further experience with other coals was needed before more general predictions could be made (Breton 1992)

The pressure shell of the Shell gasifier is protected from the heat by a membrane wall The thin layer of refractory on the membrane wall is designed to encourage a layer of chilled slag to form As the layer becomes thicker the hot face temperature increases until the surface becomes fluid A stable condition is reached with molten slag flowing over a self healing layer of chilled slag The demonstration plant at Deer Park TX USA had a design refractory life of 8000 h In practice the bottom half of the refractory was replaced after 8774 h The top half did not need refurbishing in the demonstration and experimental period totalling 14652 h operation (Phillips and others 1993)

534 Metals wastage in entrained flow gasifiers

One of the drawbacks of using entrained flow slagging gasifiers for combined cycle power generation is the high sensible heat content of the raw syngas which can be as much as 30 of the energy contained in the coal feed For efficient power generation it is necessary to recover as much of the energy as is practicable As with a conventional PC furnace initial gas cooling is necessary to ensure that molten fly slag is solidified before it encounters the convective heat exchange surfaces Some gasifiers incorporate radiant boilers with water circulating through membrane walls to generate saturated steam (Shell Prenflo and some Texaco gasifiers) Other gasifiers use some of the heat in a second stage gasification process (DowlDestec gasifier) The gas may be further cooled before it enters the syngas cooler by the recirculation of cold gas For processes that use a convective syngas cooler the hot gas enters the cooler at approximately 900degC and the gas temperature is reduced to approximately 200degC before it passes through a cyclone for the first stage of particulates removal before final gas purification

The principal gaswater heat exchange surfaces in an IGCC plant are the radiant and convective syngas coolers and the heat recovery steam generator (HRSG) The syngas coolers are the largest application for high temperature corrosion resistant alloys in an IGCC plant and the most expensive components in the plant Heat transfer calculations indicate that a commercial 500 MWe IGCC plant would need approximately 100-150 km of heat exchange tubing in its syngas coolers (Bakker 1988)

Corrosion of metallic materials by syngas atmospheres has

been the subject of extensive study for the last 25 years The resistance of metals and alloys to high temperature corrosion is usually provided by the formation and maintenance of a protective scale such as chromia alumina or silica Under the reducing and sulphiding conditions produced by a syngas atmosphere such scales may fail to form or their integrity may be compromised Early tests were designed to represent the conditions in fluidised bed oxygen blown gasifiers operating at temperatures of 600-1 OOOdegC The results of laboratory tests indicated that few if any of the commercial alloys and coatings could survive in simulated gasifier atmospheres at temperatures above 700degC for more than a few hundred hours Even the best alloys would not survive more than a few thousand hours far less than the years of service needed for commercially acceptable plant performance Tests of the same materials conducted in pilot or demonstration plants showed that the results correlated with the laboratory tests but that the rates of attack were significantly greater in operating plants Alloys containing gt25 chromium initially formed protective scales and the rate of cOlTosion declined This led to some misleading conclusions based on short term tests because after a few thousand hours of exposure the scale broke away and the alloys shifted to rapid corrosion behaviour The addition of an erosive component to the test atmosphere increased rates of cOlTosion by two orders of magnitude for all materials (Perkins and Bakker 1993)

The metal temperatures in the radiant section of the syngas cooler are determined by the insulation protecting them from the direct effect of the hot syngas and by the temperature and flow rate of the cooling fluid flowing through them Since to optimise efficiency the heat absorbed by the coolant has to be used in the process the temperature of the cooling fluid is determined by process requirements Gasifier plants require a supply of steam at various temperatures and pressures The highest temperatures and pressures are used to drive the steam turbine Steam turbines currently used for IGCC are designed to accept superheated steam at around 500-550degC and a pressure of 10 MPa The generation of saturated steam at 10 MPa requires the feedwater to be heated to 320degC This results in a metal surface temperature around 340-400degC In pursuit of higher efficiency it is anticipated that the steam pressure will eventually be increased into the range more generally used for existing subcritical utility boilers around 18 MPa This would increase the saturated steam temperature to 340degC and the metal surface temperature to the 380-450degC range Superheating the high pressure steam to temperatures of 500-550degC requires corresponding metal temperatures in the 550-600degC range (Sorell 1993) In the Shell gasifier the radiant syngas cooler the membrane wall of the gasifier is used to generate medium pressure steam only High pressure steam is generated in the convective syngas cooler and passes with only slight superheating to the HRSG where most of the superheat is provided (Koenders and Zuideveld 1995) The combustion turbine exhaust temperature at full load is around 550degC and the first heat exchange surfaces met by the exhaust gas are the steam superheat and reheat coils in the HRSG This produces a superheated steam temperature of approximately 510degC (Bergmann and Schetter 1994)

66

Gasification

More recent work on syngas induced corrosion has been focused on the syngas mixture produced by oxygen blown slagging gasifiers Two types of syngas may be distinguished based on the gasifier feed Dry coal feed to the gasifier produces a syngas containing ltI steam Coalwater slurry feed produces a syngas containing 15-25 steam EPRI studies reinforced by plant data from KEMA indicate that the rate of corrosion of ferritic stainless steels increases rapidly with increasing temperature and increasing H2S concentration in the gas (van Liere and Bakker 1993) In consequence ferritic stainless steels cannot be used for the higher temperature sections austenitic stainless steels with high nickel content as well as gt20 chromium must be used with the attendant disadvantage of higher cost Kihara and others (1993) used simulated syngas atmospheres to test a number of steels widely used for superheater tubes in conventional boilers The effect of various H2S concentrations and gas temperatures were assessed but the HCI concentration was kept constant at 02 vol Temperatures ranged from 400--600degC and the materials from I25Cr05Mo steel to 25Cr21 Ni steel (31 OS) For all the steels tested an outer and an inner layer formed The inner layer consisted of a sulphideoxide mixture and the outer layer consisted of sulphides iron sulphides for the low alloy steel and iron and nickel sulphides for the stainless steels Chromium oxide formed at the interface of the inner and outer scale layers of stainless steels Small amounts of chlorides were found in the inner scale of all the materials tested The rate of corrosion of stainless steels was found to increase with increasing H2S concentration and with increasing temperature Increasing water content tended to suppress the corrosion of stainless steels and this was attributed to the rapid fOimation of protective chromia scale The rate of corrosion in gas containing 1 H2S was about double that in gas containing 05 H2S The rate of corrosion in gas with 01 H2S was negligible

The H2S concentration in actual syngas depends on the sulphur content of the coal A concentration of I would be produced by a high sulphur coal such as Illinois No6 a concentration of 05 would be produced by a medium sulphur coal and 01 would be produced by a low sulphur coal such as SUFCo and Lemington Direct measurements of the HCI content of syngas are not published From data on boilers fuelled by high chlorine coal it can be concluded that most of the chlorine in the coal is converted to HC In conventional PC-fired power plants 01 chlorine in the coal produces less than 100 ppm of HCI in the flue gas Calculations indicate that a coal containing 01 CI would produce syngas containing 200--400 ppm HCI in an oxygen blown gasifier (Bakker 1993) This is similar to the HCI levels in UK power plants burning high chlorine coals where it has been associated with corrosion of water walls under reducing conditions In addition since gasifiers operate at elevated pressure the partial pressure of HCI in the gas is much higher than in PC-fired boilers

In addition to the problem of high temperature corrosion in the radiant syngas cooler problems of corrosion in the convective syngas cooler have also been encountered Molten fly ash is carried with the gas through the radiant syngas cooler Most of the ash leaves the gasifier as molten slag but

a proportion is carried through into the convective cooler The ash consists mainly of silicate glass but also contains some carbon and partially reacted pyrite The convective cooler is provided with rappers andor 117 sootblowers to minimise fouling but deposits of ash remain when the unit is shut down Analysis of these deposits from various syngas coolers has shown that water soluble chlorides are present in varying amounts Generally when high chlorine coals are gasified the chlorides content of the deposits is high Considerable amounts of water soluble sulphates may also be present Some of the salts such as FeCb are hygroscopic During shut-downs absorption of atmospheric water can give rise to corrosive aqueous phases causing rapid attack on the sulphide scales formed during normal operation of the plant Corrosion may be general or localised attack can occur including pitting and stress corrosion cracking (SCC) In a simulation of the process of shut-down corrosion John and others (1993) exposed a range of alloys in a two step experiment The first exposure was to a hydrogen HCI H2S mixture at 300degC to produce sulphide and chloride corrosion products The second was to moist air and water at 50--70degC The range of alloys tested had Cr contents between 13(lCr-IMo) 356 (Cr35A) and nickel contents ranging from O(Alloy 150) to 58 (Alloy C-276) Of the materials tested only the nickel alloy C-276 (l6Cr 159Mo 5Fe 36W I Co balance Ni) showed good resistance to shut-down corrosion

Hence it appears that the maximum metal temperature in contact with syngas can be limited to around 450degC and that available materials are sufficiently durable under such conditions although for optimum life low sulphur and low chlorine coals are preferable The problems of attack during shut-downs general corrosion pitting and polythionic acid SCC of sensitised austenitic alloys is well known from refinery experience but may be more severe for coal gasifiers with syngas coolers

54 Fixed bed gasifiers Although the fixed bed gasifier is not featured among the large demonstration projects currently in progress the widely used fixed bed Lurgi gasifier has been modified and developed for IGCC The principle of operation of the gasifier is similar to that of the blast furnace In comparison with the conventional Lurgi gasifier the British GasLurgi (BGIL) process utilises higher temperatures at the base of the gasifier to allow the coal mineral matter to be removed as a liquid slag A 500 tid 23 m diameter BGIL slagging gasifier operating at a pressure of 25 MPa wa~ demonstrated at Westfield UK Figure 28 shows some of the main features of the gasifier

Oxygen and steam are injected through tuyeres into the bottom of the fuel bed This creates high temperature zones near the base of the gasifier similar to blast furnace raceways The coal ash melts in this region to form a free flowing slag that collects in the gasifier hearth One of the merits of the fixed bed gasifiers for power generation is that no syngas cooler is required As with blast furnaces the sensible heat of the hot gases is used effectively by their upward passage through descending solid material that is charged cold at the top of the gasifier

67

Gasification

Feed coal

Coal lock hopper -----a~

Distributor drive --~ Cltl

Coal distributorstirrer-f--+-I

Gas quench -----II

Refractory lining

Water jacket Product gas outlet

Pressure shell

Tuyere

1Ll~__-- Slag tap

Slag quench chamber ----a

Slag lock hopper ------r

Slag

Figure 28 BGL fixed bed gasifier (Lacey and others 1988)

541 Bed permeability

For the BGL system it is important to maintain permeability of the coalchar bed In the upper zones of the bed gases must be able to pass freely upwards through the slowly descending burden of coal char and t1ux The development of the gasifier has been assisted by physical and mathematical modelling A model based on heat and mass balances has been used to predict the behaviour of scaled up versions of the gasifier and validated by comparing its predictions with the results from the 23 m gasifier The main requirements for the gasifier are efficient heat and mass transfer between solids and gases within the fuel bed Key

factors are the distribution of coal at the top of the bed of steam and oxygen at the bottom and the drainage of slag to the taphole (Lacey and others 1992)

As with a blast furnace excessive amounts of fine material lead to unstable operation that is manifested by f1uctuating outlet temperatures and varying C02 content in the product gas The fines may be present in the feedstock or may be generated by disintegration of the coal particles as they are heated The gasifier is usually supplied with a graded coal feed typically 5-50 mm However tests at Westfield UK showed that using Pittsburgh coal the gasifier could operate at rated throughput with up to 40 of fine coal added to the sized feed at the top of the gasifier Fines tolerance was marginally less at comparable throughput using Illinois No6 coal Excess fines can be slurried with water and injected into the gasifier through the tuyeres This alternative reduces the steam demand but increases the oxygen demand and lowers the efficiency of the gasifier Briquetting the fines using a bitumen binder allows them to be added at the top of the gasifier with the sized coal This enhances the efficiency of the gasifier and allows a wider selection of coals to be used

Permeability of the bed must be maintained as the coal is charred and gasified The gasifier is able to cope with coals that soften and cake because of the presence in the upper bed of mechanically driven stirring arms One of the developments of the BGL system was the development of a new stirrer with improved cooling and additional arms protected by hard facing materials The introduction of this new stirrer slightly deeper in the gasifier bed allowed strongly caking coals to be completely carbonised and converted into free f10wing solids (Lacey and others 1992)

542 Slag mobility

The fixed bed gasifier appears to need a somewhat more mobile slag than entrained t10w gasifiers Patterson and Hurst (1994) suggest a preferred ash fusion temperature of less than 1400degC compared with 1500degC for the Shell entrained f10w gasifier (Table 15)

However Maude (1993) quotes a slag tapping temperature of 1200degC for the BGL gasifier Lacey and others (1992) describe satisfactory operation with an Illinois No6 coal which from the analysis offered appears to be close to No6 high volatile B bituminous bed code 484 sample 578 (Cavallaro and others 1991) The data indicate an ash fusion

Table 15 Ash and slag requirements for major gasification processes (Patterson and Hurst 1994)

BGL HTW Prenflo Shell Texaco

Ash content low ash content is advantageous for all the gasifiers

Ash fusion temperature c low high if gt1500 ifgt 1500 ifgt 1425 (flow reducing) preferred lt 1400 preferredgt 1100 tlux is added flux is added flux is added

Ash silica ratio 55 optimum not relevant lt801 lt801 lt801

Slag viscosity at tapping temperature Pas lt5 Pas optimum lt15 optimum lt15 optimum ltIS

limit 25 limit 25 limit 25

68

Gasification

temperature of approximately I530degC The paper by Lacey and others (1992) does not indicate the level of flux addition for this or any other coal beyond noting that there has been a simplification of the tuyeres configuration to optimise the number and position of the raceways created in the fuel bed by the steamoxygen blast with the intention of inducing more uniform flow of solids down the fuel bed This has enhanced operation at both high and low loads and it is expected that it will lead the way to substantial reductions in flux requirements Davies and others (1994) reported that gasifying Kellingley coal (a UK bituminous coal) a fluxash ratio of approximately 1 I was required while for Coventry coal a fluxash ratio of 12 was needed In a study by Booras and Epstein (1988) funded by EPRI and British Gas among others it was estimated that using an 115 ash content Pittsburgh seam coal at the rate of 1537 tid 113 tid of flux would be required (flux to ash ratio I 16) There was no reference to the ash fusion temperature of the feed coal but from data on Pittsburgh coals presented in a survey of US coals it appears that the ash fusion temperature for Pittsburgh coal is normally in the range 1100-1350degC (Cavallaro and others 1990) Marrocco and Bauer (1994) ascribe some of the difficulties with ash sintering at the Tidd PFBC (see Section 43) to the extremely low ash fusion temperature of the Pittsburgh No8 coal burnt at Tidd The temperature viscosity relationship for the slag from Pittsburgh coal without flux is shown in Figure 25 It appears that while the BGL gasifier is capable of gasifying a wide range of coals the flux requirement could be considerable for high ashhigh ash fusion temperature coals

55 Fluidised bed gasification If gasification is defined as the essentially complete gasification of a fuel leaving only ash then the operation of fluidised bed systems is complicated by the need to obtain acceptably efficient carbon utilisation without using temperatures that would cause the bed to agglomerate In practice this problem has been resolved by the provision of a separate char combustion stage and it has been said that for this and a number of other reasons fluidised bed gasifiers should be classified among the hybrid combined cycle systems and optimised accordingly (Maude 1993) However with a carbon conversion of 98 in the gasifier Rheinbraun argue that the HTW system is a gasifier with an auxiliary

combustor (Adlhoch 1996) Second generation PFBC where the gasifier is an accessory to the combustor might be regarded as the other extreme of the hybrid cycle concept Between these two extremes hybrid systems are being developed with the intention of achieving the energetically optimum balance between gasification and combustion (see Section 56)

551 Char reactivity and ash fusion

In fluidised bed combustors the bed consists mainly of mineral matter derived from the coal injected sorbents and their reaction products In fluidised bed gasifiers the carbon content of the bed is much higher but mineral matter is still the major constituent of the bed If any of the components of the mineral matter soften at the bed temperature agglomeration can occur leading to uneven fluidisation poor performance and ultimately blocking of ash off-takes Hence the char must be sufficiently reactive to allow acceptable conversion rates at gasification temperatures that are safely below the ash fusion temperature This prerequisite is met by a range of feedstocks

The agglomerating properties of some British coals were studied using two pilot plant scale fluidised bed gasifiers a pressurised spouting bed gasifier and an atmospheric pressure fluidised bed gasifier (West and others 1994) Bed temperatures were allowed to rise until agglomeration was detected Coals bed materials and agglomerates from both reactors were analysed Essentially two types of bond between large decomposed clay particles were observed

in one example illite particles showing evidence of internal fusion were bonded by an Fe-S-O phase that completely covered the clay surface with coating

approximately 50 11m in thickness and in a second specimen an illite particle was bonded to a kaolinite particle by an iron aluminosilicate glassliquid phase Glassy bonds containing significant amounts of CaO were found when limestone had been added to the coal feed as a sulphur retention agent

The viscosity of the iron alurninosilicate glass was found to playa major role in the agglomeration and sintering reactions Table 16 shows that part washing a coal can

Table 16 The effect of coal washing on mineral matter analysis (West and others 1994)

Wt

Ash from Kiveton Park washed coal Quartz Illite Kaolinite

Pyrite

Ash from Kiveton Park run of mine coal Quartz Illite Kaolinite Pyrite

Sieved ash fraction 11m

lt38 38-50 50-71 71-100 100-250 250-500 50()-1000 gt1000 Bulk

15 30 29 26

7 30 35 29

5 3 37 27

6 34 30 30

25 46 29 0

21 52 24

3

22 55 24 0

16 52 29 3

18 34 33 5

25 40 24 11

14 43 29 14

6 51 26 7

12 45 25 18

19 50 31

0

2 46 32 0

28 43 28 0

20 41 29 10

69

Gasification

selectively remove quartz illite and kaolinite with a resultant enrichment of the remaining mineral matter in pyrite

Under the reducing conditions that would be found in pressurised fluidised bed gasifiers iron can act as a fluxing agent Analysis of the ash from washed coals showed that iron was concentrated in the finer size fractions of the ash The initial sintering temperature for ash fractions less than 100 lm in size was found to be at least 150degC lower than the sintering temperature of the larger sized fractions The following mechanism for agglomeration has been suggested large clay derived particles with an Fe-S-O coating act as precursors Further oxidation and reaction with fine clay particles allows an iron-rich aluminosilicate to form The rate of sintering is strongly dependent on the viscosity of this phase which is in tum related to the acidbase ratio of the melt Consequently an increase in the amount of pyrite in the finer ash fraction will increase the agglomeration potential of the ash Similarly the addition of limestone to the coal feed may also reduce the viscosity of the aluminosilicate melt (West and others 1994) It appears that cleaning a coal may increase ash fusion problems and the addition of sorbent may also be problematic Several types of air blown gasifier have features designed to widen the range of economically gasifiable coals without incurring ash agglomeration constraints

552 High Temperature Winkler (HTW) gasification process

The Winkler fluidised bed coal gasification system predated the Lurgi fixed bed gasifier Like the Lurgi gasifier it was initially operated with airsteam as the oxidant for the gasification of German brown coal The high reactivity of brown coal gave an acceptable conversion efficiency but it was necessary to bum elutriated fines in a separate boiler The use of oxygensteam allowed the process to be extended to the gasification of less reactive bituminous coals (Francis 1965) The Winkler gasifiers were superseded by the Koppers-Totzek gasifier for atmospheric pressure operation and by the pressurised Lurgi gasifiers The further use of the conventional Winkler gasifier was said to have been limited by low capacity high operating costs and low carbon conversion (Simbeck and others 1993) However Rheinbraun AG continued development of the process and have produced a high pressure high temperature version (HTW) The original Winkler process featured a bubbling f1uidised bed In the modified version the bed can be operated in an expanded bubbling bed or circulating mode A commercial scale HTW demonstration plant for gasifying brown coal went into operation in 1986 at Hiirth near Cologne in Germany The plant converts around 25 tlh of dry brown coal to coal gas at a pressure of approximately 10 MPa A second plant using dried sod peat as feedstock went into operation in Finland in 1988 The sod peat is a particularly suitable feedstock because its water content is only 30 to 40 (Keller 1990) Figure 29 shows a simplified diagram of the HTW gasifier

Fluidised bed gasifiers are designed to operate at relatively low gasification temperatures to avoid the problems of bed

Coal feeding system

Feed bin

Raw gas cooler

Lock hopper Raw gas

Charge bin

Gasification agent (02air)

Fluidised bed

Feed screw Gasification agent (02air)

Char discharge system

COllection bin

Lock hopper

Discharge bin

Figure 29 Simplified diagram of the HTW gasifier (Keller and others 1993)

agglomeration The high temperature Winkler gasifier is so called because its maximum operating temperature is higher than that of the former Winkler gasifier The temperature of the lower part of the f1uidised bed is around 800degC with the high temperature provided by injecting additional steam and oxidant into the upper region of the bed giving a freeboard temperature in the range 900--950degC This serves to improve carbon conversion and to decompose any high molecular weight organic compounds The suitability of a wide of range feedstocks for the HTW gasifier has been established by extensive bench-scale testing and in some cases by additional pilot plant and industrial scale tests (see Table 17)

Volatile matter content governs the reaction kinetics in the lower section of the f1uidised bed Biomass gives a volatiles yield of 80 to 90 by weight The residue is a reactive char High specific throughput is possible at moderate bed temperatures and so the ash melting behaviour of these feedstocks is not critical As the volatile matter content falls it is necessary to increase the bed temperature Hence the process is particularly suitable for peat and brown coal but may also be used for higher rank coals producing refractory ash (Keller 1990) Keller reported carbon conversion efficiencies up to 98 However for IGCC applications it was necessary to include a separate f1uidised bed combustor to achieve adequate carbon utilisation Design studies for a proposed 1400 MWe HTW IGCC plant fuelled by a highly reactive Australian brown coal indicated that an auxiliary char combustor would be needed with an output of 25 MWe

70

Gasification

(Hart and Smith 1992) The final combustion stage also has the merit of converting sulphide in the gasifier ash to sulphate This produces an ash similar to that from conventional FBC which normally is virtually free of sulphide

Processes exemplified by the KRW and Tampella U-GAS designs overcome the temperature limitations posed by ash agglomeration by designing a degree of agglomeration into the process However the KRW Pinon Pine gasifier at Reno NV USA will also feature a bubbling tluidised bed reactor to burn residual char in the ash and to sulphate calcium sulphide from the sorbent

Table 17 Feedstocks tested for HTW gasification (Schiffer and Adlhoch 1995)

PDU Pilot Industrial scale scale scale

Low rank coal Brown coal High sulphur brown coal Lignite Subbituminous coal

Hard coal Ensdorf - Saar Pittsburgh No8

Other low rank fuels (biomass and energy plants)

Peat Wood Straw

Waste materials Sewage sludge Loaded coke Used plastics Used rubber

56 Hybrid systems The HTW and KRW based IGCC systems appear to accept separate char combustors as a necessary evil in order to achieve acceptable carbon conversion and to SUlphate the sorbent Another approach is to optimise the gasifiercombustor combination PFBC systems can achieve efficient carbon conversion and achieve partial combined cycle operation by using a hot gas expander but their efficiency is limited by the moderate temperature of the gas to the expander and the relatively high proportion of the energy bypassing the expander The inlet temperature of the gas expander is limited by the bed temperature which is limited by bed agglomeration problems and the need to avoid excessive alkali content in the gas Hence most of the heat from the coal is removed by bed cooling tubes and passes directly to the steam cycle For the PFBC system that has been demonstrated at utility scale 15-20 of the power output comes from the expander and 85-80 from the steam turbine Thermodynamic considerations indicate that the

appropriate combination of a fluidised bed gasifier with a fluidised bed combustor can be more efficient than either FBC or IGCC alone (Lozza and others 1994 Maude 1993) In principle some of the limitations of fluidised bed IGCC and FBC might be removed by a judicious combination of the two technologies

for second generation PFBC gasification of a proportion of the coal feedstock would yield a gas that could be used in a topping combustor to increase the temperature of the gas to the expander and for fluidised bed IGCC as well as solving the problems of carbon conversion and sulphide conversion the associated FBC might ease the problems of producing high quality steam to power a high efficiency steam cycle

However the design of high efficiency hybrid cycles presents its own technical challenges The gas leaves the gasifier at a temperature around 80o-900degC Thermal efficiency is enhanced if the gas is transferred hot to the combustion turbine This is particularly valid for an air blown gasifier which produces large quantities of low heating value gas The technical challenge becomes more exacting as the definition of hot moves from 270degC (HTW process) to the region of 900degC (PFBC Tidd and Wakamatsu) Gas filtration at 270degC has been demonstrated at the HTW demonstration plant in Berrenrath Germany Testing over 7000 h showed no fundamental problems with the system and completion of the test programme in 1997 is expected to lead to a filter that is fully operational at industrial scale and has been optimised in terms of economy (Wischnewski and others 1995) The problems of cleaning coal derived gas at temperatures in excess of 600degC to a quality suitable for a high performance combustion turbine have not yet been resolved (Thambimuthu 1993) In particular volatile alkali chlorides and HCl are detrimental to the longevity of combustion turbines Table 18 shows the saturated vapour pressure (svp) of the salts at various temperatures

It has been suggested that the maximum concentration of alkali metal in the expansion gas of a turbine should be limited to 24 ppb The gas from a gasifier is mixed with air or with oxygen containing off-gas from the PFBC before being burnt and expanded through the turbine Because of the dilution the allowable alkali concentration in the gas is

Table 18 The saturated vapour pressure of alkali chlorides (Kelsall and others 1995)

Saturated vapour pressure Gas temperature degC parts per billion metal

Na K

400 500 550 600 900

0 I 15 100 160000

0 10 70 400 620000

from Sondreal and others (1993)

71

Gasification

correspondingly higher than that required for the turbine Assuming an air to fuel ratio of 25 1 gives a maximum allowable total alkali chlorides concentration in the fuel gas of 84 ppb (Kelsall and others 1995) Since alkali metals are present in coal and in the commonly used sorbents there is the potential to exceed this concentration at high gas temperatures

The volatile alkali metal species in the strongly reducing gas from a gasifier are chlorides hydroxides and sulphides The concentrations of alkali metals in the gas from FBC are dependent on a range of factors including gas temperature and pressure and coal analysis In a combustion environment below 1000degC the presence of sulphur oxides tends to convert alkalis into much less volatile sulphates Table 19 shows the vapour pressures of alkali sulphates chlorides and hydroxides at 900degC (Sondreal and others 1993)

Mojtahedi and Backman (1989) investigated the fate of sodium and potassium during the pressurised fluidised bed combustion and gasification of peat From both thermodynamic calculation and experimental determinations they found that combustion typically gave

Table 19 Alkali saturation in coal-derived gas (Scandrett and Clift 1984)

Species Saturation Concentration of vapour pressure Na or K ppm wt Pa at 900degC in gas at I MPa 900degC

Na2S04 00029 0004 K2S04 0023 006 NaCI 210 160 KCI 480 620 NaOH 1400 1000 KOH 2300 3000

based on a mean gas molecular weight of 30

much lower concentrations of volatile alkali metals than gasification At 900degC the vapour pressure of alkali metals in gasifier off-gas was two orders of magnitude higher than the vapour pressure of alkali metals in combustor off-gas A high fuel chlorine content was found to enhance the volatilisation of alkali metals during combustion by favouring the formation of vapour phase alkali chlorides Laatikainen and others (1993) measured alkali metal concentrations in the gas from a PFBC test rig using a range of fuels The range comprised

peat A a well-decomposed fuel peat peat B a young high volatile matter peat a brown coal coal A a Polish bituminous coal coal B an American coal

Table 20 presents analyses for the fuels used in the tests and Table 21 summarises the measured concentrations of alkali metals in the gas stream

Lee and others (1993) measured concentrations of alkali metals in PFBC off-gas using coals from Illinois USA They found that sodium was the major alkali vapour in species in PFBC flue gas and that vapour emission increased linearly with both the sodium and the chlorine content of the coals This suggests that the sodium vapour emissions resulted from the direct vaporisation of the sodium chloride present in these coals The measured alkali vapour concentrations 67-90 ppb were some 25 times greater than the allowable alkali limit of 24 ppb for an industrial gas turbine For the air blown gasification of peat at temperatures around 870degC Kurkela and others (1990) found a total concentration of alkali metals in the gas stream an order of magnitude higher than that allowable for a gas turbine but somewhat lower than that predicted by thermodynamic considerations Hence depending on the properties of the coal it appears that some provision for removing volatile alkali metal compounds might be required for systems where the gas is cleaned and used hot

Table 20 The average properties of peat coal and brown coal used in the tests (Laatikainen and others 1993)

Peat A Peat B Brown coal Coal A Coal B

Proximate analysis wt db Volatile matter 696 725 514 284 335 Fixed carbon 268 25 433 543 53 J

Ash 36 25 53 174 134

Ultimate analysis wt db C 54 548 694 684 688 H 57 58 48 43 43 N 17 09 07 12 12 S 02 01 04 12 29 o (by difference) 348 359 24 75 96

Na ppm wt 377-506 264-300 503 1167 857-14706 K ppm wt 446-636 504-525 244 4197 2268-3381 CI ppm wt 734-817 191 ND ND 1099-1133

results not cited because of contamination

72

Gasification

Table 21 Summary of the measured concentrations of vapour phase alkali metals (Laatikainen and others 1993)

Sodium ppb wt Potassium ppb wt Temperature Total of

degC Range Average Range Average averages

Peat A Freeboard 730-771 90-480 210 100-600 320 530 After cyclones 691-739 170--510 280 140--560 300 580

Peat B Freeboard 704 290 290 290 290 580 After cyclones 649-735 100--250 160 90-310 200 360

Coal B-1 After cyclones 788-816 80-190 120 110--340 210 330

Coal Bsect After cyclones 673-833 70-450 190 100--200 150 340

Measurements before cyclones Peat A 705-810 ND~ ND~ 210--380 290 gt290 Peat A 674-745 110--200 160 70-320 170 330 Coal A 747-799 60-280 150 100--250 160 310 Brown coal 677-689 60-100 80 100--140 120 200

without any additive sect with limestone

-I with dolomite II results not cited because of contamination

Only 70 to 80 of the coal is gasified the remaining char 561 The air blown gasification cycle passes to the CFB combustor Heat is extracted from the

The developers of the air blown gasification cycle (ABGC) avoided the more difficult problems of hot gas cleanup by cooling the gas to around 450degC A development programme funded by GEC Alsthom PowerGen Mitsui Babcock the UK Department of Trade and Industry and the European Commission has a]]owed the specification for a 75 MWe demonstration plant to be defined and a commercial director has been appointed to coordinate the funding of the demonstration project (Burnard 1995) Figure 30 shows the proposed arrangement of the ABGC process

Coal ~ amp sorbent To

steamI circuitSteam

Pressure let down

combustor by circulating the bed through a bubbling bed heat exchanger which provides final superheat for the steam cycle The fuel gas at up to 1000degC depending on the process requirements passes to a heat exchanger where the gas is cooled to around 450degC Particulates including solid state alkali metal compounds are then removed using a ceramic filter The gas leaving the ceramic filter is of a quality suitable for use in a combustion turbine but the demonstration plant will be provided with side stream facilities for testing various hot gas cleanup options If

WastePulse gas heat recovery

To steam circuit

Gas

(===~sect~===jisect~====~~~~tostack

Air

)eZlt------H- Condenser

Air to CFBC

Steam turbine FluidisingTo ampgeneratorE]Air airsteam

circuit[ZJ Steamwater Air from heater

Ash

Figure 30 The air blown gasification cycle (Dawes 1995)

73

Gasification

successful these options for removing nitrogen species and residual sulphur would improve the environmental perfomlance of the technology In this present configuration 50 of the electric power would be generated using the steam turbine and 50 using the combustion turbine The overall efficiency using a subcritical steam cycle and aGE frame 6 B combustion turbine modified for the low heating value gas is estimated at 478 HHV (Dawes and others 1995)

The ABGC might be described as a hybrid process based on an air blown gasification process In Alabama USA an advanced PFBC process is being developed that might be described as a hybrid process developed from PFBC

562 Advanced (or second generation) PFBC

The Power Systems Development Facility (PSDF) at WilsonviJ]e AL USA is a cost-shared effort between the US Department of Energy and the EPRI The facility will be used to test advanced power system components The PSDF consists of several modules for component and integrated system testing including advanced PFBC Figure 31 is a simplified presentation of the Foster Wheeler second generation PFBC concept

Coal and sorbent are fed to a pressurised carboniser where the coal is converted to a low heating value gas and char TIle char is burned using pressurised circulating fluidised bed combustion (PCFBC) The design temperature is 871degC (1 600degF) Significantly higher temperatures would cause increased alkali release and depending on the feedstock used increase the risk of sintering and agglomeration in the burning bed Fuel gas from the carboniser is burned using the PCFBC flue gas as the oxidant The hot gases are cleaned before they are mixed for combustion Each of the high temperature gas treatment systems comprises a cyclone a hot gas filter and an alkali metal absorber The design coal for the process is Pittsburgh No8 a 3 sulphur high volatile bituminous coal (proximate analysis 51 fixed carbon 36 volatile matter 10 ash and 3 moisture) (Blough and Robertson 1993 Robertson and Van Hook 1994) Development work showed that the plant efficiency is significantly affected by the perfomlance of the carboniser Initial experimental work indicated that increasing the carboniser operating temperature from 816degC to 871 DC would increase the topping combustor heat release by approximately one third This increased the estimated efficiency for a full scale plant from 436 HHV to 449 HHV (Blough and Robertson 1993) Subsequent tests using a pilot scale carboniser suggest that the earlier estimation of gas yield was pessimistic and that an efficiency of 462 HHV could be expected using the design coal and a 871degC carboniser temperature (Robertson and Van Hook 1994)

Steam generation (HRSG)

Alkali getter

Particulates removal

Ash Coal

Alkali getter

Sorbent

Sorbent Sorbent Sorbent Steam generator FBHE

Air

Figure 31 Simplified process block diagram - second generation PFBC (Robertson and others 1994)

74

6 Economic considerations

Economic considerations are central to the question of advanced power systems and the quality of coals that they are able to use The basic technologies discussed in this report can be adapted at some cost to consume virtually any coal but this is a worthwhile exercise only if there are significant commercial advantages Some factors that might be considered when assessing the commercial merits of a technology are

the cost of electricity produced per kWh investment cost per kWe and the risk of commercial failure

The dominant technology for the utility production of electricity from coal is the large subcritical PC-fired power station fuelled by bituminous coal There is also a considerable inventory of PC-fired power stations which use subbituminous coals and lignites It is generally considered that advanced power systems have higher capital cost than conventional subcritical PC systems and that the risk of commercial failure is higher An GECDIEA survey of the opinions of power generators and others who are members of the Coal Industry Advisory Board found that while power utilities clearly see the potential benefits of enhanced environmental and efficiency performance as advances over existing technology they are not prepared to pay extra for it and are reluctant indeed in most cases unwilling to take the full commercial risks of early deployment (CrABlEA 1994)

Accepting that utilities will generally not pay extra for advanced technology in cost of electricity terms leads to the problem of quantifying the benefits of the technologies Some or all of the general headings deciding the commercial desirability of a project are affected by site specific factors such as emissions consent levels the cost and availability of fuel and by factors affecting the wider locality such as expected rates of return on capital invested and economic growth prospects

61 Costs of conventional and supercritical PC power stations

Considering conventional PC power stations for which there is the largest body of experience various investment costs are quoted depending on the location the level of environmental emissions control provided and the method of assessing the cost Costs quoted mayor may not include site value provision of services to the site the costs of facilities for stores and personnel and interest charges incurred before the power station is commissioned In most countries electricity generation is capital intensive the greater part of the cost of electricity arises from the cost of the capital investment needed to pay for the engineering and construction of the power station The discount rate and the assumed commercial life of the project are key parameters in calculating this cost Govemments have used discount rates as low as 4 over a 30 year repayment life In the private sector a project life of 20 years with discount rates in the range 8-15 would be more typical with the higher end of the range applied for projects having a perceived high risk (Gainey 1994a) If a project is evaluated on a 30 year life and a 4 discount rate the levelised annual capital cost is 70 less than for the same project assessed on a 20 year life and a 75 discount rate (Weale and Lee 1995) Expressing this in mortgage terms if an initial loan of $1000 were repaid in equal repayments over 30 years at an interest rate of 4 the annual repayment would be $5783 The yearly repayment for the same loan over 20 years at an interest rate of 75 would be $9809

611 PC power stations fuelled by high grade bituminous coal

Most of the existing PC-fired power stations use subcritical steam conditions Currently both supercritical and subcritical power stations are being built In general the higher thermal

75

Economic considerations

efficiency of supercritical power stations offers savings in fuel cost but at the expense of increased capital cost The use of historic data to assess the costbenefit balance of improved efficiency is problematic because site specific factors are important

An GECD report prepared and published jointly by the International Energy Agency and the Nuclear Energy Agency presented cost data for conventional bituminous coal-fired power stations on a discounted cash flow basis The objective of the report was to compare the relative costs of coal and nuclear fuelled electricity production However the exercise provided some interesting international comparisons The total capital cost for a conventional subcritical coal-fired power station ranged from around US$1600kWe for four 600 MWe units with FGD in Japan to US$701kWe for a single 600 MWe unit with FGD in Denmark (US$ January 1987) Table 22 is a brief extract from the much more comprehensive data presented in the report

The table illustrates the difficulty inherent in discussing costs in an international context even when established technology is being considered In Denmark where plant appears to be relatively inexpensive in US$ terms the cost of the imported coal on the basis of the assumptions implicit in Table 22 is approximately 57 of the cost of electricity Table 23 shows the effect with the more commercial discount rate of 10 and the price of coal adjusted to allow for the costs of unloading and delivery

Using these assumptions the fuel cost for a 600 MWe conventional power station in Denmark was 52 of the total

electricity cost of 398 millskWh (one mill = US$ 0001) (GECD Nuclear Energy Agency 1989) Although Danish utilities buy their coal at internationally competitive prices coal appears to be relatively expensive in Denmark in comparison with the capital cost of plant This may in part explain the preoccupation of Danish utilities with achieving high thermal efficiency although environmental and other issues are also involved Internationally traded coal is priced in US$ The costs of a power station are largely defrayed in the currency of the country where it is built The turbines and generators may be imported but civil engineering works alone account for 25 to 30 of the cost of the project (CEGB 1986) and most of the balance of the plant is fabricated on site or in the locality Hence the apparent capital cost of a power station in US$ terms and the relationship between the capital cost of the power station and the cost of coal is strongly influenced by costs within the country assumed discount rates and the currencyUS$ exchange rate It should be noted that the data relate to new conventional subcritical PC-fired power stations

Concerning the relative costs of the technologies PC power stations benefit from economies of scale and this further complicates the process of drawing comparisons Maude (1993) quoted a theoretical relationship between plant cost and plant size

Where Cl and Cz represent the specific capital costs ($kWe) for plants rated at M I and Mz (MWe) respectively

Table 22 Breakdown of coal-fired investment costs (OECD Nuclear Energy Agency 1989)

All costs in January 1987 US$kWe Discount rate 5

Country Number of units xMWe

Method of cooling

Data based on

Construction cost

FGD Interest during contruction

Spare parts

Total capital cost

Japan 4 x 600 sea 1490 included 145 included 1635 USA (Midwest) I x 572 river estimate 1143 included 188 included 1340 UK Z x 850 sea estimate 1124 included 192 included 1316 Italy 4 x 613 sea ordered plant 1124 included 144 included 1268 Sweden 2 x 600 sea quotation 912 185 157 included 1254 Turkey 2 x 165 direct cooling plant under construction 1000 none 135 20 1155 Belgium 2 x 600 river quotation 1073 included 77 3 1153 Portugal 4 x 283 sea ordered plant 996 none 147 included 1143 France 2 x 580 sea recently built 1026 included 104 included 1130 Australia 4 x 350 river 968 included 92 included 1060 Germany I x 698 closed cycle plant under construction 931 included 91 included 1022 Finland 2 x 500 sea estimate 714 125 96 5 940 Canada

Central 4 x 500 lake estimate 711 included 101 4 816 East I x 400 sea estimate 819 included 96 included 915 West 2 x 350 closed circuit estimate 897 included 130 included 1027

Netherlands 2 x 600 sea quotation 776 included 104 included 880 Demark I x 600 sea estimate 641 included 60 included 701

I x 350 sea estimate 768 included 72 included 840

includes de-NO ($75kWe)

76


Maude (1993) estimated a capital cost of $1883kW for heating value of 293 MJkg then the fuel cost of electricity is 150 MWe subcritical PC power station $1537kW for a 1672 millskWh Hence in terms of fuel savings an increase 300 MWe subcritical PC power station and $1674kW for a of efficiency of around 6 percentage points is required to 300 MWe supercritical PC power station Gainey (l994a) justify an additional expenditure of $IOOkW an increase in quoted capital costs for units of approximately 700 MWe efficiency from 36 HHV to 416 HHV gives a calculated capacity subcritical PC $1200kW supercritical PC fuel cost saving of 225 millskWh $1300kW Both authors prefaced their estimates with a warning that their accuracy was likely to be of the order of VEBA Kraftwerke Ruhr Germany are reported to be plus or minus 30 The specific cost for the new power proceeding with the planning and permitting stage in the stations in Germany using bituminous coal is reported to be construction of a 700 MWe supercritical bituminous in the range OM2000-2500kW (1995 OM) coal-fired power station With steam conditions of ($1428- n86kW assuming $1 = 14 OM ) The estimated 275 MPal580degc600degC and a feedwater temperature of specific capital cost for a new supercritical power station at 300degC the predicted net efficiency is approximately 45 Bexbach Saarland Germany is said to be near the lower end (LHV) (Eichholtz and others 1994) The steam conditions of that range (Billotet and Johanntgen 1995) The design require the use of P91 at its design limits and the feedwater provides for a maximum output of 750 MWe with FGO and temperature of 300degC requires a high pressure steam bleed SCR Weirich and Pietzonka (1995) assert that assuming a from the turbine The financial gains from increased output specific cost of US$1000kWe the specific cost for a and enhanced performance were said to justify the additional supercritical plant (25 MPal540degC560degC) will be no higher expenditure involved in moving to the advanced steam Hence estimates of the capital differential between conditions However any further increase in steam conditions subcritical and supercritical PC have generally indicated an would require austenitic stainless steels to be substituted for increased specific cost in the range 0-10 P91 This would cause a step increase in capital and

maintenance costs as well as reducing operating flexibility Sensitivity analyses presented in Gaineys paper (Gainey The results of another costbenefit analysis performed in 1994a) indicate that an increased capital expenditure of Germany a few months later broadly confirmed these $100kW increased the capital element of the cost of conclusions but denied the benefit of high pressure steam electricity by 225 millskWh A life of 20 years was extraction With a coal price in the region of OM3GJ assumed with discount rate of 8 and a load factor of 65 (US$63t) a supercritical single reheat cycle According to Weale and Lee (1995) the cost of imported (27 MPal585degC600degC) and a feedwater temperature of coal at power stations in Europe was around $70t of oil 275degC gave the lowest cost of electricity This conclusion equivalent ($49t of hard coal) If the efficiency of a modem was also based on the use of P91 to its design limits The use subcritical power station with FGO is taken to be 36 HHV of high pressure steam extraction would have increased unit and the cost of coal at the burners is taken to be $49t at a efficiency by 03 percentage points but was not viable under

Table 23 Summary of levelised discounted electricity generation costs (30 years lifetime 10 discount rate lifetime average load factor 72 CIAB coal price assumption) (data derived from OECD Nuclear Energy Agency 1989)

All costs in millskWh January 1987 US$ (I mill = US$ 0001)

Country NCU Investment Operating Fuel Total Fuel cost US$ and as

maintenance of total

Denmark 734 125 67 206 398 52 Finland 479 173 59 223 455 49 Netherlands 219 169 41 179 389 46 Germany 194 181 86 215 482 45 Portugal 1461 203 57 206 466 44 France 646 198 48 187 433 43 Italy 1358 234 69 224 527 43 Turkey 7578 22 3 178 428 42 Sweden 682 231 84 222 537 41 Belgium 4041 223 96 215 534 40 Spain 1324 221 61 176 458 38 United Kingdom 068 249 69 184 502 37 USA (Midwest) 100 267 6 145 472 31 Japan 1591 321 133 199 653 30 Australia 150 185 22 70 277 25

NCUUS$ stands for national currency units per US$ as at January 1987 CIAB coal prices have a surcharge applied to cover unloading and delivery to power stations of 15 for Germany 10 for Italy and Turkey and 5 for other countries indigenous coal CIAB price assumption not applied

77

48


the conditions assumed for the study because of the relatively high capital expenditure involved (Rukes and others 1994) A number of designs for hard coal-fired power stations including IGCC PFBC double reheat supercritical and single reheat supercritical were considered For load factors in excess of 72 the single reheat supercritical design gave the lowest cost of electricity Double reheat was also considered but found to give a slightly higher cost of electricity

The Nordjyllandsvlterket supercritical power station in Northern Jutland Denmark as well as having high pressure steam extraction to preheat the feedwater to 300degC will also use double reheat Assuming an imported coal price of DM 35IGJ (73 $t) the direct financial benefit of the second stage of reheat which increased the cost of the power station by 20 million DM was said to be in the lower region of the break-even price Other operational considerations were significant in the choice of two reheat stages Cooling water temperatures in Denmark may fall below OdegC in winter The use of cold sea water for cooling the steam condensers contributes to the high efficiency figures quoted by Danish coastal power stations (see Figure 32)

However the low condenser pressure that this produces can give rise to relatively high moisture concentrations in the low pressure turbine if single reheat is used The resultant water droplets can cause serious erosion damage The double reheat process was found to give an exhaust moisture content of 8 in comparison with 15 for the single reheat process (Kjaer 1993)

547 -J

gt g46OJ 0

~

~45

2345678 9 Condenser pressure kPa

(steam conditions 285 MPaJ580degC580degC580degC)

Figure 32 Impact of condenser pressure on net efficiency (Kjaer 1993)

612 PC power stations using low rankgrade coal

In the USA low rank coals are classified under ASTM standards as subbituminous if they have a higher heating value (HHV) between 11500 Btulb and 8300 Btullb (267-193 MJkg) and as lignites if they have a HHV below 8300 Btulb (193 MJkg) The HHV is expressed on a moist mineral matter free basis Describing a coal as low rank does not necessarily imply that it is of low value Low sulphur subbituminous coals may be commercially attractive

but at the lower end of the subbituminous range and into the lignites the coals tend to have a number of other disadvantages that impact on boiler design and cost In consequence the value of the coals does tend to be less

Because low rank coals as well as having a low HHV typically have a higher water content than bituminous coals a greater tonnage has to be consumed for a given heat output Large furnaces are required to accommodate the steam produced from the high water content and a larger proportion of the heat is lost as the latent heat of water in the stack gas The high oxygen content provides active sites for organically bound cations Hence the coals tend to have a high level of bound inorganics which confer a high fouling propensity Large furnaces are required to minimise the effects of the high fouling propensity The additional volume allows flow velocities to be reduced and allows wider spacing of the tubes in the convective section of the boiler (Johnson 1992) These factors result in a higher capital cost for a boiler suitable for low rank coal burning and this tends to negate the advantages of low cost fuel

The Loy Yang power station situated in the Latrobe Valley Victoria Australia uses high sodium lignite and has boilers with about 25 times the volume of bituminous coal-fired boilers of equivalent output (Johnson and Pleasance 1994) For the subcritical 500 MWe Loy Yang A tower boiler the total height of the radiant and convective sections is 72 m from the ash hopper and the cross section is 324 m2 For a boiler of similar output firing bituminous coal the corresponding measurements are 47 m x 189 m2 (Couch 1989) Table 24 shows some estimated costs of electricity in Victoria Australia

The delivered cost of the Latrobe Valley brown coal is only a fraction of the cost of out of state sourced bituminous coal According to Johnson (1992) the heating value of the coal is in the range 7-10 GJt and the thernlal efficiency of Loy Yang is 291 HHV Hence even on a $IGJ basis and allowing for the lower thermal efficiency of a brown coal-fired boiler the cost of the coal is substantially less than that of black coal However the cost of electricity from the Latrobe Valley coal is estimated to be approximately 35 higher Similar considerations apply for some of the German brown coals and the dimensions of the German 500 MWe subcritical brown coal boilers are similar to those of Loy Yang

Table 24 Estimated cost of electricity for PC firing in Victoria Australia (Data from Johnson and Pleasance 1994)

Process Fuel cost Levelised cost A$t of electricity centkWh

A$ US$

Brown coal conventional PC 3-7 49-54 37-41

Bituminous coal conventional PC 29-34 37- 49 28-37

December 1993 dollars

78


Efficiencies considerably in excess of 29 can be attained with lignites by using more advanced steam conditions but the boilers tend to be even bigger Some features of German supercritical pulverised brown coal-fired boilers have been described in Section 24 The new 800 MWe supercritical brown coal-fired boiler for Boxberg power station in Gennany will have a tower boiler 160 m x 576 mZ the efficiency is quoted as 39 LHV (Eitz and others 1994)

62 Motivating factors for the use of low rankgrade coal

In spite of the disadvantages of low rankgrade coal for PC combustion a combination of factors may favour its use when it is locally available Although this section is primarily concerned with commercial costs broader socioeconomic issues may also be involved in the planning of electricity supply projects In the USA in defence of the continued local use of Midwestern high sulphur coals it has been said that coal mining is associated with strong labour unions fraternal leadership and close political relationships and probably most importantly in the more recent past it has continued to provide secure jobs and a secure tax base to an Appalachian region that has been devastated by downsizing andor departure of old mainstay industries (Biddeson 1994)

Some of the arguments presented in favour of the continued production and use of Midwestern USA coals might also be applied with equal or greater force to the production of low rank andor low grade coals elsewhere

In 1991 in the USA the value of production of the US coal industry which employed more than 140000 people was approximately $20 billion per year About 55 of the electricity used by US consumers is produced in coal burning power plants and of this about 10 is produced using low rank coal Jackson lignite is the lowest quality coal used for commercial electricity generation in the USA This low rank low grade Texas lignite has an ash content of 28 with 5 alkali metals in the ash (Schobert 1995) The heating value is in the range 98-148 MJkg

In Central and Eastern Europe in 1992 just under 20 of their primary energy was provided by the use of low rank coal The most significant feature of the energy economy of Eastern and Central Europe is the scale and dominance of the low rank coal industry (Randolph 1993)

In 1989 the Gennan Democratic Republic (GDR) was the largest producer of brown coal in the world with a production of 30 I miUion tonnes When the GDR joined the Federal Republic of Germany in 1990 nearly 80 of the GDRs generating capacity was based on the use of brown coal Most of the units were small inefficient and highly polluting The best of the units have been upgraded but by 1996 only about a quarter of the original brown coal-fired units will remain Around 6000 MWe of new brown coal-fired capacity will come into operation in Germany between 1996 and 1999 six 800 to 950 MWe brown coal-fired units and two units of 450 MWe are being built (Schilling 1995)

Polands Silesia region has earned the nickname The Black Triangle because of its heavy atmospheric pollution Much of this pollution comes from a concentration of power plants which burn local lignite and make an important contribution to the regional power grid serving Gennany Poland and the Czech Republic The Turow power station is located in this region Six of its ten units are more than 30 years old In recent years the power station has been found to be unreliable and excessively polluting More than 100000 jobs in the regional economy depend on its operation including 3000 in the power station and 6000 in the local mine It is not felt that shutting down the power station can be considered as a practical option but upgrading of the facilities is highly desirable In the first phase of a 10 year plan units I and 2 will be repowered using CFBC boilers By the end of the next decade the net capacity at Turow will have been increased from 2000 MWe to 2300 MWe and the station will be operating in compliance with Western European environmental standards (Gaglia and Lecesne 1995)

Bulgaria is one of the more extreme examples of an East European economy reliant on the use of low rank low grade coal According to official statistics Bulgaria has coal reserves of 5 billion tonnes 87 of which is low grade high sulphur lignite Planned coal production for this year is 2966 million tonnes rising to 42 milJion tonnes by the year 2005 (Financial Times 1995) Bulgarias largest coal deposit at Maritsa Iztok (Maritsa East) is surrounded by three thennal power stations burning the locally mined lignite with 55 moisture 224 ash 2 sulphur and with a heating value of approximately 8 MJkg HHV 5 MJkg LHV The four 50 MWe units at Maritsa East I are approximately 34 years old At Maritsa East II there are four 150 MWe units which are 28 to 29 years old two 210 MWe units which are 20 years old and a 210 MWe unit commissioned this year The four 210 MWe units at Maritsa East III are 14 to 17 years old SOz and NOx emissions are uncontrolled (Maude and others 1994) Some higher quality imported coal is also burnt but the local coal is supplied at US$20t while the imported coal costs the utility US$60t (East European Energy Report 1995)

In India much of their indigenous coal is of high ash content and because of the nature of the ash the yield from beneficiation processes is low and the costs are high However the low grade coal is a substantial national resource The total coal resource is estimated at 200 billion tonnes of which 82 is estimated to be of poor grade (35-45 ash heating value 10--21 MJkg) Nearly 66 of Indias power requirements (51040 MWe) come from PC fuelled power stations Coal is and will be the main fuel for power generation because of these huge deposits (Palit and MandaI 1995) The Central Electricity Authority insists that boiler manufacturers should design boilers for coal of 50 ash content (Subramanyam 1994)

Conventional PC boilers can be designed to burn virtually any fuel but the use low rank and low grade coal increases the capital and non fuel operating costs of the boiler The use of such coals will continue because a number of countries have large reserves of these coals and the switch to better quality coal is not a practical short to medium tenn option It

79


has been argued that alternative boiler technologies are specially suitable for such coals and may offer lower cost options

63 CFBC power generation As described in Section 31 most of the circulating f1uidised bed boilers which have been commercially deployed are small laquo100 MWe) cogeneration units In this size range they are in competition with stoker boilers and with PC-fired furnaces at the bottom end of their economic range The requirement to reduce environmental emissions imposes a considerable economic burden on these small units while FBC has the advantage of intrinsically low thermal NO x generation through low combustion temperature and low Sal emissions through sorbent injection With increasing unit capacity the specific cost of PC units decreases as described in Section 61 and hence the commercial advantage of CFBC is eroded Figure 33 presents this graphically

Johns (1989) compared the capital and operating costs for a PC boiler and a CFBC boiler Each had a main steam flow of 250 tonnesh (approximately sufficient for 60 MWe power generation) and used a medium slagging medium fouling bituminous coal (12 ash 29 volatile matter 18 sulphur) The PC boiler used dry lime injection and a fabric filters for Sal control The CFBC used limestone sorbent The PC boiler was found to be the more economic alternative for good coal Thepoor coal in Figure 33 is defined as difficult to burn fuels such as coal miningcleaning waste products (anthracite culm bituminous gob etc) and high sulphur coals which would require a wet flue gas desulphurisation system to meet 90 Sal reduction This definition of poor coal relates to a location where 90 reduction in uncontrolled Sal emission was acceptable A maximum NO x emission of 172 mgMJ was also acceptable As discussed in Chapter 3 CFBC is capable of substantially better environmental performance than this The conditions chosen do not fully reflect the potential environmental advantages of CFBe Lyons (1994) compared PC CFBC PCFBC and IGCC for an eastern USA bituminous coal (073 sulphur 97 ash 29 MJkg HHV) and a Midwest USA coal (30 sulphur 12 ash 247 MJkg HHV) Much

Poor coal

r 1

Good coal

50 MW 150 MW

Figure 33 Effect of coal grade and boiler size on product selection (Johns 1989)

more stringent emissions requirements were assumed NO x 01 lbmillion Btu (approximately 120 mgm3 ) Sal 95 removal (Sal emissions of 290 mgm3 and 70 mgm3

respectively for the two coals) These conditions were detrimental to the PC case because they required the unit to be equipped with SCR for NO x reduction followed by wet scrubbers for FGD Hence the definition of a good coal may change with changing emission standards

Because of the increased gas flows the cross section of PC and CFBC boilers increases with decreasing coal rank but the increase is less for CFBC boilers The height of the furnace decreases with decreasing coal rank for CFBC boilers but increases for PC boilers For low rank coal a PC boiler is larger than a CFBC boiler and as overall boiler cost is closely linked with the size of the boiler CFBC boilers are better suited to burning low rank coal (Lafanechere and others 1995) The relative cost of 300 MWe PC and CFBC power stations burning low grade lignite at Mae Moh Thailand has been assessed It was found that if two 150 MWe CFBC units were installed the cost of the first unit would be $1393kW and the second would cost $1174kW (US$ 1991) This compared favourably with estimates for a single 300 MWe pulverised lignite plant with FGD (Howe and others 1993)

It appears that although low rank and low grade coals are more expensive to burn than high grade medium bituminous coals and costs are further increased by the need to control emissions these factors are less detrimental for CFBC units than for PC units

631 CFBC boilers economies of scale

Until recently the largest single unit CFBC boilers were around 125-175 MWe The thermal efficiency of these CFBC units is lower than that of large PC units because of relatively larger heat losses and because the boilers supply steam at lower temperatures and pressures The capacity of single unit PC power stations is essentially decided by the capacity of available turbo generating sets so not every theoretical increment in capacity is possible but single stream PC power stations are available in a range of sizes up to 1000 MWe Based on experience with the smaller units a number of manufacturers have expressed confidence in their ability to tender for single CFBC boiler units ith a capacity around 400 MWe (Maitland and others 1994 Salaff 1994) However utilities and others who control project funding tend to be adverse to the perceived risk involved in scale up by more than 15-20 (Farina 1995) Greater capacity can be obtained by using multiple units but the economies of scale are reduced Two major projects at Gardanne (France) and Turow (Poland) are pioneering the use of larger CFBC boilers

Repowering of an existing 250 MWe unit with a single CFBC boiler has now been completed in Gardanne Provence France The total financing requirements for this the first application of such a large CFBC boiler have been reported to be 230 MECU ($1200MWe 1995 $1 = 13 ECU) The project has the benefit of more than 22 MECU of grant aid including almost 20 MECU from the

80


European Union within the framework of the Thermie programme (Thermie Newsletter 1994)

The Turow CFBC boilers will be two 235 MWe Foster Wheeler Pyropower lignite-fired reheat units Together they will produce 70 MWe more electricity than the two PC boilers which they will replace The new boilers will allow S02 and NOx emissions to be controlled to Western European standards without the need to install scrubbers and they will fit onto the existing foundations The projected repowering and refurbishment cost per kilowatt is 40 to 60 of that for a new plant and it is anticipated that the working life of the units will be extended by thirty years (Gaglia and Lecesne 1995)

Assuming that either or both of these projects are technically successful the application of single stream CFBC units up to 250 MWe with a single stage of reheat will have been demonstrated Following completion of the Gardanne project GEC Alsthom intends to market a standard 350 MWe single stream power station as part of a range of modular power stations The range currently consists of a 175 MWe power station or a 350 MWe power station with two 175 MWe CFBC boilers feeding a 350 MWe single-reheat turbine Future plans also include a 400 MWe supercritical unit and a 650 MWe subcritical unit The manufacturer expects the technology to be able to compete commercially against PC boilers up to a capacity of 600 MWe (Holland-Lloyd 1995)

64 PFBC boilers PFBC power generation units based on the ABB Carbon P200 module have been built at Viirtan in Sweden Tidd in the USA Escatr6n in Spain and Wakamatsu in Japan The first 350 MWe PFBC unit based on the ABB Carbon P800 module is under construction at Kyushu Japan Hence PFBC has been the subject of large scale demonstrations but is still in the initial stage of commercialisation Before reaching mature costs technologies typically pass through a cost maturation phase (see Figure 34)

Some of the factors that lead to higher first of a kind costs for new technologies are

higher engineering and design costs lack of an infrastructure to manufacture the new components

13 First-of-a-kind commercial plant

Demonstration plant

12 Second-of-a-kind commercial plant

Pilot plant Third-of-a-kind and subsequent

~ 11 o

c commercial plant Conceptual plant

_~ully matureden o o

10lJ _

Preliminary cost Time ---- estimate

Figure 34 New technology cost curve (Guha 1994)

the need to develop a network of sub-suppliers the need for revisions to the equipment during detailed design and commissioning and higher cost provision by the supplier for warranty and guarantee work

Typically 20 to 25 years elapse from the initial development stage of a new technology to the point where utilities can use it for commercial operation PFBC has already passed through most of this development period but is still on the upward side of the cost maturation curve (Guha and others 1994) An economic study of the costs of mature PFBC power generation in comparison with PC power generation appeared to indicate that their specific capital costs ($kWe) would be similar The study produced estimates of the cost of electricity from four power generation plants

a conceptual 350 MWe PFBC green-field power station based on the ABB P800 unit a 450 MWe conventional PC power station a conceptual 500 MWe IGCC unit and a 200 MWe natural gas combined cycle (NGCC) unit

The NGCC unit offered the lowest capital cost and the lowest cost of electricity The coal fuelled processes were compared assuming the use of a 43 sulphur Illinois bituminous coal For both PC and PFBC the capital cost was $1050kWe (1990 $) with a capital cost of $1200kWe for IGCC PFBC offered the prospect of the lowest cost of electricity (Guha and others 1994) A thermal efficiency of 376 HHV was assumed for the P800 unit This relates to a configuration using a US supercritical steam turbine with single reheat (25 MPal538degC538degC) In 1993 ABB Carbon suggested that turbines which are commercially available in Europe use more advanced steam conditions (25 MPal579degC579degC) and would give the P800 an efficiency of approximately 414 HHV (Wheeldon and others 1993b) However the exercise also assumed an efficiency of 354 HHV for the PC power station with FGD It might be argued that this is somewhat low by modern European standards In 1995 it was claimed that the design output of the P800 unit had been increased from 350 MWe to 425 MWe and the specific capital cost reduced (ABB Carbon 1995)

The effect of a range of coals on the cost of electricity from a conceptual 320 MWe PFBC power station was assessed by Wheeldon and others (1993b) It was assumed that the unit would be built on a green-field site at Kenosha WI USA Some of the results of the study are shown in Table 25

The data indicate that the lowest cost electricity would be produced using the low sulphur bituminous coal The high sulphur bituminous coal gave the highest cost of electricity because of the increased costs for sorbent and ash disposal In practice at the Kenosha site the low sulphur Western USA subbituminous coal also had a costG] advantage that was ignored in the table Taking this cost advantage into account the cost of electricity using the subbituminous coal was 379 millskWh which is 48 millskWh less than that for the high sulphur coal This cost advantage was found to hold for rail transport distances of almost 1900 km (Wheeldon and others 1993b)

81


Table 25 The effect of coal quality on PFBC costs (Wheeldon and others 1993b)

Coal Illinois No6 Utah Texas Western Pittsburgh No8 bituminous bituminous lignite subbituminous bituminous

Moisture 120 60 322 304 60 Carbon 575 700 406 479 713 Hydrogen 37 48 31 34 48 Nitrogen 10 12 07 06 14 Sulphur 40 06 10 05 26 Oxygen 58 101 131 108 48 Ash 160 73 93 64 91 HHV MJkg 235 288 159 187 305

Costs millskWh

Capital charge 204 188 204 200 191 OampM 62 59 62 61 59 Coal $ 13GJ 113 113 117 116 112 Limestone 24 03 09 04 12 Ash disposal 24 05 13 06 11 Cost of electricity 427 368 405 387 385

I mill = I x 103 US$

OampM = operating and maintenance costs including consumable items

The cost penalty imposed by the sulphur content of the coal depends on the cOst and efficiency of the sorbent It also depends on the quantity of solid residue generated and the cost of disposal It has been suggested that 95 S02 removal at a CaS molar ratio of less than 2 will be necessary for PFBC to be competitive in the utility market place (Zando and Bauer 1994) For a number of process costings it has been assumed that limestone could be used as the sorbent (Guha and others 1994 Wheeldon and others 1993b) Unfortunately there are indications that the use of limestone might contribute to bed agglomeration problems with some coals (see Section 43) Where dolomite has to be used rather than limestone COsts may be increased and the potential for selling the residue reduced

There is alack of data on the availability of PFBC boilers in commercial service because with the possible exception of Vartan the existing commercial scale units were built for demonstration and development purposes The Tidd PFBC boiler was shut down in 1995 with the completion of the test programme At Escatr6n and Wakamatsu further test work is planned

TIle operating hours for the two Viirtan boilers are shown in Table 26

Table 26 Operating hours since first firing (Hedar 1994)

Operating season Boiler I Boiler 2

198990 5 730 199091 1957 2091 199192 1645 1907 199293 2566 3526 199394 3364 3334

Totals 9537 11588 ~-----------_

82

These data may appear unimpressive because the units are used for district heating and are not operated when the heating demand is low (May to September) A fairer impression of the improving reliability of the units is given by the availability data I991 92 - 48 199293 - 73 199394 - 80 The main reasons for nonavailability were tube leakages gas turbine problems and cyclone problems (Hedar 1994)

Authors have generally assumed that with the benefit of the experience gained from the demonstration plants the availability of commercial PFBC units (with dust cleaning by cyclones) will be equal or superior to that of PC units (Guha and others 1994 Jansson 1995 Mudd and Reinhart 1995 Wheeldon and others 1993b)

65 IGCC Integrated gasification combined cycle power generation (IGCC) is widely perceived to have environmental advantages over other technologies but high capital cost is a deterrent to its adoption (Gainey 1994b) Coal-fired IGCC projects now underway have total construction cOsts close to $2000kWe They are more complex 20 to 35 more expensive on a $kWe basis and no more efficient than the best conventional PC-fired power stations with FGD (Koenders and Zuideveld 1995) The realisation of IGCC demonstration projects has been made possible by various fOnTIS of government subsidy (Dartheney and others 1994) Further development of existing processes is required to lower cOsts and to demonstrate the reliability of the innovations

It is a declared objective of the US Department of Energy Clean Coal Technology Program to develop a high efficiency clean low cost IGCC system by 2010 In this context low cost means a capital cOst of around US$lOOOkW of installed generating capacity and a cost of electricity 75 of that for a conventional PC-fired plant with


FGD High efficiency means efficiencies as high as 52 HHV (Rath and others 1994 Schmidt 1994) Given acceptable cost and reliability the perceived environmental advantages of IGCC may result in its preference by regulatory authorities as the best available technology for coal based power generation In that case the wider application of IGCC technology might follow with important implications for power station coal specifications

Exercises comparing the economics of PFBC with IGCC have found that while PFBC may provide the lower cost of electricity for low sulphur coals IGCC processes are potentially more economical for high sulphur coals (see

Figure 35)

For PFBC as coal sulphur is reduced the costs for purchasing sorbent and disposing of the solid residues are reduced For IGCC assuming that the desulphurisation

2

L

s ~ ~

E -1 Ql o c ~ -2

~ D -3 w o o -4

80 capacity factor

PFBC favoured

IGCC favoured

0-t--------------------

-5 +----------------------------------

2 3 4


Figure 35 Difference in cost of electricity (COE) between similar sized PFBC and IGCC power plants and its variation with coal sulphur content (Wheeldon and others 1993b)

To feed

product is saleable reducing coal sulphur content leads to reduced revenue with only a minor reduction in the total capital investment requirement The net effect is an increased cost of electricity for reduced sulphur content coals (Wheeldon and others 1993b)

The relatively high cost associated with conventional power generation using low rank coals may offer prospects for air blown IGCC As described in Section 612 large furnaces are required for conventional PC combustion of low rank coals The cost of a boiler tends to increase with its size and so the capital cost for a lignite-fired boiler tends to be higher than that for a bituminous coal-fired boiler of equivalent capacity In contrast the size of gasifiers for a given coal input tends to decrease as the rank of the coal decreases and its reactivity increases but this effect is countered by the increased feed rate required for low heating value coals In a study of the relative economics of using bituminous subbituminous and lignite coals in an air blown gasifier Freier and others (1993) found that the capital cost for a subbituminous coal was somewhat lower than that for a bituminous coal while for a lignite it was somewhat higher

The HTW process has been proposed as the most attractive option for utilising German brown coal and Australian lignites Coals of the Latrobe Valley Victoria Australia have lower heating value (as received basis) in the range 7-10 MJkg moisture content in the range 55-70 ash contents in the range 1-5 (dry basis) and contain about 25 oxygen (dry basis) Similarly the Rhenish brown coals typically contain between 40 and 60 water in their as received state Gasifying or burning coals with such a high moisture content is thermally inefficient The coals are normally dried to around 12 moisture before gasification Figure 36 shows a tluidised bed drying system that allows the heat of evaporation of the water to be recovered by using the heat pump principle

heating

Steam

Raw brown coal

Heating coils

1~65C F==== Compressed steam

Condensate

ro r ()

Air

Ash Exhaust gases

Figure 36 HTW system with fluidised bed dryer (Johnson 1992)

83


Steam is used to tluidise the lignite and the drying process takes place at a temperature of approximately I IOdege The water from the coal adds to the steam leaving the dryer Part of the recycled steam is compressed and passed through the bed heating coils Because of the increased pressure the steam condenses at I 10degC and its latent heat is recovered by heating the tluidised bed The condensate is said to be sufficiently clean to be usable as cooling tower make up water after simple treatment filtration through a coke bed for example (Klutz and others 1996)

66 Comments Commercially it is pointless to discuss the coal quality requirements of power generation technologies without also discussing the relative costs of the technologies If cost were not a factor any of the technologies could be used for any

coal The relative costs of coal and capital are also important Where capital is expensive and coal is inexpensive it is more difficult to secure an adequate return from expenditure to improve thermal efficiency It appears that for Northern European conditions using relatively costly bituminous coal of international thermal coal quality the lowest cost electricity is provided by a supercritical power station with single reheat (27 MPal585degC600degC or 285 MPal580degC580degC) and a feedwater temperature of 275 to 3OOdege At locations where a supply of cold seawater is available overall efficiency and availability considerations may provide commercial justification for a second stage of reheat Further development of water wall materials and of the ferritic successors to P91 may move the economically optimum steam conditions to 30 MPal600degc600degC by the end of the decade (Rukes and others 1994)

84

7 Conclusions

Conventional PC boilers have demonstrated their ability to operate using virtually the whole range of materials described as coal but some coals are more suitable than others Where an economical supply of high grade medium bituminous coal is available it tends to be the fuel of choice A PC boiler designed to use low grade low rank andor highly fouling coals is likely to be more costly to build and maintain and its thermal efficiency is likely to be lower However there are regions where fuel costs or wider strategic or socioeconomic considerations dictate the use of the more problematic coals

The cost of servicing the capital investment needed for building the power station is the largest part of the cost of electricity Increasing thermal efficiency reduces fuel cost but if it is done at excessive capital cost it can increase the cost of electricity If the pursuit of thermal efficiency is motivated solely by the need to reduce the cost of electricity attainment of the highest efficiency will be justified where the cost of fuel is high and the costs of boiler construction are low More recently political expressions of increasing concern with the effects of power generation on the environment has added a further motivation Increasing the thermal efficiency of power generation proportionately reduces its environmental impact

The most efficient PC boilers use supercritical steam conditions In general the coal quality requirements of supercritical PC boilers are similar to those for conventional boilers but there are some additional constraints related to the need to control fouling and high temperature corrosion in the convective section of the boiler Furnace gas exit temperature (FEGT) is an important design parameter Excessive FEGT for a given coal may become apparent through the rapid accumulation of fouling deposits on convective surfaces Measurements of ash fusibility are widely used as an aid to assessing the maximum FEGT advisable when designing for a given coal The desirability of having the capability to select from a wide range of different coals leads to the specification of a relatively low

FEGT However the net effect of increasing steam conditions is to reduce the proportion of the heat that can be absorbed in the furnace section without overheating the water walls In consequence FEGT has to be controlled by measures that involve compromises in the designed efficiency of the boiler Superior materials are being developed but it appears that improvements in water wall metallurgy will be barely adequate to keep up with improvements of turbine and piping materials Hence as steam conditions continue to advance ash fusion temperatures will continue to be a coal quality issue

The tubes in the boiler that operate at the highest metal temperatures are the final superheat tubes and the reheat tubes Instances of serious external wastage or con-os ion of these tubes were first encountered in boilers using high sulphur high alkali coals from Central and South Illinois USA The corrosion was found to be caused by deposits of complex alkali sulphates Further research showed that the rate of con-os ion reached a maximum at metal temperatures of approximately 680-730degC It has been found that for the present generation of supercritical boilers austenitic stainless steel can give adequate high temperature corrosion resistance where the coal specification limits both the chlorine and sulphur content to 01 or less However these quality constraints would exclude many coals While the imposition of limits on coal sulphur and chlorine content appear to be sufficient conditions to avoid excessive high temperature corrosion in the present generation of boilers it is difficult to assess whether they are necessary conditions It has been argued that correlations suggesting a role for chlorine in high temperature corrosion have been largely derived from experience with British coals having an analysis atypical of internationally traded coals Conversely for the more advanced steam conditions of the coming generations of supercritical boilers the present empirical specification could prove to be inappropriate Further basic research on the role of chlorine in high temperature corrosion might resolve these questions

85

Conclusions

CFBC boilers have the advantage of being able to bum the most unpromising fuels (high grade dirt) They also have the advantages of compact design and the ability to comply with emissions standards without expensive control equipment Hence it might be concluded that FBC boilers will bum virtually anything but this assumption does come with certain caveats The utilisation of low quality coals and coal wastes for example has led to problems during fuel preparation handling and feeding and in the ash removal and handling systems These have primarily been a result of their high moisture andor high ash contents However fuel feed and ash handling systems have significantly improved over the last few years as lessons have been learnt Provided these systems are properly designed and sized for the fuel they now provide relatively trouble free operation

Bed agglomeration and ash deposition and fouling problems have been experienced in some CFBC units Bituminous coals with a high iron content and subbituminous coals and lignites with a high sodium content have been found to promote agglomeration while coals with a high calcium content could potentially cause fouling in the convection and reheat sections of the combustor Agglomeration and deposition depend not only on the total concentration of these elements in the coal but also on their form of occurrence It is therefore important to understand the nature of the inorganic components in the original coal and the mechanisms of agglomeration and deposition so that improvements can be made in predicting FBC performance

The hard minerals (such as quartz alumina and pyrite) and the alkali and chlorine in the coal can contribute to material wastage (wear erosion andor con-os ion) At present the wear potential of a bed consisting of a mixture of different types of particles (derived from the coal and sorbent) cannot be deduced from the wear potential of the individual particles

The sulphur content ash content and chemical composition of the ash determine the potential S02 emissions from the coal and the amount of limestone required to reduce these emissions Coals with a high calcium content need less added sorbent to achieve the required S02 capture efficiency Experience with large-scale (over 100 MWe in size) CFBC boilers has demonstrated that currently required levels of sulphur removal are technically feasible The main limitation to achieving the desired level of sulphur capture is the economic penalty associated with high feed rates of limestone and the associated ash disposal costs NOx and N20 emissions are dependent on the nitrogen content and to some extent the rank of the coal They can be reduced by primary measures such as air staging but stringent emission limits may require additional measures for NOx control adding to costs N20 emissions may become a major limitation to the use of FBC N20 is not currently regulated but this may change in the future due to its role in ozone depletion in the stratosphere and because it is a greenhouse gas There is cun-ently no satisfactory way of reducing N20 emissions although afterburning in the cyclone may be a promising technique Particulate emissions are less influenced by fuel properties and can be effectively controlled by using fabric filters or ESPs Fabric filters appear to be more

popular because the high electrical resistivity and small particle size of the fly ash can lead to poor ESP performance

The disposal of the residues in landfills can have a considerable impact on the economic performance of FBC The disposal costs can represent 1-2 of the cost of electricity produced from AFBC combustion of low sulphur coals The disposal costs are site-specific depending on the availability (and cost) of the land for disposal Selling the residues for utilisation in different applications helps to offset the cost The use of low sulphur coal can appreciably reduce costs (less sorbent required and hence a lower amount of residues for disposal) and so improve FBC economics Experience has shown that CFBC boilers need to be designed for a specific coal and that top performance is likely to be had only for that coal Fuel flexibility can be built into the design but this may reduce overall boiler efficiency and will add to the construction costs It is crucial to the success of CFBC boilers that the fuel characteristics are properly related to the design and operation of the plant

Most of the CFBC boilers that have been commercially deployed are small (lt100 MWe) cogeneration units In this size range they are in competition with stoker boilers and with PC-fired furnaces at the bottom end of their economic range The requirement to reduce environmental emissions imposes a considerable economic burden on small PC units while FBC has the advantage of intrinsically low thermal NOx generation through low combustion temperature and low S02 emissions through sorbent addition With increasing unit capacity the specific cost of PC units decreases and hence the commercial advantage of CFBC is eroded Commercial CFBC currently occupies a niche market in small cogeneration and waste disposal operations However larger CFBC modules with single units of capacity up to 350 MWe are now being demonstrated and the technology may be attractive for utilities using coals that present special difficulties in PC boilers

There is less practical experience and information on the effect of coal properties on PFBC units only four demonstration units have been operated Three of these units used bituminous coal and one a local Spanish black lignite (subbituminous coal) Initial problems reported at all four demonstration units include plugging of the fuel feed and cyclone ash removal systems The presence of alkali compounds in the coal can contribute to bed agglomeration through the formation of sintered material The choice of sorbent is also important For low ash fusion coals dolomite may have to be used rather than limestone It has been suggested that circulating PFBC may be less susceptible to bed agglomeration problems Hence it may be more appropriate than bubbling PFBC for some coals having low ash fusion temperatures However circulating PFBC is at an earlier stage of development

Corrosion of the hot gas expander does not appear to be an issue for the existing PFBC units but the utilisation of coals with a high alkali metal content (such as certain low rank coals) or a high chlorine content (such as some British coals) could potentially lead to problems There is currently no fully proven method for removing volatile alkali compounds from

86

Conclusions

the combustion gas making this a key issue to be resolved in using high alkali andor high chlorine coals in PFBC or Hybrid-PFBC units

In common with CFBC units PFBC units give inherently low NOx emissions which can be further reduced by SCR andor SNCR methods However ammonia injection can increase N20 emissions N20 emissions from PFBC units are higher than those from PC power plants but are generally lower than those from AFBC units There is as yet no fully proven method for reducing N20 emissions However low rank or high volatile coals are associated with low N20 emissions Particulate emission limits can be met with the use of fabric filters or ESPs As with CFBC units the amount of solid residues produced depends primarily on the coal sulphur and ash contents An increase in the sulphur content from I to 4 can be expected to result in a 2-3 fold increase in the quantity of solid residues produced PFBC units have shown a higher S02 capture efficiency than AFBC units primarily a consequence of the effect of pressure on the process chemistry A high sorbent utilisation is important for the commercialisation of PFBC (and for CFBC) as it will reduce the quantity of the sorbent required and the amount of residues for disposal

IOCC has been proposed as being potentially the most efficient and least polluting means for generating electricity but further development is needed to reduce its cost and increase its efficiency Most of the current major development projects feature entrained flow oxygen blown slagging gasifiers These gasifiers use pulverised coal Hence the grindability and heating value of the coal is a quality issue for entrained flow gasifiers as it is for conventional power plants For all slagging gasifiers the ash quality influences the gasifier efficiency and availability The effect on efficiency is particularly important for air blown slagging gasifiers It is preferable to have an ash with a low fluid point temperature (less than l370degC) and a rheology that is compatible with consistent slag flow from the gasifier The use of coals with more refractory ashes may require the

addition of flux to secure adequately low ash viscosity and this increases the costs of the process Hot coal derived syngas is highly corrosive It appears that gasifier conditions can be controlled to give acceptable availability although for optimum life of metals in the gasifier low sulphur and low chlorine coals are preferable The problems of attack during shut-downs from corrosion and stress corrosion cracking are well known from refinery experience but may be more severe for coal gasifiers with syngas coolers

Air blown fluidised bed gasification has been advocated as a more suitable alternative for low rank coals High ash fusion temperature is an advantage for fluidised bed gasification If gasification is defined as the essentially complete gasification of a fuel leaving only ash then there is a problem in obtaining acceptable carbon utilisation without using temperatures that would cause bed agglomeration These gasifiers also produce an ash that contains calcium sulphide For ease of disposal this needs to be oxidised to calcium sulphate In practice these problems are resolved by providing a separate char combustion stage Hence air blown gasifiers are essentially hybrid systems Removal of particulates from hot gas using barrier filters appears to be an essential feature of air blown gasifiers and hybrid systems In this context the term hot has been applied to a range of temperatures from 270 to 900degC Barrier filtration of coal derived gas has been successfully demonstrated at the lower end of this range but becomes increasingly problematic towards the upper extreme

As with PC systems advanced power generation systems can use any coal but the system design may have to be modified to cope with the peculiarities of the selected fuel A plant designed for one fuel may not operate optimally using other fuels However advanced power systems each have their own set of coal quality requirements and coals of widely different properties are used around the world As the advanced systems are developed they may become increasingly commercially attractive at appropriate locations

87

8 References

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bed combustion ash In Tenth annual fluidized bed conference Jacksonville FL USA 14-15 Nov 1994 Burke VA USA Council of Industrial Boiler Owners pp 129-135 (1994) Takematsu T Maude C (1991) Coal gasification for IGCC power generation IEACR37 London UK IEA Coal Research 80 pp (1991) Takeshita M (1994) Environmental performance of coalJired FBe IEACRI75 London UK IEA Coal Research 90 pp (Nov 1994) Takeshita M Soud H (1993) FGD performance and experience on coal-fired plants IEACR58 London UK IEA Coal Research 138 pp (luI 1993) Tang J T Lee Y Y (1988) Important aspects of fuels characterization for circulating fluidized bed boilers In Joint ASMEIIEEE power generation conference Philadelphia PA USA 25-29 Sep 1988 Paper 88-JPGClFACT-I New York NY USA American Society of Mechanical Engineers 11 pp (1988) Thambimuthu K (1993) Gas cleaning for advanced coal-based power generation IEACR53 London UK IEA Coal Research 163 pp (1993) Thambimuthu K (1994) Developments in coal-liquid mixtures IEACR69 London UK IEA Coal Research 80 pp (1994) Thermie Newsletter (1994) Clean coal technology The Provence Clean Energy Project Thermie NeHsletter (2) 2-3 (1994) Thies L Heina R (1990) Burning culm in CFB boiler minimizes environmental impact Power (New York) 134(4)

S27-S32 (Apr 1990) van Liere J Bakker W T (1993) Coal gasification for electric power generation Materials at High Temperatures 11(14) 4-9 (1993) Waltenberger G (1983) Thirty years of operation of the first 600degC high temperature steam boiler plant VGB Kraftwerkstechnik - English Issue 63(8) 561-568 (Aug 1983) Wang B Q Geng G Q Levy A V (1991) Erosion-corrosion of tubing steels at simulated fluidized bed combustor convection pass conditions In Proceedings corrosion-erosion-wear ofmaterials at elevated temperatures conference Berkeley CA USA 31 Jan-2 Feb 1990 Levy A V (ed) Houston TX USA National Association of Corrosion Engineers pp 151-1528 (1991) Wardell R V (1995) Solids preparation and handling In Pressurized fluidized bed combustion Alvarez Cuenca M Anthony E J (eds) Glasgow UK Blackie Academic and Professional pp 135-163 (1995) Watts D H Dinkel P W (1989) Cool Water plant reliability and efficiency improvements achieved during four years of operation In Eighth annual EPRI conference on coal gasification Palo Alto CA USA 19-20 Oct 1988 EPRI-GS-6485 Pleasant Hill CA USA EPRI Distribution Center pp 61-617 (Aug 1989) Weale G Lee H (1995) Economics investment distortions and oppOitunities for new coal-fired plants In CoalTrans 94 conference proceedings Hamburg Gelmany 24-26 Oct 1994 London UK Coa1Trans Conferences Ltd pp 37-44 (1995) Webb R M Moser K W (1989) The DOW Syngas Project recent operating experience In Eighth annual EPRI conference on coal gasification Palo Alto CA USA 19-20 Oct 1988 EPRI-GS-6485 Pleasant Hill CA USA EPRI Distribution Center pp 71-71 0 (Aug 1989)

98

References

Weinzierl K (1994) Coal power stations of the future VGB Kraftwerkstechnik - English Issue 74(2) 102-106 (Feb 1994) Weirich P -H Pietzonka (1995) Modern-day power plant processes - enhanced cost-efficiency with accustomed reliability In Power-Gen Asia 95 Singapore 27-29 Sep 1995 Singapore Power-Gen Asia Times Conferences amp Exhibitions Pte Ltd vol 1 pp 973-989 (1995) Wert D A (1993) Application of fluidized bed combustion for usc of low grade and waste fuels in power plants In Power-Gen Europe 93 conference Paris France 25-27 May 1993 Utrecht the Netherlands PennWell Conferences and Exhibitions Book 2 (vols 5 and 6) pp 29-47 (1993) West S S Williamson J Laughlin M K (1994) Mineral interactions during fluidised bed gasification of coals In The impact of ash deposition on coalfired plants Engineering Foundation conference Solihull UK 20-25 Jun 1993 Williamson J Wigley F (eds) Bristol PA USA Taylor and Francis pp 89-100 (1994) Wheeldon J M Drenker S G Booras G S McKinsey R R (1993a) Assessment of the economics and environmental performance of pressurized fluidized-bed combustion power plants burning subbituminous coal In Proceedings of the seventeenth biennial low-rank fuels symposium St Louis MS USA 10-13 May 1993 Grand Forks ND USA Energy and Environmental Research Center pp 313-330 (1993) Wheeldon J M Drenker S G Booras G S McKinsey R R (1993b) Cost and performance improvements in utility-scale bubbling PFBC power plants In Proceedings of the 1993 international conference on fluidized bed combustion San Diego CA USA 9-13 May 1993 Rubow L (ed) New York NY USA American Society of Mechanical Engineers vol 1 pp 545-554 (1993) Wischnewski R Renzenbrink W Schumacher H -J (1995) Operational experience gained with the hot gas filter of the HTW demonstration plant at Berrenrath In Power-Gen Europe 95 Amsterdam the Netherlands 16-18 May 1995

Utrecht the Netherlands PennWell Conferences amp Exhibitions Book 3 (vols 6 and 7) pp 473-488 (1995) Wojtowicz M A Pels J R Moulijn J A (1993) Combustion of coal as a source of N20 emission Fuel Processing Technology 34(1) 1-71 (lun 1993) Wright I G Sethi V K (1990) Applicability of bubbling bed solutions In Proceedings workshop on materials issues in circulating fluidized-bed combustors Argonne IL USA 19-23 Jun 1989 EPRI-GS-6747 Palo Alto CA USA EPRI Research Reports Center pp 271- 2710 (Feb 1990) Wright S J Clark R K Hird W M Moon N C (1991) The rheological physical and mineralogical properties of coal water mixtures suitable for firing to pressurised fliudised bed combustors In Proceedings of the 1991 international conference on fluidized bed combustion Montreal PQ Canada 21-24 Apr 1991 Anthony E J (ed) New York NY USA American Society of Mechanical Engineers vol 1 pp 167-174 (1991) Wright I G Mehta A K Ho K K (1995) Survey of the effects of coal chlorine levels on fireside corrosion in pulverized coal-fired boilers In Proceedings effects of coal quality on power plants - fourth international conference Charleston SC USA 17-19 Aug 1994 Harding N S Mehta A K (eds) EPRI-TR-104982 Pleasant Hill CA USA EPRI Distribution Center pp 43-428 (Mar 1995) Yrjas K P Lisa K Hupa M (1993) Sulphur absorption capacity of different limestones and dolomites under pressurized combustion conditions In Proceedings of the 1993 international conference on fluidized bed combustion San Diego CA USA 9-13 May 1993 Rubow L (ed) New York NY USA American Society of Mechanical Engineers vol 1 pp 265-271 (1993) Zando M E Bauer D A (1994) Baseline performance of a 200 MWt pressurized bed combustor In Proceedings of the American power conference Volume 56-Il Chicago IL USA 25-27 Apr 1994 Chicago IL USA Illinois Institute of Technology pp 919-924 (1994)

99

Related publications

Further lEA Coal Research publications which might be of interest are listed below

Understanding coal gasification Alice Kristiansen IEACR86 ISBN 92-9029-267-9 69 pp March 1996 pound300

Coal combustIon - analysis and testing Anne Carpenter Nina Skorupska IEACR64 ISBN 92-9029-225-3 97 pp November 1995 pound60

Coal blending for power stations Anne Carpenter IEACR81 ISBN 92-9029-256-3 83 pp July 1995 pound450

Coal pulverisers - performance and safety David Scott IEACR179 ISBN 92-9029-254-7 83 pp June 1995 pound300

Environmental performance of coal-fired FBC Mitsuru Takeshita IEACR175 ISBN 92-9029-245-8 90 pp November 1994 pound255

Understanding slagging and fouling during pf combustion Gordon Couch IEACR72 ISBN 92-9029-240-7 118 pp August 1994 pound255

Coal specifications - Impact on power station performance Nina Skorupska IEACR52 ISBN 92-9029-210-5 120 pp January 1993 pound180

These prices apply to purchasers in non-member countries of lEA Coal Research Purchasers in member countries qualify for a discount Further discounts are available to educational establishments

Other lEA Coal Research publications

Reviews assessments and analyses of supply transport and markets coal science coal utilisation coal and the environment

Coal Highlights

Details of lEA Coal Research publications are available from

IEA Coal Research Gemini House 10-18 Putney Hill London SW15 6AA United Kingdom Tel +44 (0)181-789 0111 Fax +44 (0)181-780 1746 e-mail salesiea-coalorguk httpwwwiea-eoalorguk

Printed in England

pound300 (non-member countries)

pound100 (member countries)

pound50 (educational establishments within member countries) ISBN 92-9029-269-5


David H Scott and Anne M Carpenter

IEACR87 May 1996 lEA Coal Research London


ISBN 92-9029-269-5



lEA Coal Research










3

Abstract


4

Contents

List of figures 7


1 Introduction 11














25 Comments 23









5

39 Residues 43

310 Comments 45










463 Particulates 56

47 Residues 56


5 Gasification 59




















65 IGCC 82

66 Comments 84

7 Conclusions 85

8 References 88

6

5

10

15

20

25

Figures


























7












8

5

10

15

20

25

Tables



























9




10

1 Introduction






11









12











3 and 4


375 352 315 429 260 25 540 27

410 384 324 444 280 25 540 27

407 383 312 461 275 25 560 23

406 382 298 471 300 285sect 580

23~


13







CIl 0 E ID c 15 2 0 ] c

1il i [lgt J () () Q)

0 E 25 -t----- --- -----_---CIl Q)

(jj __---L ----__------__-----__----L L-_







economiser

reheater 1

superheater 2

reheater 2

superheater 3





14


1 Waterwalls

Superheater

Pulveriser

4 Boiler feed pump

Boiler general

Reheater first


8 Buckets or blades


Economiser

Induced draft fan

Forced draft fan


Generating tubes

Stator windings

Furnace slagging



o 100 200 300



12

13

14

15

17

18







15












1400

1300

Corrosive zone

1200

1100

Stable 1000 zone

900

600


500 550


650

16











Incoloy 67 48 52 05

Cr35At 35 45 bal 01

Cr30Asect 30 48 bal 20 03 03

T310 25 20 bal 10 HR3q 25 20 bal 10 05 03 4002 20 33 bal 35 05


T91 9 bal 03 10 01 005 02


17









Separator vessel

Outlet reheater


Circulating pump

Over air ports

Primary superheater

Over air ports

B



18











ASTM test

Height =width2





19










LHV MJkg 69-97 80-85 105-115 Ash 3-12 5-12 6~1O


0406

06

02






08 06 04 CaO+MgO+S03

08










21


















22










23









24




convective pass

cyclone

CFB combustor

staged air

l~i --+ to baghouse


air h as secondary

air







25




Heating value

Moisture content

Ash content


Sulphur content

Nitrogen content

Chlorine content



Ash fusibility


















None












Typically none






26


70

65

60

~ 0

c-o

3 0

1il is a Ql r

55

50

45

40

35

30

0

- D

co bull


D

bullD

bull D backpass

I

bull D DCO OIJ D

CJJ

5 10 15 20 25 30









35

27






bull Ash production

150









28










29







~Volatiles





Q











30












Upgrade design


Original design

Water wall

tubes

8-10mm thickness

Water wall



Refractory step


floor tubes


31









Walerwall tube

Wastage

~

Refractory lining

Water wall tubes

Refractory lining





32












SiOz 5321 6170 5579

AbOJ 1098 1646 1352

Fe20J 583 299 700

CaO 1715 665 1151 MgO 253 108 190

NazO 226 051 162


KzO 015 066 086

TiOz 087 082 068

MnOz 004 003

PzOs 034 SrO 016 011 011

BaO 010 014 007

SOJ 578 655 574 Free quartz 3674 3701 3551


33










34











HHV MJkg 65

Moisture 9

Analysis wt db

Ash 735

Carbon 22



35











381 Sulphur dioxide


36






Coal sulphur

06 15 2 6


11 345 575 863 I 15 345 15 1 518 863 1294 1725 5176 2 1 690 1150 1725 2300 6901 251 863 1438 2157 2875 8626 3 I 1053 1725 2588 3450 10351



R = CarSr





37








7

6

o




NA NA


Coal type


NA Not applicable





- ~20 0

oi c ~ 15 ltll

S as 10 0 0 ltl

5

NA



NA Not applicable


Coal type



in heating value


38












39

---




382 Nitrogen oxides







150

100

50

Or------------------------ 700 750 800 850 900 950








--

~15 E

c o (jj (f)

E10 agt c agt Ol

-~ Z 5





40












41





400

~ 0

300 o



OX 100 z

O-----------r-------~--__r--____







383 Particulates


42











43









10



Coal type




44












45






46










47

--



steam turbine

15MWe

ash

dolomite

steam


~ t coal and

economiser







48












Start-up date 19891990 1990 1990 1993



Coal sulphur 01-15 34--40 29-90 03-12

Coal ash 8-21 12-20 23-47 2-18

Coal moisture 6-15 5-15 14--20 8-26

















49











50















51













52












53




461 SUlphur dioxide








Vartan









~l

5-10 96-98 33 about 2


13 125-145

15-25

SNCR + SCR 20

5 baghouse

NA not available

54








462 Nitrogen oxides





55








463 Particulates





56









Section 562)





57










58

5 Gasification






59

Gasification













60

Gasification



synthesis gas





Convective cooler



Boiler feedwater

Slag sumPL-__---

Radiant cooler

Coal grinding mill

Recycle (optional)




Water

Coal feed

I





---------------------~



61

Gasification


80


75 bull

(1) 70 ~

Ol gt 0 (1)

~ (1) 65 (]

Q o bull

60

55 -----------------r--------- shy55 60 65 70 75 80

Calculated value wt









HHV MJkg (daf) 3521 3052 2921






62

Gasification




C iii o o (J)

gt Cooling

~====~--

t Temperature








Si02 6021 4677 4379 4337

Ah03 156 2467 2604 2928

Fe203 585 1726 2101 1657

CaO 1157 55 258 351

MgO 214 107 106 1l9

Na20 267 I 045 051

Ti02 088 102 14 152

K20 043 184 222 208

P20S 026 032 07 098

BaO 008 011 015 02

srO 012 018 026 046

PbO 0 005 008 008

Cr203 019 022 026 03

3000 --SufCo

- - Pittsburgh2500

bullbull NO8



o+-------------r---_________--=-=-o=-=_r_=_---r 1200 1250 1300 1350 1400 1450 1500

Temperature degC


63

Gasification






the CRIEPI gasifier




Fe203 + CaO + MgO + Na20 + K20


Pyrolysis of coal




Coal rzd~




and others 1991)

64

Gasification



Tf= 13545X-2 + 2908X + 1232




2825degC

2600degC

2000

~ 1800 [l

til ~

Qi 1600 0shyE 2 c 14000

[jj


1000 0 5 10 15 20

Acidbase ratio







65

Gasification










66

Gasification








67

Gasification

Feed coal




Gas quench -----II

Refractory lining


Pressure shell

Tuyere

1Ll~__-- Slag tap



Slag







542 Slag mobility










68

Gasification











Wt


Pyrite



lt38 38-50 50-71 71-100 100-250 250-500 50()-1000 gt1000 Bulk

15 30 29 26

7 30 35 29

5 3 37 27

6 34 30 30

25 46 29 0

21 52 24

3

22 55 24 0

16 52 29 3

18 34 33 5

25 40 24 11

14 43 29 14

6 51 26 7

12 45 25 18

19 50 31

0

2 46 32 0

28 43 28 0

20 41 29 10

69

Gasification






Coal feeding system

Feed bin

Raw gas cooler

Lock hopper Raw gas

Charge bin


Fluidised bed



COllection bin

Lock hopper

Discharge bin




70

Gasification








Peat Wood Straw









Na K

400 500 550 600 900

0 I 15 100 160000

0 10 70 400 620000


71

Gasification















Ash 36 25 53 174 134




72

Gasification














steamI circuitSteam

Pressure let down



To steam circuit

Gas


Air


Air to CFBC



Ash


73

Gasification







Alkali getter


Ash Coal

Alkali getter

Sorbent


Air


74










75












Method of cooling

Data based on

Construction cost


Spare parts

Total capital cost






76










77

48





547 -J

gt g46OJ 0

~

~45












A$ US$




78













79





Poor coal

r 1

Good coal

50 MW 150 MW









80









Demonstration plant



~ 11 o



10lJ _









81





Costs millskWh









198990 5 730 199091 1957 2091 199192 1645 1907 199293 2566 3526 199394 3364 3334

Totals 9537 11588 ~-----------_

82








Figure 35)


2

L

s ~ ~

E -1 Ql o c ~ -2

~ D -3 w o o -4

80 capacity factor

PFBC favoured

IGCC favoured

0-t--------------------

-5 +----------------------------------

2 3 4



To feed




heating

Steam

Raw brown coal

Heating coils


Condensate

ro r ()

Air

Ash Exhaust gases


83





84

7 Conclusions






85

Conclusions










86

Conclusions







87

8 References



88

References



89

References



90

References



91

References



92

References



93

References



94

References



95

References



96

References



97

References




98

References



99













Coal Highlights



Printed in England





ISBN 92-9029-269-5



lEA Coal Research










3

Abstract


4

Contents

List of figures 7


1 Introduction 11














25 Comments 23









5

39 Residues 43

310 Comments 45










463 Particulates 56

47 Residues 56


5 Gasification 59




















65 IGCC 82

66 Comments 84

7 Conclusions 85

8 References 88

6

5

10

15

20

25

Figures


























7












8

5

10

15

20

25

Tables



























9




10

1 Introduction






11









12











3 and 4


375 352 315 429 260 25 540 27

410 384 324 444 280 25 540 27

407 383 312 461 275 25 560 23

406 382 298 471 300 285sect 580

23~


13







CIl 0 E ID c 15 2 0 ] c

1il i [lgt J () () Q)

0 E 25 -t----- --- -----_---CIl Q)

(jj __---L ----__------__-----__----L L-_







economiser

reheater 1

superheater 2

reheater 2

superheater 3





14


1 Waterwalls

Superheater

Pulveriser

4 Boiler feed pump

Boiler general

Reheater first


8 Buckets or blades


Economiser

Induced draft fan

Forced draft fan


Generating tubes

Stator windings

Furnace slagging



o 100 200 300



12

13

14

15

17

18







15












1400

1300

Corrosive zone

1200

1100

Stable 1000 zone

900

600


500 550


650

16











Incoloy 67 48 52 05

Cr35At 35 45 bal 01

Cr30Asect 30 48 bal 20 03 03

T310 25 20 bal 10 HR3q 25 20 bal 10 05 03 4002 20 33 bal 35 05


T91 9 bal 03 10 01 005 02


17









Separator vessel

Outlet reheater


Circulating pump

Over air ports

Primary superheater

Over air ports

B



18











ASTM test

Height =width2





19










LHV MJkg 69-97 80-85 105-115 Ash 3-12 5-12 6~1O


0406

06

02






08 06 04 CaO+MgO+S03

08










21


















22










23









24




convective pass

cyclone

CFB combustor

staged air

l~i --+ to baghouse


air h as secondary

air







25




Heating value

Moisture content

Ash content


Sulphur content

Nitrogen content

Chlorine content



Ash fusibility


















None












Typically none






26


70

65

60

~ 0

c-o

3 0

1il is a Ql r

55

50

45

40

35

30

0

- D

co bull


D

bullD

bull D backpass

I

bull D DCO OIJ D

CJJ

5 10 15 20 25 30









35

27






bull Ash production

150









28










29







~Volatiles





Q











30












Upgrade design


Original design

Water wall

tubes

8-10mm thickness

Water wall



Refractory step


floor tubes


31









Walerwall tube

Wastage

~

Refractory lining

Water wall tubes

Refractory lining





32












SiOz 5321 6170 5579

AbOJ 1098 1646 1352

Fe20J 583 299 700

CaO 1715 665 1151 MgO 253 108 190

NazO 226 051 162


KzO 015 066 086

TiOz 087 082 068

MnOz 004 003

PzOs 034 SrO 016 011 011

BaO 010 014 007

SOJ 578 655 574 Free quartz 3674 3701 3551


33










34











HHV MJkg 65

Moisture 9

Analysis wt db

Ash 735

Carbon 22



35











381 Sulphur dioxide


36






Coal sulphur

06 15 2 6


11 345 575 863 I 15 345 15 1 518 863 1294 1725 5176 2 1 690 1150 1725 2300 6901 251 863 1438 2157 2875 8626 3 I 1053 1725 2588 3450 10351



R = CarSr





37








7

6

o




NA NA


Coal type


NA Not applicable





- ~20 0

oi c ~ 15 ltll

S as 10 0 0 ltl

5

NA



NA Not applicable


Coal type



in heating value


38












39

---




382 Nitrogen oxides







150

100

50

Or------------------------ 700 750 800 850 900 950








--

~15 E

c o (jj (f)

E10 agt c agt Ol

-~ Z 5





40












41





400

~ 0

300 o



OX 100 z

O-----------r-------~--__r--____







383 Particulates


42











43









10



Coal type




44












45






46










47

--



steam turbine

15MWe

ash

dolomite

steam


~ t coal and

economiser







48












Start-up date 19891990 1990 1990 1993



Coal sulphur 01-15 34--40 29-90 03-12

Coal ash 8-21 12-20 23-47 2-18

Coal moisture 6-15 5-15 14--20 8-26

















49











50















51













52












53




461 SUlphur dioxide








Vartan









~l

5-10 96-98 33 about 2


13 125-145

15-25

SNCR + SCR 20

5 baghouse

NA not available

54








462 Nitrogen oxides





55








463 Particulates





56









Section 562)





57










58

5 Gasification






59

Gasification













60

Gasification



synthesis gas





Convective cooler



Boiler feedwater

Slag sumPL-__---

Radiant cooler

Coal grinding mill

Recycle (optional)




Water

Coal feed

I





---------------------~



61

Gasification


80


75 bull

(1) 70 ~

Ol gt 0 (1)

~ (1) 65 (]

Q o bull

60

55 -----------------r--------- shy55 60 65 70 75 80

Calculated value wt









HHV MJkg (daf) 3521 3052 2921






62

Gasification




C iii o o (J)

gt Cooling

~====~--

t Temperature








Si02 6021 4677 4379 4337

Ah03 156 2467 2604 2928

Fe203 585 1726 2101 1657

CaO 1157 55 258 351

MgO 214 107 106 1l9

Na20 267 I 045 051

Ti02 088 102 14 152

K20 043 184 222 208

P20S 026 032 07 098

BaO 008 011 015 02

srO 012 018 026 046

PbO 0 005 008 008

Cr203 019 022 026 03

3000 --SufCo

- - Pittsburgh2500

bullbull NO8



o+-------------r---_________--=-=-o=-=_r_=_---r 1200 1250 1300 1350 1400 1450 1500

Temperature degC


63

Gasification






the CRIEPI gasifier




Fe203 + CaO + MgO + Na20 + K20


Pyrolysis of coal




Coal rzd~




and others 1991)

64

Gasification



Tf= 13545X-2 + 2908X + 1232




2825degC

2600degC

2000

~ 1800 [l

til ~

Qi 1600 0shyE 2 c 14000

[jj


1000 0 5 10 15 20

Acidbase ratio







65

Gasification










66

Gasification








67

Gasification

Feed coal




Gas quench -----II

Refractory lining


Pressure shell

Tuyere

1Ll~__-- Slag tap



Slag







542 Slag mobility










68

Gasification











Wt


Pyrite



lt38 38-50 50-71 71-100 100-250 250-500 50()-1000 gt1000 Bulk

15 30 29 26

7 30 35 29

5 3 37 27

6 34 30 30

25 46 29 0

21 52 24

3

22 55 24 0

16 52 29 3

18 34 33 5

25 40 24 11

14 43 29 14

6 51 26 7

12 45 25 18

19 50 31

0

2 46 32 0

28 43 28 0

20 41 29 10

69

Gasification






Coal feeding system

Feed bin

Raw gas cooler

Lock hopper Raw gas

Charge bin


Fluidised bed



COllection bin

Lock hopper

Discharge bin




70

Gasification








Peat Wood Straw









Na K

400 500 550 600 900

0 I 15 100 160000

0 10 70 400 620000


71

Gasification















Ash 36 25 53 174 134




72

Gasification














steamI circuitSteam

Pressure let down



To steam circuit

Gas


Air


Air to CFBC



Ash


73

Gasification







Alkali getter


Ash Coal

Alkali getter

Sorbent


Air


74










75












Method of cooling

Data based on

Construction cost


Spare parts

Total capital cost






76










77

48





547 -J

gt g46OJ 0

~

~45












A$ US$




78













79





Poor coal

r 1

Good coal

50 MW 150 MW









80









Demonstration plant



~ 11 o



10lJ _









81





Costs millskWh









198990 5 730 199091 1957 2091 199192 1645 1907 199293 2566 3526 199394 3364 3334

Totals 9537 11588 ~-----------_

82








Figure 35)


2

L

s ~ ~

E -1 Ql o c ~ -2

~ D -3 w o o -4

80 capacity factor

PFBC favoured

IGCC favoured

0-t--------------------

-5 +----------------------------------

2 3 4



To feed




heating

Steam

Raw brown coal

Heating coils


Condensate

ro r ()

Air

Ash Exhaust gases


83





84

7 Conclusions






85

Conclusions










86

Conclusions







87

8 References



88

References



89

References



90

References



91

References



92

References



93

References



94

References



95

References



96

References



97

References




98

References



99













Coal Highlights



Printed in England




lEA Coal Research










3

Abstract


4

Contents

List of figures 7


1 Introduction 11














25 Comments 23









5

39 Residues 43

310 Comments 45










463 Particulates 56

47 Residues 56


5 Gasification 59




















65 IGCC 82

66 Comments 84

7 Conclusions 85

8 References 88

6

5

10

15

20

25

Figures


























7












8

5

10

15

20

25

Tables



























9




10

1 Introduction






11









12











3 and 4


375 352 315 429 260 25 540 27

410 384 324 444 280 25 540 27

407 383 312 461 275 25 560 23

406 382 298 471 300 285sect 580

23~


13







CIl 0 E ID c 15 2 0 ] c

1il i [lgt J () () Q)

0 E 25 -t----- --- -----_---CIl Q)

(jj __---L ----__------__-----__----L L-_







economiser

reheater 1

superheater 2

reheater 2

superheater 3





14


1 Waterwalls

Superheater

Pulveriser

4 Boiler feed pump

Boiler general

Reheater first


8 Buckets or blades


Economiser

Induced draft fan

Forced draft fan


Generating tubes

Stator windings

Furnace slagging



o 100 200 300



12

13

14

15

17

18







15












1400

1300

Corrosive zone

1200

1100

Stable 1000 zone

900

600


500 550


650

16











Incoloy 67 48 52 05

Cr35At 35 45 bal 01

Cr30Asect 30 48 bal 20 03 03

T310 25 20 bal 10 HR3q 25 20 bal 10 05 03 4002 20 33 bal 35 05


T91 9 bal 03 10 01 005 02


17









Separator vessel

Outlet reheater


Circulating pump

Over air ports

Primary superheater

Over air ports

B



18











ASTM test

Height =width2





19










LHV MJkg 69-97 80-85 105-115 Ash 3-12 5-12 6~1O


0406

06

02






08 06 04 CaO+MgO+S03

08










21


















22










23









24




convective pass

cyclone

CFB combustor

staged air

l~i --+ to baghouse


air h as secondary

air







25




Heating value

Moisture content

Ash content


Sulphur content

Nitrogen content

Chlorine content



Ash fusibility


















None












Typically none






26


70

65

60

~ 0

c-o

3 0

1il is a Ql r

55

50

45

40

35

30

0

- D

co bull


D

bullD

bull D backpass

I

bull D DCO OIJ D

CJJ

5 10 15 20 25 30









35

27






bull Ash production

150









28










29







~Volatiles





Q











30












Upgrade design


Original design

Water wall

tubes

8-10mm thickness

Water wall



Refractory step


floor tubes


31









Walerwall tube

Wastage

~

Refractory lining

Water wall tubes

Refractory lining





32












SiOz 5321 6170 5579

AbOJ 1098 1646 1352

Fe20J 583 299 700

CaO 1715 665 1151 MgO 253 108 190

NazO 226 051 162


KzO 015 066 086

TiOz 087 082 068

MnOz 004 003

PzOs 034 SrO 016 011 011

BaO 010 014 007

SOJ 578 655 574 Free quartz 3674 3701 3551


33










34











HHV MJkg 65

Moisture 9

Analysis wt db

Ash 735

Carbon 22



35











381 Sulphur dioxide


36






Coal sulphur

06 15 2 6


11 345 575 863 I 15 345 15 1 518 863 1294 1725 5176 2 1 690 1150 1725 2300 6901 251 863 1438 2157 2875 8626 3 I 1053 1725 2588 3450 10351



R = CarSr





37








7

6

o




NA NA


Coal type


NA Not applicable





- ~20 0

oi c ~ 15 ltll

S as 10 0 0 ltl

5

NA



NA Not applicable


Coal type



in heating value


38












39

---




382 Nitrogen oxides







150

100

50

Or------------------------ 700 750 800 850 900 950








--

~15 E

c o (jj (f)

E10 agt c agt Ol

-~ Z 5





40












41





400

~ 0

300 o



OX 100 z

O-----------r-------~--__r--____







383 Particulates


42











43









10



Coal type




44












45






46










47

--



steam turbine

15MWe

ash

dolomite

steam


~ t coal and

economiser







48












Start-up date 19891990 1990 1990 1993



Coal sulphur 01-15 34--40 29-90 03-12

Coal ash 8-21 12-20 23-47 2-18

Coal moisture 6-15 5-15 14--20 8-26

















49











50















51













52












53




461 SUlphur dioxide








Vartan









~l

5-10 96-98 33 about 2


13 125-145

15-25

SNCR + SCR 20

5 baghouse

NA not available

54








462 Nitrogen oxides





55








463 Particulates





56









Section 562)





57










58

5 Gasification






59

Gasification













60

Gasification



synthesis gas





Convective cooler



Boiler feedwater

Slag sumPL-__---

Radiant cooler

Coal grinding mill

Recycle (optional)




Water

Coal feed

I





---------------------~



61

Gasification


80


75 bull

(1) 70 ~

Ol gt 0 (1)

~ (1) 65 (]

Q o bull

60

55 -----------------r--------- shy55 60 65 70 75 80

Calculated value wt









HHV MJkg (daf) 3521 3052 2921






62

Gasification




C iii o o (J)

gt Cooling

~====~--

t Temperature








Si02 6021 4677 4379 4337

Ah03 156 2467 2604 2928

Fe203 585 1726 2101 1657

CaO 1157 55 258 351

MgO 214 107 106 1l9

Na20 267 I 045 051

Ti02 088 102 14 152

K20 043 184 222 208

P20S 026 032 07 098

BaO 008 011 015 02

srO 012 018 026 046

PbO 0 005 008 008

Cr203 019 022 026 03

3000 --SufCo

- - Pittsburgh2500

bullbull NO8



o+-------------r---_________--=-=-o=-=_r_=_---r 1200 1250 1300 1350 1400 1450 1500

Temperature degC


63

Gasification






the CRIEPI gasifier




Fe203 + CaO + MgO + Na20 + K20


Pyrolysis of coal




Coal rzd~




and others 1991)

64

Gasification



Tf= 13545X-2 + 2908X + 1232




2825degC

2600degC

2000

~ 1800 [l

til ~

Qi 1600 0shyE 2 c 14000

[jj


1000 0 5 10 15 20

Acidbase ratio







65

Gasification










66

Gasification








67

Gasification

Feed coal




Gas quench -----II

Refractory lining


Pressure shell

Tuyere

1Ll~__-- Slag tap



Slag







542 Slag mobility










68

Gasification











Wt


Pyrite



lt38 38-50 50-71 71-100 100-250 250-500 50()-1000 gt1000 Bulk

15 30 29 26

7 30 35 29

5 3 37 27

6 34 30 30

25 46 29 0

21 52 24

3

22 55 24 0

16 52 29 3

18 34 33 5

25 40 24 11

14 43 29 14

6 51 26 7

12 45 25 18

19 50 31

0

2 46 32 0

28 43 28 0

20 41 29 10

69

Gasification






Coal feeding system

Feed bin

Raw gas cooler

Lock hopper Raw gas

Charge bin


Fluidised bed



COllection bin

Lock hopper

Discharge bin




70

Gasification








Peat Wood Straw









Na K

400 500 550 600 900

0 I 15 100 160000

0 10 70 400 620000


71

Gasification















Ash 36 25 53 174 134




72

Gasification














steamI circuitSteam

Pressure let down



To steam circuit

Gas


Air


Air to CFBC



Ash


73

Gasification







Alkali getter


Ash Coal

Alkali getter

Sorbent


Air


74










75












Method of cooling

Data based on

Construction cost


Spare parts

Total capital cost






76










77

48





547 -J

gt g46OJ 0

~

~45












A$ US$




78













79





Poor coal

r 1

Good coal

50 MW 150 MW









80









Demonstration plant



~ 11 o



10lJ _









81





Costs millskWh









198990 5 730 199091 1957 2091 199192 1645 1907 199293 2566 3526 199394 3364 3334

Totals 9537 11588 ~-----------_

82








Figure 35)


2

L

s ~ ~

E -1 Ql o c ~ -2

~ D -3 w o o -4

80 capacity factor

PFBC favoured

IGCC favoured

0-t--------------------

-5 +----------------------------------

2 3 4



To feed




heating

Steam

Raw brown coal

Heating coils


Condensate

ro r ()

Air

Ash Exhaust gases


83





84

7 Conclusions






85

Conclusions










86

Conclusions







87

8 References



88

References



89

References



90

References



91

References



92

References



93

References



94

References



95

References



96

References



97

References




98

References



99













Coal Highlights



Printed in England




Abstract


4

Contents

List of figures 7


1 Introduction 11














25 Comments 23









5

39 Residues 43

310 Comments 45










463 Particulates 56

47 Residues 56


5 Gasification 59




















65 IGCC 82

66 Comments 84

7 Conclusions 85

8 References 88

6

5

10

15

20

25

Figures


























7












8

5

10

15

20

25

Tables



























9




10

1 Introduction






11









12











3 and 4


375 352 315 429 260 25 540 27

410 384 324 444 280 25 540 27

407 383 312 461 275 25 560 23

406 382 298 471 300 285sect 580

23~


13







CIl 0 E ID c 15 2 0 ] c

1il i [lgt J () () Q)

0 E 25 -t----- --- -----_---CIl Q)

(jj __---L ----__------__-----__----L L-_







economiser

reheater 1

superheater 2

reheater 2

superheater 3





14


1 Waterwalls

Superheater

Pulveriser

4 Boiler feed pump

Boiler general

Reheater first


8 Buckets or blades


Economiser

Induced draft fan

Forced draft fan


Generating tubes

Stator windings

Furnace slagging



o 100 200 300



12

13

14

15

17

18







15












1400

1300

Corrosive zone

1200

1100

Stable 1000 zone

900

600


500 550


650

16











Incoloy 67 48 52 05

Cr35At 35 45 bal 01

Cr30Asect 30 48 bal 20 03 03

T310 25 20 bal 10 HR3q 25 20 bal 10 05 03 4002 20 33 bal 35 05


T91 9 bal 03 10 01 005 02


17









Separator vessel

Outlet reheater


Circulating pump

Over air ports

Primary superheater

Over air ports

B



18











ASTM test

Height =width2





19










LHV MJkg 69-97 80-85 105-115 Ash 3-12 5-12 6~1O


0406

06

02






08 06 04 CaO+MgO+S03

08










21


















22










23









24




convective pass

cyclone

CFB combustor

staged air

l~i --+ to baghouse


air h as secondary

air







25




Heating value

Moisture content

Ash content


Sulphur content

Nitrogen content

Chlorine content



Ash fusibility


















None












Typically none






26


70

65

60

~ 0

c-o

3 0

1il is a Ql r

55

50

45

40

35

30

0

- D

co bull


D

bullD

bull D backpass

I

bull D DCO OIJ D

CJJ

5 10 15 20 25 30









35

27






bull Ash production

150









28










29







~Volatiles





Q











30












Upgrade design


Original design

Water wall

tubes

8-10mm thickness

Water wall



Refractory step


floor tubes


31









Walerwall tube

Wastage

~

Refractory lining

Water wall tubes

Refractory lining





32












SiOz 5321 6170 5579

AbOJ 1098 1646 1352

Fe20J 583 299 700

CaO 1715 665 1151 MgO 253 108 190

NazO 226 051 162


KzO 015 066 086

TiOz 087 082 068

MnOz 004 003

PzOs 034 SrO 016 011 011

BaO 010 014 007

SOJ 578 655 574 Free quartz 3674 3701 3551


33










34











HHV MJkg 65

Moisture 9

Analysis wt db

Ash 735

Carbon 22



35











381 Sulphur dioxide


36






Coal sulphur

06 15 2 6


11 345 575 863 I 15 345 15 1 518 863 1294 1725 5176 2 1 690 1150 1725 2300 6901 251 863 1438 2157 2875 8626 3 I 1053 1725 2588 3450 10351



R = CarSr





37








7

6

o




NA NA


Coal type


NA Not applicable





- ~20 0

oi c ~ 15 ltll

S as 10 0 0 ltl

5

NA



NA Not applicable


Coal type



in heating value


38












39

---




382 Nitrogen oxides







150

100

50

Or------------------------ 700 750 800 850 900 950








--

~15 E

c o (jj (f)

E10 agt c agt Ol

-~ Z 5





40












41





400

~ 0

300 o



OX 100 z

O-----------r-------~--__r--____







383 Particulates


42











43









10



Coal type




44












45






46










47

--



steam turbine

15MWe

ash

dolomite

steam


~ t coal and

economiser







48












Start-up date 19891990 1990 1990 1993



Coal sulphur 01-15 34--40 29-90 03-12

Coal ash 8-21 12-20 23-47 2-18

Coal moisture 6-15 5-15 14--20 8-26

















49











50















51













52












53




461 SUlphur dioxide








Vartan









~l

5-10 96-98 33 about 2


13 125-145

15-25

SNCR + SCR 20

5 baghouse

NA not available

54








462 Nitrogen oxides





55








463 Particulates





56









Section 562)





57










58

5 Gasification






59

Gasification













60

Gasification



synthesis gas





Convective cooler



Boiler feedwater

Slag sumPL-__---

Radiant cooler

Coal grinding mill

Recycle (optional)




Water

Coal feed

I





---------------------~



61

Gasification


80


75 bull

(1) 70 ~

Ol gt 0 (1)

~ (1) 65 (]

Q o bull

60

55 -----------------r--------- shy55 60 65 70 75 80

Calculated value wt









HHV MJkg (daf) 3521 3052 2921






62

Gasification




C iii o o (J)

gt Cooling

~====~--

t Temperature








Si02 6021 4677 4379 4337

Ah03 156 2467 2604 2928

Fe203 585 1726 2101 1657

CaO 1157 55 258 351

MgO 214 107 106 1l9

Na20 267 I 045 051

Ti02 088 102 14 152

K20 043 184 222 208

P20S 026 032 07 098

BaO 008 011 015 02

srO 012 018 026 046

PbO 0 005 008 008

Cr203 019 022 026 03

3000 --SufCo

- - Pittsburgh2500

bullbull NO8



o+-------------r---_________--=-=-o=-=_r_=_---r 1200 1250 1300 1350 1400 1450 1500

Temperature degC


63

Gasification






the CRIEPI gasifier




Fe203 + CaO + MgO + Na20 + K20


Pyrolysis of coal




Coal rzd~




and others 1991)

64

Gasification



Tf= 13545X-2 + 2908X + 1232




2825degC

2600degC

2000

~ 1800 [l

til ~

Qi 1600 0shyE 2 c 14000

[jj


1000 0 5 10 15 20

Acidbase ratio







65

Gasification










66

Gasification








67

Gasification

Feed coal




Gas quench -----II

Refractory lining


Pressure shell

Tuyere

1Ll~__-- Slag tap



Slag







542 Slag mobility










68

Gasification











Wt


Pyrite



lt38 38-50 50-71 71-100 100-250 250-500 50()-1000 gt1000 Bulk

15 30 29 26

7 30 35 29

5 3 37 27

6 34 30 30

25 46 29 0

21 52 24

3

22 55 24 0

16 52 29 3

18 34 33 5

25 40 24 11

14 43 29 14

6 51 26 7

12 45 25 18

19 50 31

0

2 46 32 0

28 43 28 0

20 41 29 10

69

Gasification






Coal feeding system

Feed bin

Raw gas cooler

Lock hopper Raw gas

Charge bin


Fluidised bed



COllection bin

Lock hopper

Discharge bin




70

Gasification








Peat Wood Straw









Na K

400 500 550 600 900

0 I 15 100 160000

0 10 70 400 620000


71

Gasification















Ash 36 25 53 174 134




72

Gasification














steamI circuitSteam

Pressure let down



To steam circuit

Gas


Air


Air to CFBC



Ash


73

Gasification







Alkali getter


Ash Coal

Alkali getter

Sorbent


Air


74










75












Method of cooling

Data based on

Construction cost


Spare parts

Total capital cost






76










77

48





547 -J

gt g46OJ 0

~

~45












A$ US$




78













79





Poor coal

r 1

Good coal

50 MW 150 MW









80









Demonstration plant



~ 11 o



10lJ _









81





Costs millskWh









198990 5 730 199091 1957 2091 199192 1645 1907 199293 2566 3526 199394 3364 3334

Totals 9537 11588 ~-----------_

82








Figure 35)


2

L

s ~ ~

E -1 Ql o c ~ -2

~ D -3 w o o -4

80 capacity factor

PFBC favoured

IGCC favoured

0-t--------------------

-5 +----------------------------------

2 3 4



To feed




heating

Steam

Raw brown coal

Heating coils


Condensate

ro r ()

Air

Ash Exhaust gases


83





84

7 Conclusions






85

Conclusions










86

Conclusions







87

8 References



88

References



89

References



90

References



91

References



92

References



93

References



94

References



95

References



96

References



97

References




98

References



99













Coal Highlights



Printed in England




lEA COAL RESEARCH

Documents

Transcript of lEA COAL RESEARCH