IGCC PUERTOLLANO A CLEAN COAL GASIFICATION POWER PLANT
IGCCPUERTOLLANO
A CLEANCOAL GASIFICATION
POWER PLANT
FOREWORD
It gives me great pleasure to present this book on the ELCOGAS Puertollano Integrated
Gasification with Combined Cycle (IGCC) plant, which represents a new milestone in the
development of clean combustion technology for the production of electricity in Europe.
The plant uses low-cost fuels in a clean manner, as the gas produced during the
gasification process is cleaned before being burned in the gas turbine. Furthermore, its
high level of efficiency keeps CO2 emissions to a minimum.
This book has been written on the basis of the Final Report submitted to the European
Commission Directorate General for Energy and Transport in October 2000, under the
Thermie Programme. It describes the nature of the plant and the technology therein, as
well as the results produced to date. The Puertollano IGCC plant was a target project for
the Thermie Programme, as it complied with two of its foremost objectives: promoting
new, clean and efficient energy use and production on the market, and reducing harmful
emissions, particularly those of CO2, as a consequence of burning fossil fuels. The
Puertollano Plant also contributes to European Commission objectives in terms of
guaranteeing Europe’s energy supply, as it uses autochthonous fossil fuels, reducing
dependence on external energy sources.
At present, now that we have overcome the many, wide-ranging difficulties that this new
and complex technology presented during the IGCC plant design, construction and
commissioning phases, performance is satisfactory, with more than 900,000 MWh having
been produced with synthetic gas in 2000.
IGCC technology is demonstrating its technical viability, showing unique characteristics
and a singular potential for the incorporation of improvements in the near future. Currently
in an experimental phase, these improvements should lead to the attainment of that
notoriously elusive balance between energy, environment and economy.
José Damián Bogas Gálvez
President of ELCOGAS
1
The purpose of this publication
The Integrated Gasification with Combined Cycle (IGCC) plant stands out in the field of
clean coal technology, due to its excellent environmental features and its potential for
improvement and development, which will allow it to become more competitive in the future
with respect to alternative energy sources.
This fact, accepted by all energy technology experts, becomes highly significant if we
examine what the near future holds for electricity supplies. In effect, the question is to find
the best way to meet growing energy needs throughout the world among all the available
possibilities.
In Europe, reflections on energy policy are set out in the Green Paper on Energy outlook to
the year 2020 document, which the European Commission’s Directorate General for
Transport and Energy presented in November 2000.
Deeper reflection on the issue of the possibility of controlling demand through increased
efficiency or saving energy, together with the choices offered by a range of alternative
energy sources, including natural gas, nuclear energy, renewable energy sources and bio
energy, which does not contribute to the greenhouse effect, leaves a very important role for
coal to play, provided that its use corresponds to the clean possibilities permitted by current
techniques. This role clearly exists, even before we consider the political and strategic
factors that affect some of the aforementioned solutions and which reinforce coal’s qualities
as a resource with a stable price and a diversified supply.
The Puertollano power station is European IGCC technology’s showcase project. The
power station constitutes a reference point in terms of demonstrating how this technology
can contribute to a satisfactory solution to the problem of supplying electricity in the near
future. This book provides data and describes real experiences that will help to clarify the
real value of this technology.
This is our reason for publishing it.
Manuel Treviño Coca
Chief Executive Officer
1
CONTENTS
Page
1. THE PUERTOLLANO IGCC PLANT ..............................................................................................81.1. GENERAL ......................................................................................................................................81.2. ADVANTAGES OF IGCC PLANTS 9
2. PLANT AND TECHNOLOGY DESCRIPTION............................................................................122.1. LOCATION ..................................................................................................................................122.2. GENERAL DESCRIPTION ......................................................................................................142.3. FUEL..............................................................................................................................................15
2.3.1. GENERAL.............................................................................................................................152.3.2. FUEL DATA .........................................................................................................................16
2.4. PLANT SYSTEMS ......................................................................................................................172.4.1. GASIFICATION ...................................................................................................................17
2.4.1.1. General..............................................................................................................................172.4.1.2. Fuel Yard ..........................................................................................................................182.4.1.3. Coal Preparation ...............................................................................................................192.4.1.4. Pressurization and feeding ...............................................................................................202.4.1.5. Gasification process..........................................................................................................212.4.1.6. Ceramic filters ..................................................................................................................232.4.1.7. Slag System.......................................................................................................................232.4.1.8. Gas cleaning and desulphurization ..................................................................................232.4.1.9. Sulphur Recovery Unit.....................................................................................................25
2.4.2. AIR SEPARATION UNIT ...................................................................................................262.4.2.1. General..............................................................................................................................262.4.2.2. Chilling and purification ..................................................................................................262.4.2.3. Distillation.........................................................................................................................27
2.4.3. COMBINED CYCLE ...........................................................................................................282.4.3.1. General..............................................................................................................................282.4.3.2. Gas Turbine ......................................................................................................................282.4.3.3. Heat recovery steam generator.........................................................................................302.4.3.4. Steam Turbine...................................................................................................................31
2.4.4. INTEGRATION SYSTEM...................................................................................................332.4.5. AUXILIARY AND SERVICE SYSTEMS.........................................................................35
2.4.5.1. Cooling system .................................................................................................................352.4.5.2. Auxiliary boilers ...............................................................................................................362.4.5.3. Flare...................................................................................................................................362.4.5.4. Emergency Diesel generator ............................................................................................372.4.5.5. Water Treatment...............................................................................................................372.4.5.6. Other service and auxiliary plant systems.......................................................................37
2.4.6. ELECTRIC SYSTEMS.........................................................................................................382.4.6.1. General..............................................................................................................................382.4.6.2. Generators.........................................................................................................................39
2.4.7. CONTROL SYSTEM ...........................................................................................................402.4.7.1. General..............................................................................................................................402.4.7.2. Control levels....................................................................................................................40
2.4.9. PLANT FUNCTIONAL BASIC OUTLINE.......................................................................412.4.10. SUMMARY OF BASIC TECHNICAL DATA................................................................42
2.5. TECHNOLOGICAL VALUE AND INNOVATION.............................................................432.5.1. TECHNOLOGICAL INNOVATION..................................................................................43
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2.5.2. ACQUISITION OF SPECIFIC “KNOW-HOW” ..............................................................432.6. ENVIRONMENTAL CONSIDERATIONS............................................................................45
2.6.1. GENERAL.............................................................................................................................452.6.2. COMPARISON OF EMISSIONS FROM DIFFERENT TECHNOLOGIES TYPES.....47
3. ELCOGAS AND THE PROJECT’S ORGANIZATION ..............................................................493.1. THE ELCOGAS COMPANY....................................................................................................493.2. ORGANIZATION .......................................................................................................................51
3.2.1. GENERAL.............................................................................................................................513.2.2. PROJECT MANAGEMENT AND SUPERVISION .........................................................523.2.3. OUTLINE OF PROJECT CONTRACTS ...........................................................................53
3.2.3.1. GENERAL AND BALANCE OF PLANT ENGINEERING.......................................543.2.3.2. MAIN SUPPLIES ............................................................................................................553.2.3.3. SUPPLY OF BALANCE OF PLANT EQUIPMENT...................................................573.2.3.4. CONSTRUCTION. CIVIL WORK AND EQUIPMENT ASSEMBLY .....................603.2.3.5. QUALITY PLAN INSPECTION AGENCIES..............................................................643.2.3.6. OPERATION TRAINING ..............................................................................................643.2.3.7. FUEL SUPPLY................................................................................................................64
3.3. PROJECT DEVELOPMENT....................................................................................................653.3.1. GENERAL.............................................................................................................................653.3.2. BASIC PROJECT DATES...................................................................................................673.3.3. PROJECT BUDGET AND FINANCING...........................................................................68
3.3.3.1. Project Budget ..................................................................................................................683.3.3.2. Capital costs......................................................................................................................693.3.3.3. Project Financing..............................................................................................................70
3.4. AUTHORIZATIONS AND LICENSES..................................................................................714. PLANT OPERATION.........................................................................................................................72
4.1. OPERATION ORGANIZATION.............................................................................................724.2. PLANT OPERATION ASSESSMENT AND DATA.............................................................73
4.2.1. ASSESSMENT OF THE TOTAL PLANT PERFORMANCE .........................................734.2.1.1. Plant status update ............................................................................................................734.2.1.2. Main operation interruptions and type of failures...........................................................774.2.1.3. Lessons learned.................................................................................................................79
4.2.2. ASSESSMENT OF THE PERFORMANCE OF INDIVIDUAL EQUIPMENT.............804.2.2.1. Main operation interruptions classified by areas ............................................................804.2.2.2. Gasification Island............................................................................................................824.2.2.3. Air Separation Unit (ASU) ..............................................................................................944.2.2.4. Combined Cycle ...............................................................................................................964.2.2.5. Auxiliary systems (Balance of Plant) ..............................................................................98
4.2.3. PROCESS DATA..................................................................................................................994.2.3.1. Fuel heat rate. Year 2000 .................................................................................................994.2.3.2. Auxiliary power. Year 2000 ............................................................................................994.2.3.3. Consumption of consumables and catalysers................................................................1004.2.3.4. Generation of electricity.................................................................................................101
4.2.4. FINANCIAL DATA ...........................................................................................................1064.2.4.1 Production Costs..............................................................................................................1064.2.4.2. Operation Income ...........................................................................................................107
4.2.5. ENVIRONMENTAL DATA..............................................................................................1084.2.5.1. Absolute environmental data .........................................................................................1084.2.5.2. Emission data..................................................................................................................1094.2.5.3. By-products and waste data ...........................................................................................1134.2.5.4. Trace element mass balance...........................................................................................115
4.3. ASSESSMENT OF OPERATION WITH DIFFERENT FUELS......................................1174.3.1. INTRODUCTION...............................................................................................................117
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4.3.2. FUEL CHARACTERIZATION.........................................................................................1184.3.3. ASSESSMENT OF TESTS AND EXPERIENCE WITH DIFFERENT FUELS ..........121
4.3.3.1. History of test operation.................................................................................................1214.3.3.2. Individual analysis of performance op processing parts...............................................1284.3.3.3. Fuel consumption and other consumables ....................................................................1374.3.3.4. Electricity, by-products and wastes production ............................................................1384.3.3.5. Gasification behaviour of feedstock ..............................................................................1394.3.3.6. Main data on emissions and by-products ......................................................................1444.3.3.7. Thermo-economic diagnosis..........................................................................................151
4.3.4. REFERENCES ....................................................................................................................1605. IMPROVEMENTS FOR FUTURE IGCC PLANTS 161
5.1. ASSESSMENT OF THE GLOBAL OPERATION RESULTS FOR FUTURE IGCCPLANTS 1615.2. ASSESSMENT OF THE DIFFERENT PROCESS PARTS 163
5.2.1. PROCESS OPTIMISATION AND ADJUSTMENT .......................................................1635.2.1.1. Coal dust preparation......................................................................................................1635.2.1.2. Coal dust conveying, sluicing and feeding....................................................................1635.2.1.3. Gasifier and gas quenching............................................................................................1645.2.1.4. Waste Heat Recovery System........................................................................................1645.2.1.5. Slag handling ..................................................................................................................1655.2.1.6. Dry dedusting system.....................................................................................................1655.2.1.7. Wet scrubbing and gas stripping....................................................................................1665.2.1.8. Desulphurization system................................................................................................1665.2.1.9. Air separation unit (ASU) ..............................................................................................1665.2.1.10. Saturator........................................................................................................................1675.2.1.11. Gas turbine....................................................................................................................1675.2.1.12. Auxiliary systems (Balance of Plant) ..........................................................................1675.2.1.13. Control system..............................................................................................................1685.2.1.14. General layout...............................................................................................................168
5.3. CONCLUSIONS FOR FUTURE IGCC PLANTS 171
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Index of Tables
Table 1. Coal and pet-coke parameters (50% weight mix) 16Table 2. Feedstock parameters 18Table 3. Coal preparation. Flow composition and heating value 20Table 4. Coal preparation parameters 20Table 5. Gasification process design values 21Table 6. Gasifier parameters 22Table 7. Clean gas specifications 24Table 8. Air Separation Unit parameters 27Table 9. Auxiliary boilers parameters 36Table 10. Electric transformers parameters 39Table 11. Basic technical data 42Table 12. Comparison of emissions between coal technology types (mg/Nm3, 6% O2) 47Table 13. Comparison of emissions (g/kWh) between coal technology types. Output 320 MW 48Table 14. ELCOGAS capital share 49Table 15. Equipment Suppliers 57Table 16. Civil work contractors 60Table 17. Mechanical Assembly, Electrical and I&C Installation Contract packages 61Table 18. Main site work units 63Table 19. Project Budget constant currency Base 1991 68Table 20. IGCC's Capital costs forecast 69Table 21. Main milestones of operation. 74Table 22. Raw gas and clean gas composition 93Table 23. Main results of the Acceptance Test. 96Table 24. Plant operation consumables. 100Table 25. IGCC Plant electricity gross output. Accumulated 101Table 26. IGCC Plant electricity gross output. Year 2000 102Table 27. Total Plant electricity gross output. 103Table 28. Total Plant electricity gross output. 104Table 29. IGCC Plant emission data for 2000 109Table 30. IGCC Plant waste data for 2000 114Table 31. Fuel range designation. 118Table 32. Fuels selected for demonstration tests. 118Table 33. Actual and predicted composition of the mixtures tested. 119Table 34. Coal and coke composition during the tests. 120Table 35. Main test conditions. 121Table 36. Fuel consumption and other consumables. 137Table 37. Electricity, by-products and wastes production. 138Table 38. Carbon conversion during tests. 139Table 39. Composition of solid residues. 146Table 40. Composition of wash and Venturi water. 150Table 41. Performance Input Data. 151Table 42. Performance Output Data. 152Table 43. Mass balances. 153Table 44. Heat Balances. 154Table 45. Cost fixed for the financial study. 155Table 46. Financial costs. 155Table 47. Summary of the main system improvements based on the experience in Puertollano. 171
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Index of Figures
Figure 1. Perspective of the Puertollano IGCC Plant 11Figure 2. Map of the Puertollano area 12Figure 3. View of Puertollano town 13Figure 4. Encasur coal mine 15Figure 5. Fuel yard 18Figure 6. Coal preparation plant 19Figure 7. Gasifier building 21Figure 8. Gas cleaning and desulphurization 24Figure 9. Gasification and gas cleaning process 25Figure 10. Air Separation Unit 26Figure 11. Gas Turbine 28Figure 12. Gas Turbine VT 94.3 with internals 29Figure 13. Heat recovery boiler and gas saturator buildings 30Figure 14. Steam Turbine 31Figure 15. Energy balance of the plant 32Figure 16. Outline of the IGCC plant's main system's interfaces 34Figure 17. Cooling tower 35Figure 18. Flare 36Figure 19. Main transformer and substation 38Figure 20. Plant control room 40Figure 21. Simplified flow diagram of the Puertollano Plant 41Figure 22. Puertollano IGCC Plant 46Figure 23. EU emission limits and IGCC plant design emissions 47Figure 24. Comparison of emissions between different technology types 48Figure 25. ELCOGAS capital share 50Figure 26. ELCOGAS Basic organization chart 51Figure 27. ELCOGAS Project organization chart 52Figure 28. Project Interfaces and Contracts 53Figure 29. Transport of the gas turbine 59Figure 30. Civil construction work on the plant 60Figure 31. Assembly of the gasifier 62Figure 32. Project schedule 65Figure 33. The Puertollano IGCC Plant Project Progress 66Figure 34. Project Budget distribution. Constant currency October 1991 68Figure 35. IGCC's Capital costs forecast 69Figure 36. Operation Chart 72Figure 37. Accumulated gasifier and IGCC run time. 75Figure 38. Gasifier and IGCC run time. 75Figure 39. IGCC and NGCC availability factor. 76Figure 40. Gasifier stoppages classified by type of failure. 77Figure 41. Gas turbine syngas operation interruptions classified by type of failure. 78Figure 42. Gasifier stoppages classified by areas. 80Figure 43. Gas turbine syngas operation interruptions classified by areas. 81Figure 44. Gasifier stoppages classified by Gasification Systems. 82Figure 45. Gas turbine syngas operation interruptions classified by Gasification Systems. 83Figure 46. Comparison of fouling behaviour between September 1999 and August 2000. 87Figure 47. Candle filter fouling factor and solids in Venturi during operation. 91Figure 48. Fly ash size distribution. 92Figure 49. Main gas turbine parameters to control the “switch over”. 97
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Figure 50. Main gas turbine parameters to control the “switch back”. 97Figure 51. Fuel heat rate 99Figure 52. Plant auxiliary power 99Figure 53. IGCC Plant yearly electricity generation records 101Figure 54. IGCC Plant Monthly electricity gross output. Year 2000 102Figure 55. Total plant yearly gross output 103Figure 56. Total Plant monthly electricity gross output. Year 2000 104Figure 57. Plant availability for 2000 (up to November) 105Figure 58. NOx emission mg/Nm3 for 2000 110Figure 59. Specific NOx emission g/kWh for 2000 110SO2 emission mg/Nm3 for 2000 111Figure 61. Specific SO2 emission g/kWh for 2000 111Particulate emission mg/Nm3 for 2000 112Figure 63. Specific particulate emission g/kWh year 2000 112Figure 64. Trace distribution in feedstock. 115Figure 65. Trace distribution in by-products. 116Figure 66. Main process input data during the tests. Mixture 1 122Figure 67. Main process input data during the tests. Mixture 2 122Figure 68. Main process input data during the tests. Mixture 3 123Figure 69. Main process input data during the tests. Mixture 4 123Figure 70. Main process output data during the tests. Mixture 1 124Figure 71. Main process output data during the tests. Mixture 2 124Figure 72. Main process output data during the tests. Mixture 3 125Figure 73. Main process output data during the tests. Mixture 4 125Figure 74. Main gas composition data during the tests. Mixture 1 126Figure 75. Main gas composition data during the tests. Mixture 2 126Figure 76. Main gas composition data during the tests. Mixture 3 127Figure 77. Main gas composition data during the tests. Mixture 4 127Figure 78. Main data of the slag extraction system during the tests. Test 1. 129Figure 79. Main data of the slag extraction system during the tests. Test 2 129Figure 80. Main data of the slag extraction system during the tests. Test 3 130Figure 81. Main data of the slag extraction system during the tests. Test 4 130Figure 82. Fouling data during the tests. Test 1. 132Figure 83. Fouling data during the tests. Test 2. 132Figure 84. Fouling data during the tests. Test 3. 133Figure 85. Fouling data during the tests. Test 4. 133Figure 86. Candle filter performance during the tests. Test 1 135Figure 87. Candle filter performance during the tests. Test 2 135Figure 88. Candle filter performance during the tests. Test 3 136Figure 89. Candle filter performance during the tests. Test 4. 136Figure 90. Cold Gas efficiency against O2/ feedstock ratio 140Figure 91. Cold Gas Efficiency against fuel carbon content. 140Figure 92. Cold Gas Efficiency against fuel ash content. 141Figure 93. Cold Gas Efficiency against fuel volatile matter. 141Figure 94. Slag/ash split. 143Figure 95. Emission data during fuel tests. 144Figure 96. Comparison of emission levels during fuel tests. 145Figure 97. Distribution of trace elements among by-product streams. Mixture 1 147Figure 98. Distribution of trace elements among by-product streams. Mixture 2 147Figure 99. Distribution of trace elements among by-product streams. Mixture 3 148Figure 100. Distribution of trace elements among by-product streams. Mixture 4 148Figure 101. Distribution of ash among by-product streams. 149Figure 102. Test No. 1 (Mixture 3). 156
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Figure 103. Test No. 2 (Mixture 4). 157Figure 104. Test No. 3 (Mixture 2). 158Figure 105. Test No. 4 (Mixture 1). 159Figure 106. IGCC 2000 simplified flow diagram. 162Figure 107. General layout of ELCOGAS plant. 169Figure 108. Expected IGCC Efficiency Potential 173
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1. THE PUERTOLLANO IGCC PLANT
1.1. GENERAL
In the late eighties, looking for the development of European technologies in the energy field for the clean
use of coal, a group of European electric utilities, led by Endesa and EDF, promoted the project involving
the design, construction and demonstration of a power plant using the emerging technology of coal
gasification integrated with combined cycle. This initiative was designated as target project (projet ciblé)
by the European Commission's Directorate General of Energy because its characteristics of clean and
efficient combustion plant and was also included in the Spanish Government's National Energy Plan
1991-2001.
ELCOGAS Company was formed in 1992 by the European electric utilities Endesa, Electricité de France,
Sevillana de Electricidad, Iberdrola, Hidroeléctrica del Cantábrico, and Electricidade de Portugal to
develop the integrated coal gasification with combined cycle (IGCC) power plant project, with a gross
electric output of about 330 MW (ISO conditions), to be built in the central south area of Spain, close to
Puertollano, Ciudad Real.
The Puertollano IGCC project was launched with the signature of the contracts for the supply of
gasification and combined cycle main equipment on July 1992 with two European technology suppliers:
Siemens and Krupp Koppers, together with Babcock Wilcox Española, as manufacturer partner.
In 1993 two other important European utilities, Enel and National Power, joined ELCOGAS. The main
suppliers of the plant technology, Siemens Ag, Krupp Koppers, together with Babcock Wilcox Española
became partners of ELCOGAS few months later on.
9
1.2. ADVANTAGES OF IGCC PLANTS
In terms of electric power production, there are clear advantages to the use of IGCC plants as regards
environmental and economic considerations, feedstock and product flexibility, and ease of integration
using advanced technologies to achieve high efficiency levels. This type of plants makes it possible to use
coal and other widely available fuels in an environmentally friendly manner, contributing to the
diversification of the energy offer and to the security of energy supply. IGCC technology, already
economically competitive as regards variable costs, will benefit from further improvements in terms of
fixed costs and the increased efficiency of its main equipment.
A clean environment
IGCC plants can meet all projected environmental regulations, solving the compliance problems of
electric power generation. Because it operates at higher efficiency levels than conventional fossil-fuelled
power plants, IGCC systems emit less CO2 per unit of energy, thus contributing to reach the objectives of
the Kioto Protocol, as regards world reduction in CO2 emissions to the atmosphere. IGCC plants
emissions of sulphur dioxide and nitrogen oxides, gases linked to acid rain, are a small fraction of
allowable limits. The water required to run an IGCC plant is less than half that required to run a pulverised
coal plant with a flue gas scrubbing system. The solid residues obtained are, in its majority, vitrified, non
leacheable slag or pure products resulting in usable by-products of the process.
Feedstock flexibility
The gasifier has the flexibility to handle a variety of feedstocks. In addition to coal, possible feedstocks
include petroleum coke, refinery liquids, bio-mass, municipal solid waste, tires, plastics, hazardous wastes
and chemicals, and sludge. These alternative feedstocks are typically low-cost, sometimes even of
negative cost.
When a low-cost feed is used, the economics of gasification are usually enhanced and marketable
products are created from the waste stream, avoiding disposal costs and environmental concerns.
10
Product flexibility
An advantage of gasification lies in its ability to operate in a coproduction mode. Coproduct options help
reduce business risk by allowing the company to choose the plant configuration that best suits market
demands, producing goods that have the highest value to that particular business. System efficiencies are
improved to when transportation fuels are produced and enhanced when some of the steam is used
directly in industrial applications.
Attractive plant economics
The economic advantages of the IGCC system are its use of low-cost feedstocks, its high efficiency in
resource use and its economically efficient reduction of environmental pollutants. In addition, it can
deliver high-value marketable by-products, such as sulphur and slag. Modularity and phased construction
can distribute capital expenditures to meet financing requirements. By utilisation of part of synthetic gas,
IGCC can also produce high value products like pure hydrogen, pure carbon monoxide and other
byproductss. Because IGCC uses regenerable sorbents and catalysts, the costs of replenishing these
supplies as well as the costs of disposal can be minimised. Continued operating experience and the design
of additional units can further reduce capital and operating costs, increasing IGCC's economic
competitiveness.
Ease of integration with advanced technologies to achieve high efficiencies.
Current IGCC plant efficiency is higher than 40% compared with 35% for conventional plants. The
increased efficiency of the IGCC process significantly reduces CO2 emissions and those that cause acid
rain, and lowers the cost of power and products. As advanced technologies for gasification, turbines, fuel
cells, coproduction, gas separation and gas cleaning become available, each of these can be readily
integrated to improve overall efficiency.
Further, coal gasification with gas cleaning can be readily added to existing natural-gas combined-cycle
plants to attain a full IGCC system. Most important, system evaluations can determine the best
combinations of components to achieve cost reductions while minimising wastes and environmental
impacts.
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Figure 1. Perspective of the Puertollano IGCC Plant
12
2. PLANT AND TECHNOLOGY DESCRIPTION
2.1. LOCATION
The plant is located in the central south part of Spain, 200 Km from Madrid, in the area of Puertollano, in
the province of Ciudad Real. The site is 10 Km East-South-East of the town of Puertollano, approximately
3 km to the North-East of El Villar, on the kilometre 27 of the road between Calzada de Calatrava and
Puertollano. The ELCOGAS site occupies an area of 480,000 m2.
Figure 2. Map of the Puertollano area
13
Besides the existence of coal mines producing coal suitable for gasification, Puertollano was chosen due
to its more-than-adequate industrial infrastructure . The area has a long mining tradition and is important
in industrial terms, encompassing a Repsol petrochemical complex and refinery and an ENDESA coal
power plant, as well as coal mines, the most important of which is the ENCASUR mine. The area is
linked to both to the electrical and natural gas national networks.
Puertollano is well communicated with road and train transport facilities, including the High Speed Train,
connection with Madrid and Seville.
Figure 3. View of Puertollano town
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2.2. GENERAL DESCRIPTION
The Puertollano IGCC plant uses the pressurized entrained flow gasification technology. The synthetic
gas obtained is cleaned and burnt as fuel in a combined cycle plant (gas and steam turbines). The synthetic
gas is a result of the reaction between a mix of coal and petroleum coke with oxygen at high temperatures
of up to 1600 ºC. The oxygen required for the gasification process is produced in an integrated Air
Separation Unit, which also produces also nitrogen for drying the pulverised coke, for fuel transportation
and for the safety inertization of the different circuits.
The synthetic gas obtained, which basically consists of CO and H2, is subsequently subjected to an
exhaustive cleaning process to eliminate the small parts of pollutants. The gas, free of pollutants, is
saturated and burnt, with a high efficiency level, in a combined cycle electricity-generating unit gas
turbine. The Combined Cycle Unit gas turbine is capable of operating with both synthetic and natural
gases. The gas turbine exhaust gases with residual heat are fed into a heat recovery boiler, producing
steam that is used together with the steam produced in the gasification process to generate additional
electricity in a conventional steam turbine with condensation cycle. The Plant's target energy efficiency is
45% in ISO conditions.
The design of the heat exchangers battery is particularly relevant in terms of efficiency, basically as
regards steam production and consumption, incorporating two heat recovery boilers, one for the crude gas
produced in the gasifier and the other for the turbine exhaust gases. Furthermore, the steam acts as a heat
conductor with for several uses in the coal preparation, gasification, desulphurization and air separation
processes.
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2.3. FUEL
2.3.1. GENERAL
The plant's basic fuel is coal from the local ENCASUR mines. The coal is mixed with petroleum coke
from the Puertollano REPSOL refinery. The project's technology allows the clean combustion of a coal
and coke feedstock with a normal weight proportion of 50:50.
The plant burns 700,000 tons of mixed fuel per year at full operational capacity. The coal is sub-
bituminous, high ash content (41.1%) hard coal, from the ENCASUR mine in Puertollano. The mine has
exploitable reserves of 60 million tons. The pet-coke, a by-product from the Repsol Puertollano refinery,
has a high sulphur content (5.5%).
Figure 4. Encasur coal mine
This plant's Combined Cycle can operate fuelled with natural gas. The plant needs natural gas for fuel
during gasification start up and shut down.
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2.3.2. FUEL DATA
Main parameters for the plant fuel components: coal , pet-coke and mix are shown in the table.
Coal Coke Mix
Humidity % 11.8 7.00 9.40
Ashes % 41.10 0.26 20.68
Carbon % 36.27 82.21 59.21
Hydrogen % 2.48 3.11 2.80
Nitrogen % 0.81 1.90 1.36
Oxygen % 6.62 0.02 3.32
Sulphur % 0.93 5.50 3.21
LHV (MJ/kg.) 13.10 31.99 22.55
HHV (MJ/kg.) 13.58 32.65 23.12
Table 1. Coal and pet-coke parameters (50% weight mix)
Composition of limestone used as additive is 95% CaCO3, 5% ashes. Grain size of limestone is less than
25 mm.
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2.4. PLANT SYSTEMS
2.4.1. GASIFICATION
2.4.1.1. General
The Puertollano IGCC Plant's gasification system is based on a process developed by Krupp Koppers.
This technology, which has been used previously at atmospheric pressure in chemical plants, has been
adapted for application to a combined cycle through the generation of coal gas under pressure.
The first step in the development of this technology consisted of a test programme that took place in the
Fürstenhausen pilot plant, with a gasification capacity of 50 t/day. The aim of the programme was to
determine the optimum performance conditions for the process. The tests were carried our with a 50%
weight mix of unwashed Puertollano coal and petroleum coke.
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2.4.1.2. Fuel Yard
Coal is delivered to the site from the ENCASUR mine, 18 km away. Petroleum coke comes from the
nearby (7 km) REPSOL refinery. Coal yard management is carried out according with production supply
analysis. Feedstock is delivered in trucks carrying loads of 25 ton. The unloading conveyors take the coal
or coke to the corresponding silo. The storage capacity is roughly 100 000 t, what represents 40 days
stock..
Feedstock 50% coal -50% petroleum coke
Mills capacity 120 - 140 t/h
Material fineness 5 mm < 60 % -90 % < 100 mm
Operation range 50% -100%
Table 2. Feedstock parameters
Figure 5. Fuel yard
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2.4.1.3. Coal Preparation
In the rest of this document, the mixture of coal and coke will be generically referred to as coal. The coal
is mixed with limestone in order to lower the ash melting point and milled in two grinding roller mills. It
is then fed into two drying circuits with hot gases, corresponding to the specified 2 % moisture for the
gasifier feeding in the coal preparation plant, producing a flow of about 28.5 kg/s. The energy supply for
mixture plant drying comes from a hot gas generator operating with natural gas and steam generated in the
gasification island.
This plant is designed for 7,200 hours of operation per year and reduces the size of the fuel mix by up to
50-60 micron, with a spread of 26%. The coal dust produced is separated from the inert gases in sleeve
filters and is stored in hoppers at atmospheric pressure.
Figure 6. Coal preparation plant
20
The table shows flow composition and heating value.
Flow composition and heating value
C 61.68% S total 3.34%
H 2.92 % Cl 0.02%
O 3.45% Ashes 25.17%
N 1.42% Water 2.00%
LHV 24,087 kJ/kg HHV 23,493 kJ/kg
Table 3. Coal preparation. Flow composition and heating value
Value Unit
Number of mills 2
Solid fuel input 2,600 t/day
Size of milled grain 50-60 micron
Output flow rate 28.5 kg/s
Type of filters sleeve
Table 4. Coal preparation parameters
2.4.1.4. Pressurization and feeding
The feed mixture is pressurized (to 30 bar) in a lockhoppers system and then conveyed to the gasifier.
Pure nitrogen is used both for pressurization and as carrier gas. A full cycle within the lockhoppers
consists of filling, pressurization, discharging and depressurization.
21
2.4.1.5. Gasification process
Design values at nominal capacity are:
Input:
2600 t/d feed (pulverised coal)
Oxygen (85 %) upon C/O
Medium pressure steam upon C/H2O ratio
Output:
180000 m3/h raw gas
230 t/h high pressure steam
23 t/h medium pressure steam
Table 5. Gasification process design values
Coal dust enters the gasifier through four burners set at 90º. The oxygen, at 85% purity, comes through a
separate line from the air separation unit (ASU) to the gasifier, where it is mixed with the steam produced
by the gasifier itself. The process is carried out at a pressure of 25 bar and at a temperature of 1200-
1600ºC. Most of the ash produced is removed from the bottom of the gasifier in liquid form. A small part
is entrained by the gas (fly ash).
Figure 7. Gasifier building
22
The fuel particles are heated with a high temperature gradient when leaving the burners. Volatile
components spontaneously become free and oxidise with the free oxygen in exothermic reactions, as
shown below:
C + 1/2 O2 = COC + O2 = CO2CO + 1/2 O2 = CO2H2 + 1/2 O2 = H2O
The temperature increases and the following endothermic reactions are produced:
C + H2 O = CO + H2C + CO2 = 2 CO
Methane is produced transitorily, subsequently reacting with water producing CO y H2 .
Gases resulting from the reaction between the coal and the gasifying agents are cooled immediately, with
recycled cool gas flow at a 235 ºC in order to reduce the temperature to 800 ºC, at which point ash
becomes solid. The limestone, used as additive, lowers the ash fusion point temperature.
The gas heat is recovered in a high pressure convection boiler, cooling it to 400 ºC and producing high
pressure (HP) steam (127 bar). This operation is produced in a 60 m. high vessel with a 5 m. diameter.
The gas moves to a second stage, cooling to 235 ºC generating intermediate pressure (IP) steam (35 bar)
in a second convection boiler. The steam produced (HP and IP), at saturation conditions, is sent to the
combined cycle heat recovery steam boiler. After being re-heated the gas expands in the steam turbine.
Raw gas production in normal operation is about 180,000 Nm3/h.
Value Unit
Gasifier vessel high 15 m
Gasifier vessel diameter 5.6 m
Mix Input flow rate 107 t/h
Number of burners 4
Oxygen flow 25.3 kg/s
Combustion chamber temperature 1600-1200 ºC
Combustion chamber pressure 25 bar
Table 6. Gasifier parameters
23
2.4.1.6. Ceramic filters
The gas, at 235 ºC, is filtered in two vessels through ceramic candle filters, where the fly ash is retained.
There are more than a thousand elements (candles) in each vessel where the entrained ashes are retained
and the gas dust content is reduced to 3 mg/Nm3. The use of ceramic filters for the dust reduction is
noticeably innovative in power plants. At the exit of the ceramic filters, a significant part of the gas,
containing less than 3 mg/Nm3, is compressed in a centrifugal quench gas compressor of 1,500 kW and
recirculated to the gasifier in order to obtain the desired cooling effect on the reaction gases.
To be able to operate at any load range, the compressor is equipped with a variable speed control.
2.4.1.7. Slag System
The slag leaves the gasifier in a liquefied state (temperature above melting point) and follows into a water
bath, where it is cooled and crashed. A slag crasher, located at the discharge point, reduces the grain size if
necessary.
The solidified slag is taken to a slag collector, then depressurized in a lockhopper system and discharged
with a conveyor belt. The slag water circuit includes filters for solids, allowing the water to be recycled.
2.4.1.8. Gas cleaning and desulphurization
Venturi scrubber:
The gas physical wash in the Venturi allows halides and other compounds (HCl, HF, NH3, and H2S) to be
removed. Neutralisation is performed using a NaOH solution. Through the entire range of operations, the
pressure lost in the Venturi is less than 600 mbar. The wash water is recycled from the gas/water separator
down stream from the Venturi scrubber.
Stripping:
The Venturi wash water goes to a stripper separator that allows the water to be treated separately: the
containing organic compounds are treated in the ozoniser, and acid gas (containing H2S and NH3) are
treated in the Claus plant (sulphur recovery plant). The pH is set by sulphuric acid and sodium hydroxide.
The halides content (Cl-) mainly depends on the feedstock composition.
24
The stripper consists of an acid column for separating CO2, H2S and HCN, and a basic column for
separating NH3.
Desulphurization:
The sulphur content of the gas is eliminated in an absorption column with MetilDiEtanolAmine (MDEA),
which selectively captures sulfhydric acid (H2S). To maximise sulphur retention, the carbonyl oxysulphur
(COS) is converted into H2S beforehand in a catalytic reactor.
The MDEA solution is regenerated at approx. 100 ºC in a stripper column, which separates the acid gas.
The complex salts enrichment of the MDEA solution, based on ionic interchange, is controlled by a
desalting unit.
Value Units
Flow rate (dry basis) 183,000 Nm3/h
Maximum sulphur content 25 mg/Nm3
Maximum solids content 3,263 mg/kg
LHV (Lower Heating Value) 10,000 kJ/kg
HHV (Higher Heating Value) 10,470 kJ/kg
Table 7. Clean gas specifications
Figure 8. Gas cleaning and desulphurization
25
2.4.1.9. Sulphur Recovery Unit
The acid gas is sent to the Claus oven and reactor within the Claus plant, for the conversion of H2S to
elementary sulphur. In addition, ammonia (NH3) and cyanide (HCN) are converted into elemental
nitrogen using a catalyst.
The tail gas, which contains sulphuric acid (H2SO4), is recycled and sent to the hydrogenation reactor,
avoiding the use of an incinerator.
The Claus plant is designed to produce zero emissions, in such a way that the queue gases, which
normally contain non converted sulphur, can be recyclable at the top of the desulphurization unit and
reprocessed, avoiding atmospheric sulphur emissions.
Due to the flexibility in the supply of the fuel required by the Plant, the Claus unit has been duplicated in
order to be able to operate with medium and high sulphur content coal. Thus production capacity is
approximately 70 t/day, corresponding to coal with a 4% sulphur content.
Figure 9. Gasification and gas cleaning process
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26
2.4.2. AIR SEPARATION UNIT
2.4.2.1. General
The air separation unit plant produces the oxygen required for gasification, with a 85% purity by volume.
This plant also produces two grades of nitrogen, one of 99.9% purity for inertization and the coal
preparation unit and another, of 98% purity, used to dilute of gas before it is burnt in the gas turbine
combustion chamber.
Figure 10. Air Separation Unit
2.4.2.2. Chilling and purification
The air flow, initially cooled in a cooling unit, carries substances that must be removed for technical and
safety reasons.
• Water and carbon dioxide, which solidify approximately 0 ºC and -130 ºC respectively at
atmospheric conditions. Since air separation is based on a cryogenic process and reaches
temperatures of below -170 ºC , these substances could cause piping blockage.
• Hydrocarbons, which, like oxygen, can give raise to potentially hazardous situations.
27
2.4.2.3. Distillation
The cold box is a counter-current heat exchanger where inlet air is cooled by column products (nitrogen
and oxygen). The distillation column operates at high pressure, which is proportional to the gas turbine
load, and produces rich gaseous nitrogen at the top and rich liquid oxygen at the bottom.
This unit is designed to follow load variations in the gasifier and combined cycle, supplying nitrogen and
oxygen with the specified degree of purity. The air separation products are then compressed at the
pressure required by the process, by means of electrically actuated compressors.
Liquid oxygen and nitrogen can be stored with their corresponding evaporators, as these gases are needed
during gasifier start up and shutdown. Oxygen supply capacity operating normally is approximately,
70,000 Nm3/h.
Value Unit
Gaseous Oxygen
Flow 70,000 Nm3/h
Purity 85 %
Pressure 31 bar
IP-Nitrogen
Flow 22,100 Nm3/h
Purity 99.9 %
Pressure 49 bar
LP-Nitrogen
Flow 8,150 Nm3/h
Purity 99.9 %
Pressure 4 bar
Waste Nitrogen
Flow 188,000 Nm3/h
Purity >98 %
Pressure 13 bar
Liquid flow 25 Nm3/h
Air flow 288,000 Nm3/h
Table 8. Air Separation Unit parameters
28
2.4.3. COMBINED CYCLE
2.4.3.1. General
The SIEMENS combined cycle selected for this plant uses the most advanced technology available in the
market at the contract date. In its entirety, the combined cycle plant can generate an output of 335 MWe
(ISO conditions). Taking into account the plant's internal energy consumption (air separation unit, cycle,
gasification, and auxiliaries) a total net output of 300 MW can be delivered to the electric grid.
2.4.3.2. Gas Turbine
Before combustion takes place in the Gas Turbine, the clean coal gas is subjected to a process of water
saturation in order to reduce nitrogen oxides (NOx) formation during combustion. The gas is subsequently
heated to a temperature of 260 ºC by water from the high pressure boiler and is finally mixed with residual
nitrogen from the air separation unit, which acts as an inert dilutant with the aim of reducing NOx
formation further during combustion. As a result of these two operations (saturation and dilution),
together with the use of low NOx burners, contamination levels of less than 60 mg/Nm3 should be
obtained when 15% O2 is used.
The turbine at Puertollano is V94.3 Siemens model. This turbine has two external hopper combustion
chambers, which can burn natural gas and coal gas, individually or in mixtures maintaining high
performance level in terms of rate, efficiency and pollution. The gas turbine's gross output in ISO
conditions is 200 MW.
Figure 11. Gas Turbine
29
The 17 stages compressor reaches a compression ratio of 15.6:1. The stationary blades of the first four
stages have variable inlet guide vanes. During part-load operations, these vanes are closed so as to reduce
the compressor air mass flow down to about 80% of the base load value, which results in a constant
turbine exhaust temperature down to about 65% load. This control allows maintaining high efficiencies
for the combined cycle, even at part load.
Each combustion chamber is equipped with 8 burners able to burn natural gas and coal gas,
independently. When the turbine runs with natural gas there is no possibility, previously to its combustion,
to saturate the gas or to mix it with nitrogen in order to reduce NOx formation. Therefore, IP steam from
the HRSG is directly injected inside the combustion chambers to control NOx formation. The firing
temperature is of 1250 ºC.
Figure 12. Gas Turbine VT 94.3 with internals
30
2.4.3.3. Heat recovery steam generator
The heat from the gas turbine exhaust gases (535 ºC) is largely recovered in the heat recovery steam
generator, producing water steam at three pressure levels (127/35/6.5 bar).
Furthermore, this boiler re-heats its own steam, as well as the steam from the gasification island. Its
efficiency level is therefore higher than those of conventional boilers with 1 or 2 pressure levels. The
exhaust gases are cooled to a temperature of approximately 105 ºC in this boiler.
Figure 13. Heat recovery boiler and gas saturator buildings
31
2.4.3.4. Steam Turbine
The steam generated in the heat recovery boiler is sent to the steam turbine. The steam turbine is of two
stages, single shat design. In the first stage, inlet steam at approximately 122 bar and 506 ºC is expanded
in the high and intermediate pressure stages. In the second stage, the low pressure steam is expanded by
means of a double flow turbine.
Figure 14. Steam Turbine
The expanded steam in the high pressure turbine stage is re-heated along with the intermediate pressure
steam from the heat recovery boiler, before being sent to the intermediate pressure turbine stage,
optimising the process. The steam turbine's gross output in ISO conditions is 135 MW.
The exhaust steam in the low pressure turbine stage is condensed in vacuum conditions at about 40 ºC,
using cooling water in a closed circuit. The surface condenser has a double flow box, with water boxes on
each side. The condensate produced is sent back to the recovery boiler by means of the condensate pump.
32
Figure 15. Energy balance of the plant
33
2.4.4. INTEGRATION SYSTEM
The Puertollano IGCC plant is designed using a full integration concept., which means:
· Air to air separation unit fed from the gas turbine compressor.
· Optimal use of all energy levels in the heat exchanger network.
· The waste nitrogen produced in the air separation unit is sent to the gas turbine.
· Feed water is sent to the gasification island from the combined cycle and the generated steam is
exported to the combined cycle.
Air:
The air fed to the air separation unit is fed from the gas turbine compressor at 14 bar and 400 ºC at full
load.
In keeping with the air separation unit's temperature requirements (less than 127 ºC), the air is cooled in
the following heat exchangers:
- Waste nitrogen pre-heater.
- Two air coolers, where water circulating the flash tank is heated. This stream is used to supply the
required heat to the saturator water.
Waste nitrogen, O2 and pure N2:
Waste nitrogen (2 % O2) produced in the air separation unit is pre-heated at 360 ºC with the extracted air
and mixed with the saturated clean gas. This allows NOx formation to be reduced during the combustion
and improves the gas turbine power output, due to the higher expanded mass flow.
Clean gas:
Clean gas is saturated with steam before the combustion, to reduce the formation of NOx. It is then pre-
heated to approximately. 260 ºC with feed water and mixed with the waste nitrogen from the air
separation unit.
34
Water steam:
The combined cycle and gasification island water/steam system are fully integrated. The gasification
island feedwater comes from the combined cycle, and the steam produced in the gasifier waste heat boiler
is exported to the combined cycle drums, to be superheated and then expanded in the steam turbine. Part
of the steam produced in the gasifier is used for the internal consumption.
Figure 16. Outline of the IGCC plant's main system's interfaces
HRSGSteam Turbine Generator
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Coal Preparation
Gasifier Gas cleanning Gas Saturation Gas Turbine Generator
Sulphur recovery
Efluent treatment
Air Cooling
Air Separation
Unit
Demineralized water
Exhaust Gases
Steam Steam Condensates
Steam
Nitrogem Oxygen
Air
Waste Nitrogen
Water
LP Steam
Sulphur Dry sludge
Coal Petcoke
Slag
Electricity
Electricity
Air
Exhaust Gses
Fly Ashes
Raw Gas Clean Gas Satur. Gas
Desulphuration
Effluent
35
2.4.5. AUXILIARY AND SERVICE SYSTEMS
Besides the three main islands, the Puertollano plant is equipped with many auxiliary and service systems
that facilitate correct operation.
2.4.5.1. Cooling system
The cycle condenser is cooled by means of a wet cooling tower system. The circulation system cools two
open circuits, one for the gasification and air separation and the other for the combined cycle equipment.
The cooling tower is 122 m. high and is cooled with water from the raw water storage system. Make up
system consumption is about 500 m3/h, to compensate for the effects of evaporation and concentration.
The pumping station consists of two semi-axial flow pumps, with a capacity of 60% of the circulating
water nominal flow each.
A yearly supply of approximately 6 hm3 of clean raw water is required. This water is taken from the
Jándula river, through the artificial Montoro lake in the Guadalquivir basin.
Figure 17. Cooling tower
36
2.4.5.2. Auxiliary boilers
There are two auxiliary steam generators, which operate with natural gas, for the purpose of supplying
low and intermediate pressure steam to the plant systems. Auxiliary steam is mainly used during
combined cycle and gasification island start-up (systems preheating) and shut-down (purging) operations.
Boiler Flow rate and pressure
IP auxiliary steam boiler: 11 kg/s, 36 bar and steam lamination at 6.5 bar.
LP auxiliary steam boiler: 2.5 kg/s, 6.5 bar.
Table 9. Auxiliary boilers parameters
2.4.5.3. Flare
The coal gas produced in the gasifier during the start-up and the gases purged during plant shut-down are
burnt in the flare. The flare system is designed for 100 % coal gas production. To assure complete gas
combustion, which may have a low calorific value, natural gas is added in the flare. To increase the safety
of the flare, a redundant ignition system, operated with independent propane gas, was added during the
commissioning phase.
Figure 18. Flare
37
2.4.5.4. Emergency Diesel generator
In the case of a power cut, a back-up 2400 kW Diesel generator is connected to the 400 V line to provide
electric power to the equipment that is essential for plant safety. This essential equipment includes the
gasifier's circulating pumps and the slag cooling system.
2.4.5.5. Water Treatment
The IGCC plant includes an ozoniser to prepare the stripper water for the end effluent conditions (cyanide
content below 0.2 mg/l), before disposing of it in the Ojailén river.
The water treatment plant involves the following operations: stripper, effluent ozoniser and
homogenisation deposit.
2.4.5.6. Other service and auxiliary plant systems
The plant is also integrated by the following auxiliary and service systems:
• natural gas station
• raw water supply
• demineralised water plant
• auxiliary cooling system
• heating, ventilation and air conditioning
• compressed air
• fire fighting system
• waste water treatment plant
• cooling water conditioning plant
• others
38
2.4.6. ELECTRIC SYSTEMS
2.4.6.1. General
The electric plant systems include the systems, equipment, components and connections required to
supply electricity to the grid when the combined cycle is operating, and to supply electrical energy to the
plant's auxiliary systems when the plant is in shutdown or during starts.
The electric system includes the following equipment and systems:
• 230 MVA electric generators for both gas and steam turbines.
• High voltage system, including the 220 kV bars, the generation breaker and the 234/15/75 kV main
transformers. Two connection lines to the 220 kV grid.
• 45 kV emergency system.
• Intermediate voltage system, including the 15.75 kV/6kV bars for auxiliary equipment and the 10.5
kV bar for feeding the air and nitrogen compressor.
• 400/230 V low voltage system.
• 400 V 1200 kW emergency diesel generator.
• Uninterrupted power supply system.
• 125/24 V DC system.
Figure 19. Main transformer and substation
39
2.4.6.2. Generators
The twin shaft design consists of a gas turbine generator (nominal power 230 MWA) and a steam turbine
generator (nominal power 230 MWA) both connected to main transformers by the corresponding
breakers.
Both machines are bipolar, with a direct air cooling system for rotor wiring and an indirect system for
stator wiring. The rotor bearings are lubricated by the corresponding turbine oil system. Generators are
provided with protection devices to account for fault to earth, under-excitation, over-current, over-voltage,
unbalanced load, under-frequency and power inversion. The gas turbine generator is equipped with a
static frequency converter, which allows to drive the generator during gas turbine run-up and other
operations. This converter is fed from the 6kV system.
Transformers Name Power MVA Transformation relation
1 BAT 10 Main transformer TG 216 234±10% / 15.75 kV
2BAT 10 Main transformer T. 176 234±10% / 15.75 kV
1BBT 10 Auxiliary transformer 24/16-16 15.75±10% / 6.3-6.3 kV
2BBT 10 Auxiliary transformer 24/16-16 15.75±10% / 6.3-6.3 kV
BDT 10 Support transformer 24/16-16 45±10% / 6.3-6.3 kV
1BBT 20 Transf. compr. Air-N2 40 15.75±10% / 10.5 kV
Table 10. Electric transformers parameters
40
2.4.7. CONTROL SYSTEM
2.4.7.1. General
The Puertollano IGCC plant is equipped with a Siemens Teleperm XP distributed control system. This
system has a modular structure and consists of the following subsystems:
• An automatic system for automatic function implementation at the lowest control level.
• A communications network.
• An operation control and monitoring system for operation processes and information interchange.
• An engineering system for planning, configuration and start up.
Figure 20. Plant control room2.4.7.2. Control levels
This system's automation and control levels are as follows:
Field level: The lowest level where sensors are located and data is withdrawn. Its function is to receive
signals from sensors and to transmit them to the higher levels or the actuators.
Automation level: Individual control level: Basic control of operations with analogue and binary signals.
Actuators control in open loop and individual control in closed loop.
• Group control level: Automatic functions such as closed loop regulations, open loop control and signal
protection management.
Process level: Storage of process data and transfer of the dynamic information to the man-machine
interface.
Operation and control level: Association of the man-machine interface with the interaction supervision
and configuration systems.
41
2.4.9. PLANT FUNCTIONAL BASIC OUTLINE
The Puertollano IGCC Plant functional basic outline is shown next.
Figure 21. Simplified flow diagram of the Puertollano Plant
42
2.4.10. SUMMARY OF BASIC TECHNICAL DATA
Technology. Pressurized Entrained Flow (Prenflo by Krupp Koppers) Gasification process integrated
with SIEMENS (KWU V94.3) Combined Cycle
Fuel. Coal and petroleum coke 50% in weight
Coal Pet-coke Mix
LHV (MJ/kg) 13.10 31.99 22.55
HHV (MJ/kg) 13.58 32.65 23.12
Output (MW)
Gas Turbine Steam Turbine Raw
Site Conditions 182.3 135.4 317.7
ISO Conditions 200 135 335
Consumption
Per year Per hour
Fuel 700,000 t/year 107,000 kg/h
Limestone 24,000 t/year 3,700 kg/h
Raw water 5 hm3/year 720 m3/h
Gross Efficiency (LHV)
Value
Thermal rate 47.12%
Specific consumption 1,825 te/MWh
Emissions (6% O2)
(Design values) t/year g/kWh mg/Nm3
SO2 138 0.07 25
NOx 826 0.40 150
Particles 41 0.02 7.5
Solid by-products: 625 t/day of vitrified and inert slag and fly ash.
Table 11. Basic technical data
43
2.5. TECHNOLOGICAL VALUE AND INNOVATION
The technological value of the ELCOGAS Project is based on two key points: technological innovation,
that might allow to design a second generation plant using this technology and the acquisition of specific
know-how in IGCC projects.
Provided that the IGCC plants incorporate systems that can be used in other production processes
(gasification, filtration, desulphurization, heat recovery boilers ...), the technology incorporated and
developed by ELCOGAS becomes versatile regarding its industrial applications.
2.5.1. TECHNOLOGICAL INNOVATION
The following points constitute technological innovation in the IGCC plant:
• Utilisation for the first time of equipment, materials and processes (specially in gasification).
• World reference point in scaling IGCC technology of European origin.
• Vital experience for reducing costs in future projects.
2.5.2. ACQUISITION OF SPECIFIC “KNOW-HOW”
The following points constitute the acquisition of specific “know-how” in IGCC projects:
• Experience of managing highly complex projects:
• Role of the plant architect-engineer.
• Interface co-ordination.
• Quality Control.
• Construction and Start-Up Management.
• Experience of operating a commercial size IGCC plant:
• Operating procedures.
• Training.
• Elaboration of “performance tests”.
• Adaptation and prediction control.
• Development of advanced technology:
• Gasifier and burners.
44
• Adaptive/preventive control
• Ceramic Filters and ionic exchanger.
• Queue and Quench Gas Compressors.
• Gas Turbine.
• Distributed Control.
• Experience in manufacturing and assembling complex equipment:
• New materials.
• "In situ" gasifier assembly.
• Steam Turbine with high and intermediate pressure stages.
In terms of technological innovation, the construction of an IGCC plant with technological characteristics
that differ from those used elsewhere has involved a significant investment in R&D in Spain, which has
had a positive effect as regards industrial and energy development. The most significant differences are:
• Largest scale equipment in the world:
• Gasifier. Krupp Koppers high pressure entrained flow. (2500 t/day).
• Air Separation Unit. High pressure supply of O2 and N2.
• Gas Turbine. Siemens V94.3 with dual gas burners.
• New generation technology to reduce emissions:
• Ceramic Candle Filters.
• Tail gas recycling compressor.
• Heat recovery boiler with three levels of steam pressure.
• Gas quenching by means of recirculation with quench compressor.
• Integration of all elements:
• Residual Nitrogen Compressor with gasifier and combined cycle.
• Gas Turbine Compressor feeding the Air Separation Unit.
• Distributed Control System from a development stage.
• Adaptive/predictive control o certain functions.
45
2.6. ENVIRONMENTAL CONSIDERATIONS
2.6.1. GENERAL
Legislation for environmental protection is becoming more and more demanding every day. It is very
important for an electric utility to anticipate the evolution of this legislation and to master the new
technologies that provide a greater protection for our environment.
The Puertollano IGCC plant is demonstrating that it is possible to burn poor quality coal, with an ash
content of more than 40% and refinery by-products with sulphur content of over 5%, such as petroleum
coke, with a very small environmental impact.
• NOx emissions are reduced saturating coal gas with water and mixing it with residual nitrogen before
burning, resulting in a lower flame temperature.
• SO2 emissions are reduced by more than 99%, thanks to coal gas desulphurization. The sulphur is
separated as elementary sulphur, and forms no part of the plant's solid waste.
• At a temperature of about 1400 ºC, slag flows from the bottom of the gasifier vessel and is rapidly
cooled with water, forming a vitrified substance that encapsulates heavy metals in a non-soluble form.
Fly ash entrained by the gas is separated and recovered as a by-product, already used in the cement
preparation.
• CO2 emissions are reduced, due to a higher thermal efficiency, down to a 85% of the CO2 emissions
in a modern conventional plant.
The plant also offers other environmental advantages, such as the higher level of water consumption
efficiency and the recovery of slag in vitrified form, which has multiple industrial applications.
In addition to the environmental advantages, the plant is highly flexible in terms of the fuels it can use
(natural gas, domestic coals and refinery by-products) attaining efficiency rates using resources
compatible with the present combined cycles (when operating with natural gas) and performing better
regarding efficiency than clean coal technologies in sub-critical conditions.
46
Figure 22. Puertollano IGCC Plant
47
2.6.2. COMPARISON OF EMISSIONS FROM DIFFERENT TECHNOLOGIES TYPES
Table 12 shows atmospheric emissions from the following technology types: (1) pulverised coal with no
gas cleaning process, (2) the same plant with desulphurization system (90%), low level NOx (50%)
burners and electrostatic precipitators (99,2%), (3) ACFBC with cyclone filters (96%) and (4) Puertollano
IGCC Plant. They are all compared to the limits established by Community Directive 88/609.
In order to establish a homogenous comparison basis the same standard fuel has been considered, with a
content of 3.2% sulphur, 20.68% ashes and 23.12 MJ/kg (the Puertollano design fuel), with a gross output
of 320 MWe. The emissions measured in mg/Nm3 refer to a dry composition with 6% oxygen. For the
fluidised bed plant, the SO2 emissions have a dependence on the Ca/S rate in the bed.
Base: 320 MWe, 6% O2 , η = 37.5 HHV for ABFC & PC plants SO2
(mg/Nm3)
NOx
(mg/Nm3)
Particles
(mg/Nm3)
(1) Pulverised Coal without cleaning process 7300 1300 > 10000
(2) Pulverised Coal DeSOx(90%)/LNB(50%)ESP(99,2%) 730 650 100
(3) AFBC + cyclone filters (96% effic.) 200-400 170-230 30-50
(4) Puertollano IGCC 25 150 7.5
Limits of emissions (88/609/EEC)1 400 650 501 This directive does not apply to gas turbine plants.
Table 12. Comparison of emissions between coal technology types
NOx (mg/Nm3)
650
150
0100200300400500600700800
SO2 (mg/Nm3)
400
25
0
100
200
300
400
500
Part. (mg/Nm3)
50
7,5
0
10
20
30
40
50
60
Figure 23. EU emission limits and IGCC plant design emissions
48
For comparison purposes, conventional plants and AFBC plants have been considered to have an
efficiency level of 37,5% (HHV). The value has been estimated on the basis of EPA data [3] which
contains a representative sample for plants of each technology type.
Base: 320 MWe, 6% O2 , η = 37.5 HHV for ABFC & PC plants SO2
(g/kWh)
NOx
(g/kWh)
Particles
(g/kWh)
(1) Pulverised coal without cleaning process 25.3 4.5 > 40
(2) Pulverised coal DeSOx(90%)/LNB(50%)ESP(99,2%) 2.5 2.3 0.34
(3) AFBC + cyclonic filters (96% effic,) 1.5 0.80 0.10
(4) Puertollano IGCC 0.066 0.397 0.020
Table 13. Comparison of emissions (g/kWh) between coal technology types. Output 320 MW
The following graphs show a comparison between EU directive emission limits and the Puertollano IGCC
Plant's forecasted emissions.
Figure 24. Comparison of emissions between different technology types
49
3. ELCOGAS AND THE PROJECT’S ORGANIZATION
3.1. THE ELCOGAS COMPANY
The ELCOGAS Company was founded on April, 8th 1992, as a mercantile Company subject to Spanish
legislation, with the objective of the construction and exploitation of the Puertollano IGCC Plant.
The founding members were six European electrical companies: Endesa, Iberdrola, Sevillana and
Hidrocantábrico from Spain, EDF from France and EDP from Portugal. New European members were
later incorporated to the Project, namely the electrical companies National Power from Great Britain and
ENEL from Italy, along with the main combined cycle and gasification plant suppliers, Krupp Koppers
and Siemens from Germany, in association with Babcock Wilcox Española, from Spain as manufacturer,.
The current members, (including Sevillana in the Endesa Group), and their percentage of shares in the
ELCOGAS company capital are as follows:
COMPANY % of share
ENDESA 37.93%
EDF 29.13%
IBERDROLA 11.10%
HIDROCANTABRICO 4.00%
EDP 4.00%
ENEL 4.00%
NATIONAL POWER 4.00%
BABCOCK WILCOX ESPAÑOLA 2.50%
SIEMENS 2.34%
KRUPP KOPPERS 1.00%
Table 14. ELCOGAS capital share
The capital share is shown graphically in the following figure.
50
Figure 25. ELCOGAS capital share
IBERDROLA
EDF
ENDESA
HIDROCANTÁBRICO
KRUPP KOPPERS
NATIONAL POW ER
ENEL
EDP
BABCOCK W ILCOX SIEM ENS
51
3.2. ORGANIZATION
3.2.1. GENERAL
The ELCOGAS company's basic organization for the commercial phase is structured in three managerial
areas, reporting to the Chief Executive Officer, as shown in the following chart:
Figure 26. ELCOGAS Basic organization chart(*) With EEC participation.
As at November, 2000, ELCOGAS has a staff of 157 employees.
CHIEF EXECUTIVE OFFICER
OPERATION DIRECTION ADMINISTRATION & FINANCE DIRECTION COMMERCIAL DIRECTION
ELCOGAS BOARD
FOLLOW-UP COMMITTEEFINANCIAL COMMITTEE
DEPUTY CHIEF EXECUTIVE OFFICEROPERATION COMMITTEE *
52
3.2.2. PROJECT MANAGEMENT AND SUPERVISION
The project's management and supervision was organized and established in Madrid and Puertollano. A
Steering Committee has existed since the initial phase of the project, with the participation of
representatives of the ELCOGAS members and the European Community Commission. The Steering
Committee established the project's technical guidelines and supervised its development and progress.
Additionally, a Project Follow up Committee, including the participation of local authorities, was
established and still meets regularly. The ELCOGAS general organization flowchart for the last phases of
the project and plant construction until late 1997 is shown in the figure.
Figure 27. ELCOGAS Project organization chart
CHIEF EXECUTIVE OFFICER
CONSTRUCTION MANAGER
OPERATION MANAGER FINANCE MANAGER
BOARD
STEERING COMMITTEE
ENGINEERING
CIVIL WORK & ASSEMBLY
COMMISSIONING
QUALITY ASSURANCE
PROCUREMENT
SCHEDULING & COST CONTROL
CIVIL WORK
COMBINED CYCLE
GASIFICATION & ASU
BALANCE OF PLANT
I6C
GENERAL SERVICES & SECURITYIINTEGRATION &
OPTIMIZATION
53
3.2.3. OUTLINE OF PROJECT CONTRACTS
In accordance with a project work breakdown structure, ELCOGAS distributed certain project functions
related to the basic engineering of the plant, the engineering and supply of basic systems and equipment,
the supply of balance of plant equipment, construction and assembly, etc., among different organizations
specialised in the areas in question. This distribution of responsibilities is shown by the different contracts
between ELCOGAS and these organizations.
Figure 28. Project Interfaces and Contracts
The distribution of activities in the corresponding contracts and the final status of the contracts are
described next.
ELCOGAS
OWNERS
EU COMMISSION
OCICARBÓN
CENTRAL ADMIINSTRATION
REGIONAL ADMINISTRATION
LOCAL ADMINISTRATION
GASIFICATION SUPPLIER
COMBINED CYCLE SUPPLIER
AIR SEPARATION UNIT SUPPLIER
DCS SUPPLIER
BALANCE OF PLANT SUPPLIERS
COORDINATION AND BALANCE OF PLANT ENGINEERING
SUBCONTRACTED ENGINEERING
SITE CONTRACTORS
CONSULTANTSELCOGAS BOARD
54
3.2.3.1. GENERAL AND BALANCE OF PLANT ENGINEERING
The general and balance of plant systems engineering services were awarded at the end of July 1992 to the
Spanish engineering company, INITEC, and to Electricidade de Portugal.
INITEC subcontracted and/or co-ordinated the following areas of plant engineering:
- Civil Engineering, with Electricidade de Portugal (EDP).
- Control and Instrumentation engineering, with Electricité de France (EDF).
- Water Circulation systems engineering, with Electricité de France (EDF).
- Detail electric engineering, with Empresarios Agrupados (EA).
INITEC was responsible for the co-ordination of the entire engineering effort and was the direct contact
for the project.
Certain specialised engineering and studies activities (environmental, geo-technical, risk analysis,
security, etc.) were contracted out to specialised organizations.
55
3.2.3.2. MAIN SUPPLIES
3.2.3.2.1. Gasification System
The contract for engineering, manufacturing and equipment supply, materials and services related to the
coal gasification system was awarded, at the end of July 1992, to the consortium formed by Krupp
Koppers, with experience in plants using this type of technology, and Babcock Wilcox Española, a
Spanish power equipment supplier. The contract's scope of supply included:
- Fuel preparation system.
- Gasifier reactor, together with heat recovering units, gas cleaning system and other auxiliaries.
- Gas treatment system.
- Claus unit for sulphur separation.
The system supplier also dealt with its assembly in the plant and supervised star-up se services.
3.2.3.2.2. Air Separation Unit
The contract for engineering, manufacturing, equipment supply, materials and services and the assembly
activities related to with the air separation unit, required for oxygen supply to the gasifier, was awarded in
February 1993 to Air Liquide, a specialised supplier to plants of this type.
3.2.3.2.3. Combined Cycle
The contract for engineering, manufacturing and equipment supply, materials and services contract
related to the combined cycle unit with gas and steam turbines, arranged with separated shafts, was
awarded, at the end of July 1992, to the joint venture formed by Siemens AG, with experience in units
using this type of technology, and Babcock Wilcox Española, Spanish power equipment supplier. The
contract's scope of supply includes:
- BWE Scope of Supply
- Heat recovery steam generator and GT flue gas duct
- Piping system water/steam cycle
- Condenser
- Siemens Scope of Supply
- Gas turboset V94.3 (GT)
- Steam turboset KN (ST)
- Instrumentation and control for turbosets
- Turbine house cranes (GT + ST)
- Heat exchangers (cooling air cooler, saturator water and clean gas preheater)
56
- Saturator system for clean gas
- Electrical equipment
Overall plant control system
The supplier of the combined cycle also dealt with its assembly in the plant and supervised start-up
services.
3.2.3.2.4. Distributed Control System
The contract for engineering, manufacturing and supply of the Distributed Control System (DCS) and
services related to the assembly and start up of this system was awarded in December 1994 to the joint
venture formed by Siemens AG, Scape, Disel y Sainco.
57
3.2.3.3. SUPPLY OF BALANCE OF PLANT EQUIPMENT
3.2.3.3.1. Equipment Supply
The contracts for the remaining plant systems, equipment, components and materials were awarded to
appropriate suppliers.
Contracts packages in this area for significant units and systems are the following:
SUBJECT
Demineralised Water Plant
Distributed Control Systems (DCS)
Fuel handling plant
Fire protection system
Ventilating and Air conditioning system
Plant telephone & megaphone systems.
Plant lighting
Natural Gas Station
Plant lighting
Waste Water Treatment Plant
Slag Removal Plant
Solidification Sulphur Plant
Table 15. Equipment Suppliers
The balance of plant equipment included:
- Piping
- Miscellaneous Valves
- Control Valves
- Coal and limestone hoppers
- Tanks
- Cranes
- Lifts
- Water Circulation Pumps
- Miscellaneous pumps
- Heat Exchangers
- Air Compressors and Dryers
58
- Auxiliary Boilers IP and MP
- 45 kV Site Line and Substation
- Site Electrical ring and transformers
- Machine Breaker
- Main, back up and auxiliary Transformers
- Isolated Phase Bars
- Substation 220 kV structures
- Substation 220 kV equipment
- Electric cabinets
- Medium and low voltage electric motors control cabinets
- Medium and low voltage electric motors, motor booster for gas turbine, synchronous motor
for ASU.
- Cable trays and supports. Conduits.
- Electrical and instrumentation Cables
- Batteries and chargers
- UPS units
- Emergency Electric Generator
- Dynamic Simulator
- Instruments
- Cooling Water Treatment Plant
- Lightning-conductors
- Gas emission Control System
- Nitrogen buffer
- Water laboratory equipment
- Electrical laboratory equipment
- Instrumentation laboratory equipment
- Coal and coke mixer
- Insulation for Air Separation Plant
- Fuel Weight System
- Nitrogen vent
59
3.2.3.3.2. Complementary services
• Equipment Supply Expediting Services
• Special Transport Services
Figure 29. Transport of the gas turbine
• Insurance
The Insurance Policy for the Plant, covering the construction and operation periods, was taken out with a
consortium of Insurance companies.
60
3.2.3.4. CONSTRUCTION. CIVIL WORK AND EQUIPMENT ASSEMBLY
The construction work was supervised by ELCOGAS and was carried out in several stages.
3.2.3.4.1. Civil Work
The civil construction package contracts for buildings, outside structures, etc., were awarded to various
construction contractors specialised in power plants. The following are the main construction contract
packages:
SUBJECT
Site preparation
Combined Cycle Buildings and Structures.
Cooling Tower and Cooling Water System
Gasification area foundation.
Gasification Plant, Fuel Handling Plant and Effluent Treatment Plant
Air Separation Unit and balance of gasification
Administration Building, Workshop and Water Treatment Plant
Raw Water Supply. Pumping system and ducts
Roads connecting with the coal mine
Cooling Water treatment plant
Miscellaneous Civil Works
Table 16. Civil work contractors
ELCOGAS shared with other industrial companies of the area the construction of the aqueduct Jándula-
Montoro for the supply of water to the Puertollano area, including water supply for the plant.
Figure 30. Civil construction work on the plant
61
3.2.3.4.2. Mechanical Assembly, Electrical and I&C Installation
The mechanical, electrical, instrumentation and control systems and equipment assembly was carried out
over several stages and contracted out to various specialised companies. The assembly was supervised by
ELCOGAS. The main gasification equipment, the combined cycle and the air separation unit assembly
was further supervised by the relevant main suppliers. The main assembly contract packages for the plant
are listed below:
SUBJECT
Mechanical Assembly for the Combined Cycle and Auxiliary Systems
Construction of Heavy equipment (Gasifier, Heat Recovery Boiler)..
Assembly of steel structure Coal Preparation Building
Mechanical Assembly of BOP equipment phase I.
Mechanical Assembly of equipment in gasification area
Mechanical Assembly of equipment: Sulphur Recovery, Recycle Gas
Compressor, N2/O2 Systems, Fly Ash Discharge and Slag Water Filter
Electrical Assembly for the Combined Cycle and Auxiliary Systems
I&C equipment Assembly for the Combined Cycle and Auxiliary Systems
Insulation of equipment and piping for the Combined Cycle
Painting for Combined Cycle.
Mechanical Assembly of BOP equipment phase II.
Instrumentation and electrical assembly for the gasification island
Insulation of equipment and piping for the Gasification island.
Painting for Gasification Island.
Gasification plant electrical tracing.
BOP and ASU electrical tracing
Table 17. Mechanical Assembly, Electrical and I&C Installation Contract packages
62
Figure 31. Assembly of the gasifier
63
3.2.3.4.3. Main Work Units
Main work units performed at the site until the end of July 1998 were the following:
Concept Work units
Site preparation
Excavation 864,187 m3
Terracing 641,143 m3
Drain system
Piping (concrete) 10,776 m
Wells 324
Services
Piping 9,460 m
Wells (waste and registers) 178
Roads and walks
Asphalt coating 45,061 m2
Road banks 13,388 m
Sums 349
Structural
Reinforcing Steel 7,480 t
Concrete 97,040 m3
Building structures 8.478 t
Process Piping
Piping 3,425 t
Electrical cable
Installation 1,135,448 m
Connections 259,184
General
Man hours accumulated in construction 6,449,673
Table 18. Main site work units
64
3.2.3.5. QUALITY PLAN INSPECTION AGENCIES
The necessary inspection services to ensure the quality level required for the equipment manufacturing,
civil construction and site equipment assembly were contracted with specialised agencies.
3.2.3.6. OPERATION TRAINING
Training services for the operation of the combined cycle, gasification and air separation systems are
included in the contracts for the supply of the corresponding equipment. Other specific training courses
have been contracted as required with specialised contractors and suppliers.
3.2.3.7. FUEL SUPPLY
Contract for the supply of coal
ELCOGAS had an agreement with ENCASUR, the mining company owning the main Puertollano coal
mines, for the supply of the coal. In March 1998, ELCOGAS signed a contract with Encasur for the
supply of coal from local mines for twelve years.
Contract for the supply of petroleum coke
ELCOGAS has a contract with Repsol, petrol and chemical company with important refinery and
chemical plants in Puertollano, for the supply of the petroleum coke from the Puertollano refinery for a
period of 6 years, renewable to 12.
Contract for the supply of natural gas
ELCOGAS has a contract with ENAGAS, the Spanish gas operator, for the supply of natural gas required
for the plant operation.
65
3.3. PROJECT DEVELOPMENT
3.3.1. GENERAL
Project activities developed as shown in the following chart:
Figure 32. Project schedule
Puertollano IGCC project activities were complete when the first gasification process was achieved and
the first synthetic gas was produced. This event that took place on December 19th, 1997, ten months after
the date planned at the Project start. Delays were mainly due to design changes in the gasification area and
delays in delivery of engineering documentation and some gasification equipment.
PUERTOLLANO IGCC PROJECT BASIC PLAN
ACTIVITY JuAgSeOcNoDicEnFe MaAbMaJu Ju AgSeOcNoDicEnFe MaAbMaJu Ju AgSeOcNoDicEnFe MaAbMaJu Ju AgSeOcNoDicEnFe MaAbMaJu Ju AgSeOcNoDicEnFe MaAbMaJu Ju AgSeOcNoD
AWARD OF MAIN EQUIPMENT & ENGINEERING
ENGINEERING AND DESIGN
SITE PREPARATION
GASIFICATION PLANT MANUFACTURING AND SUPPLY
COMBINED CYCLE MANUFACTURING AND SUPPLY
CIVIL WORK
COMBINED CYCLE ERECTION AND START UP
COMBINED CYCLE 100 H. PERFORMANCE TEST
GASIFICATION ERECTION
19971992 1993 1994 1995 1996
��
66
The project percentage progress curve up to December 1997, the date of the end of the project, is shown in
the graph.
Figure 33. The Puertollano IGCC Plant Project Progress
Following the start-up activities, the first gas turbine switch-over from natural gas to synthetic gas was
carried out successfully on 20th March 1998. After this test, modifications and adjustments were made to
the system in order to improve the IGCC operation of the plant, particularly in the gasification area:
- coal preparation, coal and petcoke mixing, milling and conveying.
-
PROGRESS OF THE PROJECT
0
20
40
60
80
100
120
ene-
92
abr-9
2
jul-9
2
oct-9
2
ene-
93
abr-9
3
jul-9
3
oct-9
3
ene-
94
abr-9
4
jul-9
4
oct-9
4
ene-
95
abr-9
5
jul-9
5
oct-9
5
ene-
96
abr-9
6
jul-9
6
oct-9
6
ene-
97
abr-9
7
jul-9
7
oct-9
7
dic-
97
Prog
ress
%
Construction Start
TG Synchronization First Syngas
67
3.3.2. BASIC PROJECT DATES
The basic dates in the development of the Puertollano IGCC Power Plant project are as follows:
• The ELCOGAS company for the construction and exploitation of the plant was incorporated in
April 1992.
• Project activities started with the award of the contracts for the supply of main equipment and for
the engineering in July 1992.
• Construction of the plant at the Puertollano site started in April 1993.
• Gas Turbine was delivered in October 1994
• The DCS was energised in September 1995
• The Combined cycle start up with burning natural gas occurred in September 1996.
• First ignition in the gasifier was achieved in December 1997.
• The performance test of the gasification with synthetic gas from local coal and pet-coke was carried
out in March 1998.
• First operation of the gas turbine with coal gas and, in consequence, integrated operation of the
combined cycle, air separation unit and gasification was achieved in March 1998. The period
between first ignition in the gasifier and the first coal gas operation in the gas turbine was three
months. In September 1998, 98% of the nominal output of the plant with gasification was reached.
68
3.3.3. PROJECT BUDGET AND FINANCING
3.3.3.1. Project Budget
Project Budget in constant currency of October 1991, date of the initial Project Budget, discounting the
amounts with the rate of variation of the Consumer Price Indexes in Pesetas and Deutsche Marks, and
converting DM to PTA at the rate of exchange in force at that time of 63 PTA/DM, shows that it amounts
to: 85,486.30 Million Pesetas. This amount compared with the amount of the initial project budget in
October 1991, implies an increase of 9.8%. This increase in Project Budget was due basically to the
design changes carried out in the gasification systems and to the extension of the start up programme
owing to its complexity. Breakdown of the Project Budget in constant currency October 1991 is as
follows:Million PTA91 %
GASIFICATION 30,799.55 36.03%
AIR SEPARATION UNIT 4,283.63 5.01%
COMBINED CYCLE 20,520.13 24.00%
FUEL HANDLING PLANT 1,717.65 2.01%
BALANCE OF PLANT 8,536.18 9.99%
WATER SUPPLY 1,808.15 2.12%
CONTROL SYSTEM 1,964.88 2.30%
GENERAL 15,390.33 18.00%
TOTAL PROJECT 85,020.51 99.46%
TECHNOLOGY GROUP 465.79 0.54%
TOTAL 85,486.30 100.00%1 DM = 63 PTA (October 1991)
Table 19. Project Budget constant currency Base 1991
Figure 34. Project Budget distribution. Constant currency October 1991
GENERAL18,0%
GASIFICATION36,0%
TECHNOLOGY GROUP
0,5%
AIR SEPARATION5,0%COMBINED
CYCLE24,0%
BALANCE OF PLANT10,0%
FUEL HANDLING2,0%
WATER SUPPLY2,1%
CONTROL SYSTEM
2,3%
69
3.3.3.2. Capital costs
Capital costs of the plant, not including interests during construction, come to almost 269,000 PTA91/kW,
equivalent to 1,850 $91/kW
Forecast on the economics of the IGCC's costs, as per US DOE estimations, indicate that these costs will
decrease in the coming years while its efficiency will increase significantly by 2015. The table shows this
capital cost forecast, including interest during construction, for a typical IGCC unit.
Year
Capital costs
US$/kW Efficiency (HHV,%)
1997 1,450 39.6
2000 1,250 42
2010 1,000 52
2015 850 >60Source: US DOE. Office of Fossil Energy. Federal Energy Technology Centre
Table 20. IGCC's Capital costs forecast
Figure 35. IGCC's Capital costs forecast
IGCC's Capital costs forecast
0
500
1000
1500
1997 2000 2010 2015
US$
/kW
70
3.3.3.3. Project Financing
The Puertollano IGCC Project has been financed with the partners’ contribution to the company capital,
the subordinated debt with the owners of the plant, the THERMIE Programme subventions, as well as
other subsidies that may be obtained and the rest through a Project Financing programme.
The project has been financed with a share of 35% own assets and 65% others assets. The subsidies
received to date represent a 5.8% of the total funds.
The Project Financing system was based on limited resources and was established according to the
expected cash-flow generated from the economical unit as a source of repayment (principal + interest),
and the Spanish Electrical Sector Remuneration System (Marco Legal Estable) as the main guarantee for
the loan. In 1998, upon the modification of the competitive market, the project finance was replaced by a
Bridge Loan supported by the shareholders guarantee.
71
3.4. AUTHORIZATIONS AND LICENSES
The following principal authorizations and licenses for the plant have been obtained:
Puertollano Municipal Construction Authorization
The Puertollano Municipal Construction Authorization covering all the works in the plant was granted on
June, 23th, 1993.
Cooling and Supply Water
Water Concession: The concession by the Confederación Hidrográfica del Guadalquivir, Ministerio de
Obras Públicas y Transportes of water for cooling and supply to the plant, in January 1994.
Water Pipeline Construction: The Construction Water Pipeline Authorization in January 1995 from
Diputación Provincial de Ciudad Real
Water Disposal Authorization: The Water Disposal Authorization in February 1996, from the
Confederación Hidrográfica del Guadalquivir.
Project Authorization and Declaration of Public Interest by the Dirección General de la Energía
In May 1994 the Dirección de Política Ambiental of the Ministerio de Obras Públicas y Medio Ambiente,
issued a positive Declaración de Impacto Ambiental (Environmental Impact
Declaration) for the plant.
In June 1994, the Dirección General de la Energía issued the Project Authorization and Declaration of
Public Interest.
Combine Cycle Start Up Act
In September 1996, the Delegación Provincial de Ciudad Real, Consejería de Industria y Trabajo, of the
Junta de Comunidades de Castilla-La Mancha, issued the Start Up Act for the Combined Cycle with
natural gas, the first phase of the start up of the plant.
Authorization for waste production activity
In November, 1998, the Consejería de Agricultura y Medio Ambiente of the Junta de Comunidades de
Castilla-La Mancha granted to ELCOGAS the Authorization for waste production activity.
72
4. PLANT OPERATION
4.1. OPERATION ORGANIZATION
The organization for plant Exploitation is established in Puertollano. At the end of August 2000, this
organization comprises 138 people.
The Operation organizational chart in Puertollano for the commercial operation of the plant is the
following:
Figure 36. Operation Chart
The shift operation personnel is composed by five teams, each one with a shift supervisor, three operators
and seven assistant operators.
OPERATION MANAGER
MAINTENANCE & TECHNICAL SERVICES
CHEMICAL, SAFETY & ENVIRONMENT
QUALITY ASSURANCE
OPERATION ADMINISTRATION PUERTOLLANO
EXTERNAL RELATIONS
ENGINEERING
73
4.2. PLANT OPERATION ASSESSMENT AND DATA
4.2.1. ASSESSMENT OF THE TOTAL PLANT PERFORMANCE
4.2.1.1. Plant status update
The plant start-up has been organized, since the project’s conception, into two steps to take advantage of
an earlier natural gas operation of the combined cycle before burning syngas generated in the Gasification
Island. The high degree of integration of the major plant blocks, as a result of the selected design concept,
requires integrated and stable operation of the combined cycle and the air separation unit, which has
impacted on the timely completion of the gasification start and tests.
Integrated operation of combined cycle, air separation unit and Gasification Island has been accomplished
and the plant concept has demonstrated its feasibility.
The following list gives the most relevant figures corresponding to the operational phase up to December
31th, 2000:
• Number of gasifier runs: 190.
• Hours with gasifier operation: 6,024.
• Longest gasifier run in hours: 688.
• Hours with gas turbine on coal gas: 4,788
• Gasifier maximum load: 106 %, (Run 139).
• GT maximum load on coal gas operation in MWh: 197.6 (Run 139).
74
The facts below summarise the plant status.
Milestones and main operational stops Date
FIRST IGNITION OF GAS TURBINE. April 1996
HRSG drums. Undersized level control system modification. July 1996
COMMERCIAL OPERATION OF COMBINED CYCLE WITH
NATURAL GAS.
October 1996
Loose part in GT. Blades damage repair. October 1996
FIRST AIR EXTRACTION. January 1997
PERFORMANCE TEST OF AIR SEPARATION UNIT. June 1997
Undersized steam system for NOx control in NG and GT syngas burners
modifications.
June 1997
FIRST IGNITION OF GASIFIER. December 1997
FIRST SWITCH OVER FROM NATURAL GAS TO SYNGAS. March 1998
Waste nitrogen compressor motor (20MW) damage. May 1998
GT syngas burners modification after first IGCC tests. July-August 1998
Gasifier burner overheated. October 1998
FIRST BASE LOAD OF GT WITH SG. November 1998
Gasifier combustion chamber cooling system leak. January 1999
Modification of internal part at GT rotor. March-May 1999
FIRST 100 HOURS CONTINUOUS OPERATION AS IGCC. August 1999
High degree of fouling at gasifier cooling surfaces and candle filters damaged. August 1999
FIRST PRODUCTION OF SOLID SULPHUR. August 1999
START-UP OF RECYCLE COMPRESSOR. February 2000
500,000 MWH OF ELECTRIC PRODUCTION WITH SYNGAS. GAS
TURBINE GUARANTEE TEST ON SYNGAS.
March 2000
GT 25,000 equivalent operation hours overhaul. April/June 2000
Slag pipe and gasifier reaction chamber blocked by slag. July 2000
Table 21. Main milestones of operation.
75
The following figures show hours of operation per quarter up to November 2000.
Figure 37. Accumulated gasifier and IGCC run time.
Figure 38. Gasifier and IGCC run time.
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Accumulated Gasifier and IGCC Run Time
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1000
2000
3000
4000
5000
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ours Gasifier���
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Gasifier and IGCC Run Time
0200400600
800100012001400
Hou
rs Gasifier����IGCC
76
The following figures show IGCC and natural gas (NGCC) availability factor per quarter up to November
2000.
Figure 39. IGCC and NGCC availability factor.
To sum up, it can be said that, since September 1999, after the initial periods where corrective actions
were the predominant activities, the plant is in a phase of real optimisations and operational learning
during which it has started significantly to increase availability and production using syngas.
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IGCC and NGCC Availability factor
0
10
20
30
40
5060
70
80
90
100
%
NGCC
���IGCC
77
4.2.1.2. Main operation interruptions and type of failures
The following figures show operation interruptions classified by type of failure up to August 2000. Main
interruptions have been caused by process design1 (36%).
PROCESS DESIGN
36%
OPERATING FAULT
12%
EQUIPMENT FAULT
20%
ERECTION FAULT
4%
SCHEDULED4%
CONTROL LOGIC
24%
Figure 40. Gasifier stoppages classified by type of failure.
1 Process design fault is understood as a forced stoppage because systems or equipment did not permit operation
when they were installed and operated as they were designed.
78
EQUIPMENT FAULT22% SCHEDULED
16%
ERECTION FAULT0%
OPERATING FAULT5%
CONTROL LOGIC9%
PROCESS DESIGN48%
Figure 41. Gas turbine syngas operation interruptions classified by type of failure.
79
4.2.1.3. Lessons learned
When conducting an overall assessment of the lessons learned during the commissioning and operational
phases of the Puertollano IGCC, the main comments to be made are the following:
♦ Significant know-how has been gathered and demonstrated up to the present situation. The planning
issues with greatest impact have been:
∗ The management of interfaces between the various Engineering companies involved and the
Suppliers, in order to minimise the overlap of project, Construction and Commissioning
activities in a demonstration plant such as this. No one of the main suppliers is responsible
for the whole plant and the detailed engineering co-ordination has taken a long time.
∗ The phased construction schedule, due to the need to reach two commercial operations, has
resulted in a longer Project duration.
∗ The unique nature of the plant has led to the introduction of a high number of design
corrections during start-up and first operational periods. It has required a great deal of
operation and reengineering to analyse, find out and define the problem and the solution.
♦ The scope and extent of changes have been mostly related to optimisation of design. Largest
modifications involved problems of equipment capacity not being related to concept modifications.
♦ The complex and innovative technology requires a high level of skills from the operators and
maintenance staff.
80
4.2.2. ASSESSMENT OF THE PERFORMANCE OF INDIVIDUAL EQUIPMENT
4.2.2.1. Main operation interruptions classified by areas
The following figures show operation interruptions up to August 2000 classified by areas. Main stoppages
have been caused by the Gasification Island (58%).
Others (BOP)3%
Asu15%
Combined Cycle23%
External1%
Gasification58%
Figure 42. Gasifier stoppages classified by areas.
81
Others (BOP)3%
Asu8%
Combined Cycle45%
External0%
Gasification44%
(Gas turbine 91%)
Figure 43. Gas turbine syngas operation interruptions classified by areas.
82
4.2.2.2. Gasification Island
The following figures show operation interruptions up to August 2000 classified by gasification systems.
Among Gasification Island stoppages, most interruptions have been caused by the Slag Extraction System
(31%).
START-UP BURNER & FLAME MONITORS
10%
SULPHUR RECOVERY & TAIL GAS RECYCLE
3%
QUENCH GAS RECIRCULATION
7%
WATER STEAM SYSTEMS & BOILERS
8%
MIXING & GRINDING PLANT
6%
GAS WET TREATMENT4%
SLAGS31%
DRY DEDUSTING & FLY ASH SYSTEM
1%
DUST FUEL CONVEYING & FEEDING
30%
Figure 44. Gasifier stoppages classified by Gasification Systems.
83
GAS WET TREATMENT4% SULPHUR RECOVERY &
TAIL GAS RECYCLE2%
WATER STEAM SYSTEMS & BOILERS
2%
START-UP BURNER & FLAME MONITORS
0%
MIXING & GRINDING PLANT20%
SLAGS44%
QUENCH GAS RECIRCULATION
0%
DUST FUEL CONVEYING & FEEDING
28%
DRY DEDUSTING & FLY ASH SYSTEM
0%
Figure 45. Gas turbine syngas operation interruptions classified by Gasification Systems.
84
4.2.2.2.1. Coal dust preparation
Demonstration of equipment scale-up has been a major achievement while economies of scale advise the
use of just one train. However, availability and load changes flexibility of the grinding plant are other
factors to be taken into account.
The main experience of this system are:
• Robustness is key in obtaining an acceptable performance.
• Automatic control is complex and has required operational experience to develop it.
• Performance flexibility of roller mills is not high enough for three materials with different hardness
(coal, coke and limestone) at the same time.
4.2.2.2.2. Coal dust conveying, sluicing and feeding
High-pressure (over 25-bar) transport and feeding has been accomplished through different methods.
Main experiences of these systems during operation are the following:
• In the coal dust sluicing system, coal dust had to fall by gravity from one vessel into the vessel
underneath; however, coal discharge presents many problems and high nitrogen consumption to
improve capacity of sluicing systems has been necessary. Some modifications were implemented in
the original discharge procedure. The concrete tower where the system is placed could be
simplified.
• Damages in the sintered metal of lock hopper discharge cones were often found. These pieces were
replaced and a new design was manufactured to increase their porosity.
• Coal dust flow measure at high density has sometimes displayed erratic behaviour. This measure is
based on coal dust velocity measuring devices. These devices show problems with high coal dust
densities (> 400 kg/m3) and unstable flow conditions. As a result of these wrong measurements,
oxygen flow may increase more than permitted limits and damage gasifier burners. To improve
these measurements, some line modifications and installation of field sensors were carried out.
• These systems require improvements to the equipment parts relating to homogeneous dilution of
the fuel dust and pressure control systems.
85
4.2.2.2.3. Gasifier
A very positive experience, shown by the results of the tests, is that the gasification process itself is not
too sensitive to the operational parameters that may be changed under normal operation. This results in
reliable operation in spite of the usual variations that are present at coal/coke ratios, combustion
temperatures, cold gas recycling flow, purity of oxygen, operational pressure and so on.
From the reaction chamber the following experiences are worth highlighting:
• Low reliability of flame monitoring system. This requires a different monitoring concept.
• During the first operation runs, gasifier burners were blocked with foreign particles (oversize
material of coal and limestone), resulting into a high pressure drop in the coal dust feeding lines.
For line cleaning by back-blowing from the gasifier to the atmosphere, stoppage of the gasifier is
required.
• Auxiliary burners to control slag blockage have been dismounted.
• The igniter and start-up burner system affects to the availability, since full depressurization is
required to start ignition.
4.2.2.2.4. Waste Heat Recovery System
During the first long term Gasifier operation, high gas outlet temperatures at the HP-Boiler, which were
limiting the gasifier load, were noticed. After discussing the operating results, the following reasons for
the increase of fouling in the HP- Evaporators were considered:
• Low velocities in the bundles.
• Fly ash composition and fly ash grain size distribution different to the design.
• Limited function of the rapping devices due to blockages inside the housing.
To solve this problem, it was decided to increase the velocity of the lower HP bundle. This decision was
based on the following aspects, which were observed during operation and inspections of the plant:
• The HP bundles undergo fouling in a similar order of magnitude as the IP bundles shortly after
start-up of the gasifier.
• The gas velocity in the IP bundles is higher than in the HP bundles (approx. 30-50%).
• No accumulation and blockages of raw gas paths were found during the inspections.
86
• The fly ash is very fluffy.
• After a special inspection, accumulation of fly ash in the fin areas of the HP bundles, which could
not be removed by actuating the rappers during operation, was confirmed.
• During the last phase of inertization, which is required after any gasifier stoppage, the gas velocities
inside the HP bundles are higher than during the normal operation, which can lead to a cleaning of
the HP heating surface.
Experience on similar designed heat exchangers revealed a significant impact of the raw gas velocity on
fouling. Unfortunately, these studies became known after the design and installation of the Waste Heat
Boiler in the Puertollano Plant.
Rehabilitation of some rapping devices (no blockages in the rapper housing) was necessary. Rappers were
checked and repaired. Additionally, several actions were carried out:
• Test with different limestone content in the feedstock.
• Tests with different pet-coke/coal ratios in the feedstock.
• Characterisation of the fly ash deposits in different laboratories: ECN (Netherlands), University of
Stuttgart (Germany) and UCLM (Spain).
• Assessment of the CABRE II project fouling model with actual data from the plant. CABRE (Coal
Ash Behaviour in Reducing Environment) II is a project that began in 1996 and it was funded by an
international consortium of industrial and governmental agencies.
• Assessment of the actual fouling evolution with a fouling calculation model.
Fouling was one of the main operation parameter and its trend was followed in every run. The following
figure shows the improvement in fouling behaviour from run No. 114 (September 1999) up to run No.
169 (August 2000). Fouling in the HP II evaporator has decreased considerably even with a higher
gasifier load.
87
0,0000,0020,0040,0060,0080,0100,0120,0140,0160,0180,020
0 8 16 24 32 40 48 56 64 72 80 88 96 104
112
120
128
136
144
152
160
168
176
184
192
200
208
222
Operation hours
Foul
ing
(m2 K
/W)
0102030405060708090100
Gas
ifier
load
(%)
HP II fouling (Run 169) HP II fouling (Run 114) HP I fouling (Run 169)HP I fouling (Run 114) Load (Run 169) Load (Run 114)
Figure 46. Comparison of fouling behaviour between September 1999 and August 2000.
88
4.2.2.2.5. Slag handling
Low reliability of slag valves and slag fine filters are the main reason of the unscheduled gasifier
stoppages:
• Some problems are due to the higher production of fine slag than expected. Fine slag can block the
slag water filters. Temporary reservoirs for settling this fine slag, operating as a bypass to the slag
water filter, were sometimes used as back up. The cleaned water overflow of the settling tanks was
pumped back to the system and the settled sludge removed via a mobile filter press.
• New automatic system to fill, pressurize and discharge supervision was installed to increase
reliability of operations.
• Pump components exposed to high speed can suffer erosion and corrosion beyond the acceptable
limits and need to be replaced by a more resistant material. Slag extractor speed was decreased to
reduce the mechanical wear of the chain assembly and associated parts and improve the settling of
the slag particles.
• The complexity of the system (removal of solid slag with a system of pressure lock hoppers filled
with water and a supposed amount of fines) has made the operation and analysis of malfunctions
too complex and diffuse.
89
4.2.2.2.6. Dry dedusting system and quench gas compressor
Candle filter elements are of ceramic-type material, made of silicium carbide and manufactured in Europe
by Schumacher. The selected type of candle filter were Dia-Schumalith F40 which consists of a porous
support body of clay-bonded silicon carbide (SiC). The basic design of the Dia-Schumalith is an
asymmetric filter ceramic material with a thin outer fine filtering ceramic membrane. The operating life of
the filter elements should not be less than 8000 hours of operation.
In order to maintain a high efficiency filtration, the candle filters have to be cleaned semi-continuously
without taking them out of operation. The pressure drop from the raw gas inlet to the dedusted gas outlet
of the candle filter vessel, which is controlled, must not exceed 200 mbar an the cleaning frequency
depends on that value.
During a inspection in July 1998, an excessive accumulation of ash was observed between the two levels
of candles in both filter vessels, but no broken candles were found. However, after a 100 hours run of
operation (August 1999) most of the candles were broken. This was due to the following reasons:
• During the previous operation, pressure drop in the filters was higher than that specified in the
design.
• Some of the filter cleaning valves were in bad conditions. These valves use nitrogen for cleaning
the filters.
Several actions were carried out to avoid breakage of candle filters:
• Filter cleaning valves were checked and repaired and some of their parts were changed. A new
material, different from the specified one, was used in the new parts.
• Pressure drop in the filters is followed in every run and controlled to be lower than the design
value.
During Gas Turbine scheduled outage corresponding to 25,000 equivalent operation hours, in April 2000,
a new type of candle filter (DS 10-20 supplied by Schumacher) was installed in the dry dedusting system.
Approximately half of the candle filters were substituted by this new model.
However, cleaning dedusting is still one of the critical systems in the plant and monitoring of the cleaning
dedusting process is carried out during the operation by two parameters:
90
• The candle filter fouling factor.
• The solids in Venturi water measured in the laboratory.
91
The following figure shows the main data of the candle filter operation.
0,00
0,25
0,50
0,75
1,00
1,25
1,50
1,75
2,00
2,25
2,5072
0
920
1120
1320
1520
1720
1920
2120
2320
2520
2720
2920
3120
3320
3520
3720
3920
4120
4320
4520
Accumulated hours
Foul
ing
fact
or
0
500
1000
1500
2000
2500
3000
3500
Solid
s in
Ven
turi
(ppm
)
Candle filter fouling factor Candle filter fouling factorCandle filter fouling factor Candle filter fouling factorSolids in Venturi (ppm)
August 99 candles breakage
Jan./Feb. 2000 2nd/3rd
cleaning off
Dec. 99 1st
cleaning off
Candle filter change
Valves blockage
Figure 47. Candle filter fouling factor and solids in Venturi during operation.
The cleaning system needs to be improved. Alternative filter elements should be evaluated.
92
4.2.2.2.7. Fly ash recycling and handling
Fly ash recycling to the gasifier had as main targets the transformation of fly ash in environmental inert
slag, and achievement of a high carbon conversion rate. However, the present carbon conversion rate is
very high without recycling and this system is not used. The design carbon content was in the range of 10-
40%, but the actual values are bellow 5%.
The feed bin was designed to have a higher pressure than the gasifier in order to return fly ash to the
gasifier. The system for recycling fly ash is not necessary.
In the design, only a small part of the fly ash flow was not recycled to the gasifier. This part was
transported via discharge vessels to the fly ash bunker to be stored before being taken away. The designed
mass flow rate of fly ash to discharge was 150 kg/h (100 kg/h on a dry basis) at full load. However, in the
actual operation all fly ash is discharge (about 2000 kg/h) and the bunker, where fly ash is stored, does not
have enough capacity. Trucks have to take away fly ash too frequently.
The fly ash bunker is emptied by means of the fluidisation device located in the bottom of the bunker
using LP nitrogen to fluidise the fly ash. However, discharge and handling of fly ash presents several
difficulties due, mainly, to a smaller fly ash size distribution than predicted in the design.
FLY ASH SIZE DISTRIBUTION
1
10
1001 10 100
%
Design lower limit (%) Design higher limit (%)Sample 1 Sample 2Sample 3 Sample 4Sample 5 Sample 6
>
2
50
5
20
>> µm µmµm
Figure 48. Fly ash size distribution.
93
As observed in the previous figure, more than 6% of the design particles had to be bigger than 30 µm,
however actual particles are below this design value. Fly ash particles are finer than expected and only 2-4
% of them are above 60 µm.
ELCOGAS has participated in the ECSC project No. 7220-ED/072: “Valorisation of IGCC Power Plant
by-products as secondary raw materials in construction”, completed in December 1999, and currently fly
ash is being used in civil construction and geotechnical works. New uses of fly ash are being studied by
our Research Group in co-operation with the Research Organism UCLM, CSIC and AICIA.
4.2.2.2.8. Wet scrubbing and gas stripping
Performance of these systems has been satisfactory and main experiences to report are:
• Wrong engineering design of the system. Installed controlling filters are not necessary with the
actual concept of dry dedusting.
• Overfill of the separator downstream of the Venturi Scrubber.
• Difficulties in pH control of the stripping of the raw gas washing water due to poor detailed design
and lack of robustness.
4.2.2.2.9. Desulphurization system
Specified clean gas composition is within reach. An exhaustive gas sampling campaign was carried out
within the ECSC project 7220-ED/754: “Improved IGCC Plant performance with coal/pet-coke
coprocessing” and the good performance of the desulphurization system was demonstrated. The following
table shows the actual and forecast raw gas and clean gas composition.
Actual average Design Actual average Design
CO (%) 59,26 61,25 CO (%) 59,30 60,51
H2 (%) 21,44 22,33 H2 (%) 21,95 22,08
CO2 (%) 2,84 3,70 CO2 (%) 2,41 3,87
N2 (%) 14,32 10,50 N2 (%) 14,76 12,5
Ar (%) 0,90 1,02 Ar (%) 1,18 1,03
SH2 (%) 0,83 1,01 SH2 (ppmv) 3 6
COS (%) 0,31 0,17 COS (ppm) 9 6
HCN (ppmv) 23 38 HCN (ppmv) LDO (*) 3
Concentrations are expressed in volume on a dry basis(*) LDO: Low of detection limit.
Raw gas Clean gas
Table 22. Raw gas and clean gas composition
94
It has been noticed that raw gas, from the water separator of the wet scrubbing system, can carry out acid
condensates and cause piping corrosion and COS catalyst deterioration.
A first study into corrosion problems was carried out within the THERMIE project No. SF-200-95
ES/IT/FR: “Materials performance monitoring through a state of reference program”. Follow up of
corrosion problems is studied in new projects.
A Desalting Pilot Unit was installed within the THERMIE project No. SF-200-95 ES/IT/FR. This unit
removes the MEDEA formates from the MEDEA, stemming from the reaction of the MDEA and the
hydrogen cyanide (HCN) contained in the raw gas. The Desalting Unit performance is within expected
and an extension of this unit is envisaged to achieve full operational performance.
In general, MDEA system behaviour is good and MDEA consumption is bellow the foreseen
consumption.
4.2.2.3. Air Separation Unit (ASU)
4.2.2.3.1. Interfaces ASU-Combined Cycle-Gasifier
Main experiences during operation related to this system are:
• Development of procedures for air, O2, coal gas, waste N2, condensate recovery, and water/steam
interfaces, which lead to more effective operation, in terms of cost, than those formerly issued
during the design phase.
• The duration of the plant start-up procedure is mainly conditioned, in the Puertollano design, by the
availability of the gaseous products from ASU. ASU is the critical path during the Plant start-up.
For cold starts, it takes 5 days and for hot starts 6 hours to reach the required conditions for the
gasifier ignition.
Nevertheless, this system has a good availability. ASU control is very sophisticated but highly reliable.
95
4.2.2.3.2. Nitrogen network
The economic impact of nitrogen consumption during operation needs to be looked at closely:
• The design concept of the project was that the pure nitrogen was a surplus by-product of the
oxygen distillation and that it could be used without restrictions. In normal steady state operation
this criteria is acceptable, but in transients and, specially, in stop and start operations, the
availability of pure nitrogen is a restraint which should be avoided.
• During IGCC operation commissioning, N2 consumption is high. This is an aspect that should be
considered in new IGCC designs.
96
4.2.2.4. Combined Cycle
A first Acceptance Test of Combined Cycle operating with synthetic gas (IGCC operation) was carried
out on March 20th. The main results are summarised in the following table:
Parameters of Guarantee Measured valueson the test
Guarantee valuesadapted for thetest conditions1
Guaranteevalues for design
conditionsPower (MW) 315.6 312.7 317.7Gas turbine (MW) 178.4 174.5 182.3Steam turbine (MW) 137.2 138.2 135.4Gross efficiency (%) 50.84 50.15 52.55Auxiliary consumption (kW) 3720 4307 4307NOx emissions (mg/Nm3, 15% O2 dry) 43 60 60Saturation water (kg/s) 6.09 5.29 5.29Noise (dB(A)) 85/100 85/100 85Air to ASU (kg/s) 103.3 103.3 97.0
1 Environmental and boundary conditions have been taken into account trough predictive models.
Table 23. Main results of the Acceptance Test.
The Acceptance Test shows a better gas turbine performance than that related to the design conditions.
However, a worse performance of the steam turbine was also observed due to the IP section. Main
conclusions at the moment are:
• Total power and gross efficiency of the Combined Cycle working in IGCC mode is higher than
those of the design conditions.
• Saturator water flow required for NOx is higher than the designed one due to the need to improve
gas turbine burner performance.
Nevertheless, the analysis of this test is not completed as of the date of this report.
4.2.2.4.1. Gas turbine
Some overheating problems and acoustic oscillations phenomena (humming) was detected during coal
gas combustion since June 1998. After this, coal gas burner design was modified several times. Further
tests were required to achieve humming-free stable flame during start up with natural gas and switchover
operations and to solve overheating problems.
97
Some evaluations of the different design modifications of the V94.3 hybrid burners were carried out by
the University of Twente in Cupertino with ELCOGAS and Siemens. For these studies, numerical
calculations regarding flame behaviour and acoustic data were performed. A small scale burner was also
manufactured.
Switch Over
0
100
200
300
400
500
60025
/9/0
0 21
:20
25/9
/00
21:2
1
25/9
/00
21:2
2
25/9
/00
21:2
3
OTC
(ºC
) and
hum
min
g
0
20
40
60
80
100
120
140
GT
Pow
er (M
W) a
nd v
alve
and
IGV'
s po
sitio
ns
RCC Humming LCC Humming OTC (ºC) GT Power (MW)WN2 control valve CG control valve NG valve position IGV's
Figure 49. Main gas turbine parameters to control the “switch over”.
Switch Back
0
100
200
300
400
500
600
25/9
/00
21:2
5
25/9
/00
21:2
6
25/9
/00
21:2
7
25/9
/00
21:2
8
25/9
/00
21:2
9
OTC
(ºC
) and
hum
min
g
0
20
40
60
80
100
120
140G
T Po
wer
(MW
) and
val
ve a
nd IG
V's
posi
tions
RCC Humming LCC Humming OTC (ºC) GT Power (MW)WN2 control valve CG control valve NG valve position IGV's
Figure 50. Main gas turbine parameters to control the “switch back”.
98
4.2.2.4.2. Heat Recovery Steam Generator
In this system, the drums are a critical availability point. Their volume must be optimised.
4.2.2.5. Auxiliary systems (Balance of Plant)
• Adjustment of the strippers’s pH-operation value: In order to reduce the acid elements as CN and S
of the stripped water sent to the waste water plant, the pH value of the water leaving the strippers of
the Waste Water Pre-treatment was reduced from 8 to 6.
• The cooling tower should stop when the Plant is stopped. Auxiliary cooling should be independent.
99
4.2.3. PROCESS DATA
4.2.3.1. Fuel heat rate. Year 2000
To the end of November 2000, the plant burnt 87,344 t of coal, 84,237 t of pet-coke and 3,407 t of
limestone. The fuel heat rate, coal and pet-coke 50% weight, to August 2000 is shown in the figure.
Figure 51. Fuel heat rate
4.2.3.2. Auxiliary power. Year 2000
Power consumed by the auxiliary systems of the plant per hour of operation to November 2000 is shown
in the figure.
Figure 52. Plant auxiliary power
Plant Auxiliary Power. Year 2000
15
20
25
30
35
40
45
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov
Mw
h/h
Fuel Heat Rate. Year 2000
1000
1200
1400
1600
1800
2000
2200
Jan Feb M ar A pr M ay Jun Jul A ug Sep O ct N ov
Kca
l(HH
V)/K
wh
100
4.2.3.3. Consumption of consumables and catalysers
The following table shows the consumption of consumables and catalysers in the operation of the plant
during 2000.
Consumption (kg/month) year 2000
Jan Feb Mar Apr May Jun Jul Aug Sept Oct Nov
Sulphuric Acid 36897 42771 66303 2919 6174 30118 32814 31148 9587 48741 63103
Caustic Soda 60591 50486 105172 3953 11696 32296 120536 112615 70199 130229 107329
Coagulant 2516 4265 7590 1080 2819 3288 2057 5251 6554 7236 4913
Poly-electrolyte 25 100 50 6 15 22 75 50 50 25 14
Hydrazine 813 276 96 0 437 347 893 894 504 126 1624
Ammonia 336 597 105 30 522 342 1063 403 582 885 672
Anticorrosive 1885 1068 2128 188 2165 4125 3806 3319 2384 2215 1853
Hypochloride 5734 3050 6734 200 5136 9235 18349 24261 2401 695 671
Calcium Chloride 5189 13331 37988 0 0 10380 14883 25954 17730 3350 10329
MDEA 0 1631 0 0 0 0 5419 0 174 0 0
Catalysers 0 0 0 0 50 0 0 0 0 10000 0
Table 24. Plant operation consumables.
101
4.2.3.4. Generation of electricity
4.2.3.4.1. IGCC Plant generation of electricity
Accumulated
Historic yearly electricity gross output records of the Puertollano IGCC plant up to November 2000 are
shown in table and graph.
IGCC Gross Output
MWh
1998 8867
1999 334937
2000 (Nov.) 723241
Table 25. IGCC Plant electricity gross output. Accumulated
Figure 53. IGCC Plant yearly electricity generation records
The Puertollano plant was built and started up in two phases, the first one fuelling the combined cycle
with natural gas, which was achieved in September 1996. The plant operated with natural gas from this
date to the adjustment of the combined cycle systems and supported start up of the gasification system in
1998.
IGCC Gross Output. MWh
0
100.000
200.000
300.000
400.000
500.000
600.000
700.000
800.000
1998 1999 2000 (Nov.)
MW
h
102
Year 2000
Monthly and accumulated electricity gross output Puertollano IGCC Plant with syn-gas for 2000 up to
November is shown in table and figure.
IGCC GROSS OUTPUT MWh
2000 Monthly Accumulated
January 34494 34494
February 75850 110344
March 108183 218526
April 0 218526
May 0 218526
June 2987 221513
July 83709 305222
August 118816 424039
September 97195 605101
November 118140 723241
Table 26. IGCC Plant electricity gross output. Year 2000
Figure 54. IGCC Plant Monthly electricity gross output. Year 2000
A scheduled shutdown took place from April to the end of June 2000 to perform an overhaul of the gas
and steam turbines in the combined cycle and to do some modifications in the gasification area to improve
systems performance.
IGCC Gross Output year 2000. MWh
0
100000
200000
300000
400000
500000
600000
700000
800000
0
20000
40000
60000
80000
100000
120000
140000
103
The best monthly gross output with IGCC was reached in August with a production of 118,816 MWh. In
general, performing of the IGCC plant and electricity generation evolved positively, increasing along
2000, with the exception of the shutdown period and the subsequent start up phase which affected
negatively the electricity production of June.
4.2.3.4.2. Generation of electricity. Total plant
Accumulated
Total plant's yearly gross power output and distribution by fuel used, syn-gas (IGCC) or natural gas (NG),
is shown in table and figure.
Total Gross Output
MWh
1996 178295
1997 959685
1998 752493
1999 720521
2000 (Nov.) 1341876
Table 27. Total Plant yearly electricity gross output.
Figure 55. Total plant yearly gross output
Total plant Gross Output. MWh
150000
400000
650000
900000
1150000
1400000
1996 1997 1998 1999 2000(Nov.)
MW
h IGCC GrossOutput
NG GrossOutput
104
Year 2000
Regarding performance of the total Puertollano plant, gross output for 2000 up to November is the
following:
Total Gross Output MWh
2000 Monthly Accumulated
January 147205 147205
February 139922 287127
March 168826 455954
April 8451 464405
May 0 464405
June 100801 565206
July 159492 724698
August 170833 895531
September 142917 1179335
November 162541 1341876
Table 28. Total Plant electricity gross output.
The figure shows the monthly gross output and distribution by fuel used, syn-gas (IGCC) or natural gas
(NG), of the total plant for 2000 up to November.
Figure 56. Total Plant monthly electricity gross output. Year 2000
The best monthly gross output of the plant was reached in August with 170,833 MWh of electricity
produced this month.
Gross Output 2000 MWh
0
20.000
40.000
60.000
80.000
100.000
120.000
140.000
160.000
180.000
MW
h
IGCC GrossOutput
NG GrossOutput
105
Plant availability
Plant availability for 2000 up to November is shown in the figure.
Figure 57. Plant availability for 2000 (up to November)
Total plant (IGCC + NGCC) availability reached 58%. Availability resulting in energy generated resulted
a 50%. Non scheduled availability was only a 5% of the total.
Plant availability year 2000
Availability58%
Scheduled unavaliablity
37%
Non Scheduled unavaliablity
5%
106
4.2.4. FINANCIAL DATA
4.2.4.1 Production Costs
The budget for operational costs of the plant for year 2000 amounts to 7,900 million PTA. 49% of this
operational costs are variable costs, including coal, pet-coke, limestone, consumables and cooling water
costs.
The variable costs are the result of the plant operation costs in the different operation modes, each of them
representing very different unitary variable costs. Thus, in natural gas operation mode, the variable cost
was forecasted 4.57 PTA/kWh, while in IGCC operation mode this cost drops to 2.06 PTA/kWh. The
unitary costs obtained are higher in other transient operation modes required to reach the normal IGCC
operation mode.
During 2000, the operation unitary costs have been higher than forecasted due to the increase experienced
in the international fuel markets. By the opposite, the fixed operation costs are kept in lower levels than
those estimated in the budget.
107
4.2.4.2. Operation Income
In the new deregulated electricity market, in force in Spain since 1 January 1998, ELCOGAS obtains its
incomes from the electricity sold to the market pool plus a Capacity Payment depending on the
availability of the plant.
In ELCOGAS budget 2000, a mean income of 5.43 PTA/kWh was forecasted, 4.50 PTA/kWh from this
corresponding to the payment for energy sold to the market Pool.
During 2000, payment by the Pool has been higher than forecasted due to the increase experimented in
fuel prices, transferred by the electric utilities to the price of the energy sold. The mean price obtained by
ELCOGAS sales reached 5.83 PTA/kWh. From this price, 5.07 PTA/kWh come from energy sales to the
Pool and 0.76 PTA/kWh come from Capacity Payments. The amount obtained from this Capacity
Payments has been lower than forecasted due, by one side, to a slightly lower availability of the plant
than forecasted and, by the other side, to the lower price fixed by the Spanish Ministry of Economy for
payments under this concept.
108
4.2.5. ENVIRONMENTAL DATA
4.2.5.1. Absolute environmental data
Environmental behaviour of the Puertollano IGCC Plant has been satisfactory, despite of the fact that
there has not been a complete continuity of operations with synthetic and natural gas due to technical
problems. The effect of the pollutant emissions has been well below the limits set for ELCOGAS for
operation with synthetic or natural gas, in particular for SO2 and particulate emissions. Regarding NOx,
emissions, an improved level of performance with synthetic gas is noted, reaching less than a 50% of the
authorised emission limit. This confirms the trend forecasted, which could improve in the future, once the
optimum plant operative parameters have been reached.
In accordance with Spanish environmental regulation R.D. 649/91, yearly atmospheric pollutant
emissions measures were carried out with satisfactory results.
Continuing with on the development of the ELCOGAS Environmental Management System, the system’s
new design, integrating Quality, should be highlighted. This system is aimed at achieving the jointly
Quality and Environmental Management certification process, as soon as possible, as per ISO 14001 and
9002 quality standards, initiated previously.
A natural barrier made of trees suited to the land was designed and implemented around the perimeter of
the coal yard, with the aim of minimising impact on the landscape and as a wind-barrier to avoid coal dust
dispersion, in accordance with the requirements of the Declaration on Environmental Impact.
109
4.2.5.2. Emission data
Emission data for 2000 up to October are as follows:
SO2 (6% O2) NOx (6% O2) Particulate (6% O2)
Concen-
tration
Total
emission
Specific
emission
Concen-
tration
Total
emission
Specific
emission
Concen-
tration
Total
emission
Specific
emission
MONTH mg/Nm3 t/month g/kWh mg/Nm3 t/month g/kWh mg/Nm3 t/month g/kWh
January 11.0 1.2 0.0334 78.6 8.2 0.2383 0.02 0.002 0.0001
February 17.2 3.9 0.0522 78.1 17.7 0.2364 0.47 0.106 0.0014
March 17.3 5.5 0.0511 62.6 20.0 0.1845 0.42 0.135 0.0012
April
May
June 3.8 0.0 0.0080 63.1 0.4 0.1330 0.78 0.005 0.0016
July 11.9 2.9 0.0345 74.9 18.2 0.2169 2.38 0.577 0.0069
August 40.9 13.7 0.1153 146.7 49.1 0.4135 2.19 0.732 0.0062
September 33.0 8.0 0.0954 138.2 33.5 0.3996 2.69 0.653 0.0078
October 26.9 7.8 0.0805 99.1 28.9 0.2963 0.04 0.011 0.0001
MEAN TOTAL MEAN MEAN TOTAL MEAN MEAN TOTAL MEAN
24.3 43.0 0.0712 99.5 176.0 0.2912 1.26 2.221 0,0037
Table 29. IGCC Plant emission data for 2000
Evolution of emissions of the different pollutants for 2000 are shown in the following graphs.
110
Figure 58. NOx emission mg/Nm3 for 2000
Figure 59. Specific NOx emission g/kWh for 2000
Emission of nitrogen oxide for 2000
78 63
147 13899
7579 63
0
100
200
300
400
500
600
janua
ry
februa
rymarc
hap
rilmay jun
e july
augu
st
septe
rmbe
r
octob
er
nove
mber
dece
mber
mg/
Nm
3 6
% d
e O
2
EU emission limit
Specific emission of NOx for 2000
0,24 0,22
0,41 0,400,30
0,130,180,24
0,00,10,20,30,40,50,60,70,80,91,01,11,2
janua
ry
februa
rymarc
hap
rilmay jun
e july
augu
st
septe
rmbe
r
octob
er
nove
mber
dece
mber
g/kWh
111
Figure 60. SO2 emission mg/Nm3 for 2000
Figure 61. Specific SO2 emission g/kWh for 2000
Emission of sulphur dioxide for 2000
11,0 17,2 17,3 3,8 11,940,9 33,0 26,9
0
100
200
300
400
janua
ry
februa
rymarc
hap
rilmay jun
e july
augu
st
septe
rmbe
r
octob
er
nove
mber
dece
mber
mg/
Nm
3 6
% d
e O
2EU emission limit
Specific emission of SO2 for 2000
0,030,05 0,05
0,01
0,03
0,120,10
0,08
0,0000,0200,0400,0600,0800,1000,1200,140
112
Figure 62. Particulate emission mg/Nm3 for 2000
Figure 63. Specific particulate emission g/kWh year 2000
Emission of particulates for 2.000
0,02 0,47 0,42 0,78 2,38 2,19 2,690,04
0
10
20
30
40
50
janua
ry
februa
rymarc
hap
rilmay jun
e july
augu
st
septe
rmbe
r
octob
er
nove
mber
dece
mber
mg/
Nm
3 6%
de
O2
EU emission limit
Specific emission of particulate for 2.000
0,0001
0,0014 0,00120,0016
0,00690,0062
0,0078
0,0001
0,000
0,002
0,004
0,006
0,008
0,010
janua
ry
februa
rymarc
hap
rilmay jun
e july
augu
st
septe
rmbe
r
octob
er
nove
mber
dece
mber
g/kWh
113
4.2.5.3. By-products and waste data
By-products generated at the plant for 2000 up to August are the following:
Material Jan-00 Feb-00 Mar-00 Apr-00 May-00 Jun-00 Jul-00 Ago-00 Oct-00 Oct-00 TotalFly ashes (t) 686 697 1,354 96 604 1,491 1,242 1,242 7,135Slag (t) 6,583 7,181 60 2,848 102 7,112 14,000 7,297 7,297 52,226Filter cake (t) 121 171 501 243 999 1,400 756 756 4,690Sulphur (exits, t) 401 762 992 403 467 611 611 4,185
Official inspections and controls of the liquid effluent to the Ojailén river, carried out by the
Confederación Hidrográfica del Guadalquivir, confirmed compliance with the requirements imposed by
the provisional liquid effluent authorization. For the final authorization, ELCOGAS submitted the final
technical report with the analytical characterization of the effluent.
Regarding production of solid wastes, ELCOGAS complied strictly with the requirements established in
the official solid waste authorization, sending the vitrified slag to the Encasur coal mine as a matter of
course, but it has recently valued as a by-product to be used in the fabrication of ceramic products and it
has been agreed to sell the slag to a local ceramic workshop for next year.
Fly ashes have been also valued as a by-product to be used as an additive for concrete and are being used
by local cement and concrete industries as a component in the manufacture of concrete.
Other normal industrial wastes produced in the plant were managed by entities duly authorised by the
Environmental Authority.
114
Waste data for year 2000 until October are as follows:
Material Jan-00 Feb-00 Mar-00 Apr-00 May-00 Jun-00 Jul-00 Ago-00 Sep-00 Oct-00 TotalProcess wasteEffluent slurry (m3) 30 66 30 5 5 10 15 15 20 30 226Coal mills waste (t) 56 40 123 30 72 90 81 67 559Waste water (m3) 36,375 35,365 55,672 14,303 4,737 36,462 50,544 44,595 44,300 49,000 371,353MDEA wastes (kg) 5,000 5,000Acid contaminated absorbent (kg) 1,200 1,200MDEA contaminated absorbent (kg) 2,400 2,400Oil contaminated absorbent (kg) 1,000 600 1,600Other wasteUrban solid waste (m3) 125 146 146 135 125 125 125 146 125 145 1,342Paper and clothes (m3) 6 6 12 6 84 12 12 12 12 6 168Wood (kg) 27,480 27,480Plastics and miscellaneous (m3) 6 6 6 12 6 15 30 6 15 102Steel (t) 72 134 206Inert industrial waste (kg) 17,920 3,920 21,840Used oil (kg) 1,820 2,000 1,600 1,420 6,840Used batteries (barrels 150 l) 0Used batteries (kg) 500 300 800Fluorescent lamps (kg) 200 200Laboratory packs (kg) 2 200 202Contaminated industrial packs (kg) 1,000 200 1,200Obsolete laboratory reactive chems (kg) 40 10 50Organic halogen solver (kg) 75 75Obsolete paintings (kg) 2,850 2,850
Table 30. IGCC Plant waste data for 2000
115
4.2.5.4. Trace element mass balance
Major, minor and trace metallic elements are emitted both by natural processes and human activities. Fuel
contains many of the elements of the periodic table and metal trace elements appear in coals, at different
concentrations, according to regional and local scales, as a result of the complex (and, generally, random)
way they originally entered the coal. Even, coals from different parts of the same seam can contain
different trace element contents. In addition, petroleum wastes, as coke, can present different trace
element content depending on the original petroleum and the refining process.
Trace elements in ELCOGAS feedstock (input) and in by-products (output) have been studied within the
ECSC project No. 7220-ED/754: “Improved IGCC plant performance with coal/pet-coke coprocessing”.
Sampling trials have been carried out and main results from them are summarised in the following figures:
Trace distribution in feedstock
0%
20%
40%
60%
80%
100%
Zn Pb As Sb Cd Cu V Be Hg Ni Co Mn Cr
Coal Coke Limestone
Figure 64. Trace distribution in feedstock.
In general, most of the trace elements from the Puertollano coal. Pet-coke from REPSOL refinery is rich
in Vanadium, Nickel (Cr, Cu and Zn also appear in the pet-coke).
116
Trace distribution in by-products
0%
20%
40%
60%
80%
100%
Zn Pb As Sb Cd Cu V Be Hg Ni Co Mn Cr
Slag Filter cake Fly ash
Figure 65. Trace distribution in by-products.
The relative enrichment of metal trace elements in smaller particles is explained by a
volatilisation/condensation mechanism. During gasification, volatile types are vaporised. Later, as the
temperature falls, these types can condense out of the vapour phase on to the surface of ash particles. The
smallest particles represent a large fraction of the overall available surface area although they are only a
small part of the total mass. Therefore, on a mass basis, there appears to be preferential enrichment of the
smallest particles.
Measurements in raw and clean gas did not detect Hg.
117
4.3. ASSESSMENT OF OPERATION WITH DIFFERENT FUELS
4.3.1. INTRODUCTION
After starting the demonstration phase, ELCOGAS proceeded to perform series of tests with different fuel
mixtures. This commitment of ELCOGAS is stated in the contract number SF 337/91 ES (THERMIE
programme).
These tests were carried out according to the specification explained in the document PO-YHA-TFX-
ELX-00038, sent to the Directorate-General for Energy of the European Commission on March 7th, 2000
in the letter reference MT-LB/040.
The tests were carried out over several months, taking into account the preparation of the facilities for
each fuel used in accordance with the programme in the aforementioned document. Four of these tests
were chosen for this report.
118
4.3.2. FUEL CHARACTERIZATION
One feature of the Puertollano gasification process is its flexibility with different kinds of feedstocks. The
plant is designed to be able to gasify the following fuel ranges.
Min. Max.
Higher heating value MJ/kg) 20.90 29.32
Ash 3 25
N (%) - 3
S (%) - 4
Volatile matter (%) 13 40
Cl (%) * - 0.5(*) Plant operation is limited by restrictions resulting from high chlorine operation, i.e. wet scrubbing, stripper system and water consumption
Table 31. Fuel range designation.
Coal and coke mixtures permit to modify the composition and characteristics of the feedstock.
Four tests were envisaged to demonstrate the flexibility of the Puertollano gasification process, the
theoretical composition of which is shown in the following table:
Mixture 1 Mixture 2 Mixture 3 Mixture 4
Coal % Coke % Coal % Coke % Coal % Coke % Coal % Coke %
39 61 45 55 54 46 58 42
Ash %
Fixed Carbon %
Volatile matter
Sulphur %
Nitrogen
Chlorine %
HHV MJ/kg
Hardgrove index (º)
17.9
65.3
16.8
4.0
1.13
0.029
27.92
60.7
20.5
62.1
17.1
3.7
1.09
0.031
26.84
60.3
24.5
57.4
18.2
3.3
1.06
0.034
25.22
59.8
26.2
56.2
18.5
3.1
1.01
0.036
24.49
59.5
Water free analysis (% in weight)
Table 32. Fuels selected for demonstration tests.
119
The four tests were carried out with different coke and coal mixtures. Comparison between the predicted
theoretical composition and actual composition of the mixtures appears in the following table:
Feedstock composition
Mixture
1
Mixture
2
Mixture
3
Mixture
4
Coal % 39 45 54 58
Coke % 61 55 46 42
Actual 0.75 1.04 1.29 0.93Moisture wt. %
Predicted 2 2 2 2
Actual 68.8 65.61 62.76 60.66C wt. % (mf)
Predicted 70.51 67.79 65.52 61.89
Actual 3.36 3.68 3.15 3.24H wt. % (mf)
Predicted 3.17 3.11 3.06 2.98
Actual 1.89 2.69 3.36 3.68O (by
difference)
wt. % (mf)
Predicted 3.3 3.8 4.2 4.8
Actual 1.52 1.3 1.49 1.27N wt. % (mf)
Predicted 1.13 1.09 1.06 1.01
Actual 3.82 3.47 3.28 3.0S wt. % (mf)
Predicted 4.0 3.7 3.3 3.1
Actual 722 685 482 524Cl ppm (mf)
Predicted 290 310 340 360
Actual 20.67 23.69 25.95 28.21Ash wt. % (mf)
Predicted 17.9 20.5 24.5 26.2
Actual 16.33 17.44 18.25 18.42Volatile matter wt. % (mf)
Predicted 16.8 17.4 18.2 18.5
Actual 26.89 25.53 24.69 23.61H. H. V. MJ/kg (mf)
Predicted 27.92 26.84 25.22 24.49
Table 33. Actual and predicted composition of the mixtures tested.
120
Coal and coke composition for each mixture is the following:
Mixture 1 Mixture 2 Mixture 3 Mixture 4 Mixture 1 Mixture 2 Mixture 3 Mixture 4
Moisture (%) 10.79 8.96 12.81 9.12 6.07 8.7 5.34 5.47
Ash (wt.% mf) 45.31 47.32 42.58 44.43 0.6 0.49 0.43 0.68
Volatile matter (wt.% mf) 22.17 21.97 22.52 22.81 12.59 13.52 12.99 12.93
Fixed carbon (wt.% mf) 32.53 30.31 34.9 32.74 87.08 85.99 86.58 86.38
C (wt.% mf) 42.04 39.96 43.94 42.7 87.94 88.16 87.8 87.15
H (wt.% mf) 2.82 2.68 2.86 2.88 3.7 3.63 3.7 3.65
N (wt.% mf) 0.75 0.7 1.04 1.08 1.59 1.43 1.53 1.66
O (wt.% mf) 8.27 8.44 8.69 7,98 0.06 0.25 0.09 0.34
S (wt.% mf) 0.81 0.9 0.89 0.93 6.23 6.04 6.45 6.52
16,554 15,675 17,283 16,745 34,861 34,969 34,986 34,787
15,947 15,358 16,667 16,126 34,074 34,200 34,198 34,009
H.H.V (kJ/kg)
L.H.V (kJ/kg)
COAL COKE
Prox
imat
e an
alys
isU
ltim
ate
anal
ysis
Table 34. Coal and coke composition during the tests.
121
4.3.3. ASSESSMENT OF TESTS AND EXPERIENCE WITH DIFFERENT FUELS
4.3.3.1. History of test operation
Gasification tests of different feedstock in Puertollano IGCC plant were carried out from February 20th,
2000. Four periods were chosen as representative of these tests.
Selected test runs and conditions are listed in the following table in chronological order. In both cases the
Puertollano plant had been operating on the previous fuel and was then switched to the next feedstock.
Test run Mixture No. Coal-coke composition Period of Balance
1 3 54%-46% 26/02/00 16:00-20:00
2 4 58%-42% 07/03/00 17:23-21:20
3 2 45%-55% 21/03/00 12:00-16:00
4 1 39%-61% 23/03/00 16:28-20:16
Table 35. Main test conditions.
Approx. 12,185 tons of feedstock were gasified in 138 operating hours, during the first test; 8,883 tons of
feedstock in 130 operating hours, during the second test; 11,656 tons of feedstock in 136 operating hours,
during the third test and 9,960 tons of feedstock in 121 operating hours, during the last one, i.e. 525
operating hours altogether.
The following figures show the records of the main process data for the tests. These figures include
information about operation under load change conditions, effect of O/C ratio control and other operating
conditions.
122
MIXTURE No. 1
0
20
40
60
80
100
120
23/3
/00
16:2
5
23/3
/00
16:3
5
23/3
/00
16:4
5
23/3
/00
16:5
5
23/3
/00
17:0
5
23/3
/00
17:1
5
23/3
/00
17:2
5
23/3
/00
17:3
5
23/3
/00
17:4
5
23/3
/00
17:5
5
23/3
/00
18:0
5
23/3
/00
18:1
5
23/3
/00
18:2
5
23/3
/00
18:3
5
23/3
/00
18:4
5
23/3
/00
18:5
5
23/3
/00
19:0
5
23/3
/00
19:1
5
23/3
/00
19:2
5
23/3
/00
19:3
5
23/3
/00
19:4
5
23/3
/00
19:5
5
23/3
/00
20:0
5
23/3
/00
20:1
5
23/3
/00
20:2
5
Period of test
Feed
stoc
k (t/
h), O
2 pur
ity (%
) and
gas
ifier
pr
essu
re (b
ar)
0
7000
14000
21000
28000
35000
42000
49000
56000
63000
70000
O2 (
Nm
3 /h) a
nd s
team
(kg/
h) to
bur
ners
Gasifier pressure (bar)
O2 to burners (Nm3/h)
Steam to burners (kg/h)
Feedstock (t/h)O2 purity (%)
Figure 66. Main process input data during the tests. Mixture 1
MIXTURE No. 2
0
20
40
60
80
100
120
21/3
/00
12:0
0
21/3
/00
12:1
0
21/3
/00
12:2
0
21/3
/00
12:3
0
21/3
/00
12:4
0
21/3
/00
12:5
0
21/3
/00
13:0
0
21/3
/00
13:1
0
21/3
/00
13:2
0
21/3
/00
13:3
0
21/3
/00
13:4
0
21/3
/00
13:5
0
21/3
/00
14:0
0
21/3
/00
14:1
0
21/3
/00
14:2
0
21/3
/00
14:3
0
21/3
/00
14:4
0
21/3
/00
14:5
0
21/3
/00
15:0
0
21/3
/00
15:1
0
21/3
/00
15:2
0
21/3
/00
15:3
0
21/3
/00
15:4
0
21/3
/00
15:5
0
21/3
/00
16:0
0
Period of test
Feed
stoc
k (t/
h), O
2 pur
ity (%
) and
gas
ifier
pr
essu
re (b
ar)
0
7000
14000
21000
28000
35000
42000
49000
56000
63000
70000
O2 (
Nm
3 /h) a
nd s
team
(kg/
h) to
bur
ners
Gasifier pressure (bar)
O2 to burners (Nm3/h)
Steam to burners (kg/h)
Feedstock (t/h)
O2 purity (%)
Figure 67. Main process input data during the tests. Mixture 2
123
MIXTURE No. 3
0
20
40
60
80
100
120
26/2
/00
16:0
0
26/2
/00
16:1
0
26/2
/00
16:2
0
26/2
/00
16:3
0
26/2
/00
16:4
0
26/2
/00
16:5
0
26/2
/00
17:0
0
26/2
/00
17:1
0
26/2
/00
17:2
0
26/2
/00
17:3
0
26/2
/00
17:4
0
26/2
/00
17:5
0
26/2
/00
18:0
0
26/2
/00
18:1
0
26/2
/00
18:2
0
26/2
/00
18:3
0
26/2
/00
18:4
0
26/2
/00
18:5
0
26/2
/00
19:0
0
26/2
/00
19:1
0
26/2
/00
19:2
0
26/2
/00
19:3
0
26/2
/00
19:4
0
26/2
/00
19:5
0
26/2
/00
20:0
0
Period of test
Feed
stoc
k (t/
h), O
2 pur
ity (%
) and
gas
ifier
pr
essu
re (b
ar)
0
7000
14000
21000
28000
35000
42000
49000
56000
63000
70000
O2 (
Nm
3 /h) a
nd s
team
(kg/
h) to
bur
ners
O2 to burners (Nm3/h)
Feedstock (t/h)
O2 purity (%)
Gasifier pressure (bar)
Steam to burners (kg/h)
Figure 68. Main process input data during the tests. Mixture 3
MIXTURE No. 4
0
20
40
60
80
100
120
7/3/
00 1
7:20
7/3/
00 1
7:30
7/3/
00 1
7:40
7/3/
00 1
7:50
7/3/
00 1
8:00
7/3/
00 1
8:10
7/3/
00 1
8:20
7/3/
00 1
8:30
7/3/
00 1
8:40
7/3/
00 1
8:50
7/3/
00 1
9:00
7/3/
00 1
9:10
7/3/
00 1
9:20
7/3/
00 1
9:30
7/3/
00 1
9:40
7/3/
00 1
9:50
7/3/
00 2
0:00
7/3/
00 2
0:10
7/3/
00 2
0:20
7/3/
00 2
0:30
7/3/
00 2
0:40
7/3/
00 2
0:50
7/3/
00 2
1:00
7/3/
00 2
1:10
7/3/
00 2
1:20
Period of test
Feed
stoc
k (t/
h), O
2 pur
ity (%
) and
gas
ifier
pr
essu
re (b
ar)
0
7000
14000
21000
28000
35000
42000
49000
56000
63000
70000
O2 (
Nm
3 /h) a
nd s
team
(kg/
h) to
bur
nersO2 to burners (Nm3/h)
Feedstock (t/h)
O2 purity (%)
Gasifier pressure (bar)
Steam to burners (kg/h)
Figure 69. Main process input data during the tests. Mixture 4
124
MIXTURE No. 1
0
20
40
60
80
100
120
140
160
180
200
220
240
23/3
/00
16:2
5
23/3
/00
16:3
5
23/3
/00
16:4
5
23/3
/00
16:5
5
23/3
/00
17:0
5
23/3
/00
17:1
5
23/3
/00
17:2
5
23/3
/00
17:3
5
23/3
/00
17:4
5
23/3
/00
17:5
5
23/3
/00
18:0
5
23/3
/00
18:1
5
23/3
/00
18:2
5
23/3
/00
18:3
5
23/3
/00
18:4
5
23/3
/00
18:5
5
23/3
/00
19:0
5
23/3
/00
19:1
5
23/3
/00
19:2
5
23/3
/00
19:3
5
23/3
/00
19:4
5
23/3
/00
19:5
5
23/3
/00
20:0
5
23/3
/00
20:1
5
23/3
/00
20:2
5
Period of test
Gas
ifier
load
(%),
HP
and
IP s
team
pro
duce
d in
the
gasi
fier
and
turb
ine
pow
er (M
W)
0
20000
40000
60000
80000
100000
120000
140000
160000
180000
200000
Cle
an g
as fl
ow (N
m3 /h
)
Clean gas flow
HP steam flow
Gas turbine power
Steam turbine power
Gasifier load
IP steam flow
Figure 70. Main process output data during the tests. Mixture 1
MIXTURE No. 2
0
20
40
60
80
100
120
140
160
180
200
220
240
21/3
/00
12:0
0
21/3
/00
12:1
0
21/3
/00
12:2
0
21/3
/00
12:3
0
21/3
/00
12:4
0
21/3
/00
12:5
0
21/3
/00
13:0
0
21/3
/00
13:1
0
21/3
/00
13:2
0
21/3
/00
13:3
0
21/3
/00
13:4
0
21/3
/00
13:5
0
21/3
/00
14:0
0
21/3
/00
14:1
0
21/3
/00
14:2
0
21/3
/00
14:3
0
21/3
/00
14:4
0
21/3
/00
14:5
0
21/3
/00
15:0
0
21/3
/00
15:1
0
21/3
/00
15:2
0
21/3
/00
15:3
0
21/3
/00
15:4
0
21/3
/00
15:5
0
Period of test
Gas
ifier
load
(%),
HP
and
IP s
team
pro
duce
d in
th
e ga
sifie
r an
d tu
rbin
e po
wer
(MW
)
0
20000
40000
60000
80000
100000
120000
140000
160000
180000
200000
Cle
an g
as fl
ow (N
m3 /h
)
Clean gas flow
HP steam flow
Gas turbine powerSteam turbine power
Gasifier load
IP steam flow
Figure 71. Main process output data during the tests. Mixture 2
125
MIXTURE No. 3
0
20
40
60
80
100
120
140
160
180
200
220
240
26/2
/00
16:0
0
26/2
/00
16:1
0
26/2
/00
16:2
0
26/2
/00
16:3
0
26/2
/00
16:4
0
26/2
/00
16:5
0
26/2
/00
17:0
0
26/2
/00
17:1
0
26/2
/00
17:2
0
26/2
/00
17:3
0
26/2
/00
17:4
0
26/2
/00
17:5
0
26/2
/00
18:0
0
26/2
/00
18:1
0
26/2
/00
18:2
0
26/2
/00
18:3
0
26/2
/00
18:4
0
26/2
/00
18:5
0
26/2
/00
19:0
0
26/2
/00
19:1
0
26/2
/00
19:2
0
26/2
/00
19:3
0
26/2
/00
19:4
0
26/2
/00
19:5
0
26/2
/00
20:0
0
Period of test
Gas
ifier
load
(%),
HP
and
IP s
team
pro
duce
d in
th
e ga
sifie
r an
d tu
rbin
e po
wer
(MW
)
0
20000
40000
60000
80000
100000
120000
140000
160000
180000
200000
Cle
an g
as fl
ow (N
m3 /h
)
IP steam flow
Gasifier load
Steam turbine power
Gas turbine power
HP steam flow
Clean gas flow
Figure 72. Main process output data during the tests. Mixture 3
MIXTURE No. 4
0
20
40
60
80
100
120
140
160
180
200
220
240
7/3/
00 1
7:20
7/3/
00 1
7:30
7/3/
00 1
7:40
7/3/
00 1
7:50
7/3/
00 1
8:00
7/3/
00 1
8:10
7/3/
00 1
8:20
7/3/
00 1
8:30
7/3/
00 1
8:40
7/3/
00 1
8:50
7/3/
00 1
9:00
7/3/
00 1
9:10
7/3/
00 1
9:20
7/3/
00 1
9:30
7/3/
00 1
9:40
7/3/
00 1
9:50
7/3/
00 2
0:00
7/3/
00 2
0:10
7/3/
00 2
0:20
7/3/
00 2
0:30
7/3/
00 2
0:40
7/3/
00 2
0:50
7/3/
00 2
1:00
7/3/
00 2
1:10
7/3/
00 2
1:20
Period of test
Gas
ifier
load
(%),
HP
and
IP s
team
pro
duce
d in
the
gasi
fier
and
turb
ine
pow
er (M
W)
0
20000
40000
60000
80000
100000
120000
140000
160000
180000
200000
Cle
an g
as fl
ow (N
m3 /h
)Clean gas flow
HP steam flow
Gas turbine power
Steam turbine power
Gasifier load
IP steam flow
Figure 73. Main process output data during the tests. Mixture 4
126
MIXTURE No. 1
0
25
50
75
100
125
150
23/3
/00
16:2
5
23/3
/00
16:3
5
23/3
/00
16:4
5
23/3
/00
16:5
5
23/3
/00
17:0
5
23/3
/00
17:1
5
23/3
/00
17:2
5
23/3
/00
17:3
5
23/3
/00
17:4
5
23/3
/00
17:5
5
23/3
/00
18:0
5
23/3
/00
18:1
5
23/3
/00
18:2
5
23/3
/00
18:3
5
23/3
/00
18:4
5
23/3
/00
18:5
5
23/3
/00
19:0
5
23/3
/00
19:1
5
23/3
/00
19:2
5
23/3
/00
19:3
5
23/3
/00
19:4
5
23/3
/00
19:5
5
23/3
/00
20:0
5
23/3
/00
20:1
5
23/3
/00
20:2
5
Period of test
CO
(%) a
nd H
2 (%
)
0
20000
40000
60000
80000
100000
120000
140000
160000
180000
200000
Cle
an g
as fl
ow (
Nm
3 /h)
H2 in clean gas CO in clean gas Clean gas flow
CO
H2
Clean gas flow
Figure 74. Main gas composition data during the tests. Mixture 1
MIXTURE No. 2
0
25
50
75
100
125
150
21/3
/00
12:0
0
21/3
/00
12:1
0
21/3
/00
12:2
0
21/3
/00
12:3
0
21/3
/00
12:4
0
21/3
/00
12:5
0
21/3
/00
13:0
0
21/3
/00
13:1
0
21/3
/00
13:2
0
21/3
/00
13:3
0
21/3
/00
13:4
0
21/3
/00
13:5
0
21/3
/00
14:0
0
21/3
/00
14:1
0
21/3
/00
14:2
0
21/3
/00
14:3
0
21/3
/00
14:4
0
21/3
/00
14:5
0
21/3
/00
15:0
0
21/3
/00
15:1
0
21/3
/00
15:2
0
21/3
/00
15:3
0
21/3
/00
15:4
0
21/3
/00
15:5
0
21/3
/00
16:0
0
Period of test
CO
(%) a
nd H
2 (%
)
0
20000
40000
60000
80000
100000
120000
140000
160000
180000
200000
Cle
an g
as fl
ow (
Nm
3 /h)
H2 in clean gas CO in clean gas Clean gas flow
CO
H2
Clean gas flow
Figure 75. Main gas composition data during the tests. Mixture 2
127
MIXTURE No. 3
0
25
50
75
100
125
150
26/2
/00
16:0
0
26/2
/00
16:1
0
26/2
/00
16:2
0
26/2
/00
16:3
0
26/2
/00
16:4
0
26/2
/00
16:5
0
26/2
/00
17:0
0
26/2
/00
17:1
0
26/2
/00
17:2
0
26/2
/00
17:3
0
26/2
/00
17:4
0
26/2
/00
17:5
0
26/2
/00
18:0
0
26/2
/00
18:1
0
26/2
/00
18:2
0
26/2
/00
18:3
0
26/2
/00
18:4
0
26/2
/00
18:5
0
26/2
/00
19:0
0
26/2
/00
19:1
0
26/2
/00
19:2
0
26/2
/00
19:3
0
26/2
/00
19:4
0
26/2
/00
19:5
0
26/2
/00
20:0
0
Period of test
CO
(%) a
nd H
2 (%
)
0
20000
40000
60000
80000
100000
120000
140000
160000
180000
200000
Cle
an g
as fl
ow (N
m3 /h
)
H2 in clean gas CO in clean gas Clean gas flow
H2
CO
Clean gas flow
Figure 76. Main gas composition data during the tests. Mixture 3
MIXTURE No. 4
0
25
50
75
100
125
150
7/3/
00 1
7:20
7/3/
00 1
7:30
7/3/
00 1
7:40
7/3/
00 1
7:50
7/3/
00 1
8:00
7/3/
00 1
8:10
7/3/
00 1
8:20
7/3/
00 1
8:30
7/3/
00 1
8:40
7/3/
00 1
8:50
7/3/
00 1
9:00
7/3/
00 1
9:10
7/3/
00 1
9:20
7/3/
00 1
9:30
7/3/
00 1
9:40
7/3/
00 1
9:50
7/3/
00 2
0:00
7/3/
00 2
0:10
7/3/
00 2
0:20
7/3/
00 2
0:30
7/3/
00 2
0:40
7/3/
00 2
0:50
7/3/
00 2
1:00
7/3/
00 2
1:10
7/3/
00 2
1:20
Period of test
CO
(%) a
nd H
2 (%
)
0
20000
40000
60000
80000
100000
120000
140000
160000
180000
200000
Cle
an g
as fl
ow (N
m3 /h
)
H2 in clean gas CO in clean gas Clean gas flow
Clean gas flow
CO
H2
Figure 77. Main gas composition data during the tests. Mixture 4
The plant was operated successfully with the different feedstock, however some mechanical and
operational difficulties were observed during the tests.
128
4.3.3.2. Individual analysis of performance op processing parts
4.3.3.2.1 . Slag extraction system
During Test No. 1 (Mixture No. 3), slag collector level increased by twice the permitted level for a correct
operation (3400 mm). A trip on February 25th was caused by this problem due to the high ash
concentration in the feedstock.
During Test No. 2 (Mixture No. 4), the slag collector level was also quite high on two occasions.
However, the problem was controlled by operation parameters (mainly by decreasing the gasifier load to
85%).
In Test No. 3 (Mixture No. 2) and No.4 (Mixture No. 1), problems relating to the slag extraction system
did not appear, because of lower ash concentrations in the feedstock.
The following figures show the behaviour of the slag extraction system during the four tests. Main
parameters: slag collector level and slag crusher intensity have been registered.
129
THERMIE TEST No. 1
0
500
1000
1500
2000
2500
3000
3500
4000
20/2
/00
4:00
20/2
/00
17:2
0
21/2
/00
6:40
21/2
/00
20:0
0
22/2
/00
9:20
22/2
/00
22:4
0
23/2
/00
12:0
0
24/2
/00
1:20
24/2
/00
14:4
0
25/2
/00
4:00
25/2
/00
17:2
0
26/2
/00
6:40
26/2
/00
20:0
0
27/2
/00
9:20
27/2
/00
22:4
0
28/2
/00
12:0
0
Period of test
Slag
col
lect
or le
vel (
mm
)
0
20
40
60
80
100
120
140
160
180
200
Slag
cru
sher
inte
nsity
(A) a
nd h
eat f
lux
dens
ity
in re
actio
n ch
ambe
r (kW
/m2 )
Allowed level < 3400 mm
Slag crusher intensity
Slag collector level
Heat flow density in reaction chamber
Figure 78. Main data of the slag extraction system during the tests. Test 1.
THERMIE TEST No. 2
0
500
1000
1500
2000
2500
3000
3500
4000
6/3/
00 5
:00
6/3/
00 1
0:00
6/3/
00 1
5:00
6/3/
00 2
0:00
7/3/
00 1
:00
7/3/
00 6
:00
7/3/
00 1
1:00
7/3/
00 1
6:00
7/3/
00 2
1:00
8/3/
00 2
:00
8/3/
00 7
:00
8/3/
00 1
2:00
8/3/
00 1
7:00
8/3/
00 2
2:00
9/3/
00 3
:00
9/3/
00 8
:00
9/3/
00 1
3:00
9/3/
00 1
8:00
9/3/
00 2
3:00
10/3
/00
4:00
10/3
/00
9:00
10/3
/00
14:0
0
10/3
/00
19:0
0
11/3
/00
0:00
11/3
/00
5:00
Period of test
Slag
col
lect
or le
vel (
mm
)
0
20
40
60
80
100
120
140
160
180
200
Slag
cru
sher
inte
nsity
(A) a
nd h
eat f
lux
dens
ityin
reac
tion
cham
ber (
kW/m
2 )
Allowed level < 3400 mm
Slag crusher intensity
Slag collector level
Heat flow density in reaction chamber
Figure 79. Main data of the slag extraction system during the tests. Test 2
130
THERMIE TEST No. 3
0
500
1000
1500
2000
2500
3000
3500
4000
14/3
/00
22:3
0
15/3
/00
3:30
15/3
/00
8:30
15/3
/00
13:3
0
15/3
/00
18:3
0
15/3
/00
23:3
0
16/3
/00
4:30
16/3
/00
9:30
16/3
/00
14:3
0
16/3
/00
19:3
0
17/3
/00
0:30
17/3
/00
5:30
17/3
/00
10:3
0
17/3
/00
15:3
0
17/3
/00
20:3
0
18/3
/00
1:30
18/3
/00
6:30
18/3
/00
11:3
0
Period of test
Slag
col
lect
or le
vel (
mm
)
0
20
40
60
80
100
120
140
160
180
200
Slag
cru
sher
inte
nsity
(A) a
nd h
eat f
lux
dens
ityin
reac
tion
cham
ber (
kW/m
2)
Allowed level < 3400 mm
Slag crusher intensity
Slag collector level
Heat flow density in reaction chamber
Figure 80. Main data of the slag extraction system during the tests. Test 3
THERMIE TEST No. 4
0
500
1000
1500
2000
2500
3000
3500
4000
19/3
/00
6:00
19/3
/00
16:0
0
20/3
/00
2:00
20/3
/00
12:0
0
20/3
/00
22:0
0
21/3
/00
8:00
21/3
/00
18:0
0
22/3
/00
4:00
22/3
/00
14:0
0
23/3
/00
0:00
23/3
/00
10:0
0
23/3
/00
20:0
0
24/3
/00
6:00
24/3
/00
16:0
0
25/3
/00
2:00
25/3
/00
12:0
0
25/3
/00
22:0
0
26/3
/00
9:00
26/3
/00
19:0
0
27/3
/00
5:00
Period of test
Slag
col
lect
or le
vel (
mm
)
0
20
40
60
80
100
120
140
160
180
200
Slag
cru
sher
inte
nsity
(A) a
nd h
eat f
lux
dens
ity
in re
actio
n ch
ambe
r (kW
/m2)
Allowed level < 3400 mm
Slag crusher intensity
Slag collector level
Heat flow density in reaction chamber
Figure 81. Main data of the slag extraction system during the tests. Test 4
131
4.3.3.2.2. Waste Heat Boiler
During the first long gasifier operation run (August 99), high gas outlet temperatures at HP-Boiler, which
were limiting the gasifier load, were noticed. These temperatures (higher than the design ones) indicate
that a boiler is fouling. The monitoring of the fouling is carried out by a computing model. This model
solves energy balances, for every heat exchanger in HP and IP boiler, obtaining the fouling factor (F) from
the overall heat transfer coefficient (U):
( ) Fh
1AA
eφπλeA
h1
AA
1U
outout
t
text
tt
inin
t +×+−××
×+×
= /2/
Fouling factors in every test were registered and compared, however no influence of different fuels was
observed in fouling behaviour. In every test, fouling factor increases with the operation time. The
following figure shows fouling behaviour during the tests.
132
THERMIE TEST No. 1
0,000
0,002
0,004
0,006
0,008
0,010
20/0
2/00
4:0
0
20/0
2/00
16:
00
21/0
2/00
4:0
0
21/0
2/00
16:
00
22/0
2/00
4:0
0
22/0
2/00
16:
00
23/0
2/00
4:0
0
23/0
2/00
16:
00
24/0
2/00
4:0
0
24/0
2/00
16:
00
25/0
2/00
4:0
0
25/0
2/00
16:
00
26/0
2/00
4:0
0
26/0
2/00
16:
00
27/0
2/00
4:0
0
27/0
2/00
16:
00
28/0
2/00
4:0
0
28/0
2/00
16:
00
Foul
ing
(m2 K
/W)
0
20
40
60
80
100
Load
(%)
HP II Fouling HP I Fouling Load
Figure 82. Fouling data during the tests. Test 1.
THERMIE TEST No. 2
0,000
0,002
0,004
0,006
0,008
0,010
06/0
3/00
5:0
0
06/0
3/00
17:
00
07/0
3/00
5:0
0
07/0
3/00
17:
00
08/0
3/00
5:0
0
08/0
3/00
17:
00
09/0
3/00
5:0
0
09/0
3/00
17:
00
10/0
3/00
5:0
0
10/0
3/00
17:
00
11/0
3/00
5:0
0
Foul
ing
(m2 K
/W)
0
20
40
60
80
100
Load
(%)
HP II Fouling HP I Fouling Load
Figure 83. Fouling data during the tests. Test 2.
133
THERMIE TEST No. 3
0,000
0,002
0,004
0,006
0,008
0,010
14/0
3/00
22:
30
15/0
3/00
10:
30
15/0
3/00
22:
30
16/0
3/00
10:
30
16/0
3/00
22:
30
17/0
3/00
10:
30
17/0
3/00
22:
30
18/0
3/00
10:
30
18/0
3/00
22:
30
Foul
ing
(m2 K
/W)
0
20
40
60
80
100
Load
(%)
HP II Fouling HP I Fouling Load
Figure 84. Fouling data during the tests. Test 3.
THERMIE TEST No. 4
0,000
0,002
0,004
0,006
0,008
0,010
19/0
3/00
6:0
0
20/0
3/00
6:0
0
21/0
3/00
6:0
0
22/0
3/00
6:0
0
23/0
3/00
6:0
0
24/0
3/00
6:0
0
25/0
3/00
6:0
0
26/0
3/00
6:0
0
27/0
3/00
6:0
0
Foul
ing
(m2 K
/W)
0
20
40
60
80
100
Load
(%)
HP II Fouling HP I Fouling Load
Figure 85. Fouling data during the tests. Test 4.
134
4.3.3.2.3. Cleaning dedusting system
Cleaning dedusting is one of the critical systems in the Plant. Monitoring of the cleaning dedusting
process is carried out during the operation by the two following parameters:
1. The candle filter fouling factor:
actefref
actef
ref NQCNQTPkP
CCfatorfoulingfiltercandle
/*)/(*)/(* 2−∆
==
Where:
∆p is the differential pressure across the filters,
k is 5.11E-7 K/(m3/h)2,
P and T are the pressure and temperature of the gas respectively,
Nact is the number of active sectors,
Cref 1.389E-4 bar/(m3/h)
and Qef is given by:
15.273*01325.1* T
PQQ nef =
2. The solids in Venturi water which are measured in the laboratory
During these tests, no influence of different fuels was observed in the candle filter behaviour. However,
the candle filter fouling factor increased from the first test to the last one, due mainly to the accumulation
of operation hours.
The following figure shows the performance of this system.
135
THERMIE TEST No. 1
0,0
0,4
0,8
1,2
1,6
2,0
2,4
20/2
/00
4:00
20/2
/00
16:0
0
21/2
/00
4:00
21/2
/00
16:0
0
22/2
/00
4:00
22/2
/00
16:0
0
23/2
/00
4:00
23/2
/00
16:0
0
24/2
/00
4:00
24/2
/00
16:0
0
25/2
/00
4:00
25/2
/00
16:0
0
26/2
/00
4:00
26/2
/00
16:0
0
27/2
/00
4:00
27/2
/00
16:0
0
28/2
/00
4:00
28/2
/00
16:0
0
Period of test
Can
dle
filte
r fou
ling
fact
or
0
40
80
120
160
200
240
Solid
s in
Ven
turi
(ppm
)
Fouling factor candles Solids in Venturi (ppm)
Figure 86. Candle filter performance during the tests. Test 1
THERMIE TEST No. 2
0,0
0,4
0,8
1,2
1,6
2,0
2,4
6/3/
00 5
:00
6/3/
00 1
7:00
7/3/
00 5
:00
7/3/
00 1
7:00
8/3/
00 5
:00
8/3/
00 1
7:00
9/3/
00 5
:00
9/3/
00 1
7:00
10/3
/00
5:00
10/3
/00
17:0
0
11/3
/00
5:00
Period of test
Can
dle
filte
r fou
ling
fact
or
0
40
80
120
160
200
240
Solid
s in
Ven
turi
(ppm
)
Fouling factor candles Solids in Venturi (ppm)
Figure 87. Candle filter performance during the tests. Test 2
136
THERMIE TEST No. 3
0,0
0,4
0,8
1,2
1,6
2,0
2,4
14/3
/00
22:3
0
15/3
/00
3:30
15/3
/00
8:29
15/3
/00
13:2
9
15/3
/00
18:2
8
15/3
/00
23:2
8
16/3
/00
4:27
16/3
/00
9:27
16/3
/00
14:2
6
16/3
/00
19:2
6
17/3
/00
0:25
17/3
/00
5:25
17/3
/00
10:2
4
17/3
/00
15:2
4
17/3
/00
20:2
4
18/3
/00
1:23
18/3
/00
6:23
18/3
/00
11:2
2
Period of test
Can
dle
filte
r fou
ling
fact
or
0
40
80
120
160
200
240
Solid
s in
Ven
turi
(ppm
)
Fouling factor candles Solids in Venturi (ppm)
Figure 88. Candle filter performance during the tests. Test 3
THERMIE TEST No. 4
0,0
0,4
0,8
1,2
1,6
2,0
2,4
19/3
/00
6:00
19/3
/00
18:0
0
20/3
/00
6:00
20/3
/00
18:0
0
21/3
/00
6:00
21/3
/00
18:0
0
22/3
/00
6:00
22/3
/00
18:0
0
23/3
/00
6:00
23/3
/00
18:0
0
24/3
/00
6:00
24/3
/00
18:0
0
25/3
/00
6:00
25/3
/00
18:0
0
26/3
/00
6:00
26/3
/00
18:0
0
27/3
/00
6:00
Period of test
Can
dle
filte
r fou
ling
fact
or
0
40
80
120
160
200
240
Solid
s in
Ven
turi
(ppm
)
Fouling factor candles Solids in Venturi (ppm)
Figure 89. Candle filter performance during the tests. Test 4.
137
4.3.3.3. Fuel consumption and other consumables
Data of fuel consumption and other consumables for each test mixture is shown in the table.
Mixture 1 Mixture 2 Mixture 3 Mixture 4(39%coal–61%coke) (45%coal–55%coke) (54%coal–46%coke) (58%coal–42%coke)
Operation hours 4 4 4 4
Gasifier load (%) 84.5 93.1 91.2 85.0
Streams to burners
Fuel (t) 361.1 392.0 391.7 362.1
Limestone (t) 8.36 8.62 8.63 8.03
Oxygen (Nm3) 233,077 247,277 239,587 219,745
HP steam (kg) 40,253 43,068 34,162 28,214
Nitrogen (Nm3) 116,006 124,315 117,416 111,388
Process water
Demineralised water 93.45 86.14 71.91 70
Other consumables
NaOH (kg) 1,829 1,872 2,024 2,264
H2SO4 (kg) 8.19 8.20 6.08 11.38
Table 36. Fuel consumption and other consumables.
138
4.3.3.4. Electricity, by-products and wastes production
Mixture 1 Mixture 2 Mixture 3 Mixture 4(39%coal–61%coke) (45%coal–55%coke) (54%coal–46%coke) (58%coal–42%coke)
Gasifier load (%) 85.5 93.1 91.2 85.0
Operation hours 4 4 4 4
Power
Gas turbine (MWh) 698.2 707.8 664.5 562.1
Steam turbine (MWh) 496.5 531.6 504.9 449.1
By-products
Fly ash (t) 11.95 12.1 11.23 9.50
Slag (t) 61.34 78.62 82.08 101.66
Sulphur (t) 12.9 12.92 11.96 10.2
Wastes
Filter cake (t) 3.89 6.05 4.89 1.58
Table 37. Electricity, by-products and wastes production.
139
4.3.3.5. Gasification behaviour of feedstock
The tests with different feedstock were designed to examine the effect of the different fuels and major
process parameters (oxygen/carbon ratio and steam addition) on the gasification performance.
The tests were carried out using an oxygen purity of 85% and a pressure in the Puertollano gasifier of
approx. 25 bar.
The results of the gasification tests are shown in the following figures.
4.3.3.5.1. Carbon conversion
Carbon conversion achieved during the tests is shown in the following table.
Mixture 1 Mixture 2 Mixture 3 Mixture 4
O2/C feedstock 0.76 0.75 0.73 0.72
C conversion 98.8 98.4 98.5 99.7
Table 38. Carbon conversion during tests.
The best combination of carbon conversion and oxygen consumption was attained with mixture No. 4
(Maximum coal composition). A carbon conversion value of 99.7 was attained with just 0.72 of
O2/feedstock.
140
4.3.3.5.2. Cold Gas Efficiency
Based on the studies carried out in the University of Ulster /1/, the influence of feedstock properties on the
Techno-Economic Performance of IGCC was assessed.
70
72
74
76
78
80
0,7 0,72 0,74 0,76 0,78 0,8
O2/feedstock (m.a.f.) ratio
Col
d G
as E
ffici
ency
(%)
Figure 90. Cold Gas efficiency against O2/ feedstock ratio
70
72
74
76
78
80
60 62 64 66 68 70
Carbon content of the fuel (%)
Col
d G
as E
ffici
ency
(%)
Figure 91. Cold Gas Efficiency against fuel carbon content.
141
70
72
74
76
78
80
20 22 24 26 28 30
Ash content of the fuel (%)
Col
d G
as E
ffici
ency
(%)
Figure 92. Cold Gas Efficiency against fuel ash content.
70
72
74
76
78
80
16 17 18 19
Volatile matter of the fuel (%)
Col
d G
as E
ffici
ency
(%)
Figure 93. Cold Gas Efficiency against fuel volatile matter.
A series of correlation studies was performed to try to identify which of the fuel properties was having the
most significant effect on efficiency. It was found out that the fuel ash content, carbon content and volatile
matter are some of the most significant fuel properties with regard to efficiency.
142
The last graphs show the decrease in efficiency when increasing fuel ash content and volatile matter and
the increase when increasing O2/feedstock ratio, as well as the increase in efficiency by increasing fuel
carbon content. This tendency holds true for the simulation models based on the Shell gasifier and
therefore it can be concluded that for entrained flow gasification systems fuels with a higher carbon
content display the best performance.
143
4.3.3.5.3. Thermal Efficiency
Thermal efficiency refers to the part of the heating value of the fuel (HHV) which is transferred in the
process to other forms of usable energy (heating value of cold gas and enthalpy of the steam produced).
In the tests, values of 90.43% were obtained during the first test, 91.17% during the second test, 90.51%
during the third test and 91.35% during the last one.
4.3.3.5.4. Slag/ash split
The term slag/ash split is defined as the fraction of the fuel ash leaving the Puertollano gasifier as molten
slag through the slag hole. It is desirable to have a high slag/ash split because slag is an inert, vitreous
material and therefore exhibits optimum leachable quality.
In the gasification tests slag/ash splits of between 86.5% and 90.1% were achieved. This ratio increases
with the O2/feedstock ratio and with the ash content in feedstock, as the following figure shows.
80
82
84
86
88
90
92
20 22 24 26 28 30Ash in feedstock (%)
Slag
/ash
spl
it (%
)
Figure 94. Slag/ash split.
144
4.3.3.6. Main data on emissions and by-products
4.3.3.6.1. Emissions during the tests
During all of the tests, emissions figures were well within EEC and Spanish limits. This demonstrates the
excellent environmental performance of the Puertollano plant.
0
50
100
150
200
250
300
350
400
450
500
mg/Nm3
SO2 NOx Particulate emission(x100)
MIXTURE No. 1
EEC 88/609 ELCOGAS average
0
50
100
150
200
250
300
350
400
450
500
mg/Nm3
SO2 NOx Particulate emission(x100)
MIXTURE No. 2
EEC 88/609 ELCOGAS average
0
50
100
150
200
250
300
350
400
450
500
mg/Nm3
SO2 NOx Particulate emission (x100)
MIXTURE No. 3
EEC 88/609 ELCOGAS average
0
50
100
150
200
250
300
350
400
450
500
mg/Nm3
SO2 NOx Particulate emission(x100)
MIXTURE No. 4
EEC 88/609 ELCOGAS average
Figure 95. Emission data during fuel tests.
145
g/kWh
Dust 0.1 NOx 0.4Dust 0.02
BASIS
Feedstock (3.2 % S, 20.7 % Ash and HHV = 23.12 MJ/kg) Gross production 320 MW Gross efficiency (HHV) 37.5 % (PC and AFBC), 46% (IGCC)
LNB (50%)ESP (99.2%)
AFBCCyclone filters (96%)
PULVERIZED COALNo gas treatment
PULVERIZED COALDeSOx (90%)
IGCC PUERTOLLANOSulphur removal (99.9%)
SO2 25.3
NOx 4.5
Dust > 40
PC PC AFBC IGCC
Dust 0.3SO2 1.4NOx 0.8
SO2 2.5NOx 2.3
SO2 0.07
NOx 0.240 NOx 0.239 NOx 0.633 NOx 0.111Dust 0.0013 Dust 0.0010 Dust 0.0001 Dust 0.0002
Mixture No. 1
IGCC PUERTOLLANOIGCC PUERTOLLANO
Mixture No. 3 Mixture No. 4
IGCC PUERTOLLANO IGCC PUERTOLLANO
SO2 0.057
Mixture No. 2
SO2 0.027SO2 0.036 SO2 0.039
Figure 96. Comparison of emission levels during fuel tests.
146
4.3.3.6.2. Mass balance and trace elements in the by-products
The following table shows the main figures in terms of by-product composition.
Test 1 Test 2 Test 3 Test 4
Slag Fly
ash
Filter
cake
Slag Fly
ash
Filter
cake
Slag Fly
ash
Filter
cake
Slag Fly
ash
Filter
cake
Carbon wt. % mf 2.13 2.84 34.56 0.35 2 33.56 0.23 3.3 33.77 0.62 6.13 52.11
Total sulphur wt. % mf 0.29 0.89 2.13 0.25 0.91 2.48 0.28 1.11 2.09 0.32 1.37 3.03
Ash wt. % mf 97.91 96.15 66.24 99.83 97.02 66.17 99.98 95.59 67.36 99.32 92.08 47.12
Ash Analysis
Fe2O3 wt. % 4.41 4.82 7.38 6.17 4.92 8.80 5.78 4.82 8.26 4.31 4.72 9.51
SiO2 wt. % 64.40 63.41 61.83 57.72 62.99 56.27 55.04 61.43 56.76 58.89 63.66 54.92
Al2O3 wt. % 22.29 22.57 22.78 26.85 22.87 26.55 28.17 23.86 26.56 24.80 21.39 26.14
CaO wt. % 5.42 3.13 4.15 5.31 3.02 3.26 6.72 3.36 3.28 7.90 4.12 4.77
MgO wt. % 0.77 0.73 0.77 1.06 0.79 0.85 1.00 0.73 0.86 1.10 0.83 0.92
Na2O wt. % 0.30 0.48 0.38 0.41 0.45 0.40 0.33 0.54 0.41 0.35 0.58 0.47
K2O wt. % 1.78 3.70 2.01 1.86 3.75 3.01 2.16 3.95 3.04 1.95 3.65 2.39
TiO2 wt. % 0.56 0.64 0.60 0.71 0.64 0.72 0.70 0.64 0.72 0.63 0.58 0.72
P2O5 wt. % 0.03 0.48 0.06 0.03 0.55 0.07 0.04 0.63 0.06 0.02 0.43 0.11
MnO wt. % 0.03 0.04 0.04 0.06 0.04 0.07 0.06 0.04 0.06 0.05 0.04 0.06
Table 39. Composition of solid residues.
147
The following figure shows the distribution of trace elements among different by-products.
MIXTURE No. 1
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Zn Sb V Cr Sn Ni Cu Cd Pb As
Filter cake Slag Fly ash
Figure 97. Distribution of trace elements among by-product streams. Mixture 1
MIXTURE No. 2
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Zn Sb V Cr Sn Ni Cu Cd Pb As
Filter cake Slag Fly ash
Figure 98. Distribution of trace elements among by-product streams. Mixture 2
148
MIXTURE No. 3
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Zn Sb V Cr Sn Ni Cu Cd Pb As
Filter cake Slag Fly ash
Figure 99. Distribution of trace elements among by-product streams. Mixture 3
MIXTURE No. 4
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Zn Sb V Cr Sn Ni Cu Cd Pb As
Filter cake Slag Fly ash
Figure 100. Distribution of trace elements among by-product streams. Mixture 4
149
Feedstock ash is recovered mainly as an inert, vitreous material named slag. Slag/ash ratio increases with
the ash content in feedstock, as observed before (Slag/ash split).
Distribution of fuel ash in the solid outlet streams
0
20
40
60
80
100
(%)
Fly ash 15 13 11 8Slag 85 87 89 92
Mixture No.1 Mixture No.2 Mixture No.3 Mixture No.4
Figure 101. Distribution of ash among by-product streams.
150
4.3.3.6.3. Wash and Venturi water composition
The following table shows the main figures for wash and Venturi water .
Mixture 1 Mixture 2 Mixture 3 Mixture 4
Washwater
Venturiwater
Washwater
Venturiwater
Washwater
Venturiwater
Washwater
Venturiwater
pH 10.6 7.5 11.9 7.4 9.8 7.4 10.2 8.4
F- mg/l 430 708 395 625 619 695 400 342
Cl- mg/l 2,862 4,385 2,338 3,714 5,7 6,189 3,169 2,764
NH3+ mg/l 28 422 46.6 584 77.1 838 1,341 749
S2- mg/l 35 216 51 243 19 99 2,91 3,822
SO4- mg/l 266 - 205 - 187 - 143 230
HCOO- mg/l 182 283 211 263 548 577 512 581
CN- total mg/l 1 8.8 0.8 9.3 2.4 15 8.3 3.4
Solid content mg/l 90 209 55 87 25 25 32 41
Table 40. Composition of wash and Venturi water.
151
4.3.3.7. Thermo-economic diagnosis
The Thermo-economic analysis has been carried out by TDG system, a tool specifically developed for
ELCOGAS and co-financed by the THERMIE programme (Contract no. SF-0200-95 ES/IT/FR:
Puertollano project activities to improve the efficiency, availability and economics of the current and
future IGCC). TDG, used as an engineering analysis calculator, permits a relative comparative analysis
between different working scenarios.
In the following tables, main performance input and output data are listed for test balances. The raw gas
composition is taken at the outlet of the Puertollano gasifier and includes the nitrogen from fly ash filter
cleaning.
Mixture 1 Mixture 2 Mixture 3 Mixture 4
Input Data 16/03/00 11:00 24/03/00 12:25 25/02/00 12:00 7/03/00 11:00
Feedstock composition
Moisture wt. % 0.75 1.04 1.29 0.93
Carbon wt. % mf 68.8 65.61 62.76 60.66
Hydrogen wt. % mf 3.24 3.19 3.11 3.13
Oxygen (by difference) wt. % mf 1.89 2.69 3.36 3.68
Nitrogen wt. % mf 1.52 1.3 1.49 1.27
Sulphur wt. % mf 3.82 3.47 3.28 3.0
Chlorine ppm mf 722 685 482 524
Ash wt. % mf 20.64 23.69 25.95 28.21
Higher heating value kJ/kg mf 26,891 25,536 24,699 23,612
Table 41. Performance Input Data.
152
Mixture 1 Mixture 2 Mixture 3 Mixture 4
Output Data 16/03/00 11:00 24/03/00 12:25 25/02/00 12:00 7/03/00 11:00
Gasification temperature ºC 1,706 1,735 1,746 1,797
Gasifier pressure bar 25.1 23.87 24.87 23.54
Raw gas composition (dry)
H2 vol. % mf 20.8 20.83 20.8 19.45
CO vol. % mf 61.14 60.1 59.38 59.65
CO2 vol. % mf 1.76 2.69 2.81 3.75
N2 + Ar vol. % mf 15.09 15.22 15.87 16.07
H2S + COS vol. % mf 1.21 1.16 1.13 1.07
H2O vol. % 3.22 4.26 4.36 3.4
CH4 ppm 62.36 56.09 47.17 42.25
Clean gas composition
H2 vol. % mf 21.11 21.17 21.14 19.8
CO vol. % mf 62.06 61.1 60.36 60.7
CO2 vol. % mf 1.43 2.19 2.29 3.05
N2 + Ar vol. % mf 15.34 15.47 16.14 16.36
H2S + COS vol. % mf 0 0 0 0
H2O vol. % 0.07 0.07 0.07 0.08
Low Heat Value kJ/kg 9,911 9,751 9,646 9,355
O2/feedstock ratio tpu 0.70 0.71 0.72 0.73
H2O/feedstock ratio tpu 0.14 0.15 0.12 0.11
Carbon conversion % 98.8 98.4 98.5 99.7
Cold gas efficiency (HHV) % 76.07 74.5 74.19 74.07
Thermal efficiency (HHV) % 91.35 90.51 90.43 91.17
Slag/ash split % 84.7 88.4 86.5 90.1
Gasifier load % 84.5 93.1 91.2 85.0
Total power MW 290.2 303 287.8 247.5
Gas turbine power MW 168.7 173.0 163.0 137.8
Steam turbine power MW 121.5 130.0 124.8 109.7
IGCC gross efficiency % 46.12 46.06 46.21 44.64
CC gross efficiency % 50.25 50.7 50.77 48.86
Auxiliary power MW 39.95 41.73 37.3 38.11
Table 42. Performance Output Data.
153
4.3.3.7.1. Mass balances
The following table shows mass balances of the test. Mass balances incorporate data from around the
Puertollano gasifier after quenching.
Input streams
Mixture 1 Mixture 2 Mixture 3 Mixture 4
Feedstock kg/s 24.06 26.53 25.98 24.22
C (feedstock) wt. % 68.29 64.43 61.96 60.2
Oxygen to the gasifier kg/s 22.35 23.67 22.89 20.92
Steam to the gasifier kg/s 2.74 2.93 2.33 1.91
Nitrogen to the gasifier kg/s 7.07 7.12 6.65 7.25
Total in kg/s 56.22 60.25 57.85 54.3
Output streams
Raw gas, dry kg/s 50.87 53.52 51.04 46.48
Slag, dry kg/s 4.26 5.46 5.7 7.06
Fly ash, dry kg/s 0.83 0.84 0.78 0.66
Filter cake, dry kg/s 0.27 0.42 0.34 0.11
Total out kg/s 56.23 60.24 57.86 54.31
Table 43. Mass balances.
154
4.3.3.7.2. Heat balances
The following table shows the heat balances for the tests.
Gasifier Energy Balance Mixture 1 Mixture 2 Mixture 3 Mixture 4
Feedstock to burners kW 649,578 680,155 644,560 574,648
Oxygen to burners kW 3,933 4,161 4,027 3,680
Steam to burners kW 7,679 8,210 6,536 5,362
Nitrogen to burners kW 120 126 127 120
Total in kW 661,310 692,652 655,250 583,810
Raw gas kW 638,872 661,844 628,386 557,478
Slag + Filter cake kW 5,548 8,854 7,987 2,251
Energy extracted from the
combustion chamber
kW 9,825 10,194 7,994 10,573
Energy extracted from the slag kW 8,084 10,364 12,146 12,586
Total out kW 662,329 691,256 656,513 582,888
Table 44. Heat Balances.
155
4.3.3.7. 3. Financial costs
For the purposes of this study, the following scenario has been set:
Cost PTA/t Euro/t
Coal 5592 33.6
Pet-coke 2701 16.2
Limestone 1528 9.2
Demi-water 160 0.96
Table 45. Cost fixed for the financial study.
The following table shows the main figures related to financial costs obtained from the fuel tests.
Parameters Mixture 1 Mixture 2 Mixture 3 Mixture 4
Feedstock consumption t/h 91.3 100.9 98.7 92
Feedstock cost pta2/t 4,074 4,094 4,083 4,106
Syngas cost pta/th 0.829 0.895 0.914 0.964
Gas Turbine energy cost pta/kWh 1.29 1.39 1.42 1.56
Steam Turbine energy cost pta/kWh 2.31 2.41 2.47 2.53
Net power sent to the grid MWh 250.2 261.3 250.6 209.4
Net energy cost pta/kWh 1.81 1.92 1.95 2.1
Table 46. Financial costs.
A summary of these results is given in the following figures.
2 1 Euro = 166.386 pta.
156
Figure 102. Test No. 1 (Mixture 3).
157
Figure 103. Test No. 2 (Mixture 4).
158
Figure 104. Test No. 3 (Mixture 2).
159
Figure 105. Test No. 4 (Mixture 1).
160
4.3.4. REFERENCES
/1/ Evans, R. H.; Huang Ye; Millar S.; McMullan J.T. and Williams B. C. The influence of feedstock
properties on the techno-economic performance of coal fired IGCC. University of Ulster, Energy
Research Centre, Cromore Road Coleraine Co. Londonderry N. Ireland, UK BT52 1SA. Gasification 4
The Future, 11-13 April 2000.
/2/ Evaluation of the performance of a coal/petroleum coke mixture in the PRENFLO coal gasification
process. ENDESA, KRUPP KOPPERS. October 1992.
/3/ U.S. coal test at the PRENFLO demonstration plant. EPRI. May 1989.
/4/ Demonstration and industrial pilot projects in the field of energy (EEC regulation No 3640/85). EUR
13091 EN. 1990.
161
5. IMPROVEMENTS FOR FUTURE IGCC PLANTS
5.1. ASSESSMENT OF THE GLOBAL OPERATION RESULTS FOR FUTURE IGCC
PLANTS
In terms of design principles and components, the Puertollano power plant is the most advanced IGCC
concept with the highest level of efficiency of the IGCC plants currently in operation or under
construction. Nevertheless, when comparing the state of technology at the time of the design of this plant
with the present status, it can be seen that a degree of technical progress has been achieved in the
meantime.
Based on the design principles of the Puertollano power plant, an advanced IGCC concept named “IGCC
98” was drawn up as part of the JOULE III Programme project “Contract JOF3-CT95-0004”, financed by
the European Commission. The tasks of this project were to investigate the potential efficiency
improvements and the potential reduction in cost for manufacturing and assembly (plant delivery price) of
a Puertollano type IGCC power plant and to assess the economical and environmental impact.
Besides the Universities of Essen and Ulster and the Netherlands Energy Research Foundation ECN, the
companies Krupp Uhde and Siemens companies participated in this project. They manufactured and
supplied major components for the Puertollano IGCC power station. Siemens has also delivered the
combined gas and steam turbine plant for the Buggenum IGCC power station. They channelled the
knowledge gained from the engineering of these plants into this project and will also use the design
principles and know-how brought together in the JOULE project for subsequent IGCC power plants.
The “IGCC 98” concept is based on qualified available materials and proven processes. It is characterised
by an increase in efficiency and reduced capital requirements compared with former IGCC plants. The
influence of several process parameters and changes in the design were investigated. Also, the efficiency
potential of future IGCC concepts with more advanced components and process parameters was studied.
Nevertheless, IGCC 98 improvements, based on the experience gained from actual operation in the
Puertollano Power plant up to August 2000, have led to the ELCOGAS advanced IGCC concept: “IGCC
2000”.
162
Several process modifications based on actual operation experience, aiming at higher efficiency as well as
at cost reduction have been performed and have led to the IGCC 2000 concept (following figure).
Mixedfuel
Coalpreparation
IP
HP
Gasifier
Slag
O2
IP
N2CoalFeed
Raw gas
Waste WaterTreatment
Venturi
Improvedcandlefilter
Clean gassaturator
COSHydrolysis
Clean gas
Dedustinggas
MDEA ClausPlant
Sulphur
Air
QuenchGas
AirSeparation
Unit
O2 N2
DiluentN2
Diluent N2Saturator
Fuel Gas
Exhaust Gas
GasTurbine
Air
G
Flue Gas
Heat RecoverySteam
Generator
GLPIPHP
Make-upwater
BFWTank
Condensate
LP
Saturation WaterPreheat
IP
HP
Reheat
SteamTurbine CondenserFly
ash
Filter cakeIP
Figure 106. IGCC 2000 simplified flow diagram.
163
5.2. ASSESSMENT OF THE DIFFERENT PROCESS PARTS
5.2.1. PROCESS OPTIMISATION AND ADJUSTMENT
5.2.1.1. Coal dust preparation
The Puertollano IGCC Power Plant was designed for a coal-coke mixture (1:1) as fuel. Nevertheless,
based on results from the THERMIE tests carried out with different fuel mixtures (described above), the
Puertollano gasifier allows variations of up to 10% of coal/coke composition in the mixture without
significant changes into the process. Fuel mixing does not require an extremely high precision, thus fuel
can be mixed in the Coal Yard, so improving control problems and saving on investment in equipment.
The coal is ground in mills using nitrogen for drying. The drying circuit is heated up to about 250 ºC by
IP-steam and additional burning of natural gas. As a result of cost optimisations, no LP-steam is
consumed for heating. IP-steam and natural gas cost is quite well balanced, although drying circuit
availability for start-up and shutdown operation is worse with IP-steam than burning natural gas. A dual
drying circuit using only natural gas and the produced syngas could be studied.
Currently two circuits with two mills are installed in the plant, a system with two circuits and three mills
or three circuits and four mills could be studied. Availability of the drying circuits has to be improved by
increasing their robustness.
According to the European trend, new “green” fuels are being studied (biomass, wastes, etc.) for mixing
in small quantities to the original mixture.
5.2.1.2. Coal dust conveying, sluicing and feeding
The main problem in the coal sluicing and feeding system is the dilution of N2 in the fuel. A better
mechanic design has to lead to a N2 consumption reduction and to an improvement of this system
availability. Bridging in the equipment cones and density transient period in the feed bin and lock hoppers
discharge have to be avoided.
164
The prepared coal dust, with a residual moisture content of about 1.2% wt, could be transported
pneumatically under high pressure in dense phase flow with conveying vessels to the coal feed bin. High
pressure and high-density pumps could be studied. In this way, lock hopper system would be necessary
and the weight of the gasification building could be reduced considerably. A large concrete building may
not be necessary.
5.2.1.3. Gasifier and gas quenching
In the Puertollano plant, the gasifier is started with an atmospheric pressure igniter. After a trip the
gasification system has to reduce its pressure down to atmospheric one before starting-up again. To avoid
this loss of time, an igniter, able to work at high pressure, integrated either with the start-up burner or with
one of the gasifier burners would have to be designed. Flame and combustion performance must be
monitored. Pyrometry and spectrometry studies need to be carried out for this purpose.
Inside the gasification chamber, the fuel is converted to mainly to CO and H2. The gas residence time is
only a few seconds. The raw gas leaves the gasification chamber at a temperature of about 1300 ºC. At the
outlet, the raw gas is quenched by recycled cold gas to a temperature below 800 ºC. A study into this
optimum temperature value should be carried out.
Auxiliary burners could be removed from a new plant design.
5.2.1.4. Waste Heat Recovery System
One of the main process problems of the Puertollano plant is the fouling in the Waste Heat Recovery
System produced by fly ash deposition. Fouling in HP surfaces leads to an increase of temperatures above
permitted limits for some of the materials.
The cleaning system is performed by rappers. Rapping system versus blowing system, vibration effects
and rapper layout have to be assessed. This fouling can be mitigated with higher velocities of the gas. A
new boiler design would have to confer suitable velocities of the gas to avoid fly ash deposits.
A better selection of materials for the economiser and HP/IP heat transfer surface distribution and design
is necessary in a new plant design. Increasing HP surface has to be studied.
165
5.2.1.5. Slag handling
The main problem of the slag handling system is fine slag filtration. Filters could be replaced by a settling
system while, in addition, the slag water circuit could be simplified.
The produced filter cake has a high carbon content and it can be recycled to the gasifier.
Only one slag sluicing line and one slag extractor are necessary for discharging. One of the slag lock
hoppers and one of the slag extractors could be removed in a new plant design.
5.2.1.6. Dry dedusting system
Compared with a combined dry/wet dedusting system consisting of a cyclone (coarse dust) and a Venturi
scrubber (fine dust), the net plant efficiency is 0.45% point higher when a dry dedusting system is applied,
due mainly to the lower pressure drop in the smaller Venturi scrubber, reducing losses due to a higher
temperature of the recycled gas. The dry dedusting system also has economic advantages compared with
the wet dedusting system.
The dedusting system is one of the critical systems in the Puertollano plant. This system consists of two
candle filter devices. In new plant designs (IGCC 98), a cyclone separator is included before a candle
filter to remove and recycle coarse fly ash with high carbon content. However, due to the Puertollano fly
ash characteristics (very low carbon content and very small particle size) nor cyclone separator neither
recycling is advised for future designs.
In order to maintain a high efficiency filtration, the cleaning of candle filters must be improved. An
assessment of different filtering elements and materials need be carried out for a new plant design.
The system for recycling fly ash is not necessary owning to the poor carbon content of the fly ash. The fly
ash handling system can be greatly simplified and its cost reduced by removing the fly ash recycling
system. The feed bin was designed to have a higher pressure than the gasifier in order to return fly ash to
the gasifier. The fly ash feed bin, distributor and discharge vessels can be removed, discharging fly ash
directly from the lock hoppers to the fly ash bunker.
166
In the design, only a small part of the fly ash flow was not recycled to the gasifier. This part was
transported via discharge vessels to the fly ash bunker to be stored before being taken away by truck. The
designed mass flow rate of fly ash to discharge was 150 kg/h (100 kg/h on a dry basis) at full load.
However, in the actual operation all fly ash is discharged (about 2000 kg/h) and the bunker, where fly ash
is stored, does not have enough capacity. Trucks have to take away fly ash too frequently. For a new plant
design, a fly ash bunker, with at least one-week storage capacity, should be designed.
5.2.1.7. Wet scrubbing and gas stripping
The downstream Venturi scrubber is only designated for the removal of water-soluble gaseous pollutants.
This system displays a correct behaviour, although an improvement to materials (to avoid corrosion)
could increase its availability. Studies into surface treatments of pipes could be carried out.
Controlling filters had to remove solids present in the wash water stemming from the wet scrubbing
process. However, these filters can be removed due to the high degree of efficiency of the candle filters
and their poor capacity of filtration in case of candle filter failure.
5.2.1.8. Desulphurization system
This system presents an excellent performance. After the good performance in formate removing
demonstrated for the pilot Desalting Unit, an industrial Desalting Unit should be considered in new plant
designs.
The new MDEA-α type (with COS removing capacity), Super Claus plant (efficiency of 99.8%) and
recycling compressor should be assessed technically, economically and environmentally (taking into
account new environmental standards) before a new plant design.
5.2.1.9. Air separation unit (ASU)
This system has shown a good performance during operation of the Puertollano plant. Nevertheless, some
improvements could be carried out.
167
The liquid N2 storage capacity could be increased. A start-up low capacity (30%) compressor improves
the availability of this unit. A more flexible control range in oxygen purity should be considered and
oxygen storage would not be necessary.
5.2.1.10. Saturator
The clean coal gas from the sulphur removal unit has to be moistened and heated prior to its injection in
the gas turbine. In the clean gas moistening system, saturation of the clean gas with water takes place, in
order to reduce NOx formation during gas combustion reducing the flame temperature. The waste nitrogen
from the air separation unit is used to control NOx formation by fuel gas dilution – further completed with
saturation – and to increase the gas turbine power output.
Research areas to improve this process would be: mixing the waste nitrogen with the clean gas before or
after saturation, saturation of the waste nitrogen only and vapour injection for the dilution of the gas.
5.2.1.11. Gas turbine
Overheating and acoustic oscillations phenomena observed in the combustion chamber during the
commissioning are presently expected to be solved.
In the IGCC concept, where gasifier is integrated with the gas turbine and the gasifier is a piece of
equipment with no oscillations for ambient temperature changes, the gas turbine should absorb
oscillations due to changes in ambient temperatures. A pre-cooler could be installed in the gas turbine.
5.2.1.12. Auxiliary systems (Balance of Plant)
The condenser of the cycle is cooled by means of a system with wet cooling tower system. The circulation
system cools two open circuits, one for the gasification and air separation and the other for the combined
cycle equipment. The pumping station comprises two semiaxial flow pumps, each with a 60% capacity of
the nominal circulating water flow. The cooling water system could be split for each island, avoiding
overly high pumps for Plant start-up or isolated system working.
168
5.2.1.13. Control system
ELCOGAS plant has a Distributed Control System (DCS), which is highly integrated with most of the
systems. The performance and suitability of the DCS have generally been good but the following
improvements should be considered in future IGCC plants:
• Local control systems with “black box“ philosophy to communicate with the DCS are
creating avoidable setbacks and delays during OLM. It is clearly preferable to integrate these
local controls into the main DCS.
• Quality and finished grade of detail engineering has an important effect in installation costs,
start-ups and OLM’s. Detail engineering must be defined more consistently in the project
phase, particularly in:
• Equipment with complex control: Gas turbine control. (ELCOGAS has modified
approximately the 80% of gas turbine control diagrams).
• Alarms engineering: Structured, co-ordinated and user-friendly.
5.2.1.14. General layout
The general layout of ELCOGAS is as shown in figure 108. Of definite importance in ELCOGAS’s
experience is the location of the Sulphur recovery circuit, which is better located to the west of the
gasifier, rather than to the east, together with the balance of the by-product handling systems.
169
Figure 107. General layout of ELCOGAS plant.
170
171
5.3. CONCLUSIONS FOR FUTURE IGCC PLANTS
Some aspects of IGCC technology such as excellent emissions records, high efficiency and flexibility to
use a wide range of fuels including wastes, are already accepted. Other aspects, such as Plant availability
and reliability are still to be improved over the next few years at the existing IGCC Demonstration Plants.
Based on the operating experience at Puertollano IGCC Plant, some improvements, summarised in the
following table, could be carried out.
System/equipment Potential efficiency improvements Reduction in cost for manufacturing,
assembly and operation
Coal dust preparation - Elimination of mixing equipment.
Coal dust conveying,
sluicing and feeding
N2 saving. Elimination of concrete building for coal
storage and lock hopper system.
Gasifier Recycling of filter cake. Removing auxiliary burners.
Waste Heat Recovery
System
Improvement of cleaning system.
Increasing HP surfaces.
-
Slag handling Replacement of filtering system by
settling system.
Simplification of slag water circuit.
Elimination of one slag lock hopper and
extractor.
Dry dedusting filter Improvement of candle filter cleaning
system. Improvement of candle filter
material and design.
Elimination of fly ash feed bin, distribution
and discharge vessels (Recycling system).
Wet scrubbing and gas
stripping
- Controlling filter removing.
Desulphurization
system
Assessment of a Super Claus Plant. -
Air Separation Unit Oxygen storage removing Increase of liquid N2 storage capacity.
Gas turbine Installation of a pre-cooler. New higher
efficiency gas turbines.
-
Auxiliary Systems Cooling water system split
Control systems Integrate local control systems with
“black box” into main DCS.
General arrangement Location of Sulphur Recovery Unit. -
Table 47. Summary of the main system improvements based on the experience in Puertollano.
172
However, if this type of technology is to compete successfully with other clean electricity generation
technologies, plant investment cost must be reduced to around 1,000 US$/kW. This goal will be achieved
by a joint effort between Technology suppliers and Utilities. In order to get this lower price, plant
suppliers must design:
• Improved coal-feeding systems.
• More efficient boilers.
• Improved slag removal systems.
• More efficient ceramic filters.
• Improved gas turbines.
• Improved materials.
In the Combined Cycle and ASU areas, some sub-systems such as the gas turbine, steam power system
and Air Separation Unit are offered today at considerably lower prices than when the Puertollano plant
was ordered. This is partly due to a new generation of gas turbines of greater size and efficiency and
improvements to the materials development of Steam Power Plants.
Over the past few years, major advances have been made in the area of gas turbine development, such as
more efficient blade cooling, higher-temperature materials, lower-loss flow paths and lower-pollution
combustion processes.
Siemens is working on further increasing gas turbine inlet temperature by further improving component
cooling, materials and protective and thermal barrier coatings. Improvements are also underway for
compressor and turbine aerodynamics. The higher turbine inlet temperature and component efficiencies
made possible by these advances have significantly increased gas turbine efficiency and output. These
improvements, in combination with a bottoming steam cycle, have in turn led to the highest rates of
efficiency of all fossil-fuel power plants. Next figure shows the expected IGCC efficiency potential.
173
Puertollanoplant
Net plantefficiency
46
48
50
52
%
54
Efficiencydependingon the coal
used
with low ash bituminous coal and GT inlettemperature 1150ºC (ISO)
with low ash bituminous coal and GT inlettemperature 1120ºC (ISO)
2.4 %
GT inlettemperature
1190ºC (ISO)
0.7 %
GT inlettemperature
1250ºC (ISO)
0.7 %
Higher steamconditions
0.7 %
Improvement ofpower plantcomponents
1.0 %
Dry hot gascleaning
Fuel: Pittsburgh # 8Ambient conditions: 15ºC / 1.013 bar / f = 60%
Condenser pressure: 0.04 bar
State of the art Future development
Figure 108. Expected IGCC Efficiency Potential(*)
Efficiency improvements and cost reductions in coal-based IGCC power plants are important tasks. The
IGCC technology can be competitive compared with modern PC steam power plant. The co-gasification
of coal and biomass in IGCC is a further possibility of reducing CO2 emission and of preserving non-
regenerative fuels.
IGCC technology still has a considerable enhancement potential over the existing demonstration plants,
and possibilities for a second generation of IGCC plants to compete with other clean electricity generation
technologies in the near future appear realistic.
(*) Source: Optimized IGCC Cycles for Future Applications. Siemens AG)
174
During the coming years, competition between types of power systems and fuel resources will continue
and, as long as natural gas remains readily available and relatively inexpensive, natural-gas-based power
systems are likely to be the technology of choice. As natural gas becomes more expensive, lower-cost
energy resource options such as coal and alternative fuels will become increasingly common choices.
Gasification will then prove to be the best technology for providing efficient power and synthetic gas
conversion technologies.
The capital cost for a natural-gas combined cycle is currently well under one-half the cost of a coal IGCC
plant. IGCC is capital intensive; it needs economies of scale and fuel cost advantages to be an attractive
investment option. However, IGCC costs can be lowered when integrated synergistically with industrial
applications. For example, gasifiers can operate on low-cost opportunity feedstocks; can be used to
convert hazardous waste into useful products, reducing or eliminating waste disposal costs; and can co-
produce power, steam, and high value products for use in the market. IGCC will become more
competitive in the long term if, as is happening at present, the natural gas prices increase.
Technical trends will help gasification, include improving gas turbines and poly-generation. Each increase
in combined cycle efficiency directly reduces the size and cost of the gasification facility required to fire
that combined cycle. Advanced intercooled, recuperated, reheat gas turbines have the potential of power-
to-cogeneration heat ratio that is an order of magnitude higher than that possible with steam turbines.
For the future, IGCC will play a role as an alternative for electric energy supply due to this costs levelling
characteristics from the uses of different feedstocks, particularly coal, which are available in most
countries. The present rise in natural gas prices shall trigger this tendency,
On medium terms, the necessity for CO2 emissions control will need to be faced. The IGCC will represent
the best choice for CO2 removal, among all the fossil fuelled technologies, according to the EPRI
assessments made at the last Gasification Technologies Conference of San Francisco (California).
Europe, being a basically energy import area, shall urgently face a decision on this in order to demonstrate
his political and technical leadership and, in the first hand, to benefit from a Super Clean Coal
Technology.
December 2000
ELCOGAS
ACHIEVEMENTS OF THE EUROPEAN IGCCPLANT AT PUERTOLLANO
ACHIEVEMENTS OF THE EUROPEAN IGCCPLANT AT PUERTOLLANO
December 2000
4
THE PROJECTTHE PROJECT
December 2000
5
ELCOGASELCOGAS
European Company incorporated in April 1992 toundertake the planning, construction,management and operation of a 335MW IGCCplant located in Puertollano (Spain)
December 2000000
6
ELCOGAS LOCALIZATIONELCOGAS LOCALIZATION
December 2000
7
SHAREHOLDERSSHAREHOLDERS
EDF
ENDESAIBERDROLASEVILLANACANTABRICOB.W.ESPAÑOLA
EDP
ENEL
NATIONALPOWER KRUPP KOPPERS
SIEMENS
December 2000
8
ELCOGASELCOGAS
ENDESAENDESA
37.9337.93
KRUPP UHDEKRUPP UHDE
1.001.00SIEMENSSIEMENS
2.342.34BWEBWE
2.502.50NATIONAL POWERNATIONAL POWER
4.004.00ENELENEL
4.004.00
EDPEDP
4.004.00
CANTABRICOCANTABRICO
4.004.00
EDFEDF
29.1329.13
IBERDROLAIBERDROLA
11.1011.10
EQUITY SHARE in %EQUITY SHARE in %
December 2000
9
ELCOGAS AN EUROPEAN PROJECTELCOGAS AN EUROPEAN PROJECT
Gasification Unit: Prenflo® Process from KruppKoppersCombined Cycle Unit: SiemensAir Separation Unit: Air LiquideDistributed Control System: SiemensGeneral engineering: Initec and shareholders’engineering departments
December 2000
10
ELCOGAS PROJECT SCHEDULEELCOGAS PROJECT SCHEDULE
PUERTOLLANO IGCC PROJECT BASIC PLAN
ACTIVITY
AWARD OF MAIN EQUIPMENT & ENGINEERING
ENGINEERING AND DESIGN
SITE PREPARATION
GASIFICATION PLANT MANUFACTURING AND SUPPLY
COMBINED CYCLE MANUFACTURING AND SUPPLY
CIVIL WORKS
COMBINED CYCLE ERECTION AND START UP
GASIFICATION ERECTION AND START UP
19971992 1993 1994 1995 1996
December 2000
11
OBJECTIVES AND IMPLEMENTATIONIGNACIO MENDEZ VIGO - ALEJANDRO MUÑOZOBJECTIVES AND IMPLEMENTATIONIGNACIO MENDEZ VIGO - ALEJANDRO MUÑOZ
December 2000
12
PROJECT OBJECTIVESPROJECT OBJECTIVES
Build up and operate an IGCC power plant, takingcare of the following characteristics:
– Development of European technology for IGCC
– Environmentally friendly
– Demonstration of a commercial size IGCC plant
December 2000
13
PROJECT OBJECTIVES:EUROPEAN TECHNOLOGYPROJECT OBJECTIVES:EUROPEAN TECHNOLOGY
Development of the IGCC European technologyfor poor quality and complex fuels (high ash andsulphur content)Scaling up of the existing plant size of theEuropean Gasification technologyHighly integrated IGCC plant using Europeantechnology:– Krupp Koppers. Gasification– Siemens. Combined cycle– Air Liquide. Air separation unit
Collaboration among European utilities &engineering suppliers for the project development
December 2000
14
PROJECT OBJECTIVES: ENVIRONMENTALLYFRIENDLYPROJECT OBJECTIVES: ENVIRONMENTALLYFRIENDLY
Very low gaseous emission levelsSolid wastes:– Inert vitrified slag– High carbon content fly ash recycled to the gasifier
Low level of treated liquid effluents
December 2000
15
PROJECT OBJECTIVES:COMMERCIAL OPERATIONPROJECT OBJECTIVES:COMMERCIAL OPERATION
Competitiveness: low production costs– Fuel cost: < 359 pta/Gj (2.16 €/GJ)– Water cost: 37.31 pta/m3 (0.22 €/m3)
Plant efficiency:– CC gross efficiency/LHV (%): 50.15– IGCC gross efficiency/LHV (%): 47.12
High availability, 6500 full load equivalent hoursof operationDissemination of the results
December 2000
16
PROJECT IMPLEMENTATIONSPROJECT IMPLEMENTATIONS
Plant construction data and budget
Commissioning of the plant
Plant operation data
Conclusions and future developments
December 2000
17
PROJECT IMPLEMENTATIONS:CONSTRUCTION DATAPROJECT IMPLEMENTATIONS:CONSTRUCTION DATA
Main contracts in 1992-1993
Start of civil works at site 1993
First ignition of gas turbine April 1996
Project on budget
December 2000
18
PROJECT IMPLEMENTATIONS:COMMISSIONINGPROJECT IMPLEMENTATIONS:COMMISSIONING
Commercial operation with natural gas in October1996Acceptance of the Air Separation Unit in June1997First gasifier ignition in December 1997First electricity production with syngas in March1998Gas turbine acceptance test with syngas carriedout in March 2000
December 2000
19
PROJECT IMPLEMENTATIONS:PLANT OPERATIONPROJECT IMPLEMENTATIONS:PLANT OPERATION
Plant operation experience with differentfeedstock demonstrates:– Efficient use of poor quality and complex fuels through
an European technology
– Environmentally friendly behaviour of this technology
– Commercial operation viability
December 2000
20
USE OF POOR QUALITY AND COMPLEXFUELSUSE OF POOR QUALITY AND COMPLEXFUELS
Mixture 1 Mixture 2 Design Mixture 3 Mixture 4
Coal Coke Coal Coke Coal Coke Coal Coke Coal Coke
Feedstockcomposition
39% 61% 45% 55% 50% 50% 54% 46% 58% 42%
Moisture wt. % 0.75 1.04 2.00 1.29 0.93
C wt. % (mf) 68.8 65.61 61.68 62.76 60.66
H wt. % (mf) 3.36 3.68 2.92 3.15 3.24
O (bydifference)
wt. % (mf) 1.89 2.69 3.45 3.36 3.68
N wt. % (mf) 1.52 1.3 1.42 1.49 1.27
S wt. % (mf) 3.82 3.47 3.34 3.28 3.0
Cl ppm (mf) 722 685 200 482 524
Ash wt. % (mf) 20.67 23.69 25.17 25.95 2288..2211
H. H. V. MJ/kg(mf)
26.89 25.53 24.09 24.69 23.61
December 2000
21
400
650
50
150
7,5250,9
94
16
109
10 0,223
68
0,0418
340,10
100
200
300
400
500
600
700
SO2 NOx Particulate emission
mg/Nm3, dry gas. 6% O2
EEC 88/609 Design value Mixture No. 1 Mixture No. 2Mixture No. 3 Mixture No. 4
ENVIRONMENTALLY FRIENDLY:EMISSIONSENVIRONMENTALLY FRIENDLY:EMISSIONS
December 2000
22
* Low Limit Detection
** PCDD/FS: Polychlorinated dibenzo-p-dioxins and furans I-TEQ: International Toxicity Equivalent Concentration
(EN1948:1996 < 100 pg/Nm3)
ENVIRONMENTALLY FRIENDLY:EMISSIONSENVIRONMENTALLY FRIENDLY:EMISSIONS
Hg emissions < L.L.D.*PCDD/FS (I-TEQ)** < L.L.D.)
December 2000
23
g/kWh
Dust 0.1 NOx 0.4Dust 0.02
SO2 0.07SO2 2.5NOx 2.3Dust 0.3
SO2 1.4NOx 0.8
SO2 25.3NOx 4.5
Dust > 40
PULVERIZED COAL
No gas treatment
PULVERIZED COAL
DeSOx (90%)
IGCC PUERTOLLANO
Sulphur removal (99.9%)LNB (50%)ESP (99.2%)
AFBC
Cyclone filters (96%)
BASIS Feedstock (3.2 % S, 20.7 % Ahs and HHV = 23.12 MJ/kg) Gross production 320 MW Gross efficiency (HHV) 37.5 % (PC and AFBC), 46% (IGCC)
ENVIRONMENTALLY FRIENDLY:EMISSIONSENVIRONMENTALLY FRIENDLY:EMISSIONS
December 2000
24
ENVIRONMENTALLY FRIENDLY:EMISSIONS (Cont.)ENVIRONMENTALLY FRIENDLY:EMISSIONS (Cont.)
NOx 0.240 NOx 0.239 0.196 NOx 0.111Dust 0.0013 Dust 0.0010 Dust 0.0001 Dust 0.0002
MIXTURE NO. 1
SO2 0.039SO2 0.036 0.067
MIXTURE NO. 2
SO2 0.027
MIXTURE NO. 3 MIXTURE NO. 4
NOx
SO2
IGCC Puertollano NOx 0.4Dust 0.02
SO2 0.07
DESIGN
December 2000
25
ENVIRONMENTALLY FRIENDLY:BY-PRODUCTSENVIRONMENTALLY FRIENDLY:BY-PRODUCTS
More than 85% of fuel ash is inert vitreous slag.Uses:– Roads, construction material manufacturing (cements,
bricks and tiles) and return to the mine as fillerDue to its low carbon content, fly ash is notrecycled, but it is suitable for:– Construction material and additive for concrete
manufacturingSmall portion of high carbon content filter cakefor:– Recycling to the gasifier after dry, additive for
construction material and energetic by-product
December 2000
26
ENVIRONMENTALLY FRIENDLY:EFFLUENTSENVIRONMENTALLY FRIENDLY:EFFLUENTS
ELCOGASvalues
Spanish standard limits(R.D. 927/1988)
Al <1 1As 0.025 0.5Ba <0.2 20B 1.78 5Cd <0.001 0.2
Cr VI <0.050 0.2Fe 1.16 3Mn <0.050 3Ni 0.047 3Hg <0.002 0.05Pb 0.030 0.2Se <0.02 0.03Sn <0.100 10Cu 0.016 0.5Zn 0.172 10
Suspended solids (mg/l)
December 2000
27
ELCOGASvalues
Spanish standard limits(R.D. 927/1988)
CN- <0.05 0.5Cl- 1240 2000S2- <0.2 1F- 0.87 8
NH 4+ 9.13 50P total 0.68 20
Detergents (LAS) 0.13 3
ENVIRONMENTALLY FRIENDLY:EFFLUENTS (Cont.)ENVIRONMENTALLY FRIENDLY:EFFLUENTS (Cont.)
Suspended solids (mg/l)
December 2000
28
PROJECT IMPLEMENTATIONS:COMMERCIAL OPERATIONPROJECT IMPLEMENTATIONS:COMMERCIAL OPERATION
Competitiveness: Low production costs
– Heat rate (gross, LHV): 7894 kJ/kWh
– Raw water consumption: 3 hm3/year
High Plant efficiency
High availability
December 2000
29
Scenario Variable cost3rd quarter 2000
Cost pta/t €/t
Coal 5592 33.6
Pet-coke 2701 16.2
Limestone 1528 9.2
Demi-water 160 0.96
ParametersNo. 1 No. 2 No. 3 No. 4
Feedstock consumption t/h 91.3 100.9 98.7 92
Feedstock cost pta/t 4,074 4,094 4,083 4,106
Syngas cost pta/Th 0.829 0.895 0.914 0.964
Gas Turbine energy cost pta/kWh 1.29 1.39 1.42 1.56
Steam Turbine energy cost pta/kWh 2.31 2.41 2.47 2.53
Net power sent to the grid MWh 250.2 261.3 250.6 209.4
pta/kWh 1.81 1.92 1.95 2.1Net energy variable cost
€/MWh 10.88 11.54 11.72 12.62
COMPETITIVENESS:LOW PRODUCTION COSTSCOMPETITIVENESS:LOW PRODUCTION COSTS
Mixture
December 2000
30
CC IGCC
Design gross efficiency (%) 50.15 47.12
Acceptance test gross efficiency (%) 50.13 45.67
Auxiliary power (MW) 4.3 35
Acceptance test auxiliary power (MW) 3.72 42.64
Design Power (MW) 317.7
Acceptance test Power (MW) 320.6
PLANT EFFICIENCY:IGCC ACCEPTANCE TESTSPLANT EFFICIENCY:IGCC ACCEPTANCE TESTS
December 2000
29
Total accumulative production
December 2000
January-Novemb 2000
Total 1999
187,972MWh
MWh
MWh 334,937
723,241
Total 1998 MWh 8,867
MWh 1.255,017
IGCC GROSS PRODUCTION
COMPETITIVENESS:PRODUCTIONCOMPETITIVENESS:PRODUCTION
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December 2000
30
LAST 12 MONTHSACCUMULATED IGCC PRODUCTIONLAST 12 MONTHSACCUMULATED IGCC PRODUCTION
Gross Output IGCC cumulated last 12 months
0100.000200.000300.000400.000500.000600.000700.000800.000900.000
1.000.000M
Wh
December 2000
31
IMPROVING AVAILABILITYIMPROVING AVAILABILITY
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Availability IGCC & Natural Gas
01020
3040506070
8090
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Gas natural
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December 2000
32
YEAR 2000 IGCC AVAILABILITYAND UNAVAILABILITYYEAR 2000 IGCC AVAILABILITYAND UNAVAILABILITY
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�������������������������������������������������� A S U1 2 ,0 %
Ga s if ic a t io n1 7 ,7 %
Inte g ra t io n4 ,5 %
A v a ila bility3 8 ,2 %
C o m bine d C yc le2 7 ,6 %
% hours
December 2000
36
Mixedfuel
Coalpreparation
IP
HP
Gasifier
Slag
O2
IP
N2CoalFeed
Raw gas
Waste WaterTreatment
Venturi
Improvedcandlefilter
Clean gassaturator
COSHydrolysis
Clean gas
Dedustinggas
MDEA ClausPlant
Sulphur
Air
QuenchGas
AirSeparation
Unit
O2 N2
DiluentN2
Diluent N2Saturator
Fuel Gas
Exhaust Gas
GasTurbine
Air
G
Flue Gas
Heat RecoverySteam
Generator
GLPIPHP
Make-upwater
BFWTank
Condensate
LP
Saturation WaterPreheat
IP
HP
Reheat
SteamTurbine CondenserFly
ash
Filter cakeIP
PROJECT IMPLEMENTATIONS:CONCLUSIONSPROJECT IMPLEMENTATIONS:CONCLUSIONS
€ million
December 2000
37
System/equipment Potential efficiency improvements Reduction in cost for manufacturing,
erection and operation
Coal dust preparation - Elimination of mixing equipment.
Coal dust conveying,
sluicing and feeding
N2 saving. Elimination of concrete building, coal
storage and lock hopper system.
Gasifier Recycling of filter cake. Removing auxiliary burners.
Waste Heat Recovery
System
Improvement of cleaning system.
Increasing HP surfaces.
-
Slag handling Replacement of filtering system by
settling system.
Simplification of slag water circuit.
Elimination of one slag lock hopper and
extractor.
Dry dedusting filter Improvement of candle filter cleaning
system. Improvement of candle filter
material and design.
Elimination of fly ash feed bin,
distribution and discharge vessels
(Recycling system).
PROJECT IMPLEMENTATIONS (cont.)PROJECT IMPLEMENTATIONS (cont.)
December 2000
38
System/equipment Potential efficiency improvements Reduction in cost for manufacturing,
erection and operation
Wet scrubbing and gas
stripping
- Controlling filter removing.
Desulphurisation
system
Assessment of a Super Claus Plant. -
Air Separation Unit Oxygen storage removing Increase of liquid N2 storage capacity.
Gas turbine Installation of a precooler. New higher
efficiency gas turbines.
-
Auxiliary Systems Cooling water system split
Control systems Integrate local control systems with
“black box” in main DCS.
General arrangement Location of Sulphur Recovery Unit. -
PROJECT IMPLEMENTATIONS (cont.)PROJECT IMPLEMENTATIONS (cont.)
December 2000
39
ELCOGAS : SIEMENS CONTRIBUTIONJORGE WIENHOLZELCOGAS : SIEMENS CONTRIBUTIONJORGE WIENHOLZ
December 2000
40
CONSORTIUM SIEMENS/BWESCOPE OF SUPPLYCONSORTIUM SIEMENS/BWESCOPE OF SUPPLY
BWE Scope of Supply– Heat recovery steam generator and GT flue gas duct– Piping system water/steam cycle– Condenser
Siemens Scope of Supply– Gas turboset V94.3 (GT)– Steam turboset KN (ST)– Instrumentation and control for turbosets– Turbine house cranes (GT + ST)– Heat exchangers (cooling air cooler, saturator water
and clean gas preheater)– Saturator system for clean gas– Electrical equipment– Engineering– Overall plant control system
December 2000
41
CONSORTIUM SIEMENS/BWESCOPE OF SUPPLY (Cont.)CONSORTIUM SIEMENS/BWESCOPE OF SUPPLY (Cont.)
Supplementary Orders for Siemens– Design of heat exchangers for the air/nitrogen system
connecting gas turbine and air separation unit– Optimisation study
Background information for the final plant designStart-up and shut down concept for the overall plantEngineering support for integration aspects and the design ofthe overall plant control concept
December 2000
42
Syngas-proven operation40
38
36
34
32
30
281970 1980 1990 2000
%
Gross Efficiency *
Year
Model V84.3A / V94.3A
Model V93
Model V84.3 / V94.3
Lünen
Buggenum, Priolo Gargallo
Puertollano
* Related to natural gas operation, including generator losses
Model V84.2 / V94.2
in IGCC plants
V93
V94.2
V94.3
DEVELOPMENT OF EFFICIENCY LEVELSFOR V-TYPE GAS TURBINESDEVELOPMENT OF EFFICIENCY LEVELSFOR V-TYPE GAS TURBINES
December 2000
43
Basic Definition ⇒ Syngas Diffusion BurnerBasic Design Parameter ⇒ Syngas Dilution (NOx value, flame stability)
Fuel oil(diffusion)
Natural gas+ steam(diffusion)
Air
Siemens Syngas Burner
Syngas
Air
Air
Natural gas(premix)
Fuel oil(premix)
Natural gas(diffusion)
Siemens Hybrid Burner
SYNGAS COMBUSTIONSYNGAS COMBUSTION
December 2000
44
SYNGAS BURNER DESIGN PARAMETERSSYNGAS BURNER DESIGN PARAMETERS
Syngas pressure drop Definition of min. Gas Turbine load in syngas operation Flame stability reason and suppression of pressureoscillations Definition of syngas passage capacity
Syngas swirl angle (recirculation zone) Stable burning conditions without flame blow off or burneroverheating condition
Cross-sectional area of syngas nozzle Adjustment of syngas outlet velocity slightly abovecorresponding air outlet velocity
Swirl perturbators ⇒ Lessons learned fromBuggenum and implemented in Puertollano
Suppression of flame induced pressure oscillations
December 2000
45
GAS TURBINE FUEL GAS AND AIREXTRACTION SYSTEMGAS TURBINE FUEL GAS AND AIREXTRACTION SYSTEM
IGCC - specific feature of Combined CycleapplicationsTasks:– Syngas dilution control (ensuring heating value range)– Optimal heat flow recovering
– Syngas preheating and extracted air cooling– Low temperature utilisation by syngas saturation
– Flushing and inertisation procedures
December 2000
46
GAS TURBINE FUEL GAS AND AIREXTRACTION SYSTEM PUERTOLLANOGAS TURBINE FUEL GAS AND AIREXTRACTION SYSTEM PUERTOLLANO
December 2000
47
3.9 – 5.1MJ/kg
Puertollano
4 – 6 MJ/kg
Buggenum
around 8.6MJ/kgOperational Heating valuerange
ISAB
OPERATIONAL EXPERIENCEOPERATIONAL EXPERIENCE
Initial Combustion Problems in Buggenum andPuertollano are solved and a wide operating rangeestablished
Gas Turbine syngas commissioning period in ISABreduced to 1 MonthDemonstration of new control features for integratedoperation in Puertollano to increase IGCC plant reliabilityPerformance Test procedure with extended scope ofmeasurements and new complex calculationcarried out in Puertollano
31/10/2000
48
Plant/Project ElectricalOutput (net)
GasTurbine
Main Features Start-up
Hörde Steelworks(Germany)
8 MW VM5 Blast-furnace-gas-fired,gas turbine as mechanical drive
1960
U. S. Steel Corp.(Chicago, USA)
20 MW CW201 Blast-furnace-gas-fired gas turbine 1960
Kellermann(Lünen,Germany)
163 MW V93 First CC plant in the world with integratedLURGI coal gasification (hard coal)
1972
Plaquemine(Lousiana, USA)
208 MW 4) 2 x W 501D5 CC plant with integratedDOW coal gasification
1987
Buggenum 1)
(Netherlands)253 MW V94.2 CC plant with integrated
SHELL coal gasification (hard coal)1993 3)
1994/95
Puertollano 1)
(Spain)300 MW V94.3 CC plant with integrated PRENFLO coal
gasification (coal and petroleum coke blend)1996 3)
1997/98
ISAB(Priolo, Italy)
521 MW 2 x V94.2K CC plant with integratedTEXACO heavy-oil gasification (asphalt)
1998 2)
1999
Servola(Italy)
180 MW V94.2K CC plant with steel-making recovery gas 2000
1) Demonstration plant 2) Oil firing 3) Natural-gas firing 4) 160 MW from syngas and 48 MW from natural gas
CC = Combined-cycle V94.2K = V94.2 with modified compressor
APPLICATION OF SIEMENS GAS TURBINETECHNOLOGY FOR UTILISATION OF SYNGASAND STEEL-MAKING RECOVERY GASES
APPLICATION OF SIEMENS GAS TURBINETECHNOLOGY FOR UTILISATION OF SYNGASAND STEEL-MAKING RECOVERY GASES
December 2000
December 2000
49
ELCOGAS : KRUPP UDHE CONTRIBUTIONWOLFGANG SCHELLBERGELCOGAS : KRUPP UDHE CONTRIBUTIONWOLFGANG SCHELLBERG
December 2000
50
IGCC POWER PLANT AT PUERTOLLANOIGCC POWER PLANT AT PUERTOLLANO
Consortium Krupp Uhde (Koppers) andBabcock & Wilcox Española was responsiblefor the gas island– Coal preparation
– PRENFLO ® Gasification
– Desulphurisation
– Claus unit
December 2000
51
Oxygen
Nitrogen
Raw fuel Coalpreparation
PRENFLOgasification
Desul-phurisation
Claus unit
Boiler feed water Sulphur
Claus gas
Recycle gas
Raw gasCoaldust
Clean gas
Steam
GASIFICATION ISLANDGASIFICATION ISLAND
December 2000
52
PRENFLO® PLANT INFÜRSTENHAUSEN/GERMANYPRENFLO® PLANT INFÜRSTENHAUSEN/GERMANY
December 2000
53
Oxygen
Coaldust
Boilerfeed water
1
2
3 4
5
6
7
8
9
10
11
12
13
Steam
Raw gas
Slag
Washwater
1 Cyclone filter2 Lock hopper3 Feed bin4 PRENFLO gasifier5 Slag crusher/collector
6 Slag lock hopper7 Waste heat boiler8 Steam drum9 Filter
10 Fly ash lock hopper11 Fly ash feed bin12 Scrubber13 Quench gas compressor
PRENFLO® ProcessPRENFLO® Process
December 2000
54
ERECTION OF PRENFLO® GASIFIERAND HP-BOILER AT PUERTOLLANO, SPAINERECTION OF PRENFLO® GASIFIERAND HP-BOILER AT PUERTOLLANO, SPAIN
December 2000
55
CO2
COH2
N2 + ArH2S + COS
Total
3.960.522.113.512
100.0
vol. % vol. %vol. % vol. % ppmv
vol. %
1.960.0 22.315.812
100.0
Design Actual
CLEAN GAS COMPOSITION OFPUERTOLLANOCLEAN GAS COMPOSITION OFPUERTOLLANO
December 2000
56
LESSONS LEARNEDLESSONS LEARNED
Scale-up of PRENFLO® Gasification including burnersfrom demonstration plant without problemsDedusting of raw gas with ceramic candles possible,which leads to higher efficiencyProblems with coal dust lock hopper system could besolved (capacity restrictions)Clean coal gas quality is excellent for gas turbineLow environmental impact of total gas islandFly ash and sulphur are saleable productsFull integration of the gas island with air separation andpower block was successful
December 2000
57
SULPHUR STORAGE AREASULPHUR STORAGE AREA
December 2000
59
COMPETITIVENESS FACTORSANDRES FERNANDEZ LOZANOCOMPETITIVENESS FACTORSANDRES FERNANDEZ LOZANO
31/10/2000
60
COST COMPETITIVENESS OFELCOGAS IGCC PLANTCOST COMPETITIVENESS OFELCOGAS IGCC PLANT
High investment cost due to the innovative project technology and theplant demonstration nature
High potential cost reduction for future project investment
Fuel cost less than those of other technologies (except nuclear) owing to:High energy efficiency (higher than other coal plants)Use of low cost fuel (mixture of refinery residuals -coke- and high ashcoal)
Operational and maintenance cost higher than those of a conventionalplant due to the innovative project nature:
Use of sophisticated technology (equipment, material, processes) High plant integration Commercial demonstration phase
INVESTMENT
FUEL
O&M
December 2000
December 2000
61
COST COMPETITIVENESS OFELCOGAS IGCC PLANTCOST COMPETITIVENESS OFELCOGAS IGCC PLANT
Total cost of the electricity generated byELCOGAS IGCC (using syngas) is lower than thecost of generation through nuclear plants andcomparable to conventional domestic coal-firedgeneration plantsVariable cost is lower compared to conventionalgeneration plants, coal- or gas-fired, in thedomestic market
December 2000
62
ELCOGAS IGCC OTHER GENERATION SYSTEMS
High investment cost of theproject (technological investmentcost) compared to othertechnologies.
Cost of IGGC plants will bereduced in the future due to theexperience acquired.
Mature technologies, with a lowerpotential to reduce investmentlevels in the future.
In conventional plants, theinvestment per kW tends to growdue to the addition ofenvironmental investments(desulphurisation).
MAIN ASPECTS OF ELECTRICITY COSTINVESTMENTMAIN ASPECTS OF ELECTRICITY COSTINVESTMENT
December 2000
63
ELCOGAS IGCC OTHER GENERATION SYSTEMS
Uses a cheap mixture of fuel(0.134 € cents/MJ) competitiveagainst imported coal due to theuse of refinery residuals.
High energy efficiency of theproject.
Flexibility to use other fuels(natural gas with a 50.5%efficiency).
Imported coal price slightly higherthan ELCOGAS mixture, fired inconventional PC plants with aworst efficiency.
Lower nuclear fuel cost by kWh.
Higher energy efficiency ofCombined Cycles but with ahigher volatility on natural gasprice.
MAIN ASPECTS OF ELECTRICITY COSTFUELMAIN ASPECTS OF ELECTRICITY COSTFUEL
December 2000
64
MAIN ASPECTS OF ELECTRICITY COSTOPERATIONAL & MAINTENANCEMAIN ASPECTS OF ELECTRICITY COSTOPERATIONAL & MAINTENANCE
ELCOGAS IGCC OTHER GENERATION SYSTEMS
Operational and maintenance costsof this “first of its kind” plant shouldbe reduced in the near future(learning curve).
Higher operational andmaintenance costs due to itsdemonstration plant nature.
Lower operational andmaintenance cost of conventionalplants due to the simplicity of itsprocess and the experienceacquired.
Other power plants belongs tobigger companies witch deliverscommon services, and does nothave a demonstration plant nature.
December 2000
65
TOTAL COST OF ELECTRICITY FORELCOGAS IGCC (€ cents/kWh)TOTAL COST OF ELECTRICITY FORELCOGAS IGCC (€ cents/kWh)
Discount rate: 6.00%Annual Production: 6,500 Full Load Equivalent Hours.High investment cost
Lower fuel cost than other technologies
Higher operational and maintenance costs than conven-tional plants due to the innovative nature of the project
Lower cost than nuclear plants, in the samerange of domestic coal plants
INVESTMENT3.15
FUEL1.13
O&M0.90
5.18
December 2000
66
OPERATION IN A COMPETITIVESCENARIOOPERATION IN A COMPETITIVESCENARIO
NGCC – Price scenario
IGCC Low Medium High
Fuel Cost (€ cent/kWh) 1.13 2.06 2.74 3.43
% hours in which pool price > fuel cost
199819992000 (1/1 to 26/10)
99.799.9
100.0
77.678.880.6
35.042.554.2
8.211.734.3
December 2000
67
YEAR CAPITAL COSTSUS$/ kW
EFFICIENCY (HHV ,%)
1997200020102015
145012501000850
39,6 %42 %52 %
> 60 %
Source :US DOE. Office of Fossil Energy. Federal Energy Technology Centre
TOTAL COST OF ELECTRICITY FORIGCC PROJECTIONSTOTAL COST OF ELECTRICITY FORIGCC PROJECTIONS
IGCC´s CAPITAL COSTS FORECAST
0
500
1.000
1.500
1997 2000 2010 2015
IGCC´s CAPITAL COSTS FORECAST
0
500
1.000
1.500
1997 2000 2010 2015
Forecast on the economics of the IGCC´s costs, as per US DOE estimations, indicate that these costs willdecrease in the coming years, while its efficiency will increase significantly by 2015. The table shows thiscapital cost forecast, including interest during construction, for a typical IGCC unit.
December 2000
68
TOTAL COST OF ELECTRICITY FORIGCC PROJECTIONSTOTAL COST OF ELECTRICITY FORIGCC PROJECTIONS
0
1
2
3
4
5
6
c€ /k
Wh
1997 2000 2010 2015
O&MFUELINVES TMENT
0
1
2
3
4
5
6c€
/kW
h
1997 2000 2010 2015
O&MFUELINVES TMENT
Decrease of Investment cost as per US DOE projections Efficiency increase from 42% to 50% Slight reduction of operational and maintenance costs
5.184.67
4.033.61
December 2000
69
COST COMPETITIVENESS OF ELCOGAS VISA VIS OTHER GENERATION SYSTEMSCOST COMPETITIVENESS OF ELCOGAS VISA VIS OTHER GENERATION SYSTEMS
InitialInvestment
O&M Fuel Total“strict costs”
Environmentalcosts
Total costs in a“broad sense”
Nuclear ++//--Advanced coalgenerationsystems
= =
Conventionaldomestic coalgeneration
=
Conventionalforeign coalgeneration
=
Combinedcycle
Costs of each type ofpower station comparedto ELCOGAS
Higher= Comparable
Lower
December 2000
70
ECONOMIC FACTORSECONOMIC FACTORS
December 2000
71
PERFORMANCE AGAINST GOALSPERFORMANCE AGAINST GOALS
Goal:– Demonstrate, with a commercial size Plant, the
virtues of this clean coal technologyFacts:– The capital expenditure that was required is out
of range in a liberalised market– Variable costs are competitive and stable (low
volatility)– Excellence on environmental matters
December 2000
72
Project Development– From 1992 up to 1998
1992 ELCOGAS’ incorporation1993 Bridge Loan plus Sub. Debt1994 Project Finance
Operation– From 1998 up to now
1998 Refinancing the Project Finance with aShareholders Guarantied Loan
FINANCIAL PROJECT PHASESFINANCIAL PROJECT PHASES
December 2000
73
0
100
200
300
400
500
600
700
800
92 93 94 95 96 97 98
Other AssetsCAPEX
€ million
PROJECT DEVELOPMENT. ASSETSPROJECT DEVELOPMENT. ASSETS
December 2000
74
0
100
200
300
400
500
600
700
800
92 93 94 95 96 97 98
SubsidiesOther LiabilitiesLoanSub DebtEquity
€ million
PROJECT DEVELOPMENT. LIABILITIESPROJECT DEVELOPMENT. LIABILITIES
December 2000
75
EXTERNAL SERVICES
0,6%
OTHER3,7%
LABOUR5,2%
TRAVEL & RELATED
0,3%
MATERIALS90,2%
TOTAL 669,6 € million
PROJECT DEVELOPMENT.TOTAL ELIGIBLE COSTS THERMIE contract
PROJECT DEVELOPMENT.TOTAL ELIGIBLE COSTS THERMIE contract
December 2000
76
OPERATIONOPERATION
Plant working as a natural gas CC since the endof 1996– Recognition under the former Spanish
electricity legal framework (standard costs +recognised margin)
– Profit in 1997 fiscal year (1.64 € million)New legal framework: Liberalisation– Competition in generation– Stranded costs and new accounting system
December 2000
77
OPERATION (cont.)OPERATION (cont.)
Competition in generation– Pool price determined by the market– Technical incidences due to:
New technology (first of it’s kind)Learning curve
Stranded costs and new accounting system– Main part of them depending on actual
production– Transitory period: 10 years– Very aggressive amortisation path
December 2000
78 0
100200
300
400
500600
700
800
1998 1999 2000
Other AssetsCAPEX
OPERATION . ASSETSOPERATION . ASSETS
These facts have caused ELCOGAS to incur inlosses in the following years:
€ million
December 2000
79
0100200300
400500600700800
1998 1999 2000
SubsidiesOther LiabilitiesLoanSub DebtEquity
€ million
OPERATION . LIABILITIESOPERATION . LIABILITIES
December 2000
80
OPERATION (cont.)OPERATION (cont.)
Added difficulties for the company: the recognitionof the stranded costs in Spain is under review bythe EC Commission as State-aidELCOGAS’ viability now depends on the finalapproval of the recognised stranded costs