Integrated Gasification Combined Cycle Power Plants with Focus on Low Emission Gas Turbine Technology by Mohammad Mansouri Majoumerd Thesis submitted in partial fulfillment of the requirements for the degree of PHILOSOPHIAE DOCTOR (PhD) Faculty of Science and Technology Department of Petroleum Engineering 2014 University of Stavanger N-4036 Stavanger NORWAY www.uis.no ©2014 Mohammad Mansouri Majoumerd All rights reserved ISBN: ISSN: PhD Thesis UiS, No. Abstract It is foreseen that global demand for electricity will increase continuously, mainly due to population growth and improved living standards, worldwide. At the same time, the climate change issue due to increasing GHG emissions, more specifically from the heat and power sector, has become one of the most important global concerns. Thus there has been a genuine demand for the delivery of innovative solutions to provide electricity in a more sustainable way. Several pathways, which have significant potential for GHG emissions mitigation, while providing electric power, have been introduced and investigated during recent years. The improvement of energy efficiency and the deployment of carbon capture and storage (CCS) in fossil-based power plants are amongst the options to stabilize the atmospheric levels of greenhouse gas emissions, while enabling the continued use of fossil fuels. In this regard, the integrated gasification combined cycle (IGCC) power plant is one of the most promising power generation technologies. Environmentally benign use of coal as primary fuel, use of highly reliable gas turbine (GT) technology, possibilities for poly-generation of different products and for pre-combustion CO2 capture are important features of this technology. In 2009, the European Union co-financed the “Low Emission Gas Turbine Technology for Hydrogen-rich Syngas (H2-IGCC)” project to achieve its targets of higher energy efficiency and lower GHG emission levels along with greater security of energy supply. This project aimed at providing technical solutions for using undiluted hydrogen-rich syngas in gas turbines for IGCC application with CO2 capture. As part of the H2-IGCC project, this PhD thesis presents investigations into the deployment of pre-combustion CO2 capture in IGCC power plants aiming at providing practical and realistic system integration solutions. The emphasis has been on the gas turbine block to enable the combustion of undiluted hydrogen-rich syngas, a requirement iii iv Abstract of future IGCC technology with CO2 capture. For this purpose, different state-of-the-art technologies for various sub-systems of the IGCC plant were proposed and the most practical options based on the feedback from industrial partners within the H2-IGCC consortium were selected for further thermodynamic analyses. The outcomes of these analyses together with technical constraints related to the proposed cycle configurations were used by other working groups as boundary conditions for the development of a gas turbine technology optimized for undiluted H2-rich syngas. Moreover, a techno-economic tool has been generated, which enabled economic assessments of the IGCC plant with CO2 capture and its main fossil-based competitors, using realistic cost and performance data confirmed by important players in the European power market. During the implementation of this thesis, it is demonstrated that the combustion of undiluted H2-rich syngas and the meeting of fuel flexibility targets are not possible using the existing GT technology. Accordingly, necessary modifications were proposed and implemented to provide an optimized GT technology suitable for the combustion of undiluted H2-rich syngas. It is also found that investigated fossil-based power plants have similar cost levels. The marginal difference in the cost of electricity for different plants was within the level of uncertainties in the assessment of investment costs. Therefore, other main drivers, apart from the cost of electricity, can affect the selection of a power generation technology such as operational flexibility and potential for future technological improvements. Keywords: CO2 capture and storage, gas turbine, H2-rich syngas, IGCC, power generation, system integration, techno-economy Acknowledgements This research was co-financed by the European Union’s Seventh Framework Programme for Research and Development. Financial support from the European Commission, Directorate-General for Energy is gratefully acknowledged. I would like to express my sincere gratitude to Professor Mohsen Assadi for his excellent supervision and encouragement throughout my PhD program. I also appreciate his efforts in providing me with the unique opportunity of being involved in two European-funded projects, the H2-IGCC project and the European North Sea Energy Alliance (ENSEA) project. I would like to thank Peter Breuhaus at the International Research Institute of Stavanger (IRIS) for sharing his long-term experience and profound knowledge within the field of gas turbine technology. Thanks to Nikolett Sipöcz, Sudipta De, and Homam Nikpey for sharing their knowledge and the collaborative works resulting in several journal and conference papers. I would like to thank all the project partners in the H2-IGCC project whose contributions have been used in this work. In this regard, my special thanks go to Han Raas at Nuon/Vattenfall for performing gasification simulations and for sharing knowledge about operational aspects of IGCC power plants. I am also thankful to Chris Lappee at Nuon/Vattenfall, Stuart James, James Bowers, Karel Dvorak and Adam Al-Azki at E.ON UK for sharing their industrial perspectives and providing technical and economic inputs. Inputs from our partners in other sub-projects of the H2-IGCC project such as combustion, materials and turbo-machinery in addition to the perfect coordination activities, which were carried out by European Turbine Network (ETN) are also appreciated. v vi Acknowledgements Furthermore, my sincere thanks must go to my former colleagues at the University of Stavanger (UiS) and my friends in Stavanger for their motivation and encouragement. I would also like to express my gratitude to the new energy, risk management and well construction group at IRIS. Finally, and perhaps most importantly, I would like to take this opportunity to express my deep gratitude to my family for their endless love and support. Mohammad Mansouri Majoumerd, Stavanger, Norway Table of Contents Abstract.............................................................................................................................. iii Acknowledgements ............................................................................................................. v Table of Contents...............................................................................................................vii Nomenclature...................................................................................................................... xi List of appended papers .................................................................................................... xxi Additional papers not included .......................................................................................xxiii 1. Introduction ..................................................................................................................... 1 1.1. Background information ........................................................................................... 1 1.2. Objectives ................................................................................................................. 3 1.3. Limitations ................................................................................................................ 4 1.4. Methodology ............................................................................................................. 5 1.5. Outline of the thesis .................................................................................................. 6 2. Technical background ...................................................................................................... 7 2.1. Growing energy demand ........................................................................................... 7 2.2. Climate change ......................................................................................................... 8 2.2.1. Greenhouse gas emissions ................................................................................. 9 2.2.2. Climate change and the power sector .............................................................. 11 2.3. Mitigation policies .................................................................................................. 12 2.3.1. Carbon capture and storage .............................................................................. 13 vii viii Table of Contents 2.3.2. The European Union climate strategy .............................................................. 14 2.4. Various capture technologies in the power sector................................................... 15 2.4.1. Post-combustion CO2 capture .......................................................................... 17 2.4.2. Pre-combustion capture ................................................................................... 19 2.4.3. Oxy-fuel combustion ....................................................................................... 21 3. Coal-based power plants ................................................................................................ 25 3.1. Why coal-based power plants? ............................................................................... 26 3.2. Coal-fired power generation ................................................................................... 27 3.3. IGCC power plant’s components ............................................................................ 30 3.3.1. Air separation................................................................................................... 30 3.3.1.1. Cryogenic ASU and power island integration options .............................. 32 3.3.1.2. Other ASU technologies ........................................................................... 35 3.3.2. Gasification ...................................................................................................... 35 3.3.2.1. Entrained-flow gasifiers ............................................................................ 36 3.3.2.2. Gasification performance .......................................................................... 38 3.3.2.2.1. Coal quality ........................................................................................ 39 3.3.2.2.2. Cold gas efficiency ............................................................................ 40 3.3.3. Syngas cleaning and conversion ...................................................................... 41 3.3.3.1. Syngas cleaning ........................................................................................ 41 3.3.3.2. Water-gas shift reaction ............................................................................ 42 3.3.3.3. Acid gas removal ...................................................................................... 44 3.3.3.4. Sulfur recovery unit .................................................................................. 47 3.3.3.5. Advanced syngas cleaning and conversion ............................................... 48 3.3.4. CO2 compression and dehydration ................................................................... 50 3.3.5. Gas turbine ....................................................................................................... 52 Table of Contents ix 3.3.5.1. Combustion process .................................................................................. 52 3.3.5.2. Turbo-machinery ...................................................................................... 54 3.3.5.3. Materials ................................................................................................... 56 3.3.5.4. Commercial syngas-fueled gas turbine ..................................................... 56 3.3.5.5. Advanced hydrogen turbine technology ................................................... 57 3.3.6. Bottoming cycle ............................................................................................... 58 3.4. Current IGCC power plants status .......................................................................... 58 4. H2-IGCC power plant.................................................................................................... 61 4.1. H2-IGCC project .................................................................................................... 61 4.2. System integration .................................................................................................. 64 4.2.1. Cryogenic air separation unit ........................................................................... 65 4.2.2. Gasification ...................................................................................................... 66 4.2.3. Syngas conversion ........................................................................................... 66 4.2.4. Acid gas removal ............................................................................................. 67 4.2.5. Gas turbine ....................................................................................................... 68 4.3. System performance analysis .................................................................................. 70 4.3.1. Software tools .................................................................................................. 71 4.3.2. Boundary conditions ........................................................................................ 74 4.3.2.1. Ambient conditions ................................................................................... 74 4.3.2.2. Feedstock properties ................................................................................. 74 4.3.2.3. Gas turbine boundaries and performance .................................................. 76 5. Economic evaluation ..................................................................................................... 81 5.1. Cost estimating methodology ................................................................................. 81 5.1.1. Costing scope ................................................................................................... 83 5.1.2. Capital costs ..................................................................................................... 84 x Table of Contents 5.1.2.1. Step-count costing method ........................................................................ 84 5.1.2.2. Capacity adjustment .................................................................................. 86 5.1.2.3. Price fluctuations ...................................................................................... 86 5.1.2.4. Currency exchange ................................................................................... 87 5.1.3. Operation and maintenance (O&M) costs ....................................................... 87 5.1.4. Fuel cost ........................................................................................................... 87 5.1.5. CO2 cost measures ........................................................................................... 88 5.2. Uncertainty in the economic results ........................................................................ 89 6. Concluding remarks ....................................................................................................... 93 6.1. Conclusions ............................................................................................................ 93 6.2. Scientific contributions ........................................................................................... 96 6.3. Suggestions for further research ............................................................................. 98 7. Summary of appended papers ...................................................................................... 101 Bibliography .................................................................................................................... 109 Paper I .............................................................................................................................. 121 Paper II ............................................................................................................................ 133 Paper III ........................................................................................................................... 147 Paper IV ........................................................................................................................... 161 Paper V ............................................................................................................................ 175 Paper VI ........................................................................................................................... 187 Nomenclature Abbreviations AGR acid gas removal Al2O3 aluminum (III) oxide or alumina Ar argon AR4 4th assessment report of Intergovernmental Panel on Climate Change ASU air separation unit BFW boiler feed water BUA bottom-up approach CAESAR CArbon-free Electricity by SEWGS: Advanced materials, Reactor-, and process design CaO calcium oxide CAPEX capital expenditure CCS carbon capture and storage CEPCI Chemical Engineering Plant Cost Index CHP combined heat and power xi xii Nomenclature CH4 methane CI cost index CLC chemical looping combustion CMD coal milling and drying CO carbon monoxide Co cobalt COE cost of electricity COS carbonyl sulfide COT combustor outlet temperature CO2 carbon dioxide Cr chromium Cu copper DCF discounted cash flow DGAN diluent gaseous nitrogen DLN dry low NOx DOE Department of Energy EBTF European Benchmarking Task Force EOS equation-of-state EPCC engineering, procurement and construction costs ETS emissions trading system Nomenclature xiii EU European Union E-GasTM ConocoPhillips gasifier FBC fluidized bed combustion Fe iron FeO ferrous or iron oxide FGD flue gas desulfurization FP7 Seventh Framework Programme GAN gaseous nitrogen GDP gross domestic product GE General Electric GHG greenhouse gas GOX gaseous oxygen GT gas turbine HHV higher heating value HP high pressure HRSG heat recovery steam generator HSE health, safety and environment HT high temperature HTS high temperature shift H2 hydrogen xiv Nomenclature H2O water H2S hydrogen sulfide H2-IGCC Low Emission Gas Turbine Technology for Hydrogen-rich Syngas project IC indirect costs IEA International Energy Agency IGCC integrated gasification combined cycle IGV inlet guide vanes IL ionic liquid IP intermediate pressure IPCC Intergovernmental Panel on Climate Change IR index ratio ITM ion transport membrane KP Kyoto Protocol LHV lower heating value LP low pressure LT low temperature LTS low temperature shift MAC main air compressor MEA monoethanolamine MgO magnesium oxide Nomenclature xv MHI Mitsubishi Heavy Industry Mo molybdenum M&S Marshall and Swift cost index NETL National Energy Technology Laboratory NG natural gas NGCC natural gas combined cycle NGV nozzle guide vane NH3 ammonia NOx nitrogen oxides NPV net present value N2 nitrogen N2O nitrous oxide OC owner costs OECD Organization for Economic Co-operation and Development OEM original equipment manufacturer OPEX operational expenditure O&M operation and maintenance O2 oxygen PC pulverized coal PCC pulverized coal combustion xvi Nomenclature PC-SAFT perturbed-chain statistical associating fluid theory PGAN pressurized gaseous nitrogen PM particulate matter PR Peng-Robinson RE renewable energy R&D research and development SC supercritical SCGP Shell Coal Gasification Process SCOT Shell Claus off-gas treating SCPC supercritical pulverized coal SCR selective catalytic reduction SEWGS sorption-enhanced water-gas shift SFG Siemens Fuel Gasification SiO2 silicon dioxide SOA state-of-the-art SOx sulfur oxides SO2 sulfur dioxide SR Schwarzentruber and Renon SRU sulfur recovery unit ST steam turbine Nomenclature xvii SWGS sour water-gas shift TBC thermal barrier coating TDPC total direct plant cost TEC total equipment costs TEG tri-ethylene glycol TGT tail gas treating TIT turbine inlet temperature TOT turbine outlet temperature TPC total plant costs UHC unburned hydrocarbons UNFCCC United Nations Framework Convention on Climate Change USC ultra-supercritical USCPC ultra-supercritical pulverized coal U.S. DOE United States Department of Energy VIGV variable inlet guide vanes WGS water-gas shift Zn zinc Latin ∆ℎ enthalpy change (kJ kg-1) 𝐴 area (m2) xviii Nomenclature 𝐶 cost (€) 𝑐𝑝 specific heat transfer coefficient at constant pressure (kJ mol-1 K-1) 𝐼𝑗 installation costs of a component (sub-system) (€) 𝐿𝐻𝑉 lower heating value (kJ kg-1 or kJ m-3) 𝑚̇ mass flow rate (kg s-1) 𝑝 pressure (bar) 𝑄̇ volumetric flow rate (m3 s-1) 𝑅 gas constant (kJ kg-1 K-1) 𝑆 scaling parameter 𝑇 temperature (K) 𝑊 work (kW) 𝑥̅ mean value of a parameter Greek letters 𝛽 pressure ratio (-) 𝛾 isentropic exponent (-) 𝜅 constant 𝜂 efficiency (%) 𝑓 cost scaling exponent (-) Subscripts Nomenclature xix 𝑎𝑢𝑥 auxiliary 𝑐 compressor 𝑐𝑎𝑝𝑡𝑢𝑟𝑒 power plant with carbon dioxide capture 𝑐𝑎𝑝𝑡𝑢𝑟𝑒𝑑 carbon dioxide captured at a power plant 𝑐𝑔 cold gas 𝑐𝑖 coal input 𝑒 expander 𝑒𝑙 electrical 𝑖 inlet 𝑖𝑠 isentropic 𝑗 sub-system (or component) 𝑚 mechanical 𝑜 outlet 𝑜𝑏𝑦 original base year 𝑝 pumping 𝑝𝑟𝑜𝑐, 𝑐 process contingencies 𝑝𝑟𝑜𝑗, 𝑐 project contingencies 𝑟𝑒𝑓 reference 𝑠 specific 𝑠𝑔 syngas xx Nomenclature 𝑠𝑡 steam turbine 𝑡ℎ thermal 𝑢𝑏𝑦 updated base year Units Gt Giga tonnes Hz Hertz kWh kilowatt hour Mt million tonnes Mtoe million tonnes of oil equivalent MW Megawatt MWe Megawatt electricity MWh Megawatt hour Pa.s Pascal second ppm part per million ppmvd part per million volumetric dry tC tonne of carbon TJ Terajoule TWh Terawatt hour wt% weight percentage List of appended papers Paper I Sipöcz, N., Mansouri, M., Breuhaus, P., Assadi, M., Development of H2-rich syngas fuelled GT for future IGCC power plants – Establishment of a baseline, Presented at ASME Turbo Expo 2011, GT2011-45701, Vancouver, Canada, June 2011. Paper II Mansouri Majoumerd, M., De, S., Assadi, M., Breuhaus, P., An EU initiative for future generation of IGCC power plants using hydrogen-rich syngas: Simulation results for the baseline configuration. Applied Energy, 2012, 99: p. 280-290. Paper III Mansouri Majoumerd, M., Raas, H., De, S., Assadi, M., Estimation of performance variation of future generation IGCC with coal quality and gasification process – Simulation results of EU H2-IGCC project. Applied Energy, 2013, 113: p. 452-462. Paper IV Mansouri Majoumerd, M., Assadi, M., Fuel change effects on the gas turbine performance in IGCC application, Presented at 13th International Conference on Clean Energy (ICEE-2014), Istanbul, Turkey, June 2014. Paper V Mansouri Majoumerd, M., Assadi, M., Breuhaus, P., Techno-economic evaluation of an IGCC power plant with carbon capture, Presented at ASME Turbo Expo 2013, GT2013-95486, San Antonio, Texas, USA, June 2013. Paper VI Mansouri Majoumerd, M., Assadi, M., Techno-economic assessment of fossil fuel power plants with CO2 capture ‒ Results of EU H2-IGCC project. International Journal of Hydrogen Energy, 2014, 39: p. 16771-16784. xxi Additional papers not included Paper VII Mansouri Majoumerd, M., Breuhaus, P., Smrekar, J., Assadi, M., Basilicata, C., Mazzoni, S., Chennaoui, L., Cerri, G., Impact of fuel flexibility needs on a selected GT performance in IGCC application, Presented at ASME Turbo Expo 2012, GT2012-68862, Copenhagen, Denmark, June 2012. Paper VIII Nikpey Somehsaraei, H., Mansouri Majoumerd, M., Breuhaus, P., Assadi, M., Performance analysis of a biogas-fueled micro gas turbine using a validated thermodynamic model. Applied Thermal Engineering, 2014, 66: p. 181-190. Paper IX Nikpey, H., Mansouri Majoumerd, M., Assadi, M., Breuhaus, P., Thermodynamic analysis of innovative micro gas turbine cycles, Presented at ASME Turbo Expo 2014, GT2014-26917, Düsseldorf, Germany, June 2014. Paper X Mansouri Majoumerd, M., Nikpey Somehsaraei, H., Assadi, M., Breuhaus, P., Micro gas turbine configurations with carbon capture – Performance assessment using a validated thermodynamic model. Applied Thermal Engineering, 2014, 73: p. 170-182. Paper XI Mansouri Majoumerd, M., Assadi, M., Breuhaus, P., H2-IGCC system integration and techno-economic analysis, Presented at 7th International Gas Turbine Conference (IGTC-14), Brussels, Belgium, October 2014. Paper XII Assadi, M., Mansouri Majoumerd, Jana, K., De, S., Intelligent biogas fuelled distributed energy conversion technologies: Overview of a pilot study in Norway, Accepted for presentation at ASME 2014 Gas Turbine India Conference, GTINDIA2014-8231, New Delhi, India December 2014. xxiii 1. Introduction This work is based on a research project co-financed by the European Union (EU) Seventh Framework Programme for Research and Development. The aim of this project was to provide and demonstrate technical solutions, which allow the use of state-of-the-art highly efficient and reliable gas turbines (GT) in the next generation of integrated gasification combined cycle (IGCC) plants with carbon dioxide (CO2) capture. 1.1. Background information The rapid growth of the world’s population coupled with the improved living standards has led to an increasing demand on energy, worldwide. The global economic situation during the past few years has offset this increase to some extent by the reduction in industrial activities. However, some factors including global population, living standards and global economy are foreseen to be the main drivers of the energy demand increase in coming years. Though there will be a significant improvement in energy efficiency, the projected primary energy use in the year 2040 will be approximately 35% higher compared to the 2010 level. Electricity generation will represent the largest driver of energy demand by 2040 and is expected to account for about half the increase in global demand for energy [1]. Climate change due to anthropogenic greenhouse gas (GHG) emissions is identified as the greatest threat to mankind [2]. The major source of these GHGs is CO2 emissions, and the heat and power sector is identified as the largest contributor to these emissions. CO2 emissions from the heat and electricity supply sector were about 42% of total global CO 2 emissions from fossil fuels in the year 2011 [3]. The present challenge for the power 1 2 Introduction sector is to meet the ever-increasing demand for electricity and simultaneously mitigate the greenhouse gas emissions, principally CO2. Several sustainable solutions have been developed and introduced to cover the additional demand and to mitigate CO2 emissions in recent years. One possible option is to replace fossil-based power plants by renewable energy (RE) sources. In 2008, renewable energies contributed approximately 19% of global electricity demand, and most scenarios foresee a higher projected share in coming years [4]. Renewable sources are ultimately the most important option for the future. However, apart from the long timescale for the complete transformation from fossil-based fuels, RE sources suffer from the fluctuating nature or variability of production [5]. Given all these aspects, the development of suitable technology for large-scale power generation using fossil fuels during this transition is urgently needed. The other solution to mitigate CO2 emissions is the enhanced use of lower carbon intensity fuels in power plants instead of e.g. oil and coal, which have higher carbon contents. In this context, the use of natural gas (NG) for power generation has been increasing in some countries, mostly due to the fact that it is more environmentally friendly. However, coal is still the most widely used fossil fuel for large-scale power generation [5], although the CO2 emissions from coal power plants are almost two times higher than those from NG-fueled power plants. The International Energy Agency’s (IEA) New Policies Scenario foresees a 25% increase in coal consumption in the year 2035 compared to the 2009 level. This increase will be 65% based on the Current Policies Scenario [5]. The security of energy supply due to wider geographical distribution of coal reserves and availability of abundant resources has promoted coal-fueled power generation technologies. In addition, factors such as safe storage, easy transportation over a long distance, less volatile pricing status motivate higher use of coal. Amongst available reliable technologies for electric power generation, coal plants are still dominating the market, mainly due to better economic attributes [6]. Carbon capture and storage (CCS) is also one of the key players for decarbonizing the heat and power supply according to the European Energy Roadmap 2050 [7]. The deployment of CCS in coal-fired power generation will maintain coal consumption at a certain level among other fossil fuels under more restricted emissions regulations in future. Nomenclature 3 By virtue of the aforementioned aspects, there has been a demand for the development of a reliable, environmentally-friendly, coal-based technology with the deployment of CO2 capture and storage. 1.2. Objectives The vision of this PhD thesis, as part of the European H2-IGCC project, was to enable the application of the state-of-the-art (SOA) gas turbine technology in the next generation of IGCC plants (i.e. with CO2 capture system) with the flexibility to operate on undiluted H2rich syngas. Figure 1.1 illustrates the structure of the current thesis. Figure 1.1. The structure of the current thesis The overall objective of this thesis was, therefore, to provide a detailed system analysis that generates realistic techno-economic performance indicators for future IGCC plants with the deployment of CO2 capture. In this regard, special efforts were dedicated to: Establish and improve a thermodynamic model in order to evaluate the thermodynamic performance indicators of the IGCC plant with pre-combustion CO2 capture unit. 4 Introduction Investigate the consequences of burning H2-rich syngas in IGCC power plants at both the system level and the GT level. Investigate the fuel flexibility target by burning non-capture clean syngas instead of H2-rich syngas and natural gas in the GT. Update and improve an available GT model using new designed GT characteristics to cope with the needs of the project and to allow future adjustments based on the feedback from the project’s partners. Identify different alternatives for component integration to reach higher plant efficiency and investigate various configurations of the system in terms of the plant’s operability. Develop a tool for economic evaluation and assess capital expenditures (CAPEX) and operational expenditures (OPEX) for the IGCC plants. Compare the technical and economic performance indicators of the IGCC plants with other fossil-based power plants, i.e. advanced supercritical pulverized coal (SCPC) and natural gas combined cycle (NGCC) plants. 1.3. Limitations The main focus of this research work was on system modeling and analysis for low carbon IGCC power plants with special emphasis on the gas turbine technology. Accordingly, different plant’s components were integrated to establish the selected IGCC plant with CO2 capture unit. Then, the system was thermodynamically modeled and analyzed along with continuous modifications of the gas turbine to enable the combustion of undiluted hydrogen-rich syngas. In addition, a part of the activities was related to techno-economic assessments of the selected IGCC plant and its fossil-based competitive technologies. The techno-economic studies performed were exclusively reviewed by some European utility providers, and economic figures were compared with realistic cost data provided by project partners. It should be highlighted that the lack of large-scale IGCC plants with CO2 capture system increases the level of uncertainty in both technical and economic indicators. However, realistic performance and cost data used in simulations and techno-economic assessment reflects the current development level of IGCC plants. Moreover, some of the major alternative plant’s components contributing to efficiency improvement have been identified and are presented here. Nomenclature 5 This work does not address the issues revolving around the transport and storage of captured CO2 and only focuses on the CO2 capture part. Transient (and dynamic) simulation of the investigated cycles is also outside the scope of this thesis. While practical heat integration was used for the selected system, thermodynamic optimization is excluded from the present work. 1.4. Methodology A literature review was performed to provide a process description as well as performance data for different components of the IGCC plant based on state-of-the-art technologies. The collected information, together with data generated during the implementation of this work, was used for the modeling of the entire IGCC system. The thermodynamic models described in this thesis were developed using different software tools. The simulation of power block was performed using the heat and mass balance program, IPSEpro. For this purpose, existing component models in IPSEpro, as well as certain models developed during the H2-IGCC project, were used. In addition, the Enssim software, developed by a member of the H2-IGCC project, was used to simulate and analyze the gasification block. Simulation and modeling of the gas cleaning process of the IGCC plant were carried out using ASPEN Plus. After establishing the baseline IGCC plant with CO2 capture, the performance of different components and the layout of the plant were continuously modified using the feedback from operators of similar plants. In order to determine state-of-the-art methodologies for cost estimation in the power sector, a literature review was performed. A Microsoft Excel-based tool has been developed for the techno-economic comparison of different power generation technologies, using performance data obtained from simulations and available cost data in open literature. A techno-economic comparison between three fossil-based power systems, i.e. IGCC, SCPC and NGCC plants, was conducted using the developed tool. Moreover, the developed tool enabled the effects of the variation of different parameters on the economic indicators to be investigated. 6 Introduction 1.5. Outline of the thesis The present thesis is a summary of six scientific papers, preceded by an introduction to the work that provides supplementary information to that presented in the papers. Chapter 1 provides an overview of the present thesis by means of a brief background to current energy related issues and an explanation of the objectives and limitations of this thesis. Chapter 2 presents an extended background to the climate change concern, different GHG mitigation options and the main CO2 capture methods. Chapter 3 gives a brief introduction to coal power plants and concisely describes different sub-systems of an IGCC power plant as well as different challenges for the integration of such an energy conversion system. Chapter 4 contains the selected IGCC plant configuration, challenges related to the use of undiluted hydrogen-rich syngas and a general description of heat and mass balance tools used for the investigations performed during the course of this thesis. Chapter 5 describes the economic methodology selected for the techno-economic assessments as well as calculations performed for techno-economic studies within this PhD project. The main conclusions of this work are presented in Chapter 6, and, finally, Chapter 7 introduces the papers included in the thesis. 2. Technical background The provision of energy in its most modern state, i.e. electricity, has been faced with a major concern over the past two decades, and that is climate change. Climate change due to anthropogenic greenhouse gas emissions is considered to be one of the most serious threats to natural ecosystems and human life in the 21st century. The aim of this section is, therefore, to provide a clear picture about future energy mix and its link to the climate change concern. Accordingly, a brief review of the most important energy indicators published by various organizations will be presented. This review will offer an approximate picture of future energy growth. The second part of this section is dedicated to the climate change concern and greenhouse gas emissions. An overview of different mitigation policies to stabilize greenhouse gas concentration in the atmosphere will be given with a focus on carbon capture and storage. Finally, the most mature carbon capture technologies will be briefly described. 2.1. Growing energy demand World total primary energy consumption was 12,470 Mtoe in 2012 [8]. Global population, global economy, energy-intensity of the global economy and living standards are the main drivers of the world’s energy demand [9]. The global population will increase more than 30% from 2013 to 2050 and reach nearly 9.6 billion [10]. This number shows another 2.4 billion energy consumers, mainly in Asia and Africa. During recent years, the global economy has faced the worst recession since the Second World War [11]. It began with the crisis in the United States in 2007-08 and then the EU zone faced a weak economy. However, using stronger measures to stimulate the economy has had a positive effect and 7 8 Technical background a marginal economic growth has been visible recently. The projected gross domestic product (GDP), which is an indicator of economic growth, is expected to increase at an annual average rate of 2.8-3.7% in the next two to three decades [1, 12, 13]. Most of this growth will come from emerging economies and non-OECD (Organization for Economic Co-operation and Development) countries. Meanwhile, the projected GDPs of China, India, and Africa are expected to grow by an annual average rate of about 4-5% until 2040. Global economic growth will then slow gradually as the emerging economies become mature. Together with the rapid growth of the economy, urbanization, industrialization and increased living standards are also projected for the future. The projected urbanization rate for 2035 is 61%, compared to 51% in 2010 [13]. The greater part of this increase will again come from non-OECD countries, where people want to reach higher living standards. The shift of population to cities means a greater number of homes and higher average energy consumption compared to rural areas, although it enables people to have access to more efficient energy use. As mentioned, all the fundamental drivers of energy demand (except energy-intensity) will continuously grow in the coming decades. Energy efficiency will continue to play a major role in moderating the energy growth. The energy-intensity (energy consumption per capita) projection shows a downward trend worldwide over the coming decades [13]. This is an indicator of more efficient utilization of energy. However, improved living standards will outpace energy efficiency and will ultimately result in a higher demand for energy in the future. Therefore, global primary energy consumption, with a small variation between data from different scenarios and organizations, is projected to grow at an average annual rate of 1.2-1.6 % over the period of 2010 to 2030 [1, 12, 14]. To conclude this section, the need for a greater supply of energy through the development of efficient technologies seems inevitable in the future. 2.2. Climate change The change in the state of the climate as a result of human activities, in addition to natural climate variability, represents a potentially serious threat facing humanity in the 21st century. Some of the variations in climate, which have been observed during past years, are [15]: Increase in global average air and ocean temperatures; Technical background 9 rise of global average sea level; decrease in snow and ice extent; change in hydrological systems, e.g. increased runoff and warming of lakes and rivers; and changes in terrestrial, marine and freshwater biological systems. According to the Fifth Assessment Report (AR5) of Intergovernmental Panel on Climate Change (IPCC), “Warming of the climate system is unequivocal”. Moreover, “it is extremely likely that human influence has been the dominant cause of the observed warming since the mid-20th century”. The global average combined land and ocean surface temperature increased 0.85 °C from 1880 to 2012. A comparison between the average temperature of 1850-1900 and of 2003-2012 shows a total increase of 0.78 °C [16]. 2.2.1. Greenhouse gas emissions A change in the atmospheric concentration of greenhouse gases such as carbon dioxide, methane (CH4), nitrous oxide (N2O) and halocarbons altered the energy balance of the climate system and is considered as one of the main drivers of climate change. It is very certain that the anthropogenic increase in greenhouse gas concentrations, together with other anthropogenic forces, is responsible for more than half of the observed increase in global average surface temperature from the mid-20th century to 2010 [16]. Figure 2.1 shows the share of different anthropogenic greenhouse gases in total emissions in 2004 [15]. CO2 (other) 3% CO2 (deforestation , decay of biomass, etc.) 17 % CH4 14 % N2O 8% Fluorinated gases 1% CO2 (fossil fuel use) 57 % Figure 2.1. Global anthropogenic greenhouse gas emissions in 2004 (data adopted from IPCC AR4) 10 Technical background The global atmospheric concentration of CO2, which is widely recognized as the most important GHG contributor to global warming, has increased from a pre-industrial value of about 278 to 394 ppm in 2012 [15, 17]. Figure 2.2 illustrates that CO2 concentration has increased almost 25% between 1958 and 2012 [17]. The combustion of fossil fuel, some energy-intensive industrial processes, land use changes (mainly deforestation), agriculture and domestic waste disposal are the most important contributors to the growing CO2 emissions [15, 18]. 400.00 Average CO2 concentration (ppm) 390.00 380.00 370.00 360.00 350.00 340.00 330.00 320.00 310.00 1955 1965 1975 1985 Year 1995 2005 2015 Figure 2.2. Annual mean atmospheric carbon dioxide concentration at Mauna Loa Observatory, Hawaii, USA Given the negative effects of increasing GHG emissions, the United Nations Framework Convention on Climate Change (UNFCCC) was set up as a first international climate treaty in 1992. The aim was to mitigate climate change due to the global temperature rise and to cope with its inevitable impacts. A few years later, the need for stronger measures to limit the increasing GHG emissions resulted in the adoption of the Kyoto Protocol (KP) on December 11, 1997 in Kyoto, Japan [19]. The main objective of this international agreement was to legally commit its parties by setting internationally binding targets and timetables for reducing GHG emissions. The protocol came into force in 2005, and a heavier burden has been placed on developed nations. This is mainly because such countries are recognized as principally responsible for the current levels of GHG emissions in the atmosphere due to their industrial activities over the past two centuries. The average emission reduction target for the first commitment period of this protocol Technical background 11 (2008-2012) was 5% from the 1990 levels [19]. During the second commitment period from 2013 to 2020, the target was set to at least an 18% reduction of GHG emissions from the 1990 levels [20]. 2.2.2. Climate change and the power sector Currently, about 37% of global primary energy is consumed by electricity generation. The global electricity generation was 22,126 TWh in 2012 [21], with an annual average growth rate of 2.95% from 1990 to 2012 [8]. Fossil-fuel electricity generation accounted for 68% of the total generation and coal, the most carbon-intensive fossil fuel, was the largest contributor to the electricity supply in 2012. Figure 2.3 shows the share of all sources in the production of electricity in 2012 (data adopted from key world energy statistics 2013, International Energy Agency [21]). Other Oil 4.5 % 4.8 % Hydro 15.8 % Natural gas 21.9 % Nuclear 11.7 % Coal 41.3 % Figure 2.3. Electricity generation from various sources in 2012 The ever-increasing world demand for electricity generation represents the largest driver of demand for primary energy consumption. The demand for electricity is projected to grow more rapidly than the increase in total energy consumption over the next few decades [1, 12]. This demand will be almost 70% higher in 2035 than the current electricity demand [22]. As mentioned earlier, CO2 is the most important greenhouse gas contributing to climate change and the power sector is identified as the single largest sector emitting CO2. 12 Technical background According to the IEA, CO2 emissions from the electricity and heat supply sector constituted about 42% of total global CO2 emissions from fossil fuels in the year 2011 [3]. 2.3. Mitigation policies The successful implementation of efficient mitigating measures is extraordinarily vital to stabilizing GHG concentration in the atmosphere. The mitigation of greenhouse gas emissions can be achieved through a wide variety of measures and tools in different sectors including energy, industry, agriculture, forestry, etc. The focus of this sub-section is on the mitigation options for the energy sector, which has the highest importance in terms of sectorial share of global GHG emissions [9]. These options can ultimately reduce the GHG emissions per unit of energy consumption through the following actions: Energy conservation and efficiency improvement; transformation/replacement of carbon-intensive fossil fuels by cleaner technologies such as switch from coal to natural gas, enhanced use of RE sources, and enhanced utilization of nuclear energy; and reduction of CO2 emissions using CCS while utilizing energy from fossil fuels. Improving energy saving and efficiency is a priority within all mitigation policies [7]. Energy saving could be performed using more stringent minimum requirements for appliances and new buildings, high renovation rates for existing buildings and the establishment of energy savings obligations on energy utilities. The reduction of GHG emissions due to the efficiency improvement will, however, be gradually decreased because of the associated cost of further improvements [9]. On the contrary, less carbonintensive technologies such as RE and GHG emissions abatement through CCS will be more attractive because of their decreasing costs as a result of technological maturity [9]. There has been a great deal of speculation on the further utilization of nuclear energy since 2011 after the Fukushima accident at the Fukushima Daiichi plant in Japan. Soon after this accident, a few countries such as Germany and Switzerland adopted constrained nuclear energy scenarios, which allow the retirement of plants over their lifetime or earlier, without commissioning any new installations. Some countries will maintain the total deployment of nuclear energy at current levels. Nevertheless, economic considerations as well as the security of the energy supply would result in the domination Technical background 13 of pre-Fukushima nuclear scenarios coupled with tighter safety requirements [23] as several new nuclear plants are currently under construction around the globe [24]. Renewable energy has considerable potential to play an important and increasing role in achieving GHG mitigation targets and to eliminate GHG emissions from the combustion of fossil fuels. These energy sources are undoubtedly the only option for the future. During recent years, many RE technologies have become increasingly market competitive, resulting in a significant increase in their global deployment [4]. Renewablebased electricity generation is expected to continue growing over the next few decades due to high government support and declining investment costs. Under different IEA scenarios, the share of RE sources in total electricity generation rises from 20% in 2011 to 25-48% in 2035. However, producing energy from renewable sources is still not wholly mature and cannot meet the present demand fully in an economic and feasible way. The estimated timescale for the complete transformation from fossil fuels to renewable resources is not definite and is likely to be a significant time away [5]. Carbon capture and storage could constitute an important part of the mitigation portfolio for the stabilization of atmospheric greenhouse gas concentrations over the course of the 21st century [7, 9]. The deployment of this decarbonization strategy in the power sector will maintain continued utilization of fossil fuels and the available infrastructure, while also limiting the anthropogenic CO2 emissions in the near future. The widespread deployment of CCS technologies might also prevent a drastic falling of fossil fuel consumption as a result of the higher share of RE sources and more stringent emissions regulations in the future. It should be clearly underlined that no single mitigation option can provide all of the emission reductions required for the stabilization of atmospheric GHG concentrations [25]. Thus, a portfolio containing all the aforementioned mitigation options is necessary to provide a comprehensive package of different sustainable solutions to tackle increasing anthropogenic GHG emissions. 2.3.1. Carbon capture and storage Carbon capture and storage is an essential measure designed to curb global CO 2 emissions. The commercial realization of the CCS process involves three main steps a) separation of CO2 from industrial/energy-related sources, b) transport of the 14 Technical background predominantly captured CO2 to a storage site (using high pressure pipelines, trucks, or vessels) commonly in a supercritical state, and finally c) long-term isolation from the atmosphere (please note that the latter two steps are not covered in this thesis). The separation of the CO2 emissions, so called capture, is usually regarded as the most expensive component in the CCS chain. The main application of CCS is most likely to be in the large point sources (due to technoeconomic aspects) such as fossil-fuel power plants, fuel processing plants as well as other industrial plants such as iron, steel and cement production plants. The application of CCS in power generation, industries and fuel transformation has a mitigation potential of up to 20% by 2050 according to IEA scenarios [26]. Despite the great progress achieved in the development of highly effective capture technologies, large-scale CCS application is not yet commercially available for the power generation sector [27]. Although considerable global efforts were under way to develop efficient and affordable CCS technologies, some barriers towards the widespread deployment of CCS-related technologies remain unsolved such as: Lack of international agreement on cutting CO2 emissions [28]; public perception and knowledge of CCS [28]; legal and regulatory aspects such as lack of regulations on CO2 quality for transport and storage and lack of required assessments of pipelines and storage sites [18, 28]; market and political issues such as carbon credits and uncertainty of future carbon costs [28]; High risk for leakage and other safety aspects associated with transport and injection of CO2 in the designated storage sites; high capital-intensity of most CCS technologies [26]; and lack of commercial-scale demonstration plant, high efficiency loss, technical maturity and uncertainties for CCS application in power plants. 2.3.2. The European Union climate strategy Taking serious actions to mitigate the dangerous effects of global warming has been one of the European Union’s strategic priorities during the last two decades. This will ensure more sustainable and secure energy systems. To limit the increase of the global average Technical background 15 temperature so that it does not exceed 2 ºC higher than the pre-industrial level, the European Council adopted three targets to meet by 2020 in relation to the 1990 level [29]: Reduction of GHG emissions by 20%; improving the energy efficiency by 20%; and increasing the share of renewable energy to 20%. The EU has also implemented several measures to reach these targets and to stimulate the economy and job market. Measures include, but are not limited to, are establishing the 1st international carbon market, the EU emissions trading system (ETS), assigning national targets for domestic GHG reduction and increasing RE sources, setting up new standards to improve energy efficiency and reducing GHG emissions in the transport sector [30, 31]. In implementing foregoing actions and strategies, Europe has made a good progress towards its target for GHG emissions reduction. The estimation for combined emissions from the European member countries was about 18% below the 1990 level in 2012 [31]. The share of renewable energy sources in gross final energy consumption was about 14%, and some countries could have already achieved their 2020 targets in 2012 [32]. The European Commission has recently announced its 2030 climate and energy goals, including: GHG emission reduction by 40% below the 1990 level, increase of renewable energy by at least 27% and renewed ambitions for energy efficiency policies. The European Union aims to achieve a competitive, secure and low-carbon economy, while maintaining the affordability of energy for end-users [33]. 2.4. Various capture technologies in the power sector The previous background information showed the necessity for CO2 emissions reduction in the power generation sector. Various CO2 separation methods have been developed and utilized by industry for many years. However, these technologies have not been commercially applied in the power sector through CCS application. All of the currently available technologies for large-scale CO2 separation require both significant additional equipment and energy input than the standard power plants without capture [34]. Progress in many directions connected to CO2 capture technologies has been rapid, and many innovative concepts have been developed during the last decade. Concepts like chemical 16 Technical background looping combustion (CLC), membrane and adsorption technologies have been explored to find more energy-efficient and less expensive approaches [35]. In spite of extensive development of the aforementioned emerging technologies, the timescale for the deployment of each technology in the power generation sector and its current development status differ. Due to the urgent need for successful demonstration of capture projects, it is important to check the near-term prospect of each capture approach to reduce the number of available options. The current section will, therefore, give an overview of the proven technologies for commercial CO2 capture deployment in fossilbased power plants. The available approaches for this purpose are often divided into the three following categories: Post-combustion capture from combustion flue gas; pre-combustion capture or de-carbonization of the fuel stream; and oxy-fuel combustion or direct combustion of fuel with oxygen (O 2). These three approaches are shown in Figure 2.4. These technologies can be applied to both gas-fired and coal-fired power systems. Post-combustion capture N2, O2, H2O Fuel Power & Heat CO2 separation Air CO2 Pre-combustion capture N2, O2, H2O Fuel Reforming/ Gasification Steam or Air/O2 Syngas Shift reaction, gas clean-up + CO2 separation H2 Power & Heat CO2 dehydration, compression, transport, and storage Air CO2 Oxy-fuel combustion Recycled CO2&H2O CO2 Fuel Power & Heat O2 Air N2 Air separation Figure 2.4. Technical options for CO2 capture from fossil-based power plants Technical background 17 Regardless of the CO2 capture type, the following common challenges need to be addressed by further development in CO2 capture technologies: The complexity of the power plants inevitably increases with deployment of CO2 capture. The operability and flexibility of the power plants are negatively affected by deployment of CO2 capture. In particular, these items need to be assessed: the dynamic/transient behavior of the plants during start-up, shut-down and loadchanging conditions. 2.4.1. Post-combustion CO2 capture The post-combustion CO2 separation comprises the removal of carbon dioxide from flue gas after combustion of the fuel. The small fraction of CO2 in the flue gas, which is mixed with other combustion products and a large fraction of nitrogen from atmospheric air, makes capture difficult. There are four main processes which can be utilized for largescale CO2 removal from flue gases: Absorption using re-generable liquid solvents; cryogenic separation anti-sublimation; membrane technology; and adsorption using solid adsorbents. The absorption process, by means of a re-generable chemical solvent (Figure 2.5), typically based on a form of amine, is currently considered as the most common/developed technique for post-combustion capture [36, 37]. Other CO2 separation methods still need more research and development attention to achieve mature and costeffective processes. The solvent is counter-currently being contacted by the sour gas (gas containing CO2) from the top of the absorber column. From the absorber bottom, the CO2-rich solvent is then transferred to a regenerator where it is stripped of the CO 2 by heat transfer (e.g. heat release from steam). The regenerated or CO2-lean solvent is cooled via a lean/rich solvent heat exchanger and recirculated to the top of the absorber, completing the cycle. 18 Technical background CO2 Lean gas Condenser Lean pump Lean amine cooler Absorber Blower Rich/lean solvent HEX Stripper Steam Reboiler Rich solvent Flue gas Direct contact cooler Treatment Figure 2.5. The schematic configuration of the conventional absorption system One of the most important features of the post-combustion capture is that it can be applied to newly designed or existing fossil-fuel power plants. In addition, this capture approach can be applied to other industries such as cement production, oil refining and petrochemicals. Moreover, the impact of this approach on the power conversion process is marginal [38], especially when an external heat source for regeneration is applied. However, the capture process is less efficient due to the low concentration of CO2 in the flue gas [38], which is typically between 3 and 15 vol% depending on the fuel type [18]. The major challenge ahead for the widespread deployment of post-combustion capture is the relatively large parasitic load on the power plant due to the energy intensive solvent regeneration process [38, 39]. Other secondary challenges are the high capital costs required for the capture unit and to develop proper solvents (in the case of the absorption method) with low degradation rate and volatility with fewer negative environmental impacts. Technical background 19 2.4.2. Pre-combustion capture Carbon dioxide can also be separated prior to the combustion process by converting the fuel to CO2 and hydrogen (H2) and removing the CO2 from the fuel gas. The following main processes can be utilized for large-scale CO2 separation from the fuel stream: Absorption using physical or chemical solvents or hybrid system using physical/chemical solvent; pressure/temperature/electric/vacuum swing adsorption; membrane technology; and calcium oxide carbonation. Similar to post-combustion, the absorption process is the most preferred technology for pre-combustion capture, more specifically using physical solvents when the pressure of the syngas is high. The other technologies are still at an early stage of development, and many uncertainties remain concerning the performance of these individual technologies when integrated into the rest of the power plant [18]. One of the promising technologies that could benefit from pre-combustion capture is the integrated gasification combined cycle. The block flow diagram of the IGCC power plant with CO2 capture is illustrated in Figure 2.6. The synthesis gaseous product (often known as syngas) leaving the gasifier, where partial oxidation of the fuel (e.g. coal or oil) occurs, is mainly a mixture of H2 and carbon monoxide (CO). By the addition of steam, the CO content of the syngas is catalytically shifted to CO2. The CO2 is finally removed from the H2 and the hydrogen-rich syngas is used as fuel in a gas turbine. The high CO2 concentration after CO-shift reaction allows efficient de-carbonization of the fuel stream. Therefore, pre-combustion imposes a lower energy penalty than for post-combustion with similar size and duty [40-42]. The other technologies which have great potential for pre-combustion capture are H2 production plants using steam reforming, partial oxidation and auto-thermal reforming of natural gas or light hydrocarbons [18]. Detailed descriptions of these technologies are available in standard textbooks and hence are not given here. 20 Technical background Sulfur recovery Sour gas Fuel Raw Gasification syngas Gas cooling/ dedusting Acid gas removal Shift reaction Steam Air/O2 Slag Clean syngas Liquid CO2 N2 N2 Air Air separation unit Power & Heat H2-rich syngas CO2 removal CO2 CO2 compression & dehydration Air Flue gas to atmosphere Electricity to grid Stack Figure 2.6. The block flow diagram of the IGCC power plant with CO2 capture As with CO2 captured at higher pressure level, compression energy demand and capture unit size (and consequently costs) are lower than those for post-combustion capture [40]. This capture approach also has the following advantages: Chemical processing of the syngas (as in IGCC plants) coupled with CO2 capture offers a wide range of products (e.g. H2, Fischer-Tropsch fuels) and a wide range of downstream equipment such as gas turbines and fuel cells [40]. Due to the higher pressure and lower volume of the syngas flow to be treated in the capture unit, the size of the capture unit is smaller than for the postcombustion capture, where flues gases are treated. Although the pre-combustion approach offers a less-expensive CO2 mitigation technology, the incorporation of this method has major effects on the power conversion process [38]. This drawback limits the application of pre-combustion on the existing power plants. It should be highlighted that the current thesis will focus on the application of postcombustion CO2 capture in IGCC plants and its effects on the techno-economic performance of the entire plant as well as on the GT unit. Technical background 21 2.4.3. Oxy-fuel combustion Oxy-fuel combustion is the last promising approach described in this chapter designed to support the separation of CO2 from fossil-based power generation. Similar to other carbon capture approaches, oxy-fuel has yet to be commercially deployed, while it has a lower technological readiness than the two latter capture technologies [28, 36, 39]. The nitrogen content of the air is almost 80 vol%, which dilutes the CO2 concentration in the flue gas from the combustion process and makes the downstream CO2 capture process costly. In the oxy-fuel combustion process, N2 is removed from the air by means of a large-scale air separation unit (ASU) before the combustion (refer to Figure 2.7). This process comprises a combination of high purity oxygen (typically around 95 mol%) and recirculation of the flue gas for combustion of the fuel. The combustion product is a gas consisting mainly of concentrated CO2 and water (H2O). Such a process (i.e. pure O2 combustion) has a combustion temperature of about 3500 °C [18]. Current materials cannot handle such a high temperature. Oxy-fuel combustion is not feasible for currently available gas turbines in natural gas combined cycles since their compression and expansion systems are not suitable for CO2 as the main working fluid instead of N2 in air [43]. Recirculation of a part of flue gas is, hence, to control the flame temperature and consequently NOx formation in the boiler. In addition, this recirculated stream compensates for the missing N2 flow to carry the heat through the boiler [27, 28]. This stream is also used to feed the fuel to the boiler in the case of coal-firing plants [28]. The recycle stream is about 60-70% of the flue gas, depending on the fuel composition [28]. The rest of the flue gas that is not recycled is then treated for undesirable components such as particulates and sulfur removal. The clean flue gas is finally compressed, cooled and purified from water vapor by condensation. The final product is predominantly CO 2, which is ready for transport and storage. 22 Technical background Flue gas to atmosphere Power N2 Air separation unit Air Pulverized coal O2 Gas-gas HEX Electrostatic precipitator Flue gas desulfurization Flue gas condenser Fly ash Sulfur product Water To CO2 purification, compression, transport & storage Flue gas secondary recirculation Coal Coal mill Flue gas primary recirculation Figure 2.7. The block flow diagram of the pulverized coal plant with oxy-fuel combustion One of the advantages of the oxy-fuel combustion is its significantly lower size of capture unit compared to other technologies by combusting the fuel using purified oxygen [38]. Furthermore, the oxy-fuel combustion eliminates the need for conventional CO2 removal technologies using chemical or physical absorption. Significant cost and energy savings can, therefore, be realized. Moreover, oxy-fuel combustion offers flexibility for the positioning of O2 injection either into the recycled stream (as pre-mixed condition) or directly to the burner compared to the air combustion, which may help to control pollutant emissions e.g. CO emissions [28]. However, the major challenges of oxy-fuel combustion also revolve around a drastic change of working fluid from conventional air combustion to a mixture of mainly CO2 and water vapor. The other technical uncertainties regarding the commercial deployment of oxy-fuel combustion are as follows: The need to supply high purity oxygen results in a large efficiency penalty using energy-intensive processes such as conventional cryogenic distillation. Such a process is not economically viable for oxy-fuel combustion [28] and can be replaced with emerging technologies such as ion transport membrane (ITM) technology to reduce the costs and energy consumption. Oxy-fuel combustion has a high impact on the power plant process, which complicates retrofitting existing plants [38]. This approach needs substantial modifications (redesign) for the GT or conventional steam boiler technologies (more specifically combustion system) due to the drastic change in the working fluid [38, 44]. Technical background 23 This approach cannot be applied just to a fraction of the main stream, so-called slipstream, similar to post- or pre-combustion capture. This causes such an approach to be applied only to a complete power plant module [39]. The high proportions of CO2 and H2O in the flue gases (compared to air combustion) result in higher gas emissivity (radiative heat transfer) [27]. Thus more sophisticated and expensive materials are required to be resistant against the higher heat transfer rate [38], and a large volume of the flue gas needs to be recirculated to offset the higher gas emissivity. Full-scale demonstration boilers/GTs are required to validate radiative CFD models and thereby provide accurate predictions of heat transfer between working fluid and materials [28]. In the case of boilers, the high concentration of CO2 (which has a high solubility in water), high level of sulfur, and chlorine species generate a corrosive media which requires particular caution when selecting proper materials [28, 38]. The condensation of water in the presence of a substantial amount of CO2 needs to be carefully assessed [38]. 3. Coal-based power plants The current chapter firstly includes a synopsis of energy supply by coal and CO2 emissions from coal-based power generation technologies. Different coal-based power systems are then reviewed. An overview of different available technologies and components which constitute an integrated gasification combined cycle power plant is further presented and discussed. Finally, the existing IGCC plants are listed and their specifications are reviewed. The outline of Chapter 3 of this thesis is shown in Figure 3.1. Why coal-based power plants? (3.1) Coal-fired power generation (3.2) Integrated gasification combined cycle (3.3) Air separation Gasification (3.3.1) (3.3.2) Syngas cleaning and conversion (3.3.3) CO2 compression and dehydration (3.3.4) Current IGCC power plants status (3.4) Figure 3.1. Outline of Chapter 3 25 Gas turbine (3.3.5) Bottoming cycle (3.3.6) 26 Coal-based power plants 3.1. Why coal-based power plants? Coal showed 2.5% higher consumption in 2012 compared to 2011 and has been the fastest-growing fossil fuel during recent years [8]. The global distribution of proved coal reserves (total: 860,938 Mt), together with coal consumption (total: 3,730 Mtoe) and production (total: 3,845 Mtoe) are shown in Figure 3.2 (data from Ref. [8]). The IEA’s New Policies Scenario projected a 25% increase in coal consumption in the year 2035 compared to 2009, while the other IEA scenario, Current Policies, predicted 65% higher coal consumption than the level of 2009 [5]. 2% 14 % 29 % 31 % 12 % 1% 4% 4% 68 % 35 % 0% 0% (b) (a) North America 1% 12 % South & Centerl America Europe & Eurasia 14 % 0% 70 % 3% Middle East Africa Asia Pacific (c) Figure 3.2. Global share of (a) proved coal reserves, (b) coal production, and (c) coal consumption at the end of 2012 Coal-based power plants 27 The main reasons for the continued utilization of coal are the abundant resources of coal (more than 100 years with current proved reserves and consumption rate), its widespread availability and less-volatile price compared to the other fossil fuels [8, 45, 46]. Thus, coal has emerged as the most widely used fossil fuel for large-scale power generation, though natural gas use is also increasing, mostly in localities of availability due to the fact that it is more environmentally friendly [5]. Coal is not only the most used fossil fuel for power generation but it is, unfortunately, the most polluting fuel due to its heavy carbon content per unit of energy released. Carbon content is 15.3 tC/TJ for natural gas, while it is almost double, 25.8 to 28.9, for different types of coal [47]. Carbon dioxide emissions from coal for heat and power production were 8.9 Gt CO2 in 2011, about 28.5% of the global anthropogenic CO 2 emissions [3]. Given the continued need to use coal as primary fuel and requirements to limit its CO 2 and conventional emissions, a genuine demand for the development of reliable and lowemission coal technology has been generated. In addition, some political actions have been taken which are in favor of clean coal technologies. New regulations which enforce the construction of new coal-fired power plants with CCS demonstration or CCS ready capability are among those [27]. However, it should be mentioned that due to low costs for CO2 allowances, there is still not enough pressure on owners to build plants with CO2 capture. 3.2. Coal-fired power generation The major coal-based power generation technologies available today are pulverized coal combustion (PCC), fluidized bed combustion (FBC) and IGCC. This sub-section will briefly touch on PCC and FBC technologies, while the rest of this chapter will focus on IGCC. PCC technology has been dominating coal-fired electricity generation worldwide for almost 100 years. Figure 3.3 illustrates the block flow diagram of the typical pulverized coal-fired plant (with post-combustion CO2 capture unit). Typical operating parameters of pulverized coal plants using a sub-critical steam cycle are 163 bar pressure and a temperature of 538 °C for both superheat and reheat [48]. The efficiency of a steam cycle is a function of the steam pressure, superheat and reheat temperatures, which are all 28 Coal-based power plants dependent to the advances in materials that are selected for the boiler and turbine and pipework connecting them [49]. In order to achieve higher technical performance and lower emissions, supercritical and ultra-supercritical pulverized coal plants have been developed. These plants are operated beyond the critical point of water, i.e. 221 bar and 374 °C [49]. Supercritical and ultra-supercritical technologies are more beneficial, avoiding surface tension between liquid and gas phase and eliminating the use of a drum for separation of water and steam in sub-critical plants. They are also better suited to frequent load variations compared to sub-critical boilers. The typical pressure range of SCPC is more than 245 bar, with the temperature in excess of 550 °C for both superheat and reheat steam, and the temperature range of ultra-supercritical pulverized coal plants (USCPC) is around 600°C or higher [48]. Although the share of SCPC and USCPC plants currently under construction or planned is increasing, sub-critical technology has still continued to dominate coal-fired power plants. However, the share of supercritical and ultra-supercritical plants might be increased with stricter requirements for CO2 emissions [50]. Steam/water to and from capture plant Feedwater heater system Air Ammonia Oxidation air Electrostatic precipitator Pulverized coal boiler Water Coal Limestone Flue gas Flue gas Pre-heated air Coal and ash handling DeNOx plant FGD Capture unit Bottom ash CO2 product Fly ash Effluent HP turbine IP turbine LP turbine Gypsum Condenser Flue gas Stack Figure 3.3. Block flow diagram of typical pulverized coal-fired plant with CO2 capture Coal-based power plants 29 The other coal-based plant, i.e. FBC technology, contributes in niche applications, e.g. in the combustion of low quality coals [51]. This technology offers both atmospheric and high pressure operation [52]. A fluidized bed combustion system is generally characterized by acceptable availability and fuel flexibility and has a good emissions performance. Its emissions control is usually cheaper than that of PCC technology. Although development efforts have been focused on scaling up the technology, the capacity of this technology is far behind the conventional PCC plants [53]. Similar to SCPC and USCPC technologies, the development of advance materials to cope with higher pressure and temperature will improve the technical performance of this technology [27]. Carbon dioxide emissions can be captured from both the abovementioned technologies, i.e. PCC and FBC, using oxy-fuel and post-combustion methods. However, challenges including the parasitic effects of CCS using post-combustion (refer to Chapter 2) require technical progress such as achieving higher plant efficiency. The other alternative coal-fired technology is the IGCC power system. The integrated gasification combined cycle is currently one of the most promising technologies for the efficient use of coal. This technology enables the conversion of coal (and other solid or liquid fuels) into synthetic gas fuel, while still maintaining ambitious emissions targets and high efficiency. IGCC technology benefits from its widely known environmental credentials such as low emissions of sulfur dioxide (SO2) and nitrogen oxides (NOx) [54]. Although this technology suffers from high capital costs and is perceived to be more complex than other technologies, e.g. pulverized coal plants, its significantly better emissions performance is of high interest for future large-scale deployment [27, 49]. In addition, the IGCC technology offers co-gasification of biomass1, good performance with lower grade coals and other feedstock [55], as well as co-production of H2 and electricity [56]. Moreover, IGCC technology is technically well suited for CO2 capture. If CCS becomes mandatory for the next generation of fossil-based power plants, high-efficient precombustion carbon capture methods can be incorporated into the IGCC system. The additional cost due to the capture unit will be significant but probably lower than for PCC 1 The biomass co-gasification can be utilized to achieve even a CO2-free or CO2-negative condition when CO2 capture is integrated into the cycle. 30 Coal-based power plants systems [57]. Regardless of the lack of demonstration activities for IGCC plants with CO2 capture, every component of this system has been commercially utilized in other industries, such as chemical industries, petrochemical complexes, etc. The heart of the power generation unit, i.e. gas turbine technology, suited to an IGCC system with and without carbon capture unit, when the diluted syngas is used, is also currently available on the market [58, 59]. 3.3. IGCC power plant’s components An IGCC power plant consists of several components which can be categorized in different sub-systems depending on their main processes. The main sub-systems of an IGCC plant are as follows: Coal receiving and storage unit; air separation unit; coal milling, drying, and gasification; syngas cleaning and conversion unit; water-gas shift reaction unit (in a plant with CO2 capture unit); acid gas removal (AGR) unit; CO2 compression and dehydration (in a plant with CO2 capture unit); and power island consisting of a gas turbine and a heat recovery steam generator (HRSG), steam turbine, generator, auxiliaries, etc. With the exception of coal receiving and storage units, process descriptions of the stateof-the-art technologies for main sub-systems together with currently potential alternative technologies for each sub-system will be presented here. 3.3.1. Air separation Oxygen supply to the gasifier represents a major part of the energy consumption and capital costs of any IGCC power plant. The technology currently used for oxygen production is the cryogenic separation of the air by distillation, a mature technology used for over 100 years. In a typical cryogenic air separation unit (refer to Figure 3.4), the air is initially compressed to a pressure of about 5 bar [18]. It is then purified using multiple fixed bed adsorption units to remove water, CO2, N2O and trace hydrocarbons. Such components Coal-based power plants 31 could accumulate to undesirable levels in the cryogenic parts such as the reboilercondenser, causing a blockage (due to freezing of CO2 and H2O) and other safety issues for the plant operation. The adsorption units are regenerated by either temperature or pressure swing with a low pressure N2 stream. Then, the air is cooled to about its dew point by heat transfer with returning products (O2 and N2) in the main heat exchanger. The air is finally separated into oxygen, nitrogen and, optionally, argon (Ar) streams in the separation part. The separation process depends on the relative volatility of the more volatile components (N2 and Ar) relative to less volatile O2. A basic arrangement for the separation part involves a double distillation column which has a reboiler-condenser between two columns [60]. The O2 product can be withdrawn from the base of the low pressure column (upper column in Figure 3.4) either as a liquid or a gas. Air Filter MAC Pretreatment Low pressure column GOX GAN Expander Product compression Reboiler/ condenser Main heat exchanger Subcooler High pressure column Figure 3.4. Schematic configuration of the cryogenic air separation unit The main parameter controlling the power consumption of a cryogenic ASU is the main air compressor (MAC) discharge pressure, which is inherently affected by the pressure 32 Coal-based power plants balance and reboiler-condenser design. Consequently, numerous alternatives for the configuration of heat exchange, distillation, compression and pumping exist to minimize the energy consumption of an air separation unit. The second important parameter affecting power consumption is the number of product streams and their purity. The higher purity of the O2 product (typically higher than 97%) requires a higher number of separation stages, which results in higher MAC discharge pressure, capital and operational costs [60]; hence, there is a trade-off between capital cost and power consumption and the purity of oxygen. Generally, the main areas to reduce specific energy consumption and costs are: Efficiency improvement by integration of ASU with other sub-systems such as GT compressor; development of other air separation technologies to reduce specific energy consumption for O2 production (kWh per unit of O2 product); and improvement of basic components of cryogenic ASU. 3.3.1.1. Cryogenic ASU and power island integration options The power generation block of an IGCC plant could be integrated with the air separation unit (refer to Figure 3.5) through the following ways: Gas turbine air extraction (full or partial air integration) to supply the ASU; and N2 supply from the ASU to the GT for dilution purposes (NOx control), for turbine cooling, for GT power augmentation, and for increase of steam generation in the HRSG. Air extracted from a GT compressor can be used to partially or fully supply the requirements of the ASU, which can be defined according to the following equation: Air − side integration = Air to ASU from the GT Total Air to ASU (Eq. 3.1) Full GT-ASU integration means that the feed air for the ASU is completely supplied by the gas turbine air compressor [61]. The integration between the ASU and the gas turbine can significantly affect GT performance [62], which will be discussed later in this chapter. Most European IGCC designs have selected full GT-ASU integration targeting maximum overall plant efficiency [63]. However, this integration option generates some operation problems. The main difficulty is control of the ASU when the GT operates at variable Coal-based power plants 33 load. Increase of GT power output may result in an increased GT compressor discharge pressure, which causes a pressure rise of the air delivered to the ASU. Consequently, the boiling pressure and temperature of the liquids in the ASU will be elevated, meaning that liquids in the columns will be sub-cooled. The net vapor flows will then be reduced, while the GT combustor requires higher fuel flow for the increased power production and vice versa. This problem may be efficiently resolved utilizing an expansion turbine before air injection to the ASU to maintain the discharge pressure of the GT compressor similar to that required by the ASU. The other problem with full air integration arises during start-up of the ASU and the gasification system. Gasification needs O2 and N2 (depending on the technology selected for gasification) to produce syngas (i.e. the GT fuel). Therefore, the gas turbine should operate on NG or liquid fuels to supply the initial amount of air, or a supplementary air compressor for start-up of the ASU should be considered. Partial air integration means that only a part of the air required for the ASU is supplied from the GT compressor and the rest is provided by a supplementary compressor. This configuration allows the GT system to be started after the start-up of the ASU and gasification processes. The amount of air flow to be withdrawn from the GT compressor depends on the air flow required for the plant start-up (to be supplied by a separate compressor) and the amount of air available from the GT (based on the GT design [64] and the prevailing atmospheric conditions). The optimal situation is to ensure that the overall loading of the GT expander is maximized (choked). The required thermal energy input of the GT shows a substantial increase in fuel gas flow in the case of using diluted syngas fuel due to its significantly lower calorific value compared to that of NG. The additional fuel flow (compared to the NG case) possibly results in bleeding of the GT compressor air to avoid an increase in flow rate expanding in the GT expander, which is already maximized. Consequently, this is the available air feed which could be allocated to the ASU [60]. 34 Coal-based power plants To gasification O2 To atmosphere N2 Air separation unit Syngas fuel Air LP DGAN Heat recovery steam generator Stack HP DGAN Air LP DGAN Heat integration LP DGAN (and H2O) Air Figure 3.5. Integration options of the ASU and the power island The zero supply of air from the GT compressor to the ASU (or non-integrated air-side GT-ASU) is usually only optimum when higher operational flexibility, availability, and reliability of the overall IGCC system is the main concern [65]. However, this option may be also applied under circumstances when the air flow from the GT compressor is limited (e.g. due to the re-allocation of the GT compressor air for cooling purposes of expander’s parts) [60] and there is no need for dilution using N2 coming from the ASU. In addition to air-side GT-ASU integration, high pressure (HP) diluent gaseous nitrogen (DGAN) from the ASU can be integrated into the GT as diluent to control NOx emissions [66]. Nitrogen could be compressed and then heated by the extracted air feed stream from the GT in the case of partial or full air integration. It should be mentioned that, in the most recently developed GTs, the margin allowing for extra fuel (or added N2) is limited and depends on atmospheric conditions [60]. N2 injection could be performed directly to the combustor or as a mixture with the syngas. This nitrogen can also contribute to increased power output from the expander [62]. Low pressure (LP) diluent gaseous nitrogen (DGAN) is commonly used in the ASU as a source to cool the compressed air feed stream from the GT [67]. Low pressure DGAN together with chilled water from the ASU could be fed to the inlet of the gas turbine compressor to reduce the bulk air temperature and thereby increase the air mass flow rate to achieve higher GT power output. The use of Coal-based power plants 35 nitrogen as diluent also provides the opportunity to exploit higher steam generation in the HRSG due to the lower dew point of flue gases containing higher amounts of N2. 3.3.1.2. Other ASU technologies The other important oxygen production technologies are adsorption, polymeric membrane and ion transport membrane processes. Ongoing research and development will continue to improve both the economy and the energy efficiency of these technologies. Unlike cryogenic plants, which need approximately two hours to produce O2 and N2 from a coldcondition start-up, adsorption and membrane systems can be started and powered up to full load within a few minutes [68]. Adsorption and polymeric membrane systems are less complex and more passive compared to cryogenic systems. However, neither technology could yet compete with cryogenics for large-scale O2 production, especially at high purities. Moreover, neither technology is capable of directly producing argon [69]. Ion transport membrane technology is a breakthrough ASU technology and the most promising alternative to cryogenic technology for the production of large quantities of oxygen. Compressed high-temperature air (at about discharge pressure of GT compressor and 800-900 °C) is electrochemically passed through highly selective ceramic membranes at high flux. Oxygen on the feed side (i.e. air) is ionized on the surface of the membrane and diffuses through the membrane as ions forming oxygen molecules on the permeate side [60]. The primary advantage of such technology is its significant potential for capital costs reduction compared to cryogenic systems [70]. This potential could be up to 30% compared to cryogenics in IGCC application [71]. Furthermore, ITM offers the possibility of providing O2 with a less adverse effect on the efficiency of the power plant than the cryogenic system, although this performance improvement is not strong (in the range of a few decimal points) [72]. However, similar to other non-cryogenic technologies, ITM has shortcomings concerning the production of pure and liquid by-products [69]. Moreover, this technology needs to be commercially developed and integrated into the IGCC system [73]. 3.3.2. Gasification The gasification process is one of the most important parts of the IGCC system and has gained special significance in the context of future generation IGCC plants with CO2 capture. This process is to convert coal (can also be other feedstock, e.g. biomass, liquid 36 Coal-based power plants fuels, etc.) through sub-stoichiometric reaction with oxidant agents, either air or O2 at a temperature exceeding 700 °C to produce a synthetic gaseous product [41]. Compared to conventional pulverized coal combustion, gasification offers great opportunities for both higher efficiency and improved capture of pollutants. The commercial gasification technologies can be classified into three categories according to the flow geometry: entrained-flow, fluidized bed, and moving bed gasification technologies [74]. In most existing industrial plants, including IGCC power plants, the entrained-flow gasifiers have had extensive operating experience [75]. Thus, the description of other main categories, i.e. fluidized bed and moving bed are excluded here and can be found in references [41, 74]. 3.3.2.1. Entrained-flow gasifiers Entrained-flow gasifiers allow high operating pressures (20-80 bar) and temperatures (1200-1600 °C). The high pressure and temperature environment of the gasifier facilitates the gasification of the fed coal [76]. However, challenges corresponding to measurement techniques and instrumentation due to the rigid environment, and possible problems with slag handling and removal still need more development [77, 78]. High operating temperatures enable a favorable slagging process to remove ash and render gasification almost tar-free. The released heat results in the melting of the ash content and the production of molten, inert slag (eventually as the only solid waste). Meanwhile, and under extremely hot conditions, the carbon content in the coal is converted mainly to CO due to the reducing environment of the gasifier. This type of gasifier typically provides a high H2/CO ratio syngas. Apart from these combustible compounds, products typical for combustion, CO2 and H2O, are also produced. Steam or other compounds are added to the gasifier to moderate the hot temperature of the process. Further details such as dominant reactions within the gasifier can be found in Paper III of this thesis. The oxidant agent can be oxygen or air. Amongst the various gasification technologies, oxygen-blown gasification is an attractive process for the production of high calorific value syngas (mainly due to its high H2 content). The plant’s components (gasifier and downstream equipment) are also much smaller than that with the air-blown technology due to oxygen combustion in the gasifier. On the other hand, the absence of a large ASU in air-blown gasification offers some advantages in terms of capital and operating costs Coal-based power plants 37 and efficiency. However, the increase in the capital costs associated with a less effective capture process (due to the removal of CO2 from a larger volume syngas diluted by N2 in air) offsets the reduced power consumption of an air-blown system [79]. The feedstock can be fed either dry (using N2 as a conveying gas) or wet (using slurry water) into the entrained-flow gasifier. In a dry-fed system, there is no need for water evaporation (like for those slurry systems) in the gasifier, leading to high cold gas efficiencies 1 compared to (single stage) slurry-fed entrained-flow gasifiers [80]. In slurryfed gasifiers, pulverized coal is mixed with water to produce a slurry feed. The typical range of slurry (ratio of solid to whole mixture) varies from 35 to 70 wt%, depending on the coal’s characteristics [65, 81, 82]. The slurry type of gasifier utilizes a slurry pump to feed the slurry into the gasifier, enabling the process to have a higher operating pressure compared to dry-fed systems. High operating pressures result in a more efficient CO2 separation due to the high partial pressure of CO2 in the syngas. In slurry-fed gasifiers some CO and H2 burning is required to vaporize the slurry water. The syngas, therefore, has a relatively high content of the combustion products (i.e. CO2 and H2O), which is again suitable for the operation of downstream shift reaction and CO2 capture units. The relatively high operating pressure of slurry-fed gasifiers compared to dry-fed gasifiers results in a higher partial pressure of CO2 and consequently a lesser energy penalty due to the removal process [83]. However, the ratio of hydrogen sulfide (H2S) to CO2 is higher in dry-fed gasifiers, which improves sulfur recovery using a conventional absorption system unit [84]. In addition, the dry-fed gasifiers show better performance when operating on low quality fuels (with low calorific values) compared to the slurry-fed. Moreover, the quality of produced syngas in dry-fed gasifiers is relatively constant compared to slurryfed types, even when low calorific fuel is gasified. The aforementioned features of entrained-flow gasifiers are very desirable for large-scale power generation. Hence, almost all the commercially useful coal gasifiers deployed for large-scale power generation are of this type. Some of the leading companies in the power sector have patented their gasification technologies, such as Shell Coal Gasification Process (SCGP), General Electric (GE) gasifier (formerly Texaco), and ConocoPhillips (E-GasTM) gasifier for O2-blown and Mitsubishi Heavy Industry (MHI) for air-blown 1 This term will be introduced later in this section. 38 Coal-based power plants entrained-flow type. The main characteristics of commonly used oxygen-blown and airblown entrained-flow gasification technologies are shown in Table 3.1. Table 3.1. The main characteristics of various commercial gasifiers Specification SCGP GE/Texaco E-GasTM Flow regime Entrained-flow Entrained-flow Entrained-flow Type of ash Slag Slag Slag Oxidant O2-blown O2-blown O2-blown Dry/slurry Dry-fed Slurry-fed Slurry-fed Feed type PC PC PC Pressurization Lock hopper Slurry pump Slurry pump Number of stages Single Single Double Slag removal Lock-hopper Lock-hopper Continuous system pressure letdown system [41] Flow direction Upward flow Downward flow Upward flow Boiler position Side-fired Top-fired Side-fired Quenching type Quenching with Full water quench, Two-stage recycle gas and radiant cooler, and gasification radiant cooler radiant/convective coolers Reactor type Membrane-wall Refractory-lined Refractory-lined [80] Cold gas 78-83% [80] 69-77% [85] 71-80% [85] efficiency Carbon conversion Above 99% [80] Above 96% Above 99% [86] Availability targets 92%[87] 88-90% [83] 92% MHI Entrained-flow Slag Air-blown Dry-fed PC Lock hopper Double Lock-hopper Upward flow Side-fired Two-stage gasification Membrane-wall 70-75% [85] Above 99% [76] Not available 3.3.2.2. Gasification performance Coal properties and characteristics such as ash content and reactivity are amongst the most important parameters affecting the performance of gasifiers in IGCC application. The effects of important coal properties on the performance of the gasification process are briefly presented here. In addition, cold gas efficiency, which is an indicator of gasification performance, is also introduced later. Coal-based power plants 39 3.3.2.2.1. Coal quality There are various types of coal, and each has specific properties. Coal is typically classified based on the content of fixed carbon and volatile matters. Table 3.2 shows the four classes of coal with their characteristics and thermal properties [41]. Class Anthracite Bituminous Sub-bituminous Brown coal (lignite) Table 3.2. Coal classification Volatile matter (wt%) Fixed carbon (wt%) <8 >92 8-22 78-92 22-27 73-78 27-35 65-73 HHV (MJ/kg) 36-37 32-36 28-32 26-28 An advantage of entrained-flow gasification is its fuel flexibility. This type of gasifier allows the choice of a wide range of feedstock with different prices, including low-rank coals with lower prices. The main specifications of low-rank coals (e.g. lignite coals) are typically high levels of ash, moisture, sulfur, chlorine and alkali metals as well as low ash melting point [55]. It is estimated that 53% of global coal reserves consist of average and low-rank coals, i.e. sub-bituminous and lignite [8]. Even though an entrained-flow gasifier can process a wide range of feedstock [65, 78], the feedstock characteristics significantly influence the gasification performance [56, 78]. The existing gasifiers show a substantial increase in cost combined with a drastic reduction in performance operating on low-rank feedstock, e.g. lignite coals [83]. Nevertheless, the utilization of such types of coals can broaden the range of suppliers and consequently improve the security of the energy supply [55]. The main parameters for selection of coal type in IGCC plants are ash content, slag viscosity and coal reactivity. A low ash content coal is favorable for IGCC power plants since it produces a lower fly ash and lower bottom slag that can result in a possible plugging of exit pipes and downstream heat exchangers [78]. The slag viscosity directly determines the operating conditions of the gasifier. Higher slag viscosity induces the possibility of a blockage of the slagging system and also requires a higher gasification temperature, which decreases the lifetime of the refractory materials. In order to have a continuous slag tapping process, a viscosity less than 25 Pa.s (250 Poise) is required [41, 88]. The viscosity of the slag tends to be high at high concentrations of Al2O3 and SiO2. Conversely, the viscosity has a tendency to be low if the CaO, MgO and FeO contents are high [55, 88]. The slag viscosity needs to be reduced when it is higher than the 40 Coal-based power plants abovementioned critical value. Utilizing a fluxing agent (such as limestone) or mixing with a coal which has a lower slag viscosity are the main solutions for lowering the viscosity. Coal reactivity determines the amount of required oxidant agent for gasification. The lower coal reactivity results in a higher injection of oxidant agent and consequently lower gasifier performance. In summary, the best coal type for IGCC to reduce operation difficulties and shutdowns appears to be one which contains low ash, has low slag viscosity and high coal reactivity [74, 78]. The secondary parameters for coal selection are coal water and sulfur contents. Generally, coal containing lower surface moisture would be beneficial in terms of lower drying cost in dry-fed gasifiers and lower oxygen consumption in slurry-fed gasifiers [78]. A higher sulfur content results in a higher loss of H2 content produced within the process, such as H2S, and has a detrimental effect on electricity production. 3.3.2.2.2. Cold gas efficiency One of the main parameters to determine gasifier performance is cold gas efficiency. This parameter is an indication which shows how much of the energy input has been recovered as chemical energy in syngas [78]. The cold gas efficiency is defined as: ηcg = LHVsg Q̇sg LHVci ṁci (Eq. 3.2) The cold gas efficiency of a single-stage slurry-fed entrained-flow gasifier is lower than that for dry-fed gasifiers (refer to Table 3.1). A slurry-fed gasifier requires 20-25% more O2 for vaporization compared to a dry-fed gasifier due to the higher water content (because of slurry) [76]. Therefore, more carbon in coal is oxidized to CO 2 in the slurryfed gasifier, which reduces the cold gas efficiency. The problem is even larger when the coal rank is low. The higher moisture content of the coal is not useful for the slurry’s transport properties and a large amount of water is still required for the slurry. Consequently, the overall efficiency of the plant is reduced by an increase in the ASU size and higher auxiliary power demand. This water content results in a higher H2/CO ratio (details concerning the gasification’s CO-shift reaction are available in Paper III). On the contrary, the dry-fed gasifier can handle a wide range of feedstock such as any type of coal with a relatively lower effect on the produced syngas’ properties and cold gas efficiency [80]. Coal-based power plants 41 3.3.3. Syngas cleaning and conversion Raw syngas produced in a gasifier contains many impurities such as particulate matters (PM), heavy metals, undesirable gaseous components such as acid gases, etc. It also contains a high amount of carbon monoxide, which needs to be converted to carbon dioxide for CO2 capture application; hence, cleaning, conditioning and conversion of syngas is required for its efficient use in IGCC applications. 3.3.3.1. Syngas cleaning The cleaning of the syngas produced in the gasifier is unavoidable before its combustion in a gas turbine to protect the GT and to keep the pollutant emissions below the environmental restriction levels [89]. The cleaning process consists of the removal of ash and particulates, as well as control of ammonia (NH3) and heavy metals (such as mercury, arsenic, selenium, etc.). It should be mentioned that the separation of H 2S and carbonyl sulfide COS is excluded here and will be described later in Section 3.3.3.3 (Acid gas removal). Most of the coal ash is removed from the gasifier as slag in all entrained-flow gasification technologies. The remaining ash in syngas is captured in the downstream equipment. The clean-up configuration strongly depends on the gasification process. Ash and PM control consists of cyclones, candle filters and a syngas scrubber in the case of the SCGP and the E-GasTM gasifiers, while it consists of a water quench and a syngas scrubber for the GE gasifier [90]. De-dusted syngas exiting the water wash scrubber is almost free of chlorides, NH3, SO2 and PM. Water used for quenching purpose or scrubbing is then sent to a sour water stripper for treatment. For mercury removal efficiency, the design target is about 90-95% [90], although environmental targets (if available) for mercury control differ, based on the local regulations [91, 92]. Mercury removal is typically performed via an adsorption process. Sulfur-impregnated activated carbon is used as adsorbent and the lifetime of the adsorption bed is up to two years. This process is performed prior to the acid gas removal unit in power plants with and without CO2 capture. Conventional syngas cleaning commonly consits of multi-stage pollutants’ separation. Advanced syngas clean-up technologies are thus being developed to eliminate several plant components for contaminants control [77]. Such clean-up processes will be 42 Coal-based power plants concisely presented in Section 3.3.3.5 (Advanced syngas cleaning and conversion), since they simultaneously remove H2S in addition to other pollutants and convert syngas. 3.3.3.2. Water-gas shift reaction The produced syngas from commercial gasification technologies for IGCC application contains high amounts of CO (25–50%) [93]. In IGCC power plants with CO2 capture, the water-gas shift (WGS) process is the first step in converting the gasifier product into a high hydrogen content syngas. This process is a moderate exothermic reaction, which is used to convert CO as a component of the syngas into CO2. This is carried out by shifting the CO with steam over a catalyst bed (Reaction 3.1). KJ (44mole) CO(g) + H2 O(g) ↔ CO2 (g) + H2 (g) (Reaction 3.1) The reaction is equilibrium limited, implying the dependency of CO conversion on reaction temperature, which is thermodynamically favored at low temperatures. On the other hand, WGS reaction is kinetically favored at high temperatures (higher catalyst activity as well as faster reaction is achieved at higher temperatures). Therefore, this reaction is typically designed in two sequential reactors, where the first reactor (operating at a higher temperature) converts the bulk of CO and the second reactor (operating at a lower temperature) increases the overall CO conversion [94, 95]. However, factors such as desired CO2 capture efficiency, sulfur emission limit (will be described later), coal quality, gasifier design, etc. change the number of reaction stages and process design [96]. The operating temperatures of each stage are determined by catalyst type used in the reactors, the amount of steam injected to the syngas stream and heat integration with other components. The temperature range is between 150 and 530 °C [96, 97]. The reactor can be located either upstream (sour shift) or downstream (sweet shift) of the acid gas removal unit (Figure 3.6). The location depends on the type of catalysts used for the reaction. Some catalysts such as Fe, Cr or Cu-based are poisoned by a small amount of sulfur compounds (higher than a few ppm levels) in the syngas. Hence, such catalysts should be utilized after separation of sulfur compounds [97]. In contrast, Co or Mo-based catalysts have the advantage that the sulfur compounds do not need to be separated from the syngas prior to the WGS unit [98]. It has to be borne in mind that such catalysts need a minimum level of sulfur compounds to operate actively. Shift catalysts based on Coal-based power plants 43 molybdenum sulfide need a certain H2S concentration to stabilize the catalytic active phase (higher than 100 ppm depending on the temperature level). The sulfur levels required by catalysts may not be reached with low sulfur coals. Therefore, coal characteristics are also a key element to be considered for efficient WGS design [99]. Steam WGS HT shift LT shift Syngas High CO2 & H2 content Compressed CO2 Sour Fuel Gasification Raw Gas syngas cleaning Sweet H2S removal CO2 capture To atmosphere O2 Air Slag ASU Heat recovery steam generator Stack HP Air IP/LP Gas turbine Figure 3.6. Schematic configuration of the IGCC plant with sour or sweet WGS unit In order to protect the catalytic bed from carbon deposit, to control the reaction temperature, as well as to increase equilibrium conversion of CO to CO2, the WGS reaction requires a large amount of steam (much larger than stoichiometric requirement) [100]. Syngas produced in dry-fed gasifiers (e.g. SCGP and Siemens Fuel Gasification (SFG) technologies) has lower water content and requires an injection of a considerable amount of steam (mostly from the steam cycle) to ensure acceptable CO conversion. On the contrary, syngas produced in slurry-fed gasifiers (e.g. GE gasifier) has higher water content and requires lower supplementary steam injection. However, higher CO2 content in the syngas produced in such gasifiers changes the equilibrium reaction direction to a backward WGS reaction. Hence, it requires higher residence time for the reactor to reach the targeted conversion of carbon monoxide. 44 Coal-based power plants For IGCC power plants with CO2 capture, a sour WGS (SWGS) reaction may be a better option. This helps to avoid additional cooling of the syngas required by the conventional AGR unit (refer to the next section) upstream of the WGS unit and then reheating to the level required for the catalyst’s activation in the WGS unit. It is also beneficial in order to postpone the water condensation that occurs during the conventional AGR process downstream of the WGS unit, as the WGS unit requires the existence of a considerable amount of steam. Despite the extensive ongoing research into finding improved catalysts [101], innovative WGS configuration has also been investigated in order to reach a higher technical performance of the WGS unit in IGCC application. An advanced WGS reaction configuration equipped with syngas splitting has been utilized to feed four WGS reactors in a staged configuration with intermediate water and synthesis gas quenches. The potential of such a configuration for steam reduction is significant (54%), while it is moderate for a reduction in efficiency penalty (2.7%) compared to the conventional WGS [102]. However, the increased number of reaction units as well as the amount of water quench should be optimized to balance the steam reduction with the higher capital costs. These higher capital costs compared to the conventional unit are not only associated to a higher number of reaction units but to the overall larger volume caused by a lower thermodynamic driving force for CO conversion [100]. 3.3.3.3. Acid gas removal In IGCC plants, the sulfur content of the coal is mainly converted to H2S and COS due to the highly reducing conditions of the gasifier [89]. Such gaseous components can produce acidic solutions after dissolving in water and hence, are corrosive under moist conditions. The combustion process converts H2S and COS to sulfur oxides, which are precursors of acid rain. Their emissions to the atmosphere are, thus, limited by stringent environmental regulations. Acid gases must, therefore, be removed from the syngas prior to the gas turbine to avoid GT damage and to comply with legislation [103]. The removal of acid gases from the gaseous streams has been widely practiced using the gas-liquid scrubbing process. This process consists of three solvent-based methods including physical, chemical and hybrid (physical/chemical) solvents. Though some of the current IGCC plants (without CO2 capture) have utilized chemical solvents (mainly amine-based solvents), physical solvents (e.g. Selexol or Rectisol) are the most preferred Coal-based power plants 45 choice for the IGCC application with CO2 capture [104]. The reasons are high partial pressure of acid gases in the syngas, highly efficient sulfur removal process and moderate operation costs offered by these solvents, and low desorption heat for solvent regeneration [105-107]. Figure 3.7 schematically highlights the better performance of physical solvents than chemical solvents at a higher partial pressure of acid gases (based on the data available in [107]). As shown in Figure 3.7, the solubility of acid gases in a physical solvent follows Henry’s law and increases linearly, unlike the chemical solvents which plateau at a higher partial pressure of acid gases [45]. Chemical solvents Solvent loading Physical solvents Partial pressure Figure 3.7. Schematic comparison between loading characteristics of chemical (monoethanolamine (MEA)) and physical (Selexol) solvents Different physical solvents for absorption processes have their own advantages and disadvantages. In this regard, the following criteria should be considered for the selection of a proper solvent [104, 107-109]: High loading capacity for different acid gases and high thermal stability; low vapor pressure for minimal solvent losses and low viscosity; non-reactive as well as non-corrosive; high availability with a reasonable price; low degradation rates; and low health, safety, and environmental impacts. 46 Coal-based power plants Amongst several physical solvents, Selexol (dimethyl ethers of polyethylene glycol), has been extensively employed for acid gas removal. Its main advantages are high H2S solubility, low vapor pressure, wide operating conditions, chemical stability, non-toxicity and biodegradable material [107]. The characteristics of Selexol solvent are presented in Table 3.3, below [107, 108]. Table 3.3. Characteristics of Selexol Gas Unit Value H2 solubility -a 0.047 CO solubility -a 0.10 CO2 solubility -a 3.63 COS solubility -a 8.46 H2S solubility -a 32.4 Chemical formula CH3(CH2CH20)nCH3 Density kg/m3 1030 Molecular weight g/mol 280 Vapor pressure mbar 9.7e-4 Viscosity Pa.s 5.8e-3 a Solubility ( gas volume Selexol volume Remark 3≤n≤9 at 25 °C at 25 °C at 25 °C ) at 25 °C and 1 atm. According to Table 3.3, solubility of both H2S and CO2 is much greater than CO and H2, which results in a limited co-absorption of such combustible gases. Hence, Selexol offers a good match prior to the GT in the IGCC application. Selexol’s potential for H2S removal is greater than that of CO2, since the solubility of H2S in Selexol is about nine times higher than that of CO2. In IGCC plants with CO2 capture, where both H2S and CO2 should be removed, the Selexol process typically takes place in two successive and typically independent absorption-regeneration stages, in which the H2S is first removed from the shifted syngas and consequently the CO2 is separated in the second stage of absorption. The process is similar in principle to what was presented for CO2 capture using an absorption process in Chapter 2 (Technical background). The syngas enters from the bottom of the first absorption column, where the H2S is removed by a counter-current flow of the solvent. The H2S-rich solvent is then thermally regenerated in a stripper. The regenerated solvent is cooled, pressurized and recycled back to the top of the H2S absorber, while acid gases are sent to a sulfur recovery unit (SRU). The H 2S-lean syngas enters the second absorber for CO2 removal. Similar to the first stage, the CO2-rich solvent exits the absorber bottom and then passes through a few flash drums in series. Carbon dioxide is released from the physical solvent as a result of stepwise pressure Coal-based power plants 47 reduction, unlike the chemical solvents which need significant thermal energy input [107]. The CO2 released from flash drums goes to the compression unit, while the clean and CO2-lean syngas is sent to the GT. The CO2-lean solvent (after the flash drums) is also cooled, pressurized and recycled back to the absorption column. In order to achieve higher sulfur removal (more than 99%) from the syngas in IGCC plants, it is necessary to add a COS hydrolysis unit to convert COS to H 2S in the case of CO2 capture trip, according to Reaction 3.2 [104, 110, 111]. KJ (33.6mole) COS(g) + H2 O(g) ↔ H2 S(g) + CO2 (g) (Reaction 3.2) In the case of using a sour WGS reaction unit (IGCC with CO2 capture), COS hydrolysis is directly carried out in the WGS unit, avoiding a dedicated reactor compared to the IGCC plant without CO2 capture [112]. 3.3.3.4. Sulfur recovery unit The AGR process results in three product streams, i.e. the fuel gas to the GT, a CO 2-rich stream and an acid gas stream. The acid gas stream from the AGR unit cannot be directly vented to the atmosphere, according to stringent environmental regulations [104]. A sulfur recovery unit is, therefore, required to treat the acid gas stream and recover sulfur (with more than 99% recovery) as a by-product. The conventional SRU typically is based on the Claus process for oxidizing H2S, obtaining elemental sulfur. The Claus process catalytically converts H2S to elemental sulfur by the following reactions: H2 S + 3⁄2 O2 → SO2 + H2 O (Reaction 3.3) 2H2 S + SO2 ↔ 3⁄2 S2 + 2H2 O (Reaction 3.4) The Reaction (3.4), the Claus reaction, is equilibrium limited. The overall reaction is: 3H2 S + 3⁄2 O2 ↔ 3⁄2 S2 + 3H2 O (Reaction 3.5) The oxygen required for the Claus combustion is supplied by the ASU without any major penalty on the overall plant efficiency [113]. Since the Claus reaction is exothermic, HP 48 Coal-based power plants steam production usually follows the Claus furnace. Moreover, LP steam is raised in the condenser downstream of the HP steam recovery section [104]. To reach more than 99.8% sulfur removal efficiency, the tail gas from the Claus plant needs to be further cleaned-up, an exercise which is widely practiced using a Shell Claus off-gas treating (SCOT) unit. The SCOT unit treats the Claus tail gas by employing a dedicated absorption unit (typically amine-based) and recycles the resulting acid gas to the AGR unit. The tail gas treating (TGT) can also be performed by recycling the Claus tail gas to the AGR unit [104]. 3.3.3.5. Advanced syngas cleaning and conversion In general, advanced gas cleaning and conversion processes are under investigation to enhance both the technical and the economic performance of IGCC plants with CO2 capture [65]. Most of the reaserch activities have focused on the development of reliable adsorption, membrane, improved scrubbing, and hybrid technologies. In the case of IGCC plants with CO2 capture, the syngas exiting the conventional gas cleaning needs to be heated up to certain limits for downstream sour WGS reaction. It requires cooling down again for H2S separation in the AGR unit, which typically operates at near-ambient temperature. The clean syngas may be reheated before combustion in the GT. These repeated heating and cooling processes cause the inherent energy losses and have detrimental effects on the plant’s overall efficiency [99]. To perform the removal of H2S and multi contaminants in fewer unit operations, and to avoid the penalties associated with syngas cooling and heating, a warm (hot) gas cleaning process is being developed to operate at high temperatures (250-700 °C). Such a cleaning method employs sorbents (typically metallic type e.g. Zn-based) to remove H2S or alkali species [103]. Significant capital cost redcution and efficiency improvement could be achieved by replacing the cold gas clean-up systems with warm systems [77]. The use of warm gas cleaning may also allow heat extraction from IGCC power plants that could be beneficial for combined heat and power (CHP) application [114]. However, the low duarbility and thermal stability of the sorbents increases the operation costs and reduces the avaialability of such processes [42]. In addition, such technologies still require a considerable time frame to be commercially developed for large-scale implementation in IGCC power plants [42, 99]. Coal-based power plants 49 To reduce the penalty of the capture process, advanced technologies such as membrane separation are also being developed. Membrane technology has attracted the attention of the research community due to its process simplicity, which can separate different gas components through a continuous process. Different kinds of membranes can selectively separate either H2 or CO2. The combination of warm gas clean-up technology (~480 °C) with CO2 separation by membrane technology is projected to reduce the cost of electricity by 14% [77]. Membrane technology can also be integrated into the system in order to enhance WGS reaction either by the permeation of CO2 (according to Figure 3.8) or H2 [18, 115]. Catalyst particle H 2O High pressure side Syngas (CO, H2, CO2) CO + H2O Retentate H2, H2O (CO, CO2) CO2 + H2 Membrane CO2 CO2 CO2 CO2 Permeate CO2 in sweep flow Sweep flow Low pressure side Figure 3.8. Operating principle of an enhanced WGS reactor by membrane technology For scrubbing process in the AGR unit, research activities are foccused on the improvement of the acid gases’ loading to achieve better techno-economic performance. Solvents that could show a good performance for acid gases at higher temperatures are highly required in order to avoid the cooling necessary for current scrubbing agents. Some salty compounds such as ionic liquids (ILs), which are at the early stage of development, could be suitable alternatives for the current physical/chemical solvents for CO2 absoprtion. They can opperate at high temperatures (up to 200 °C), which is a good match for the warm gas clean-up process [116]. Another promising concept for pre-combustion CO2 capture is the sorption-enhanced water-gas shift (SEWGS) process. Simultaneous removal of CO2 in the WGS reactor will enhance the conversion of carbon monoxide [94]. This system offers a higher CO2 capture rate, higher H2 recovery in the fuel, simultaneous separation of H2S with CO2 and avoids the cooling required by conventional AGR and CO2 capture [113]. The process comprises of multiple sorbents beds (containing WGS catalysts), operated in parallel, that adsorb 50 Coal-based power plants CO2 at high temperature and pressure and release it at lower pressure. The combination of CO conversion and instantaneous CO2 removal enhances H2 production and thereby the purity of the fuel feeding the GT combustor. A separate CO2 stream (mixed with H2S) can be recovered from the sorbents by regenerating the bed. Regeneration is carried out by a pressure swing, producing a low-pressure CO2-rich stream. The CO2 stream, which contains certain amount of H2S, needs to be further treated for the removal of H2S from CO2 for final compression and storage [113]. The COE for the IGCC plant using SEWGS can be reduced by 4%, while the overall efficiency can be improved by 2-3% compared to the conventional IGCC plants with solvent-scrubbing CO2 capture [117]. However, similarly to other sorbent-based cleaning methods, practical issues such as handling and regeneration of the solid sorbent materials need to be addressed by ongoing research [42]. 3.3.4. CO2 compression and dehydration Carbon dioxide captured at a power plant can be stored in depleted oil and gas reservoirs and deep saline formation or utilized for enhanced oil and gas recovery [18]. The captured CO2 can be transported by several means including ships, pipeline, railways or roads. Amongst those, however, ships and pipelines are more cost-effective for the transportation of substantial amounts of CO2, depending on the distance to storage sites [18]. In order to provide an optimum condition for transportation of large amounts of CO2, it is necessary to transform gaseous CO2 into a phase comprising less volume and more density, i.e. a liquid, solid or supercritical state. For pipeline transportation, the suitable condition is in the supercritical region, as shown in Figure 3.9 (data for triple and critical points are from [118]). Being above supercritical pressure eliminates the risk for the two-phase flow regime due to temperature variations along the pipeline [18]. Recompression stages are commonly considered in order to keep the pressure over supercritical pressure and to overcome the pressure drops whenever the length of CO2 pipeline is more than 150 km [119]. For tank transportation (e.g. ship), the most economically feasible condition is to keep the CO2 in the liquid state at about 7 bar and -50 °C [119, 120]. Irrespective of the choice of transportation, CO2 compression has a negative impact on the plant’s technical and economic performance. The loss of overall plant efficiency associated with CO2 compression is approximately 5 percentage points. Considering such a unit for an IGCC plant with CO2 capture increases the capital costs and cost of electricity by approximately 10% [65]. Coal-based power plants 51 Pressure, p (bar) Meltin Solid g line Supercritical region Liquid Satu n ratio line Critical point Tc = 31.0 ºC pc = 73.8 bar 5.2 Triple point Vapor -56.6 Temperature, T (ºC) Figure 3.9. The schematic temperature-pressure diagram for CO2 There are several compression alternatives to reach the required pressure of the CO 2 for transportation/storage [121]. In reality, a process closer to isothermal compression, such as that which occurs in compression with intercooling, is beneficial to reduce the compression power demand [122]. Inter-cooled compressors offer smaller sized compression units and hence reduce costs and increase overall plant efficiency by appropriate heat integration with other sub-systems at higher costs [122]. A further reduction in the demand for power to pressurize the CO2 could be accomplished by eliminating the final stage of the inter-cooled compressor using a less power-, costintensive pumping process [121]. Initial compression to the condition where the CO2 is transformed to a liquid state is carried on by the intercooled compressor, while the pump is utilized to reach the final pressure. In addition to compression, CO2 needs to be treated for the removal of accompanying water to prevent the risk of corrosion and the formation of gas hydrates in the 52 Coal-based power plants transportation pipeline [120]. In addition to water vapor, the CO2 stream from the AGR unit of the IGCC plants with CO2 capture contains minor species such as N2, Ar, H2, CO and traces of H2S [107]. All these impurities have a negative impact on the compression power demand, although these effects are marginal due to their trace existence [123]. Dehydration can be accomplished using an absorption process, vapor-liquid separator drums or an adsorption process [122]. Maximum allowable water content of the CO2 stream is a critical factor in order to select a suitable dehydration process [120]. Often, a dehydration unit based on glycol solvents such as tri-ethylene glycol (TEG) is considered to absorb water from the CO2 stream for IGCC application with CO2 capture [43]. It should be mentioned that the saturated water content first decreases by the increased pressure of the high-purity CO2 stream then increases again at pressures above 60 bar [107]. Thus, the optimum pressure and location of the dehydration unit to remove water content (i.e. the lowest saturated water content) is about 60 bar at 25 °C [124]. 3.3.5. Gas turbine Due to the continuous need for coal utilization in power generation, the development of reliable, environmentally friendly and cost-competitive gas turbine technologies for hydrogen-rich syngas combustion is highly essential. The performance of the GT varies with changes in the properties of the fuel gas [65]. The behavior of the gas turbine changes with the transformation from NG (as conventional fuel for the GT industry) to a H2-rich syngas, which is a typical fuel in IGCC plants with CO2 capture. The current section presents various operational challenges and effects of using syngas instead of NG on the existing gas turbine. 3.3.5.1. Combustion process The state-of-the-art combustion technology for NG operation is dry low NOx (DLN) premixed burners. Such burners principally work at lean condition by forcing more air than stoichiometric in the primary combustion zone, which results in moderate flame temperatures [125]. Unfortunately, the available pre-mixed technology could not comply with flammability limits for H2-rich fuels, which are much larger than those for natural gas [126]. Moreover, high hydrogen content syngas has higher adiabatic flame temperature, higher flame speed, and higher flashback potential compared to NG, complicating the use of a combustor that is designed using NG design criteria [60, 127]. The SOA combustion technology for burning H2-rich syngas (25-40 vol%) is the diffusion Coal-based power plants 53 flame burner [125]. Note that this value could be much higher in an IGCC plant with CO 2 capture, depending on the performance of upstream operation units. In general, diffusion flame burners produce considerably more NOx than the pre-mixed combustors for NG combustion and this is exacerbated when burning high hydrogen content fuels which is typical for IGCC power plants with CO2 capture [27, 127]. Stoichiometric adiabatic flame temperature is a representative indicator for NOx formation in diffusion flame combustors [126]. In order to lower the flame temperature (down to about 2300 K [125]) and, consequently, to minimize NOx formation (25-45 ppmvd @ 15% O2 [125]), hydrogen-rich syngas is normally mixed with a diluent gas such as nitrogen [128]. There are several methods to control NOx emissions from diffusion flame burners of gas turbines including: Saturation with water [126], steam or N2 injection [60], and combination of saturation, steam and N2 injection [128]; and use of selective catalytic reduction (SCR) in the bottoming cycle [126]. Irrespective of the method selected for controlling NOx emissions, all strategies work on the basis of lowering the adiabatic flame temperature [126]. Nitrogen dilution is generally recognized as the most efficient method due to its availability in conventional IGCC plants [60]. It results in reduction of water consumption, though it increases auxiliary power requirements (for N2 compression) [66]. Steam injection or syngas saturation with water causes a higher convective heat transfer coefficient between combustion products (hot stream) and the expander blade materials due to the change in hot stream composition compared to an undiluted case. Accordingly, the blade metal temperature will increase at a given turbine inlet temperature (TIT), geometry and cooling flow, which results in faster life consumption of the blades [125]. In order to keep the same blade metal temperature, TIT is commonly de-rated (reduced) [129] or new geometry and design should be adopted to increase cooling flows. In the case of using SCR in the HRSG unit, a highly efficient upstream AGR process (COS+H2S < 20 ppmv) needs to be employed to prevent ammonium sulfate from fouling due to the presence of SOx in the flue gas [104]. In addition to the higher costs induced by the SCR technology, a larger HRSG is required for such a process [125]. As mentioned earlier, N2 is typically used as diluent in conventional IGCC plants with cryogenic ASU. In this regard, the presence of a large amount of N 2 in the syngas derived 54 Coal-based power plants from an air-blown IGCC plant is advantageous to minimize N2 dilution [126]. The coal feeding system into the gasifier also has some effects on the NOx formation. The required steam for NOx control in IGCC plants with slurry-fed gasifiers (e.g. GE and E-GasTM) is considerably lower than that for dry-fed gasifiers due to the greater water content of the syngas in slurry systems [64]. 3.3.5.2. Turbo-machinery Syngas property significantly affects GT operation. Syngas combustion results in different product composition and thermo-physical properties (such as heat transfer coefficients) compared to NG combustion. The fuel change (from NG to syngas) leads to [125]: Different expansion line (enthalpy drop) in the expander; change in the hot gas flow rate at the expander inlet; and different cooling flow required for expander blades. As a consequence, there a new compressor design might be needed to match the new turbine characteristics, or compressor re-design might be considered to provide different cooling flows. The isentropic enthalpy drop in the expander for a H2-rich syngas is higher than for NG. This drop will be significantly increased by steam dilution or water saturation to the minimum required level for NOx emissions. If the working fluid is assumed to be an ideal gas, the isentropic enthalpy drop can be evaluated using the following equation: 𝑇 ∆ℎ𝑖𝑠 = ∫𝑇 𝑖 𝑐𝑝 (𝑇)𝑑𝑇 = 𝑐̅𝑝 (𝑇𝑖 − 𝑇𝑜,𝑖𝑠 ) 𝑜,𝑖𝑠 (Eq. 3.3) According to Equation 3.3, isentropic enthalpy drop is a function of average 𝑐𝑝 and temperature drop through the expansion. The 𝑐̅𝑝 is enhanced by fuel transformation from NG to H2-rich syngas and increases even more in the case of steam or water dilution. The temperature drop is influenced by the change in isentropic exponent (𝛾) according to isentropic 𝑝 − 𝑇 relation. Assuming constant expander inlet pressure, inlet temperature and outlet pressure, the temperature drop reduces by an increase of 𝑐̅𝑝 and simultaneous reduction in 𝛾. Consequently, turbine outlet temperature (TOT) is also increased, which threatens the lifetime of the expander blades. TOT increase is intensified in the case of water saturation or steam injection. In the case of N2 dilution, the change in isentropic Coal-based power plants 55 enthalpy drop from NG combustion remains almost constant with an increase in N2 dilution as the hot gas already contains a considerable amount of N2 from the combustion air [125]. The heating value of the produced syngas in IGCC plants is lower than that of NG, a commonly used fuel for GT design [62]. This results in a higher flow rate of the fuel gas to the GT to reach the same order of TIT and thereby a similar efficiency level at a given compressed air flow [130]. The flow rate of the hot gas stream into the expander further increases by the dilution process (in the case of SOA combustion technology, i.e. diffusion flame burners). This increase is exacerbated in the case of N2 dilution, which requires more injection to lower the adiabatic flame temperature and thereby NOx formation due to its lower 𝑐𝑝 value compared to steam [125]. Irrespective of dilution type and use of undiluted syngas, increased fuel flow rate: Affects the compressor/expander matching [126]; induces higher back pressure to the compressor [125]; and reduces available surge margin [130]. An increase in pressure ratio adversely affects the expander blade wall temperature. The mass flow of the cooling stream increases by pressure ratio due to the higher cooling flow density. The enhanced density results in higher convective heat transfer coefficients for both fluid and outer blade wall. The higher heat transfer coefficient of the cooling stream could not compensate for the higher outer blade wall heat transfer coefficient, which increases the blade wall temperature beyond its admissible level [125]. The lifetime of the turbine materials will then be shorter than normal operation (NG operation). The cooling flow temperature also rises by the higher pressure ratio, which results in less effective cooling [130]. In the case of using an existing GT, which is originally designed for NG, the following options are available to improve GT operation for syngas fuel. Allowing the pressure to increase up to the minimum surge margin level or adding one or more high pressure (rear) stages to the compressor in order to increase the available surge margin [130] at the price of higher costs [127]. Keeping the existing compressor design while widening the swallowing capacity of the expander without increasing the pressure ratio, although it results in higher blade wall temperature [130]. Partially closing the compressor variable inlet guide vanes (VIGV), which can compensate for part of the higher hot gas flow rate [125]. 56 Coal-based power plants De-rating the TIT which has a negative effect on the performance of the GT. The reduction of TIT can marginally diminish the problem of higher pressure ratio and consequently surge margin [130]. Air bleeding from the GT compressor to the ASU to maintain the pressure ratio increase [62]. As mentioned earlier, this option results in higher overall plant efficiency but reduces the operational flexibility, more specifically during transient conditions [63]. Note that the higher degree of air-side integration leads to improved surge margin and reduced pressure ratio at a given TIT and amount of diluent and vice versa [130]. Effects of lower integration degree on the blade wall temperature are similar to that presented for higher hot gas flow and pressure ratio and hence, are not repeated again. 3.3.5.3. Materials The combustion of H2-rich syngas results in higher heat transfer to the hot section materials. The other major material concern, applicable to any coal-derived syngas, is the need to protect the gas turbine from the corrosive effects of sulfur compounds [131], alkali metal salts [132], and fly ash deposition [133]. The existence of such compounds coupled with high temperature media can boost hot corrosion of metallic alloys [132] and results in extensive thermal barrier coating (TBC) spallation [133]. Advanced turbine aerodynamic and cooling schemes are, therefore, required to maintain the lifetime of the hot path at existing gas turbines. Otherwise, advanced high temperature low conductivity TBC materials and superalloys need to be incorporated into the expander hot path for the combustion of syngas [127]. 3.3.5.4. Commercial syngas-fueled gas turbine The original equipment manufacturers (OEMs) simultaneously improve their GT technology for NG operation and perform required developments to enable syngas operation and thus the integration of GTs into IGCC plants [63]. There are many commercially available heavy-duty GT models originally designed for NG operation with different modifications (e.g. different burner design) for syngas application. Amongst those are Siemens (E and F frames), GE (EB and FB models), and MHI (e.g. M701DA) [58, 59, 63, 134]. Nearly all these models use diluted syngas (using water saturation, N2, or steam injection), and all are equipped with diffusion flame burners. The general specifications of different commercially available 50 Hz F-frame gas turbine models Coal-based power plants 57 suitable for syngas operation are shown in Table 3.4. Please note that available data are based on NG operation. Table 3.4. Main specifications of two commercial 50 Hz gas turbine models for syngas operation Parameter Unit 9FB a [135] SGT5-4000F [136] OEM General Electric Siemens TIT °C 1360 [126] 1265 b COT °C 1454 [126] 1500 b TOT °C 623 577 19.7 [137] 18.2 Pressure ratio (𝛽) Exhaust flow rate kg/s 745 692 Gross power output MW 338 292 % 40.0+ 39.8 Gross efficicency (𝜂𝑔𝑟𝑜𝑠𝑠 ) Power output (combined cycle) c MW 510 423 [138] Heat rate c kJ/kWh 5894 6164 [138] % 60.0+ 58.4 [138] Net thermal plant efficiency (𝜂𝑡ℎ ) d Number of compresssion stages 14 15 e Number of expansion stages 4 4 a 2011 model. b According to personal comminucation. c Value represents 1×1 combined cycle configuration. d Value is LHV basis and represents 1×1 configuration. e The modified SGT5-4000F has an additional compressor rear stage in order to accommodate higher back-pressure caused by diluted syngas in the case of zero or low air-side integration with ASU [63]. 3.3.5.5. Advanced hydrogen turbine technology One of the most important on-going research and development (R&D) programs is the development of fuel flexible hydrogen turbine technology, which has great potential for the further development of IGCC plants through improved thermal efficiency [127]. Most recently, many R&D activities have focused on the development of low NOx gas turbine technology for undiluted hydrogen-rich syngas operation [73]. A report by the U.S. Department of Energy (DOE) confirms that significantly higher overall efficiency (1.3 HHV%) and lower specific plant costs (9%) can be achieved by the deployment of such technology in IGCC plants with CO2 capture [72]. In addition, novel aerodynamic designs, advanced cooling schemes, advanced TBC systems and superalloys are under development to further enhance GT performance [127]. The use of advanced gas turbine technologies operating at elevated firing temperatures and pressure ratios such as H-class machines will also significantly improve the overall efficiency of IGCC plants with CO 2 58 Coal-based power plants capture [65]. Utilizing such GT technologies (60+% efficiency for NG operation) will tackle the increasing GHG emissions from another area, i.e. energy efficiency [64, 128]. 3.3.6. Bottoming cycle The gas turbine exhaust gas is used to produce steam in an HRSG for electricity generation in steam turbines. The process is quite similar to that of the conventional bottoming cycle in natural gas combined cycles, with few changes in terms of thermal energy inputs and outputs. The bottoming cycles in existing IGCC plants are typically based on a triple-pressure level design with reheat consisting of an HRSG, steam turbine (ST), condenser, and associated auxiliary pumps. The HRSG section includes economizers, evaporators, super-heaters, and re-heaters for the three pressure levels. The HP steam turbine inlet conditions in the existing IGCC units are about 100-120 bar and 520-540 °C with 520-540 °C reheat inlet temperature for the intermediate pressure (IP) stage [139]. The steam turbine power output changes significantly in IGCC plants compared to that in conventional combined cycles due to the many interactions between HRSG and other subsystems. The primary thermal energy input to the HRSG is from the GT exhaust gas, which enters at about 560-590 °C [139]. The other energy inputs are HP, IP, or LP steams generated in the gasifier, syngas coolers and WGS unit, depending on the heat integration scheme between different process units. The HRSG supplies the high and intermediate pressure boiler feed water (BFW) used in the gasifier, syngas cooler’s water-gas shift process, the IP steam used in the WGS and the LP steam used in the AGR unit (i.e. for the solvent regeneration). In IGCC plants with capture, the ST power output decreases due to the extraction of steam for the WGS reaction unit. Consequently, the WGS unit is typically viewed as a burden on the steam cycle [96]. In addition to steam production and consumption, the operation of the steam cycle is dependent on ambient temperature which imposes a vacuum at the condenser and, therefore, controls the performance of the steam turbine [43]. 3.4. Current IGCC power plants status Seven IGCC power plants have been operated on coal as main feedstock (refer to Table 3.5), but none has been equipped with a CO2 capture unit [27, 49, 79]. Although Coal-based power plants 59 operational experience from the current plants has proven the viability of IGCC technology, the demonstration of a full-scale IGCC plant with integrated CO2 capture unit is highly essential. Some of the European IGCC plants, even without CO2 capture, are simply not economically viable under current electricity market conditions. Buggenum IGCC plant has recently been decommissioned, and Puertollano plant is at risk of closure. Therefore, further IGCC deployment is tightly connected with its competitiveness against other power generation technologies. Important areas which have tremendous effects on the economy of this technology, that should therefore be improved or developed, include [27]: Higher plant availability and reliability for all types of coals; cheaper solutions e.g. quench gasification for low grade coals; development of highly efficient multi-pollutant gas clean-up systems; and development of gas turbine technology burning hydrogen-rich fuels. In addition to the coal IGCC plants mentioned in Table 3.5, many IGCC plants with and without CO2 capture have been in the evaluation, planning, and construction phases, especially in the USA and China [140, 141]. However, only a few, such as Kemper County (Mississippi, USA) and GreenGen (China), show significant progress due to the sustainability of government incentives and supports [142, 143]. 60 Name Location Coal-based power plants Table 3.5. Specification of the operating coal-based IGCC power plants Buggenum Wabash River Vresova Polk Puertollano Nakoso [27, 49] [27, 49] [27] County [27, [27, 49] [27, 49] 49] The Indiana, USA Czech Florida, Spain Japan Netherlands Republic USA Edwardsport [144, 145] Indiana, USA Start 1994 1995 1996 1996 1998 2007 2013 Gasifier SCGP E-GasTM Lurgi (26 fixed-bed gasifiers) GE Prenflo MHI GE Feed Dry Slurry Dry Slurry Dry Dry Slurry Oxidant O2 O2 O2 O2 O2 Air O2 GT Siemens V94.2 (SGT52000E) GE 7FA GE 9E GE 7FA Siemens V94.3 (SGT54000F) MHI M701DA GE 7FB Air-side integration Full Zero Zero Zero Full Partial Partial Diluent (NOx control) Saturation, N2 dilution Saturation (>20 vol%) [139] Steam injection N2 dilution, saturation [66] Saturation, N2 dilution Without dilution, with SCR N2 dilution Net output (MWe) 253 262 350 250 300 250 618 40.0 Not available 36.7 42 42.0 a ~ 44.0 a [146] Efficiency 43.0 (LHV%) a estimated value. 4. H2-IGCC power plant The current chapter briefly presents the main objectives of the European co-financed Low Emission Gas Turbine Technology for Hydrogen-rich Syngas (H2-IGCC) project, as well as its multiple research areas together with its main outcomes. Furthermore, the selected IGCC configuration with CO2 capture consisting of several sub-systems is briefly described. This configuration represents a realistic and practical integration of various state-of-the-art technologies for different components of the plant. Limitations which have arisen from the selection of each technology and operating mode compared to other alternatives are also presented. As the focus of the H2-IGCC project was on the development of a combustor for burning undiluted high H2 content syngas fuels in gas turbine technology, various challenges tackled by different sub-project groups are briefly summarized. Finally, the methodology for the performance analysis of the selected IGCC plant with CO2 capture is described. Different software tools used for thermodynamic modeling, together with reasons for the selection of each tool as well as boundary conditions of the entire cycle and the gas turbine, are then presented. 4.1. H2-IGCC project As mentioned previously in Chapter 3, current GT technology (preliminary developed for natural gas and used) in IGCC application with CO2 capture suffers from several challenges. Amongst those are the wide variation of fuel composition compared to NG, increased hot gas flow to the expander, increased heat transfer between the hot gas and expander materials, high NOx emissions from diffusion flame burners, and high dilution rate to control NOx emissions. 61 62 H2-IGCC power plant In November 2009, the H2-IGCC project was started, aiming at the knowledge development necessary to overcome the abovementioned drawbacks, while burning H2rich fuels. The overall objective was to provide and demonstrate technical solutions which allow the use of SOA highly efficient, reliable GTs in the next generation of IGCC plants after introducing CO2 capture. The goal was to enable the combustion of undiluted H2rich syngas with low NOx emissions and also to allow for high fuel flexibility by enabling the burning of back-up fuels (e.g. NG) with limited adverse effects to reliability and availability. Twenty-four partners including academia and manufacturers, as well as plant operators from ten European countries, worked together to achieve the abovementioned goals. The project was divided into four major research areas, namely, combustion, materials, turbo-machinery and system analysis. Figure 4.11 shows different research areas with their overlaps on a schematic configuration of the IGCC plant with CO2 capture. Compressed CO2 Coal O2 Air SWGS, H2S removal, CO2 capture Raw Gas syngas cleaning Gasification Slag ASU C b om us n tio Materials To atmosphere Heat recovery steam generator Turbo-machinery Stack HP IP/LP System analysis Figure 4.1. The structure of the H2-IGCC project 1 The GT image is courtesy of Siemens SGT5-4000F gas turbine. H2-IGCC power plant 63 Different technical sub-projects (research areas) had various main objectives, as detailed below [147]: Combustion group aimed to develop and demonstrate a safe and low emission pre-mixed combustion technology for undiluted H2-rich syngas. Materials group aimed to develop and demonstrate improved materials with advanced coatings able to protect base materials of the blades and combustor against the potentially more aggressive temperature and composition of the exhaust gas. Turbo-machinery group aimed to provide required design for the compressor/expander aerodynamics and cooling schemes to cope with changed fluid properties of the hot gas. System analysis group aimed to evaluate optimum IGCC plant configurations and to establish guidelines for optimized full-scale integration. Moreover, a detailed systems analysis needed to be performed to generate realistic technoeconomic results for IGCC plants with pre-combustion carbon capture. As the main target of the project was to develop and demonstrate a reliable and low emission combustion technology, great efforts have been dedicated to the GT block. Note that the successful implementation of this project could only be realized by intensive collaboration between project partners due to the cross-disciplinary nature of the project’s tasks and objectives. The interactions between the system analysis group and other project groups (please refer to Figure 4.1) can be summarized as follows: Syngas composition and mass flow, total mass flow (cold/hot path), turbine inlet temperature and pressure from the system analysis group to the combustion group, necessary for successful experimental campaigns and burner designs; total mass flow (cold/hot path), turbine inlet temperature and pressure from the system analysis group to the materials group, required for the selection of materials and coatings as well as testing of the blades; syngas composition and mass flow, total mass flow (cold/hot path), turbine inlet temperature and pressure from the system analysis group to the turbo-machinery group, necessary for modifying the GT designs (compressor and expander aerodynamics); flue gas composition and nitrogen demand (if any) for dilution from the combustion group to the system analysis group, which influenced the steam cycle calculations; flue gas temperature and mass flow from the turbo-machinery group to the system analysis group, which influenced performance analysis of the steam cycle; and 64 H2-IGCC power plant gas turbine characteristics (expander and compressor maps, cooling flows, TIT, combustor outlet temperature) from the turbo-machinery group to the system analysis group, required for thermodynamic modeling of the GT. The importance of an appropriate sub-system selection and integration, as well as overall system analysis, should be clearly highlighted. It should be underlined that every decision made at the entire system level had some impacts on the component targeted by the H2IGCC project (i.e. the gas turbine) and vice versa. Amongst those decisions, but not limited to them, are: Employing the current SOA technologies1 with respect to both the gas turbine and also the entire IGCC system; selecting a proper degree of integration between GT and ASU to achieve higher flexibility, availability, and operability of the plant; and defining fuel flexibility targets considering both planned and sudden changes in fuel composition due to trip of the carbon capture unit or a failure upstream of the gas turbine. 4.2. System integration The thermodynamic performance calculations required the establishment of a reference IGCC plant with carbon capture. This was performed based on a comprehensive review of the present IGCC technology as well as openly available data. The results of thermodynamic simulations of the baseline case have been published in Paper I. The configuration (and input data/settings) of the plant has then been improved, incorporating more realistic performance data reflecting industrial experiences from the operation of similar plants during the project’s development (for details see Paper II). The major sub-systems and the way in which they were integrated into the cycle are presented here. Further information can be found in Papers I-III. In addition, the current section briefly reviews the pros and cons of such sub-systems in terms of the operability and thermodynamic performance of the overall IGCC plant. 1 Most of improved technologies for different sub-systems (e.g. ITM, hot gas clean-up, etc.) are not likely to be commercially available in the time frame for plants discussed within the H2-IGCC project, i.e. 2020. H2-IGCC power plant 65 4.2.1. Cryogenic air separation unit The ASU is the most power-demanding auxiliary unit in the IGCC plant, and the level of its integration to other sub-systems has to be properly analyzed with respect to costs, efficiency, operational flexibility and plant availability. Operating experience from Buggenum IGCC plant by an industrial partner of the H2IGCC project (NUON/Vattenfall) confirmed that a fully-integrated GT-ASU solution adversely affects the availability of the plant. Therefore, a stand-alone ASU was considered for the H2-IGCC project. The advantage obtained by selecting no air-side integration between the GT and the ASU is also driven by higher plant operability. However, it should be noted that the overall plant efficiency increases with the degree of integration due to the higher isentropic efficiency of the GT compressor [113]. Lower efficiency of the non-integrated GT-ASU case could be balanced with the selection of an inter-cooled MAC to achieve similar overall equivalent compression work compared to a fully-integrated GT-ASU case. Furthermore, as there is no need for injection of diluent gaseous nitrogen into the GT for the dry-low NOx combustion, heat integration between the GT compressor bleed air and DGAN from the ASU is not an option in order to enhance the overall plant efficiency. Using undiluted syngas in the GT has also resulted in the selection of a low pressure ASU, where O2 and N2 are produced at near atmospheric pressure, as there is no need to reduce the compression work required for injection of DGAN into the GT. Due to the high competitiveness within the oxygen production industry, compressors’ characteristics, performance data, and detailed cost of cryogenic air separation plants are difficult to obtain. Consequently, the performance data for main air, pure gaseous nitrogen, and gaseous oxygen compressors, as well as for a number of inter-cooling stages for all ASU compressors, have been gathered from H2-IGCC industrial partners based on currently available technologies (presented in Paper II). The purity of the final product of the ASU (95 mol% for O2) reflects an economic choice, maintaining the balance between higher capital expenditure and higher efficiency loss. Moreover, as the combustion process in the GT uses air as the oxidant agent, additional N2 and Ar in the syngas produced by the gasifier does not make any major difference compared to when higher purity O2 is produced by the ASU. 66 H2-IGCC power plant 4.2.2. Gasification The gasification technology is based on the Shell Coal Gasification Process. Such a technology was selected due to its highest cold gas efficiency and its operating pressure level. A key parameter governing the overall plant pressure is the operating pressure of the GT combustor. The pressure prior to the combustion chamber was fixed at about 30 bar to overcome the pressure loss over the fuel valves for pre-mixing of fuel and air in the combustor. The pressure of the gasification block was then calculated and fixed at 45 bar, considering all pressure losses from the gasifier to the combustion chamber and eliminating any supplementary syngas compression. The conventional Shell gasifier had a slightly lower pressure (~ 42 bar) at the time the gasification technology was selected (in 2010). However, the fast pace of technology improvement could result in higher operating pressures (e.g. 45 bar) of dry-fed gasifiers in the period of 2015-2020, when the results of the H2-IGCC project could be commercially demonstrated. The adoption of SCGP technology was also justified by the availability of a validated gasification model provided by a member of the consortium, Nuon/Vattenfall, who operated the Buggenum IGCC plant. An assessment of the impact and behavior of various gasification technologies fed by different coal types and qualities on the overall technical performance of the IGCC plant with CO2 capture was investigated and has been presented in Paper III. A relatively cheaper slurry-fed gasification technology could be an appropriate substitute for the SCGP technology, more specifically when high quality coal reserves are available. Nevertheless, dry-fed gasifiers can offer more stable performance, even when fed by low quality coals or biomass. 4.2.3. Syngas conversion A sour water-gas shift unit has been selected for modeling the IGCC cycle with CO2 capture. This type of shift reaction helps to avoid the additional cooling of the syngas required by conventional AGR units and then reheating to the level required for the catalyst’s activation in the SWGS unit. It is also beneficial in order to postpone the water condensation, which occurs during the conventional AGR process downstream of the SWGS unit, as the SWGS unit requires the existence of a considerable amount of steam. It should be noted that the dry-feed characteristics of the Shell gasifier required the injection of a considerable amount of steam, which adversely affects the steam turbine power H2-IGCC power plant 67 output. The selection of sour shift reaction was also motivated by industrial partners of the project. In order to increase the lifetime of the shift catalyst by eliminating the carbon deposition, a large amount of steam injection, indicated by a high steam to CO ratio (i.e. 2.4 molar basis), has been considered. 4.2.4. Acid gas removal A double-stage physical absorption system using Selexol was selected for the H2S and CO2 removal from the shifted syngas. The heat required for the regeneration of the solvent from the acid gas has been provided from the low quality heat, which must be rejected downstream of the SWGS before the conventional Selexol unit. The CO2 capture target for simulations has been set to be 90%, as it was found to be an optimal capture efficiency for IGCC power plants [65]. In order to reach this target, coabsorption of CO2 with H2S should be minimized. This has been achieved by use of the pre-loaded solvent in the AGR unit. However, using the pre-loaded solvent may have an adverse effect on the H2S recovery through the decrease in temperature rise within the absorber column [108]. Furthermore, the solubility data presented in Table 3.3 (see Chapter 3) may be differentiated due to the higher interactions between polar compounds such as CO2 and H2S in the pre-loaded solvent [104]. In the absorption process, a part of the combustible constituent of the syngas, i.e. H2 and CO, are also co-absorbed by the rich solvent. Lowering the pressure to separate CO2 or H2S from the rich solvent will result in a loss of the combustible gases. Therefore, products of the first flash drums after H2S and CO2 absorbers are compressed and recycled to the absorbers to minimize the CO and H2 slips. The high CO2/H2S ratio in the syngas from the SWGS unit together with a requirement for 90% CO2 capture efficiency resulted in the production of an unsuitable acid gas stream to the Claus plant due to increased coabsorption of CO2. Therefore, an acid gas enrichment unit was considered in order to reach a higher H2S content (> 35 mol%) of the acid gas stream. H2S removed in the AGR section is sent to the sulfur recovery unit, which has not been modeled in this work. However, the oxygen required for the Claus plant has been considered for the calculation of the capital costs of the ASU. Furthermore, net steam 68 H2-IGCC power plant required for the SRU has been assumed to be zero, as the heat required to keep the sulfur molten and to regenerate the SCOT solvent is balanced by the steam raised by H2S combustion in the Claus plant, according to [113]. 4.2.5. Gas turbine The baseline GT design has been selected considering the best available gas turbine technologies. Accordingly, a Siemens SGT5-4000F/Ansaldo Energia V94.3A gas turbine was chosen, as the manufacturers are partners of the H2-IGCC project. Suitable values for relevant parameters (e.g. for pressure ratio, gross power, etc.) have been selected, taking the present SOA technology and the OEMs available data into consideration. As mentioned in Section 4.2.2 (gasification), one of the most important interactions between the overall IGCC system and the GT is the required fuel pressure at the GT fuel valves. The inlet pressure of the fuel upstream of the combustor is dictated by the compressor outlet pressure. Higher inlet pressure to the fuel valves compared to compressor outlet pressure should be considered to compensate for a certain pressure loss between the fuel valves and nozzles. The flame temperature and thereby NOx emissions are principally controlled by premixing the fuel and air in dry low NOx burners. Such burners are equipped with a certain number of swirlers to stabilize the flame and to create the necessary turbulent conditions. This eventually results in higher pressure loss in premixed burners compared to diffusion flame burners. Therefore, a high pressure loss (~10 bar) through the fuel injection system has been considered for the H2-IGCC project. Syngas can be preheated (up to 200-300 °C) in the IGCC plant prior to the GT combustion to increase overall plant efficiency, exploiting available waste heat. The selection of preheating temperature is a compromise between the thermodynamic benefits at higher temperatures and the operational risks for handling hydrogen-rich, high temperature syngas (compared to NG) as well as higher fuel system costs [126]. However, lowering the risk for auto-ignition of H2-rich syngas, this alternative was considered neither in simulation tasks nor in experimental tests within the H2-IGCC project. As previously mentioned, for IGCC plants with CO2 capture, either syngas dilution (with N2 or steam) or syngas saturation (with water) is often considered to control the NOx emissions from the diffusion flame burners. However, as the goal of the project was to develop a pre-mixed combustor for the combustion of “undiluted” hydrogen-rich syngas, H2-IGCC power plant 69 this strategy was not applicable. Once H2-rich syngas was considered as the GT fuel in the existing GT (i.e. SGT5-4000F/Ansaldo Energia V94.3A) designed for NG operation, the operating parameters and performance of the GT deviated from the original design. Therefore, a full off-design analysis was performed in order to realistically simulate those changes. An existing compressor model was improved using a characteristics map provided within the H2-IGCC project. The turbine off-design operation was modeled considering a constant swallowing capacity at choking condition, which is a reasonable assumption for heavy duty gas turbines: Swallowing capacity = Constant = 𝑚̇𝑖 √𝑇𝑖 𝜅 𝐴𝑖 𝑝𝑖 (Eq. 4.1) where, 𝛾 𝜅=√ ( 2 𝑅 𝛾+1 ) 𝛾+1 𝛾−1 (Eq. 4.2) The sizing of the entire IGCC plant is governed by the gas turbine as it requires a specific amount of fuel depending on the fuel composition. The operating condition of the GT has been determined by matching the operating characteristics of the compressor and the expander. Thus, if the gas flow rate, e.g. due to the change of syngas composition, varies at the expander inlet, the operating condition of the GT adapts to this change. This could result in a change of pressure ratio, even at similar firing temperatures. When using H2-rich syngas, gas turbine power output increased due to the higher hot gas flow expanding in the turbine at a certain TIT compared to the NG operation. It should be highlighted that, in the case of using slurry-fed gasifiers (or water saturation in diffusion flame burners), the potential for enhanced power output is higher. This is because of the higher enthalpy drop through the expander due to the higher H2O content in the syngas and consequently in the flue gas, according to [126]. As shown in Eq. 4.1, the syngas flow rate at the expander inlet is proportional to the square root of the temperature. In the GT designed for NG in IGCC application, once the fuel flow rate is increased due to the change in upstream operations (e.g. slip of CO2 capture unit) or transformation of fuel gas, the compressor stability and expander hot gas path could be affected. Different alternatives to solve various problems incurred by the 70 H2-IGCC power plant introduction of H2-rich syngas instead of NG are reviewed in Paper IV. As mentioned previously in Chapter 3, to maintain the GT operation’s stability and safety, TIT could be de-rated (refer to Eq. 4.1) at the expense of lower GT efficiency. The addition of one or more high pressure stages to the end of the compressor can resolve the problem of reduced surge margin due to the higher mass flow of the H2-rich fuel compared to NG [125]. The turbo-machinery group of the H2-IGCC project has investigated this option, and the results of their calculation showed that the stable operation of the compressor could be maintained by just adding one rear stage. The other strategy adopted by the H2-IGCC project was to modify the turbine, i.e. re-staggering or opening up the expander nozzle guide vanes (NGVs) in order to increase the swallowing capacity of the expander. This strategy reflects the fact that industry prefers modifications to the expander side as it has fewer stages and requires less effort compared to the compressor. Nevertheless, extensive modifications to the expander should be avoided as they will be costly and are unlikely to be accepted by the industry. Hence, only modifications to the first stator of the turbine were followed as the main alternative by the project. Note that the modifications could be minor in the case of using an integrated GT-ASU (air-side). The proper degree of integration could result in just a change of cooling scheme and no modifications to the expander/compressor designs, as pointed out in [130]. Therefore, the opportunity to keep the NG-designed GT for operation on H2-rich syngas has been lost by selecting a non-integrated GT-ASU to achieve simpler operation of the plant, higher reliability and the possibility to run the GT only on NG. The zero integration necessitated modifications to both expander hot gas path and cooling scheme to keep the blade wall temperature under its prescribed level provided by the materials group (895 °C for the 1st expander stator). 4.3. System performance analysis One of the most important criteria for supporting any decision for investment in a technology (here, the IGCC technology) is to analyze its performance both technically and economically. The methodology for technical performance analysis is presented here, while the method for economic evaluation will be given in the next chapter. H2-IGCC power plant 71 For the field of power generation, thermodynamic analyses by means of computer-aided tools have become the most widely used practice. In this regard, thermodynamic simulations by heat and mass balance programs are cost-effective and fast. In order to obtain realistic performance indicators, different heat and mass balance programs have been utilized by this project; these are briefly presented here. 4.3.1. Software tools The entire IGCC power plant with CO2 capture (and also the NGCC with CO2 capture for the techno-economic assessments) was modeled by simulation of several sub-systems mentioned in Chapter 3. Each sub-system’s model and embedded characteristics represent commercially available technologies, as each major component/sub-system of the IGCC plant has been broadly utilized in industrial and power generation applications. Access to the experienced utility owners and operators of similar plants in the H2-IGCC project provided realistic performance characteristics for the relevant components. As the main focus of the project was on the gas turbine, IPSEpro software tool, a commercial heat and mass balance program by SimTech [148], was initially selected for the modeling of the entire plant as well as the turbo-machinery parts. This choice was made to reduce the number of software tools and thereby data exchanges between them. It should be noted that most commercial heat and mass balance programs provide a limited number of component models and relevant details. Furthermore, the necessary modifications to the component models are often difficult as access to the source code of the models and their underlying assumptions is restricted. The main feature of the IPSEpro software is its component-by-component approach. This capability enables the modeling of virtually any type of power plant by the integration of basic modules such as expander, compressor, combustor, steam section, heat exchanger, etc. In addition, the performance of each component (e.g. gas turbine, HRSG, steam turbine, and pumping units) can be effectively predicted at their design and off-design points by means of embedded component characteristics. Though the calculation process does not include the dimensional design of any components, it is accurate enough to estimate system level performance of the power block. Moreover, different parameters can be calibrated to reproduce the performance of advanced gas turbines as realistically as possible. However, this software suffers from some limitations, including upper limit of the operating pressure of gaseous streams, as well as lack of enough chemical elements generated 72 H2-IGCC power plant during coal gasification. Moreover, simulation results for the acid gas removal showed a considerable difference compared to the results from Aspen Plus, as well as results from an industrial partner’s simulator (ProMax). This was justified by the differentiated solubility data of Selexol solvent, which was only based on a certain operating temperature and pressure and for non-, pre-loaded solvent in IPSEpro. The mentioned limitations, as well as the specific capabilities of different tools to model certain sub-systems, resulted in the use of a combination of different software tools, including IPSEpro, for simulation tasks. In addition to IPSEpro, two main software tools have been employed to establish the thermodynamic models of the power plant system and thereby to analyze the thermodynamic performance in this thesis as follows: Enssim: simulation tool developed by Enssim Software [149]; and Aspen Plus: commercial process engineering software by Aspen Tech [150]. This approach has been selected to obtain reliable results and to utilize the possibility of incorporating detailed component characteristics into relevant sub-system models. Even though different software tools have been used for the simulation of different sub-systems, proper matching between those tools enables simulation of the entire plant. Data exchange between software tools was performed manually to find the optimal match, which was a time-consuming process. A combination of the following simulation tools was used to model the IGCC and NGCC power plants as follows: Detailed modeling of the gasification block including various processes, e.g. coal milling and drying (CMD), gasification, raw syngas cooling and scrubbing, was performed using the Enssim software tool. Selection of this software was justified by the fact that a validated gasification model against real plant operational data was provided by Nuon/Vattenfall that could simulate the process with a high level of accuracy. The validation results for the Shell gasifier are available in Paper III. It should be noted that the interface between simulations performed by the author of this thesis and the Enssim software was only at the level of data and information exchange to modify the existing gasification model and to simulate the entire IGCC system. The air separation unit was modeled using Aspen Plus. The Peng-Robinson (PR) equation-of-state (EOS) was selected as the properties’ method. The sour water-gas shift reaction was modeled in Aspen Plus using PR EOS. The acid gas removal unit was modeled in Aspen Plus. Two different equationsof-state, i.e. Peng-Robinson and perturbed-chain statistical associating fluid H2-IGCC power plant 73 theory (PC-SAFT), were used for simulation. However, based on a benchmarking study with one of the industrial partners, the simulation using PCSAFT equation-of-state was selected. For IGCC plant without CO2 capture, the COS hydrolysis unit and H2S removal (i.e. AGR unit) was modeled in Aspen Plus, using PR EOS and PC-SAFT EOS, respectively. The compression of captured CO2 and dehydration of CO2 stream were modeled in Aspen Plus, using PR EOS and Schwarzentruber and Renon (SR polar) equation-of-state, respectively. The power block, including the GT, and the triple-pressure steam cycle were modeled in IPSEpro. The NGCC including the gas turbine, the triple-pressure steam cycle, and the amine plant for CO2 removal were modeled using IPSEpro software. Enssim Gasification Aspen O2 & N2 ASU IPSEpro H2-rich syngas Gas turbine Steam Coal milling and drying SWGS Raw syngas cooling H2S removal and CO2 capture Syngas scrubbing Water HRSG Water Raw syngas Steam turbine CO2 compression and dehydration Steam Figure 4.2. Schematic figure of the interface and parameter exchange between different software tools As shown in Figure 4.2, the software tools had various interactions with each other, including the amount of O2 and high pressure N2 from the ASU to the gasifier; intermediate and high pressure BFW from the HRSG to the gasifier; the high, 74 H2-IGCC power plant intermediate, and low pressure BFW and IP steam from the HRSG to the SWGS; the composition and operating parameters of the produced syngas from the gasification block to the SWGS; the composition and the operating parameters of the syngas from the gas cleaning unit to the GT; the required syngas flow by the GT to the upstream units; and different BFW flows and steam flows to the HRSG. The calculation of the syngas fuel composition was performed by Aspen Plus software. It was then manually transferred into the IPSEpro gas turbine model. The input parameters to IPSEpro include the composition of the syngas, any inputs or bleeds of steam or hot water. Once the fuel flow was determined by the IPSEpro GT model, the backward calculations were performed to update the coal flow, ASU duties, auxiliary compression and pumping power demands, etc. Heat integration was finally performed between the Aspen Plus and IPSEpro models, where heating and cooling streams was required. Given the final values for heating and cooling inputs, the calculation of the steam turbine power output and HRSG duties was carried out using the IPSEpro HRSG model. 4.3.2. Boundary conditions In this section the basic assumptions for thermodynamic calculations are presented, including the ambient conditions, characteristics of the fuels, and boundary conditions of the gas turbine as the main focus of this project. 4.3.2.1. Ambient conditions For gas turbine modeling within the H2-IGCC project (and this thesis), ISO standard was used as a standard choice in the power industry, as shown in Table 4.1. 4.3.2.2. Feedstock properties The design feedstock for simulation of the IGCC power plant is a mixture of various trade coals on the world market (mainly Russia, but also USA, Colombia and South Africa). The composition and thermal properties of the design coal (bituminous coal) and the natural gas (used in NGCC simulation) are listed in Table 4.2. H2-IGCC power plant 75 Table 4.1. Ambient conditions and air composition Parameter/ component Unit Value Ambient air pressure bar 1.013 Ambient air temperature °C 15 Relative humidity % 60 Air composition N2 wt% 75.10 O2 wt% 23.01 Ar wt% 1.21 H2O wt% 0.63 CO2 wt% 0.05 Table 4.2. Composition and thermal properties of bituminous coal and natural gas Fuel type Parameter/ component Unit Value Proximate analysis (dry basis) Moisture wt% 10 Ash wt% 12.50 Volatile matter wt% 27.00 Fixed carbon wt% 50.50 LHV MJ/kg 25.10 HHV MJ/kg 26.20 Ultimate analysis (as received) C wt% 64.10 Coal H wt% 5.02 N wt% 0.70 O wt% 16.09 S wt% 1.50 Cl wt% 0.09 Main ash composition SiO2 wt% 55.00 Al2O3 wt% 24.00 Fe2O3 wt% 5.50 CaO wt% 4.50 CH4 wt% 95.53 C3H8 wt% 4.02 Natural gas CO2 wt% 0.40 N2 wt% 0.05 LHV MJ/kg 49.70 76 H2-IGCC power plant 4.3.2.3. Gas turbine boundaries and performance Different assumptions made for thermodynamic modeling of various sub-systems of the selected IGCC cycle with CO2 capture have been presented in Papers I-III and hence are not given here. However, the general assumptions for the thermodynamic modeling of the gas turbine designed for H2-rich syngas operation, which have not been presented in the previous papers, are listed in the following Table 4.3. a Table 4.3. Technical assumptions for the modeling of the gas turbine Parameter Unit Value Compressor Air flow at the compressor inlet kg/s 685.2 Air flow at the compressor outlet kg/s 497.0 Pressure ratio 18.2 st Cooling flow 1 stator kg/s 45.7 Cooling flow 1st rotor kg/s 42.8 Cooling flow 2nd stator kg/s 31.5 Cooling flow 2nd rotor kg/s 24.5 Cooling flow 3rd stator kg/s 12.8 Cooling flow 3rd rotor kg/s 17.2 Low pressure cooling flow a kg/s 13.7 Compressor isentropic efficiency % 89.0 Mechanical efficiency % 88.7 Expander Combustor outlet temperature ᵒC 1500 Turbine inlet temperature ᵒC 1265 Expander isentropic efficiency % 92.9 Expander total inlet pressure bar 17.9 Expander static outlet pressure bar 1.1 Mechanical efficiency % 88.7 Gas turbine Exhaust flow rate kg/s 709 Exhaust temperature ᵒC 574 This cooling flow shows a part of the cooling flow which does not go through the expander and was assumed for cooling of the shaft and bearings. H2-IGCC power plant 77 The compressor characteristics map, which relates the compressor mass flow, pressure ratio, and isentropic efficiency, has been implemented in the compressor model. The compression power demand was then calculated based on the operating points on the compressor map. Figure 4.3 shows the generic characteristics map used for modeling the GT compressor. 22 Pressure ratio [-] 18 IGV 100% IGV 90% 16 IGV 80% 14 IGV 70% 12 IGV 60% 10 Isentropic efficiency (%) 95% 20 94% 93% 92% 91% IGV 50% 90% 8 85 90 95 100 105 110 115 120 Corrected mass flow [-] (a) 8 10 12 14 16 18 Pressure ratio [-] 20 22 (b) Figure 4.3. Generic compressor characteristics maps, (a) pressure ratio versus corrected mass flow and (b) isentropic efficiency versus pressure ratio, for different IGV positions The targeted lumped surface temperature provided by the materials group of the H2-IGCC project is presented in Table 4.4. It should be mentioned that the equations for the calculation of the metal temperature have not been incorporated into the GT model. Hence, the provided data are presented here just to give an overview of the temperature figures at the expander side, where only the first three stages are cooled with the cooling flows. 78 H2-IGCC power plant Table 4.4. Targeted surface lumped temperatures Parameter Unit Value 1st stator °C 895 1st rotor °C 879 2nd stator °C 820 2nd rotor °C 807 3rd stator °C 787 3rd rotor °C 757 4th stator °C 772 4th rotor °C 771 The temperature increase for cooling air between extraction and injection due to the heat loss from the combustion chamber has been set to be zero for the HP cooling flow (for 1st stator and rotor) and 20 °C for the cooling flows to the 2nd and 3rd stators and rotors, as shown in Figure 4.4. 20 ºC temperature increase Fuel VIGV 1-5 6-9 10-13 Compressor 14-15 S1 No temperature increase R1 S2 R2 S3 R3 S4 R4 Expander Exhaust gas Air Shaft cooling Figure 4.4. Temperature increase for the cooling flows The calculation of system performance was started using a change of NG to H2-rich syngas, given the fact that the gas turbine model was able to calculate off-design behavior. Nevertheless, during an extensive iterative process within the H2-IGCC project, the model was improved to represent a gas turbine designed for operating on undiluted H2-rich syngas. During the evolutionary calculation process, off-design operations were considered to be limited only to the GT and not to the HRSG and steam turbine. This H2-IGCC power plant 79 could be justified as the gas turbine is extremely sensitive to its design, while the HRSG and the steam turbine are more flexible and can be adapted to different operating conditions. During the modeling and experimental activities in the H2-IGCC project, the following limits have been considered for continuous operation of the gas turbine and not during start-up or shut-down. SO2 emissions from the gas turbine were considered to be less than 10 ppmvd at 15% O2. This resulted in 99.9% removal of the sulfur content by the acid gas removal unit. NOx emissions from the gas turbine were considered to be less than 25 ppmvd at 15% O2. CO emissions from the gas turbine were considered to be less than 10 ppmvd at 15% O2. Unburned hydrocarbons (UHC) from the gas turbine have been considered to be less than 10 ppmvd at 15% O2. Upstream sub-systems Waux Fuel Gas Turbine Steam Turbine Wp Wc We Wst Ambient air Figure 4.5. The boundary for efficiency calculation of the entire IGCC plant Figure 4.5 shows the boundary for efficiency of the whole IGCC plant, which is calculated by the following Equation 4.3, considering the mechanical losses, generator loss, and all auxiliaries. 𝜂𝑛𝑒𝑡 = (𝑊𝑒 +𝑊𝑐 ) 𝜂𝑚 𝜂𝑒𝑙 +𝑊𝑠𝑡 𝜂𝑚 𝜂𝑒𝑙 +𝑊𝑝,𝐻𝑅𝑆𝐺+ 𝑊𝑎𝑢𝑥 𝑚̇𝑐𝑖 . 𝐿𝐻𝑉𝑐𝑖 × 100 (Eq. 4.3) 5. Economic evaluation Widespread utilization of any power generation technology depends heavily on its economic viability in addition to its technical benefits. The demonstration of a new power plant’s competitive position, compared to other potential technologies, is therefore essential to attract market attention. In this regard, a comprehensive cost estimating methodology was adopted and adjusted to reality, based on the feedback from industrial partners within the H2-IGCC project. In addition, a techno-economic comparative study was performed to highlight the economic feasibility as well as the advantages/disadvantages of the IGCC plant compared to other competing fossil-fuel power plants. One important goal of this chapter is to provide a brief description of different steps in order to perform the techno-economic evaluation of the selected energy conversion systems. 5.1. Cost estimating methodology A complete analysis of any electricity generating system is carried out by an evaluation of current and future projected costs as well as its performance characteristics. Technoeconomic assessments play an important role in determining the competitiveness of a selected technology against existing/reference technologies by evaluation of CAPEX and OPEX in addition to the technical indicators. Such assessments are crucial to investigate whether and under what circumstances investment in the selected technology is economically viable. The economic evaluation consists of different stages. Estimations of capital costs, operation and maintenance (O&M) costs, and fuel costs are necessary to calculate the cost of electricity (COE). 81 82 Economic evaluation Economic assessments are not definite and rely on the underlying assumptions as well as on the choice of selected parameters. There are significant differences in the cost estimating methods and basis of the calculations employed by various authors and organizations performing economic assessments of fossil-fuel power plants with CO2 capture [151]. These inconsistencies complicate a fair comparison between the COEs for different fossil-fuel power plants using different CO2 capture options from various publishing sources. However, a cost comparison between different alternative systems based on the same sort of assumptions and methodology is valid even in the presence of uncertainty in absolute costs of the plant’s components. Various publicly available reports by different organizations presented their recommended approaches for cost estimation of power plants [73, 90, 152, 153]. Amongst these reports, two publicly available reports have been initially selected as sources for equipment cost data and reference cost estimating methodologies. These two reports are from the European Benchmarking Task Force (EBTF) under the EU-FP7 CAESAR project [153] and the National Energy Technology Laboratory (NETL) of the U.S. Department of Energy (DOE) [90, 154]. The benefit of choosing these two studies from different organizations was to highlight the effects of different costing methodologies (e.g. different cost layers and assumptions) and various electricity market conditions (i.e. European and American types) on the projected capital investments. The methodology used for Paper V is based on the same methodology used in [90], while the methodology used for Paper VI is based on what is presented in [153]. Although these reports share many common features, the final cost estimating method selected for this work is based on the study provided by the EBTF report [153]. This selection can be justified by the enhancement of the exploitation of the results achieved during implementation of other European-funded projects. A set of assumptions has then been made in order to evaluate the economic indicators of the selected cycle, i.e. the H2-IGCC plant with CO2 capture, on a consistent basis. The economic viability of the selected cycle has been measured through the cost of electricity. This cost indicator is a standard metric used in the assessment of project economics, which represents the revenue per unit of electricity that must be met to reach breakeven over the lifetime of a plant. In other words, it is the selling price of electricity that generates a zero profit. For this purpose, the net present value (NPV) or discounted cash flow (DCF) computations have been carried out in order to place expenditures that occur Economic evaluation 83 in different time periods on a common value basis. In addition to cost estimation for the selected H2-IGCC plant, other alternative fossil-fuel power plants, i.e. a super-critical pulverized coal plant and a natural gas combined cycle, have been techno-economically evaluated, and the results have been published in Papers V and VI. The main purpose of these articles was to compare the technical and economic performance of the selected power plants. Special emphasis was placed on constructing a set of realistic parameters, ensuring that the comparison is performed in a consistent and fair way. In Paper VI, in addition to COE, different aforementioned plants were economically compared using the cost of CO2 avoided, which will be described later in this chapter. Moreover, economic sensitivity analyses of the selected plants were investigated, considering the realistic variation of the most uncertain parameters. 5.1.1. Costing scope The performed techno-economic studies focus on the commercial installation of each plant (or nth-of-a-kind technology) and do not cover the costs for the demonstration plants. The following general considerations have also been taken into account in the technoeconomic studies performed: The assessments carried out for this project were based on the reference years of 2012 and 2013. The power plant boundary was defined as the total power plant facility within the “fence line”. Moreover, site-specific considerations were not taken into account, and cost estimations were based on a complete power plant on a generic greenfield site. Coal receiving and water supply systems were within the battery limit. Costs associated with CO2 transport, storage, and monitoring were included in the reported cost of electricity for Paper V, while only the CO2 compression cost was included in Paper VI. All performance data are based on nominal base-load operation under clean and new conditions Due to large uncertainties in the available cost data for some cost elements, they were excluded from the assessments. Hence, any labor incentives; costs associated with plant’s decommissioning; costs associated with the transmission networks, handling distribution 84 Economic evaluation network and administration of supply; as well as all taxes (with the exception of property taxes) were excluded from the assessments. 5.1.2. Capital costs The following sub-sections firstly present the method and equations used for overall capital costs assessment and then the equations used for costing any component/subsystem of the selected IGCC plant. 5.1.2.1. Step-count costing method The capital cost assessment for the IGCC plant was based on a bottom-up approach (BUA). The BUA is the step-count exponential costing method using dominant parameters or a combination of parameters derived from the mass and energy balance simulation. The capital costs levels is illustrated in Figure 5.1, showing that there are three main levels, i.e. total direct plant costs (TDPC), engineering, procurement and construction costs (EPCC), and total plant costs (TPC). Figure 5.1. Capital costs levels and their elements for a bottom-up costing approach The following equations show the calculation method for total equipment costs (TEC) and TDPC, respectively. Table 5.1 lists various sub-systems and plant components which were systematically grouped according to their processes in the IGCC plant. Economic evaluation 85 TEC = ∑𝑛𝑗=1 𝐶𝑗 (Eq. 5.1) TDPC = ∑𝑛𝑗=1 𝐶𝑗 + ∑𝑛𝑗=1 𝐼𝑗 (Eq. 5.2) Table 5.1. Major plant components of the IGCC plant with CO2 capture # Plant components 1 Coal handling 2 Gasifier 3 Gas turbine 4 Steam turbine 5 Heat recovery steam generator 6 Low temperature heat recovery 7 Cooling 8 Air separation unit 9 Ash handling 10 Acid gas removal 11 Gas cleaning 12 Water treatment 13 Sour water-gas shift 14 Claus burner 15 SELEXOL plant 16 CO2 compression The engineering, procurement and construction costs were calculated using the following equation: EPCC = TDPC + IC (Eq. 5.3) The indirect costs (IC) were considered for the integration of the individual modules into the entire plant, such as costs for piping/valves, civil works, instrumentations, and electrical installations. The indirect costs can be simplified as a fixed percentage of the TDPC. An example of the simplified indirect costs with relevant assumptions is shown in Table 5.2. The total plant costs are the sum of EPCC, owner costs (OC) and contingencies (process and project contingencies), which is shown in the following equation: TPC = EPCC + OC + Cproc,c + Cproj,c (Eq. 5.4) 86 Economic evaluation Table 5.2. Breakdown of the indirect costs Indirect costs % of TDPC Yard improvement 1.5 Service facilities 2.0 Engineering/consultancy costs 4.5 Building 4.0 Miscellaneous 2.0 Total indirect costs 14.0 5.1.2.2. Capacity adjustment The capital costs for plant components could be found in the open literature. However, these data could not be used unless they were made consistent by using correction of size and the reference year. Calculation of the equipment cost for a certain plant, based on utilization of the cost data for different component sizes, could be performed using the following equation: 𝑆 C𝑗 = C𝑗,𝑟𝑒𝑓 ( 𝑗⁄𝑆 𝑗,𝑟𝑒𝑓 ) 𝑓 (Eq. 5.5) The term (𝑓), cost scaling exponent, incorporates economies of scale in the equation and indicates that the percentage change in cost is smaller than the percentage change in size for each major component. The typical values of the scaling exponent for power utilities vary between 0.6-0.7 [155]. 5.1.2.3. Price fluctuations The economic evaluation, based on the cost data found in the literature, should consider the economic ups and downs (market fluctuations) from the date of the original cost data to the current time. The cost adjustments are necessary since equipment cost estimates correspond to a specific time. All the cost data used in the economic evaluation need to be brought to the same reference year to reflect the market conditions for that specific year. The adjustment for price fluctuations of equipment, materials, and labor over time could be performed using a suitable cost index (CI) such as the Chemical Engineering Plant Cost Index (CEPCI), the Marshall and Swift (M&S) cost index, etc. The cost index ratio (IR) for a component is achieved by using the following equation: 𝐼𝑅 = 𝐶𝐼𝑢𝑏𝑦 𝐶𝐼𝑜𝑏𝑦 (Eq. 5.6) Economic evaluation 87 The updated cost for a component from its original base year could be then adjusted using the following equation which is derived from Eq. 5.5 and Eq. 5.6. 𝑆 C𝑗 = C𝑗,𝑟𝑒𝑓 ( 𝑗⁄𝑆 𝑗,𝑟𝑒𝑓 𝑓 ) . 𝐼𝑅 (Eq. 5.7) 5.1.2.4. Currency exchange In the economic calculations carried out, all figures extracted from the literature given in different currencies (e.g. US$ or €) were recalculated to the desired currency using the universal currency conversion XE rates [156]. 5.1.3. Operation and maintenance (O&M) costs The operations and maintenance costs are the costs associated with operating and maintaining the power plants over their expected lifetimes. These costs usually include: Operating labor; maintenance (materials and labor); consumables; waste disposal and management; and co-product/by-product credits (negative costs for any co/by-products sold can be considered). The abovementioned costs are classified in two categories: the fixed O&M costs, which are independent of the plant output (products) such as labor cost, overheads, insurance, and property taxes; the O&M costs that vary proportionally to the plant output are variable costs. These costs include consumables (such as water, chemicals, solvent, and catalysts) and waste disposal. 5.1.4. Fuel cost The fuel cost, similar to variable O&M costs, is dependent on the plant output. Although the coal cost, based on mine-mouth coal prices, has been stable over recent years, the market price shows significant variation. The price for the bituminous coal was, therefore, based on the market price. The fuel quantity, for the fuel cost calculation, was taken from 88 Economic evaluation simulation results, and the corresponding cost was determined on the basis of yearly consumption. 5.1.5. CO2 cost measures A variety of measures are used in the literature to report the cost of CO 2 capture and storage systems for power plants. The most common measures include the cost of CO 2 avoided and cost of CO2 captured [18]. The cost of CO2 avoided compares a plant with carbon capture with a reference plant without capture and quantifies the cost of avoiding CO2 emissions for the provision of electricity, which is defined as: 𝐶𝑜𝑠𝑡 𝑜𝑓 𝐶𝑂2 𝑎𝑣𝑜𝑖𝑑𝑒𝑑 [€/𝑡𝐶𝑂2 ] = 𝐶𝑂𝐸𝑐𝑎𝑝𝑡𝑢𝑟𝑒 −𝐶𝑂𝐸𝑟𝑒𝑓 [€/𝑀𝑊ℎ] 𝐶𝑂2 𝑠,𝑟𝑒𝑓 −𝐶𝑂2 𝑠,𝑐𝑎𝑝𝑡𝑢𝑟𝑒 [𝑡𝐶𝑂2/𝑀𝑊ℎ] (Eq. 5.8) where 𝐶𝑂2 𝑠 is tonne of CO2 emissions to the atmosphere per MWh (based on the net capacity of each power plant), and the subscripts “𝑐𝑎𝑝𝑡𝑢𝑟𝑒” and “𝑟𝑒𝑓” refer to plants with capture and without capture (or reference plant), respectively. It should be highlighted that the cost of CO2 avoided can be more comprehensive, incorporating the costs associated with CO2 capture, transport and storage rather than only considering the capture part. However, the boundary conditions for this study did not include transport and storage steps, as these areas are different research fields that could not be covered by the H2-IGCC project. As shown in Eq. 5.8, calculation of the cost of CO2 avoided requires the definition of a reference plant. This could be an identical/similar plant of the same type as the plant with CO2 capture or a different plant type. The choice of an identical/similar reference plant is typically made to quantify the cost of CO2 avoidance for a particular technology. Such a choice is also made assuming that the investigated technology has a similar chance to be built in future under a no-carbon-constraint scenario [157]. Another important cost measure is the cost of CO2 captured for a particular capture technology in a specific type of power plant [18]. This measure is to quantify only the cost of capturing CO2 and the economic viability of a CO2 capture system could be evaluated Economic evaluation 89 using this measure compared to the CO2 market price as an industrial commodity [42]. The cost of CO2 captured for a power plant is defined as: 𝐶𝑜𝑠𝑡 𝑜𝑓 𝐶𝑂2 𝑐𝑎𝑝𝑡𝑢𝑟𝑒𝑑 [€/𝑡𝐶𝑂2 ] = 𝐶𝑂𝐸𝑐𝑎𝑝𝑡𝑢𝑟𝑒 −𝐶𝑂𝐸𝑟𝑒𝑓 [€/𝑀𝑊ℎ] 𝐶𝑂2 𝑠,𝑐𝑎𝑝𝑡𝑢𝑟𝑒𝑑 [𝑡𝐶𝑂2 /𝑀𝑊ℎ] (Eq. 5.9) where the subscript “𝑐𝑎𝑝𝑡𝑢𝑟𝑒𝑑” shows the total mass of CO2 captured per net MWh for the power plant with capture. It should be noted that, in this case, the reference plant is the same type as the plant with capture unit. The cost of CO2 captured is always lower than the cost of CO2 avoided, mainly because the efficiency penalty caused by the CO2 capture unit means that more CO2 is captured than avoided per net MWh generated (see also Figure 5.2). The values illustrated in Figure 5.2 are based on the selected IGCC cycle with and without capture unit in Paper VI. CO2 emitted CO2 captured 60 700 50 600 500 40 400 300 €/t CO2 CO2 avoided CO2 produced (kg/MWh) 800 30 20 200 10 100 0 0 Reference plant Plant with capture Cost of CO2 captured Cost of CO2 avoided Figure 5.2. The relationship between the CO2 emitted, avoided and captured (left) and the cost of CO2 captured and avoided (right) 5.2. Uncertainty in the economic results Generally, some degree of uncertainty is expected in economic and technical performance data for any technology. Additional uncertainties are commonly encountered in executing a project which results in an increase in cost [158]. Uncertainty reflects lack of knowledge/experience about the precise value(s) of one or more parameters affecting the 90 Economic evaluation economic (or technical) performance of a technology [157]. In any case, the most mature technologies show the smallest range of uncertainty compared to what is demonstrated by the new technologies. The IGCC technology is a complex energy conversion system. Moreover, operating experience with IGCC power plants is limited compared to e.g. NGCC and SCPC plants. In addition, currently there is no pre-combustion carbon capture system operating on a commercial scale. As a consequence, there are substantial uncertainties associated with cost data and technical performance for any economic assessment related to IGCC plants with CO2 capture [65]. The most important uncertainty factors or sources of uncertainties in the economic assessments carried out are summarized below: The current and expected heat and electricity market conditions can have a major impact on the capital costs of the plants, as well as financial assumptions such as discount rate. With the current market condition for fossil-fuel power plants, which is considered a volatile market, a low capacity factor can be considered due to the increased share of renewable energy sources; a high discount rate may be applied as investors try to gain a return on their investments as fast as they can. In addition, assumptions about market prices for e.g. chemicals, catalysts, etc. are uncertain. Different technical assumptions such as process design assumptions and parameters used for simulation such as equipment sizing parameters, requirements for catalysts, chemicals and consumables are also sources of uncertainty in the economic results. As no existing full-scale carbon capture plant has been integrated into a power plant on a commercial scale, any estimates have been made from scaling up from prototypes or detailed bottom-up engineering estimates. Therefore, there is a high degree of uncertainty in the cost data of the CO2 capture systems, including capital costs and O&M costs, apart from technical performance such as the additional energy consumption required for the capture unit. There is uncertainty as to how the state of technology of all CO2 capture systems (including pre-combustion) will be developed in the future, even though it is expected that the costs of capture technologies will decrease in future [34]. However, this cost reduction is strongly connected to experience gained by more demonstration plants and incremental technological improvements. Economic evaluation 91 The IGCC technology is not currently a widely deployed technology so the cost of IGCC plant itself (even without CO2 capture unit) is somewhat uncertain. There is also the possibility that substantially cheaper technologies may become commercially available (e.g. ITM for O2 production in IGCC cycles). Given all these sources for uncertainties in economic (as well as technical) results, performing a sensitivity analysis is a way to examine the effects of uncertainties (or variability) in key parameters on the economic results. Therefore, such analyses were carried out in order to disclose the effect of a plant’s capacity factor (or load factor) and fuel price on the economic attributes of the selected IGCC plant. 6. Concluding remarks The ever-increasing demand for electricity has been faced with a global concern, i.e. increasing worldwide GHG emissions. Several potential pathways to mitigate these emissions have been investigated during recent years. The most important ones, having substantial impacts, are increase in the renewable energy share in the power mix, increase in energy efficiency, and carbon capture and storage. As one of the leading stakeholders, the European Union set a 20% reduction in GHG emissions (compared to 1990 level) by 2020 and has included CCS in the portfolio of technologies to meet this target. Accordingly, many R&D projects were financed by the Directorate-General for Energy (European Commission) under the Sixth and Seventh Framework Programmes including the Low Emission Gas Turbine Technology for Hydrogen-rich Syngas (H2-IGCC) project in 2009. As mentioned earlier, this PhD study has been carried out as a part of the research activities under the framework of the H2IGCC project. The following sub-chapters will summarize the main findings/conclusions of this work and the scientific contributions of this study as well as offering some suggestions for further investigations which can be accomplished by future research activities. 6.1. Conclusions The two important driving forces for defining, obtaining financial support for, and implementing the H2-IGCC project were the continuing need to use coal as primary fuel for the security of the energy supply and the requirements to curb CO2 emissions. The electricity supply must be secured by utilizing various environmentally-friendly technologies in every modern society. Undoubtedly, IGCC plants can contribute to the 93 94 Concluding remarks security of the electricity supply under stringent emission regulations. However, it should be clearly underlined that electricity must be supplied at an affordable cost so that the global competitiveness of countries/regions is not affected in negative way. The technoeconomic results presented by this study showed that the three fossil-fuel power generation alternatives without CO2 capture perform quite similarly with respect to the cost of electricity. However, IGCC and SCPC are advantageous among plants without capture based on underlying assumptions. The marginal difference in the cost of electricity was within the level of uncertainties in the assessment of investment costs. Therefore, other main drivers, apart from the cost of electricity, affect the selection of a power generation technology including: operational flexibility and availability; compatibility with grid requirements assuming much higher share of renewable energy sources in future energy mix and the risks for underperformance; compatibility with utilities’ experience; availability and diversity of equipment and technology suppliers; various aspects relevant to health, safety and environment (HSE); and potential for future improvements. Given these criteria, opportunities for substantial economically attractive investments in IGCC plants without CO2 capture remain questionable. Under current electricity market conditions, new investments even in “standard” fossil-fuel power plants, i.e. pulverized coal and NG simple and combined cycles (without CO2 capture), are foreseen to be limited in Europe. This is mainly due to the increasing share of renewable energy sources in the European power mix, which has had a tremendous impact on operating strategies and the profitability of fossil-fuel power plants. Anyhow, intermittent RE requires reliable-, fast balancing/backup power plants as well as large storage capacity. Hence, gas turbine cycles fueled with NG, which are much faster, are superior compared to coalbased plants (e.g. IGCC and SCPC). However, the reduction in the coal price in Europe, mainly due to coal import from the USA as well as inexpensive costs for carbon emissions, has recently resulted in the increased use of old coal plants (which have already repaid their investment costs) in this region, compared to costly, high-efficiency and low emission NGCC plants. Concluding remarks 95 The limited or non-existent tendency of European power market might change from standard fossil-fuel plants to IGCC plants in a carbon-constrained future when CCS technologies will play an important role in the mitigation of GHG emissions. In this context, the value of CO2 credits should be established with certainty, and appropriate regulations on the required CO2 quality, storage access, monitoring of the storage sites, etc. should be introduced. Even then, the IGCC technology with CO2 capture should prove its competitive position against other low-carbon emissions technologies with respect to issues like economic viability, operability, availability and reliability at a high share of renewable energies in the global power mix. Assuming all these issues will be resolved by policy changes and technological improvements, the findings of the current thesis indicated that higher carbon prices should be set for the economic benefits of cycles with capture compared to their reference plants (i.e. without capture). Given all the aforementioned uncertainties and challenges facing the application of IGCC technology, the precautionary principle suggests that doing nothing is not the best choice. Indeed, it is quite clear that investigations such as those presented by this work are highly necessary, especially when political and market conditions are being changed to force new fossil plants to be built only with CO2 capture. Perhaps under these assumptions, and given the need to keep the electricity supply versatile (energy diversity), IGCC application will still be limited in some localities with abundant coal reserves such as China and the USA. In addition to aspects related to the aforementioned general view, such as current market condition, economic viability, and the risk of CCS deployment, technological aspects of the H2-IGCC project also need to be presented. Theses aspects include the application of pre-mixed combustion for H2-rich syngas, knowledge built within the field of system analysis, and techno-economic assessment. It is questionable whether and under what condition the technology proposed in this thesis for the combustion of H2-rich syngas can be employed in gas turbines specifically for IGCC application in the near future. However, rapid changes in the global structure of heat and electricity supply and demand have a tremendous impact on the application of combustion technology developed within the H2-IGCC project. Likewise, via the application of power-to-gas to reach the maximum utilization of renewable energy sources, the hydrogen produced needs to be stored, perhaps in the existing NG pipelines. 96 Concluding remarks This will assist the existing infrastructure (e.g. pipelines) to be maintained and the carbon footprint to be reduced. Knowledge built in this project will then enable the use of premixed combustion technology for high H2 content natural gas in the gas turbines, which is amongst the options to balance/back-up renewable energies. With respect to the system analysis performed for this project, the knowledge built will be helpful in taking a holistic approach to analyzing any other energy conversion systems. In addition, the level of detail in every component of the system was appropriate to provide the necessary boundary conditions and data for combustor design, gas turbine design and techno-economic assessment. However, it should be highlighted that different types of optimizations are still required for successful utilization of the IGCC technology, such as heat integration, cost-benefit optimization, desired level of integration, etc. The cost estimate presented in this work clearly confirmed the considerable negative impact of applying CO2 capture systems in different power plants, as the total investment and cost of electricity are much higher compared to the same plant type without CO 2 capture. Accordingly, in order to make power plants with CO2 capture economically attractive, the cost of emitting CO2 must be much higher than the current cost for CO2 allowances. Finally, it should be noted that the economic calculations performed here are relevant based on data available today and underlying assumptions. Such uncertainties should be kept in mind when interpreting the outcomes of this thesis. 6.2. Scientific contributions The research work presented in this thesis places emphasis on the development of technical solutions to allow the use of highly efficient gas turbine technology in the IGCC plants with CO2 capture suitable for combusting undiluted H2-rich syngas. The two major contributions of this study are: 1. System analysis and integration: system analysis using detailed validated models provides highly valuable contributions concerning low cost, reliable results prior to any piloting and demonstration activities. In this regard, system integration alternatives with a high degree of complexity in both the IGCC plant and the integrated pre-combustion carbon capture were evaluated. This has shed light on the pros and cons of various alternatives, paving the way for future Concluding remarks 2. 97 implementation of the most efficient and practical system integration alternatives. Techno-economic model and assessments: the available techno-economic approaches for the power plant were thoroughly reviewed, and the most suitable method was selected. Accordingly, correction/adjustment of these methodologies was carried out. Realistic cost and performance data supported by the industrial partners of the project were then used to establish a solid base for a comparative techno-economic study. The tool developed in the Microsoft Excel environment provided the opportunity to update and modify any underlying assumptions and enabled the economic evaluation of the IGCC plant with carbon capture as well as its main competitors with a good level of accuracy. The following list presents the other secondary contributions, which enhance the current knowledge in this field: i. An undiluted H2-rich syngas was used for the gas turbine modeling and simulation, and the plant’s configuration was established and modified compared to what is available in the literature. ii. A non-integrated ASU-GT was selected to provide more availability and flexibility to the operation of the IGCC plant. The plant’s overall performance data could be marginally better in more integrated layouts but at the expense of additional costs as well as less availability. iii. Different gasification technologies have been investigated and integrated into the selected IGCC configuration in order to explore the most appropriate option for the application of pre-combustion CO2 capture in IGCC plants. iv. Fuel flexibility targets in the gas turbine, with respect to fuel change due to slip of CO2 capture unit, could not be accomplished using an identical combustor designed for H2-rich syngas. This was mainly due to the large difference between thermal properties of the H2-rich syngas and the syngas produced in the noncapture IGCC plant. v. The use of existing gas turbine technology, which is designed for NG operation, would not be appropriate for handling H2-rich syngas. In this regard, a new gas turbine was designed by other partners, involving some modifications, mainly in the expander. Accordingly, the boundary conditions generated were used to update the GT model and the overall IGCC plant. 98 Concluding remarks 6.3. Suggestions for further research The following topics from different perspectives, i.e. a holistic view on energy conversion systems to a detailed technological level, are considered by the author as an appropriate continuation in this field and thus recommended for further research: In the context of fossil-fuel energy conversion systems vi. An investigation into the operating strategies of newly built or existing fossil-fuel power plants under current market conditions is highly essential. Therefore, a techno-economic study on existing fossil-based technologies for power generation could be performed, defining different scenarios for increasing the share of renewable energies and the need for fossil-fuel plants as a backup/balancing option. The major difference from the underlying assumptions made for the current study would then be operating at part load rather than at base load. The cyclic operation of the fossil-fuel power plants and its effects on maintenance costs and lifetime consumption of different parts could be incorporated to improve such an analysis. In the context of system integration and analysis of the IGCC power plants vii. In order to achieve better performance indicators of the IGCC plant, alternative technologies listed in this thesis, such as ITM for air separation or SEWGS for shift reaction and CO2 capture, could be integrated into the cycle. However, the efficiency improvements should be evaluated against the economic implications and operational challenges. It should be highlighted that different types of optimizations, such as heat integration, cost-benefit optimization, and desired level of integration, are required to make the IGCC technology ready for future application. viii. In order to have appropriate control over the simulation and modeling of such an integrated and complex energy conversion system (i.e. IGCC system with CO2 capture), integrating software tools could be beneficial. For this purpose, it could be an option to generate dynamic link library files, assuming that all software tools used for this study are available. This option provides all the benefits which could be gained by using each and every one of the previously mentioned software tools. In the case of performing a simple techno-economic analysis, it Concluding remarks 99 would be beneficial to simulate the whole system in e.g. IPSEpro or ASPEN Plus, assuming the level of uncertainties in the cost assessments. In the context of hydrogen-rich fueled gas turbine The dynamic behavior and off-design conditions of the gas turbine when it is fed by a hydrogen-rich syngas need to be investigated. Off-design modeling of such gas turbines will be very useful, especially when the gas turbine technology is used as a back-up or balancing power option for renewable energy sources. Power-to-gas technologies might be considered for storing a part of intermittent RE and then high hydrogen content NG might be used as a fuel for GTs, perhaps not at the base load condition. 7. Summary of appended papers This chapter briefly presents the main findings of the papers appended to this thesis. These papers are mainly related to the establishment of the baseline IGCC plant for the purpose of system analysis; an investigation of the effects of coal quality and gasification process type on the overall performance of the selected IGCC plant; a study of the effects of fuel flexibility on the performance of the selected gas turbine; and techno-economic comparatives studies on different fossil-fuel power plants including the selected IGCC plant. Paper I Development of H2-rich syngas fuelled GT for future IGCC power plants – Establishment of a baseline, Presented at ASME Turbo Expo 2011, GT2011-45701, Vancouver, Canada, June 2011. This paper presents the establishment of two baseline IGCC power plants, i.e. with and without pre-combustion CO2 capture. For this purpose, different sub-systems including gas cleaning, gas turbine, steam turbine, heat recovery steam generator along with the inputs from the industrial partners Vattenfall/Nuon and E.ON were integrated. The gas turbine used for this study is based on Ansaldo Energia 94.3A without any dilution of the syngas. The main goal of this study was to provide a baseline for further investigations incorporating the necessary changes/modifications related to the gas turbine during the lifetime of the H2-IGCC project. The secondary objective was to provide the potential of burning undiluted H2-rich syngas and its effects on enhancement of the efficiency of the IGCC power plants with CO2 capture. 101 102 Summary of appended papers The analysis shows that the combustion of H2-rich syngas has the potential for increasing the overall IGCC efficiency compared to data available in the literature for IGCC plants with diluted syngas and CO2 capture. The overall efficiencies of the plants are 37.4% and 47.2% (LHV basis) respectively for the IGCC plant with CO 2 capture and for non-capture IGCC. The difference between two configurations, IGCC with and without CO2 capture, results in two completely different syngas compositions. Preliminary results of this study show that combustion of undiluted H2-rich syngas does not impose any significant effects on the gas turbine, at least from a system perspective. However, the large change in fuel flow in the case of non-capture IGCC plant generates some challenges for both the combustion process and the turbo-machinery. Paper II An EU initiative for future generation of IGCC power plants using hydrogenrich syngas: Simulation results for the baseline configuration, Applied Energy, Vol. 99, pages 280-290, June 2012. This paper is in continuation of Paper I to investigate the use of undiluted H 2-rich syngas in the IGCC plant with CO2 capture. However, simulation of the gas cleaning part of the IGCC plant including the acid gas removal unit and the CO2 capture system was performed using ASPEN Plus, unlike Paper I which was in IPSEpro. The main reason for this was the specific capabilities of ASPEN Plus to simulate gas cleaning processes. Moreover, additional plant’s components were integrated into the system to provide more comprehensive and practical plant layout. The paper presents a detailed thermodynamic model of the baseline IGCC plant with and without CO2 capture. Realistic performance indicators verified by the operators of similar/relevant plants were used, as compared to Paper I, which was mainly based on data available in the literature. In addition to changes in performance indicators of some plant’s components, some information on the GT provided by other partners was incorporated into the GT model. Results revealed that the effects of these changes/modifications on the model presented in Paper I were negative in terms of the overall plant efficiency. The estimated overall efficiency of the IGCC power plant without carbon capture is 46.3%, while it is 36.3% for the plant with carbon capture, somewhat lower than the results presented in Paper I. The Summary of appended papers 103 results confirm the fact that a significant penalty on efficiency (21.6% relative) is associated with the capture of CO2. Through comparison with other published studies, more integration of sub-systems indicated some potential for better efficiency, although probably at the expense of lower reliability. Using undiluted syngas in the GT significantly improves GT power. However, some challenges related to the unstable operating condition of the GT combustor and compressor, as well as reduced lifetime of the blades of the existing gas turbines when using undiluted H2-rich syngas, should be addressed by future studies. Paper III Estimation of performance variation of future generation IGCC with coal quality and gasification process – Simulation results of EU H2-IGCC project, Applied Energy, Vol. 113, pages 452-462, August 2013. This paper presents the effects of gasifier type and coal quality on the overall performance of the baseline configuration of the IGCC plant. In this regard, four commercially available gasifiers from Shell, GE, Siemens, and ConocoPhillips have been considered for this comparative study. The effects of three different types of coals on these gasifiers, as well as on the overall performance of the IGCC plant, have been investigated. Utilizing validated models against existing plant data for simulation of gasification block resulted in more reliable results. The results confirm that the coal quality considerably influences the cold gas efficiency for slurry-fed gasifiers, while dry-fed gasifiers are relatively insensitive to the quality of the input coal. Amongst slurry-fed gasifiers, the coal quality has the greatest impact on the performance of the GE gasifier. The cold gas efficiency of the GE gasifier gasifying lignite coal is 29% lower than gasifying bituminous coal. It is also shown that dry-fed gasifiers are advantageous compared to slurry-fed types with respect to constant quality of produced syngas even when low-rank coal is gasified. Based on the findings of this paper, slurry-fed gasifiers investigated in this study, i.e. GE and ConocoPhillips, are suitable for bituminous and sub-bituminous coals, while dry-fed gasifiers, i.e. Shell and Siemens, show a relatively constant behavior for a wider range of coal quality. 104 Summary of appended papers The higher water content of the produced syngas from slurry-fed gasifiers results in an enhanced ST power output due to reduction of the steam extraction from the steam cycle for the water-gas shift reaction. However, this power increase cannot compensate for the increase of ASU power demand and results in lower system efficiency for low-rank coal. Paper IV Fuel change effects on the gas turbine performance in IGCC application, Presented at 13th International Conference on Clean Energy (ICEE-2014), Istanbul, Turkey, June 2014. The effect of fuel change (i.e. from NG to H2-rich syngas and clean syngas) for the selected GT is reported in this paper. This study focused on the operation of the gas turbine as a stand-alone unit. The results of this paper proved the preliminary findings of Paper I, showing that operation on undiluted H2-rich fuel (syngas produced in the IGCC plant with CO2 capture) is feasible. However, a reduced surge margin should be accepted without significant changes made to the gas turbine compared to the NG-fired engine. It should be noted that the challenges concerning pre-mixed combustion of the H2-rich fuel and different heat transfer rate to the expander materials when operated with H 2-rich fuel are not within the scope of this study. The GT operation on clean syngas (i.e. syngas produced in the IGCC plant without CO 2 capture) results in a significantly low surge margin and high turbine outlet temperature, which needs different operating conditions and/or engine modification options to be considered. When operating with a fuel with low calorific value, such as clean syngas, expected operational hours are very important for the selection of appropriate operating conditions or modification options. Although several modification options as well as operating strategies have been suggested in this paper with regard to clean syngas operation, reduced efficiency and compressor stability can be tolerated for limited operational hours with clean syngas. The results revealed that the effect of the altered VIGV angle on maintaining a reasonable surge margin is not significant for the selected GT. In order to have a minor modification of the GT compared to the design case engine for clean syngas operation, decreasing the TIT and keeping the TOT similar to the reference case (NG-fired GT) with fully open VIGV is a plausible option. However, results show a significant reduction of efficiency Summary of appended papers 105 and power output. Concluding this paper, using clean syngas requires major modifications on the GT, including additional compressor stages, air bleed from compressor outlet, and expander re-staggering, which resulted in putting this option (i.e. operation on the clean syngas) aside within the H2-IGCC project. Paper V Techno-economic evaluation of an IGCC power plant with carbon capture, Presented at ASME Turbo Expo 2013, GT2013-95486, San Antonio, Texas, USA, June 2013. This paper presents a techno-economic analysis for the selected IGCC plant configuration with CO2 capture using the cost data and methodology of the U.S. Department of Energy. The main objective was to generate a database using publicly available literature to calculate the COE for the IGCC plant. The secondary objective was to compare the COE for the IGCC plant with other fossil fuel competing technologies, i.e. NGCC and SCPC plants, all with CO2 capture system. In this paper, the methodology used for the economic evaluation of the plant, as well as relevant assumptions, calculation methods, and economic figures are described. The COE for the IGCC plant with CO2 capture is projected to be 160 US$/MWh. It should be noted that all economic results are strongly dependent on presented assumptions. Therefore, a sensitivity analysis was also carried out, showing that the most influential parameter amongst selected parameters on the COE is the capacity factor. The fuel price was the second ranked parameter. As the selected IGCC plant is considered with CO2 capture, most of the CO2 produced is actually captured. Moreover, the costs for CO2 allowances are very low. Therefore, the effect of CO2 allowances’ costs on the COE is negligible. Finally, a comparative study was carried out to highlight the cost difference between various power generation technologies, i.e. IGCC, SCPC, and NGCC plants with CCS. The total overnight costs for IGCC, SCPC, and NGCC with CO2 capture are estimated at 4677, 4065, and 1669 US$/kW, respectively. The results revealed that the investment cost in the IGCC plant is projected to be more than double that for the NGCC plant. However, other aspects such as the security of the energy supply may encourage investors to select IGCC plants. Moreover, it is shown that with the higher capacity factor and CO2 allowances’ cost, which is plausible in the coming 106 Summary of appended papers years, the IGCC plant could attract more investments compared to the SCPC plant. Furthermore, income from poly-generation applications might also improve the economic viability of future IGCC plants. Paper VI Techno-economic assessment of fossil fuel power plants with CO2 capture ‒ Results of EU H2-IGCC project, International Journal of Hydrogen Energy, Vol. 39, pages 16771-16784, September 2014. In this paper the thermodynamic performance indicators of various power plants, including IGCC, advanced supercritical pulverized coal, and natural gas combined cycle power plants are presented. The technical indicators of the selected IGCC plant and NGCC with and without CO2 capture unit are based on the simulations carried out during the lifetime of the H2-IGCC project. These indicators for the SCPC were adopted from literature. Results confirm that the NGCC is the most efficient plant, while the advanced SCPC plant is the least efficient plant amongst non-capture cases. This trend is similar for the plants with capture unit. The relative efficiency penalties associated with the capture deployment (compared to the identical plant with CO2 capture) are 24%, 27%, and 16% for the selected IGCC, advanced SCPC, and NGCC plants, respectively. In this article, a comparative study was also conducted, comparing the COE and the cost of CO2 avoided for the mentioned fossil-based power plants. The economic performance indicators of each plant were estimated using the model developed in the Microsoft. Excel environment. It is very important to take into account that such a techno-economic analysis cannot provide an absolute result, since the cost data and assumptions are uncertain by nature. The COE for the IGCC plant with and without capture is 91 and 59 €/MWh, respectively. The COE for the advanced SCPC is 96 and 59 €/MWh for the capture and non-capture cases, respectively. The COE for the NGCC with and without capture is 61 and 91 €/MWh, respectively. The results show that the least capital-intensive plant is the NGCC plant without CO2 capture. However, the high fuel costs for this plant decrease the gap between the COE for this plant compared to that for the other plants. The COE for the Summary of appended papers 107 NGCC technology was the most sensitive to changes in the fuel price amongst other COEs for different technologies. However, the COE for the NGCC technology was also the least sensitive to variations of the plant’s capacity factor. The estimated costs of CO 2 avoided for the IGCC, SCPC, and NGCC technologies are 51, 57, 99 (€/t CO 2 avoided). 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Paper I Development of H2-rich Syngas fuelled GT for future IGCC power plants – establishment of a baseline Nikolett Sipöcz, Mohammad Mansouri, Peter Breuhaus, Mohsen Assadi Presented at ASME Turbo Expo 2011, Vancouver, Canada, June 2011 121 Proceedings of ASME Turbo Expo 2011 GT2011 June 6-10, 2011, Vancouver, British Columbia, Canada GT2011-45 DEVELOPMENT OF H2-RICH SYNGAS FUELLED GT FOR FUTURE IGCC POWER PLANTS – ESTABLISHMENT OF A BASELINE 1 1 2 Nikolett Sipöcz , Mohammad Mansouri , Peter Breuhaus , Mohsen Assadi 1 2 Department of Mechanical- and Structural Engineering and Materials Science University of Stavanger 4036 Stavanger, Norway ABSTRACT As part of the European Union (EU) funded H2-IGCC project this work presents the establishment of a baseline Integrated Gasification Combined Cycle (IGCC) power plant configuration under a new set of boundary conditions such as the combustion of undiluted hydrogen-rich syngas and high fuel flexibility. This means solving the problems with high NOx emitting diffusion burners, as this technology requires the costly dilution of the syngas with high flow rates of N2 and/or H2O. An overall goal of the project is to provide an IGCC configuration with a state-of-the-art (SOA) gas turbine (GT) with minor modifications to the existing SOA GT and with the ability to operate on a variety of fuels (H2-rich, syngas and natural gas) to meet the requirements of a future clean power generation. Therefore a detailed thermodynamic analysis of a SOA IGCC plant based on Shell gasification technology and Siemens/Ansaldo gas turbine with and without CO2 capture is presented. A special emphasis has been dedicated to evaluate at an intermediate stage of the project the GT performance and identify current technical constraints for the realization of the targeted fuel flexibility. The work shows that introduction of the low calorific fuel (H2 rich fuel more than 89 mol% H2) has rather small impact on the gas turbine from the system level study point of view. The study has indicated that the combustion of undiluted syngas has the potential of increasing the overall IGCC efficiency. 1 International Research Institute of Stavanger (IRIS) Postbox 8046 4068 Stavanger, Norway for the development of reliable, low-emission, cost-competitive gas turbine technologies for hydrogen-rich syngas combustion. Integrated gasification combined cycle is currently one of the most attractive technologies for the use of coal with high efficiency and it offers the greatest fuel flexibility among the most advanced technologies for power production. In addition, gasification also provides an opportunity to control and reduce gaseous pollutant emissions such as NOx and SOx. It in addition offers one of the least costly approaches to concentrate carbon dioxide (CO2) at high pressure to facilitate CO2 capture and storage (CCS). However, coal-based IGCC plants have still not achieved any commercial breakthrough, even though research and development of IGCC plant technology began 40 years ago. The currently six IGCC power plants in the world, operating on coal as primary feedstock are demonstration plants with capacities of 250-400 MW [1]. The design and operational experiences along with the technical limitations of current state-of-the art IGCC power plants have been reported in the recent past [2]-[5]. Important contribution to field highlighting the two design variables affecting the gas turbine operation i.e. the integration level of the ASU and the nitrogen supply ratio for dilution of the syngas has been presented by Kim et al [6]. These two parameters do also have an influence on the turbine metal temperature. It has been shown that low integration degree designs cause overheating of the turbine metal due to higher pressure ratios. Overheating of the turbine metal also becomes more severe as the heating value of the syngas decreases. As a consequence of the increased fuel flow the pressure ratio is increased, which in turn gives higher temperature of the extracted air for turbine cooling [7]. Even though higher integration levels results in a higher IGCC efficiency [6] the operational experience from 1 INTRODUCTION The continued need to use coal as primary fuel engenders both increased interest and concern while, in connection with coal gasification, generating a sincere demand 1 Copyright © 2011 by ASME with a SOA GT with minor modifications to the existing SOA GT and with the ability to operate on a variety of fuels (H2-rich, syngas and natural gas) to meet the requirements of a future clean power generation. Therefore a detailed thermodynamic analysis of a SOA IGCC plant based on Shell gasification technology and Siemens/Ansaldo gas turbine with and without CO2 capture is presented. A special emphasis has been dedicated to evaluate the GT performance and identify current technical constraints for the realization of the targeted fuel flexibility. Buggenum has shown that the highly integrated design layouts are problematic and has a negative effect on the plant availability. With the last years growing concern about greenhouse gas emissions the near-term implementation of pre-combustion CO2 capture technologies in IGCC applications has drawn increased R&D interest [8]-[11]. One of the most promising alternatives to the pre-combustion technology in IGCC power plants is the oxy-combustion IGCC [12], [13], having the potential of increasing both efficiency and environmental characteristics of coal power plants. However, the large oxygen consumption and required re-design of the gas turbine are still the main drawbacks [13]. Accordingly, this CO2 abatement technology along with membranes, adsorption onto solids and cryogenic separation are different in terms of efficiency and cost compared to chemical or physical absorption of CO2 and thus the realization of these are within the mid-long term time frame. Nevertheless, the capital costs associated with current SOA IGCC is a major challenge, especially compared to natural gas combined cycles. Adding the costs for implementing any near term CCS technology makes the challenge even greater [14]-[17]. In this context the high operational costs, coming at the top of the investment, is another drawback deriving from the currently low reliability and availability of the gasifier, reduced efficiency due to de-rating of the gas turbine, and the required syngas pre-treatment in terms of dilution. Although IGCC offer significant advantages over pulverized coal (PC) plants in terms of cost effective reduction of CO2 emissions, the main challenges including cost, compatibility with alternative technologies and the insecurity of the implementation of any future CCS remain critical obstacles for widespread commercialization [18]. Numerous research projects such as Australia’s COAL21 National Action Plan, the European funded Clean Coal Technology activities under the 7th Framework Program, and the Canadian Clean Coal Technology Roadmap have thus been released in recent years. They are aiming at reducing these barriers by focusing on new coal feeding systems, novel H2 production and purification processes, and CO2 management [19]. In addition to capture, CCS involves two other major components: transport and storage. One of the biggest uncertainties in the CCS chain is finding suitable sites for the storage of CO2 close to the emissions sources. Other storage issues that need be addressed are: storage capacity estimation, the potential for storage e.g. in deep saline reservoirs, understanding the CO2 trapping mechanisms and quantifying the risks of CO2 geological storage. Even though considerable progress has been made in understanding many of these issues trough the many research and demonstration projects around the world i.e. Sleipner, Weiburn, In Salah and Otway to mention a few, the regulatory framework and incentives for a near term implementation of CCS is still to be solved [20]-[22]. As a part of the EU funded H2-IGCC project this work presents the establishment of a baseline IGCC power plant configuration under a set of new boundary conditions. An overall goal of the project is to provide an IGCC configuration 2 H2-IGCC PROJECT One of the largest barriers towards the usage of syngas in current IGCC power plants is its inherently variation in composition and heating value. At the same time the high content of H2 in syngas derived from gasification of coal complicates the application of pre-mix burners (Dry Low Emission of Dry Low NOx burners) , which is current SOA in natural gas fired GTs. The restriction of using DLE burners is due to the higher reactivity of H2 compared to natural gas. For this reason GTs in existing IGCC power plants are utilizing high NOx emitting diffusion burners that also requires the hydrogen-rich syngas to be diluted with nitrogen or water/steam to control the higher adiabatic flame temperature. Given these limitations the overall objective of the H2IGCC project is to provide and demonstrate technical solutions which will allow the use of SOA highly efficient, reliable GTs in the next generation of IGCC plants. The goal is to enable combustion of undiluted hydrogen-rich syngas with low NOx emissions and also allowing for high fuel flexibility by enabling the burning of back-up fuels, such as natural gas, without adversely affecting the reliability and availability. The project is divided into the following four technical subprojects (SP)[23]: Combustion (SP1) – development and demonstration of safe and low emission combustion technology for undiluted, hydrogen-rich syngas. Materials (SP2) – development and demonstration of improved materials systems with advanced coatings able to protect base blade and combustor materials against the different and potentially more aggressive temperatures and compositions of exhaust gases. Turbomachinery (SP3) – investigation of modified compressor/turbine aerodynamics and hot path cooling in order to manage the increased mass flow rate of fuel and the increased heat transfer of exhaust gases. System Analysis (SP4) – evaluation of optimum IGCC plant configurations and establishment of guidelines for optimized full scale integration while providing detailed system analysis to generate realistic techno-economical results for future gas turbine based IGCC plants with CCS. 2 Copyright © 2011 by ASME 3 METHODOLOGY This work covers the description of the current thermodynamic model set-up of the whole IGCC cycle including important aspects of assumptions and limitations as well as a discussion of the results. A special emphasis in this regards has been given to the GT since this component is the major of the overall H2-IGCC project. The thermodynamic model set up, described by the mass and energy balances of the IGCC plant with gasification of coal and pre-combustion CO2 capture has been established based on commercially available technology: oxygen-blown, entrained flow coal gasifier (Shell technology), sour water-gas-shift (WGS) reactors, physical absorption using Selexol solvent for acid gas removal (AGR), power island consisting of a 300 MW single shaft gas turbine based on the Ansaldo Energia 94.3A with a conventional triple-pressure steam cycle as the bottoming cycle. The focus of utilizing SOA technology is an important element of the overall project. Thus the foundation of the reference IGCC layout provides a fairly conservative baseline for future studies. At the end of the project the goal is to find the optimum combination of commercial gasification units with modified gas turbines, incorporating solutions to the technical challenges of burning undiluted hydrogen-rich syngas at an appropriate level of integration. Modelling of the IGCC power plant has been made using three different modelling tools: Data exchange between these codes was done manually and iterated for optimal match. Even though three different tools have been used for simulating the whole IGCC power plant with as well as without CO2 capture, the main platform for the simulations is IPSEpro and the aim is to be able to simulate the whole IGCC except from the gasification island in the IPSEpro environment by solving current limitation in terms of pressure of pure gaseous streams. The main reason for using IPSEpro as basis for the simulations is the comprehensive model library, which has been developed as a result of many years work within the research group of University of Stavanger. This includes detailed and sophisticated models of various power plant components that have been developed due to the main advantage of IPSEpro, allowing for introducing new and modified components in a very straight-forward and flexible manner. This advantage is very important in this project as the GT model will need to be adapted to certain changes based on the results from the different SPs. IPSEpro also provides additional benefits in terms of thermo-economical optimization features that will be of major significance to achieve the overall project target of finding optimum combination of commercial gasification units with modified gas turbines and appropriate level of integration. The schematic outline of the IGCC with CO2 capture is illustrated in Figure 1. Enssim – Simulation tool developed by Enssim Software. Aspen HYSYS – Commercial process simulator by AspenTech [24]. IPSEpro- Commercial heat and mass balance programme by SimTech [25]. The reason for using a combination of several simulation tools is that each of the selected tools have shown advantages when simulating different parts of the IGCC plant in terms of providing reliable results and the possibility of incorporating detailed component characteristics. Hence, the simulation tool among these three satisfying these requirements for each sub-system to the greatest extent has been selected as described below: syngas and steam in Aspen HYSYS (Peng-Robinson EOS) while the subsequent shift and two stage acid gas removal has been performed in the heat and mass balance program IPSEpro. In the case when no capture of CO2 takes place the syngas leaving the wet scrubber is bypassed to the H2S absorber before entering the power island (without any dilution). The clean syngas leaving the CO2 absorber/H2S absorber is directed to the GT, which together with the triple-pressure steam cycle is modelled in IPSEpro. The CO2 captured in the second absorber in the AGR process is compressed in a seven-stage intercooled compressor and finally pumped to appropriate transportation conditions. This part has also been completed using the Aspen HYSYS modelling tool (Peng-Robinson EOS). 4 IGCC POWER PLANT DESIGN 4.1 Coal input Bituminous coal being a mixture of various trade coals on the world market (mainly Russia, but also USA, Columbia and South Africa) with the composition according to Table 1. It is milled and dried to a moisture level of 2%wt, and fed to the gasifier by means of lockhopper pressurization using pressurized N2 as conveying gas. Heat for drying is provided by burning approximately 0.9% of the shifted syngas. The amount of coal needed is determined by the thermal power required by the gas turbine model, based on the Ansaldo Energia 94.3A GT. The resulting coal input is within the range of 1’008 -1’110 MWLHV. The detailed modelling of the Shell gasification process including the process components: coal milling and drying, gasification, raw syngas cooling and scrubbing have been performed by Nuon using the Enssim modelling tool. The required compression work in the air separation unit (ASU) has been calculated using Aspen HYSYS (Peng-Robinson equation of state (EOS)). The syngas cleaning downstream the wet scrubber has been modelled by first simulate the mixing of raw 3 Copyright © 2011 by ASME Table 1 – Composition (% by weight) and heating value of as received of the Bituminous coal used in the calculations. C 64.10 Moisture 10 H 3.90 Ash 12.50 N 0.70 O 7.21 kJ/kg S 1.50 HHV 26195 Cl 0.09 LHV 25100 4.2 Air separation unit The ASU is a stand-alone unit generating oxygen with a purity of 95mol% (with 2% N2 and 3% Ar) from air supplied by the non integrated main air compressor (MAC). Selection of the non- integrated MAC was motivated by negative experiences concerning plant availability, from partially or fully integrated ASU systems. The MAC is a seven-stage intercooled B Coal milling & drying Raw syngas A HRSG D B F E F, G Gasifier F C D HT WGS LT WGS H Wet Scrubber Make-up water E Syngas Cooler CO2 Slag I CO2 removal flash drums Demister C M M D A Fly Ash Claus/ SCOT GOX compressor ambient air H M H2S removal M O2 liquified CO2 G I H2-rich syngas MAC M N2 M ASU PGAN compressor HP IP/LP Waste N2 ambient air gas turbine Condenser Figure 1 – Plant schematic of the Shell IGCC with CO2 capture and conventional WGS compressor with a discharge pressure of 5.5 bara. The gaseous oxygen (GOX) is compressed to 55 bara in a nine-stage intercooled compressor and fed to the gasifier while the pure gaseous nitrogen (PGAN) is compressed to 80 bara in a tenstage intercooled compressor used for fuel feeding to the gasifier. Since the GT is operated on undiluted syngas all remaining nitrogen from the ASU not needed in the gasification island is vented to the atmosphere. For further technical assumptions for the air separation unit please see Table A1 in Annex 1. 4 4.3 Gasification, syngas cooling and scrubbing The gasification of the coal is taking place in an O2blown, entrained flow gasifier based on the technology licensed by Shell [26]. The gasification process (technical assumptions presented in Table A2 in Annex 1), in which the milled and dried coal is gasified in the presence of intermediate pressure (IP) steam and oxygen is modelled assuming full equilibrium at 45 bara and 1600 °C. This condition determines the composition of the raw syngas and it is achieved by adjusting the O2 to coal mass ratio while setting the heat loss to the membrane wall to 2.5% (LHV). The single pass and overall Copyright © 2011 by ASME carbon conversion rate is 99.3% (no recycling of fly ash) and the fine particles that are not captured as fly ash by the ceramic filter (after syngas cooling) leave the bottom of the gasifier as vitreous slag. The raw syngas from the gasifier is first cooled to 900 °C by adding a stream of recycled, cooled, ash-free syngas in order to lower the gas temperature below the ash melting point. The raw syngas is then further cooled to 340 °C in syngas coolers that evaporate high pressure (HP) and IP pressure boiler feedwater to produce HP steam for the steam cycle and IP steam to be used in the water-gas-shift process. After passing the dry particulate filters removing the fly ash, a small part of the raw syngas is recycled back (0.84%) for cooling the raw syngas exiting the gasifier. The rest is sent to the wet scrubber for removal of species soluble in water, and trace particulate matter such as unconverted carbon, slag and metals. The quenched and cleaned syngas leaving the scrubber has a temperature and pressure of 165 °C and 43 bara respectively. However, the dry-feed characteristics for the Shell gasifier leaves the raw syngas with a relatively low steam-to-CO ratio thus requiring injection of steam to insure adequate CO to CO2 conversion during the WGS. The IP steam for this purpose is partly supplied from the syngas cooler, but since the requirement is larger than the amount generated in the gasifier the rest is bled from the HP/IP turbine crossover. In order to promote the WGS reaction sufficiently and to avoid carbon formation on the WGS catalyst the steam-to CO ratio has been adjusted to 2.4 (molar basis). passed through a demister before being sent to the acid-gas removal. The total pressure loss of the syngas from the exit of the wet scrubber to the exit of the demister is 9.1%. 4.5 Acid gas removal During gasification, sulphur in the raw coal is converted to H2S and COS. Nevertheless, in the CO2 capture case most of the COS is converted to H2S during the WGS reaction. The H2S and CO2 are removed from the shifted syngas in a two-stage physical absorption system using dimethyl ether of polyethylene glycol also known as Selexol. The syngas enters the first absorption column in which the H2S is removed by a counter current flow of the solvent. The acid gases in the rich solution exiting the bottom of the absorber column is flashed and then stripped off in a regenerator for which heat (approximately 13.6 MWth) is provided from steam bled from the LP steam turbine. The regenerated solvent is cooled and recycled back to the top of the absorber while H2S is sent to a sulphur recovery unit including a Claus plant for oxidizing H2S to elemental sulphur and a Shell Claus off gas treating (SCOT) plant for tail gas cleanup. After leaving the H2S absorber the syngas enters the second absorber for removal of CO2. Similar to the removal of H2S the CO2 is absorbed by the solvent flowing downwards the column and exits the bottom of the column with the CO2 solved in the solution. This collected rich CO2 solvent exiting the bottom of the tower is passed through four flash drums connected in series, where CO2 is released as a result of lowering the pressure. The lean solvent leaving the last flash drum is pumped and returned back to the top of the absorber column. The release of the pressure of the rich solvent between the column and the different flash drums is achieved by hydraulic turbines. In this way part of the solvent pumping power could be recovered. The solubility of CO and H2 in Selexol is low, but not negligible, hence in order to minimize the amount of H2 and CO that are co-absorbed with the CO2 in the absorber and thereby lowering the heating value of the fuel. The gas leaving the first flash drum is recycled back to the absorber column, since virtually all H2 and CO absorbed is released in this drum. The CO2 released in the flash drums two to four is sent to compression. The CO2 removal rate in the AGR unit is 96.3% (molar basis), though, the overall CO2 capture rate as defined in Eq. 4 is 88.6% (molar basis). 4.4 Water-gas-shift The water-gas-shift process is the reaction used to convert most of the CO in the raw syngas into CO2, by shifting the CO with water over a bed of catalyst. Besides CO2 hydrogen is generated in this reaction (Eq.1). In IGCC applications with CO2 capture this is the first step in order to convert the gasifier product into a hydrogen-rich-syngas. The CO converter is located upstream of the AGR unit (sour shift) and is arranged as two reactors in series to meet higher CO2 capture rates. The WGS reaction is exothermic (44 KJ/moleCO) and it is thermodynamically favoured at lower temperatures, where reaction rates are comparatively slow. However, catalyst activity is in general higher at high temperatures. (1) The scrubbed and steam mixed syngas is pre-heated to 250 °C before entering the first stage of the WGS unit. The syngas leaving the first high temperature (HT) reactor is cooled down from the equilibrium temperature of 463 °C to 250 °C by generating HP steam and it then enters the low temperature (LT) WGS reactor. The warm syngas leaving the second reactor at an equilibrium temperature of 278 °C is cooled to 25°C by means of preheating the raw syngas entering the first WGS reactor and by preheating HP boiler feedwater. The resulting overall adiabatic conversion of CO to CO2 and H2 in the WGS process is 98.9% (molar basis). The cooled shifted syngas is (4) In the case when CO2 is vented, the raw syngas leaving the wet scrubber is passed through the demister before entering the H2S absorber. The rich solution leaving the bottom of the column is regenerated and the sulphur is stripped off using IP steam produced in the gasification island. Since this amount is only partly sufficient the rest is extracted from the HRSG. However, since the solvent flow rate in this case is 5 Copyright © 2011 by ASME considerably lower (the flow rate of dry raw syngas is lower than that of dry shifted) the thermal heat input is 3.6 MWth lower than for the case with CO2 capture. The H2S poor syngas exiting the absorber top is passed to the GT combustor. For further technical assumptions for the AGR unit please see Table A3 in Annex 1. according to the results provided by the working group for combustion. Fuel pre-heating has not been included, but will be considered in the optimization of the whole IGGC plant. Turbine model - The turbine part has been modelled using a simplified approach based on the input received. The turbine model used in this work has been assumed with a constant hot gas flow, even though the real turbine is cooled and cooling air is mixed into the hot gas at different stages this was not considered in the existing model. In order to never the less cover the overall performance of the turbine the turbine-, inlet temperature and efficiency are calculated in terms of virtual measures according to following equations: 4.6 CO2 compression The CO2 collected in the flash drums in the CO2 removal process is compressed in a seven-stage intercooled compressor to 60 bara, liquified and then pumped up to final pressure of 150 bara. The compressor/pumping approach has been evaluated in a previous work by the authors and found to be the most efficient approach [27]. (2) 4.7 Gas turbine model The gas turbine model has been modelled based on internal project information exchange with the working group focussing on the GT design (SP3). This information included initial performance calculation results of a lumped turbomachinery model of the GT, Ansaldo Energia 94.3A, with a first version of the compressor map and some turbine data. All information received was based on natural gas as fuel. The control algorithm currently adopted when burning undiluted hydrogen-rich syngas and cleaned syngas is without any major modifications to the natural gas operation: and (3) This has been done to match the data received from the turbomachinery working group. By doing so the general expansion in the turbine (mainly the pressure ratio and therefore also the power consumption in the compressor) as well as the overall power output was met. The technical assumptions for the GT are presented in Table A4 in Annex 1. The above described simplifications are an often used approach in the early stage simulation of a GT process. These models are going to be replaced by more detailed ones as soon as this information will become available. The turbine inlet temperature (TIT) was fixed to 1331 °C. The compressor variable inlet guide vanes (VIGV) are slightly closed to adjust for the increased fuel flow by reducing the air mass flow. Due to the increased fuel flow the model adjusts the pressure ratio accordingly. 4.8 Heat recovery steam generator design Downstream the GT is a three pressure level heat recovery steam generator (HRSG) with reheat. The admission levels have been set according to internal discussions and agreements within SP4. The superheating temperature has been set to 530 °C in order to meet the GT exhaust temperature and the required amount of HP steam needed to be superheated. The heat integration represents somewhat a first approach and has not been optimized. The assumptions of the parameters of the HRSG are considered to be conservative in terms of pressure losses, approach temperatures, steam turbine efficiency, etc. There is potential of increasing the HRSG efficiency in order to maximize the net electrical output, however the economical feasibility of such optimization should not be disregarded. The IP and HP boiler feedwater (BFW) needed in the gasification island is taken from the HRSG and all HP steam is returned back to the HRSG and mixed with the HP steam produced in the WGS and superheated before expanded in the steam turbine. The IP level has been set to meet the pressure of the syngas leaving the wet scrubber 43 bara, since a considerable amount of IP steam is extracted from the HRSG in the case with CO2 capture and mixed with the raw syngas in The GT models used at current state have some limitations for off-design calculations, as only subsections of the compressor- and turbine maps are implemented, there is no detailed modelling of the cooling flows, etc., but will be handled as soon as more information from other teams within the project will be available. Nevertheless, the current model is built up accordingly: Compressor model – In terms of the speed lines, a characteristic has been used which is, according to the authors, reflecting state of the art characteristics Besides, cooling air extraction at different pressure level has not been considered as this information was not available at this time. However extractions are already part of the model and can be activated when needed. It is planned that the characteristic currently in use is going to be replaced as soon as a more detailed version of the compressor map is available. Combustor model – The fuel composition to the combustor was calculated using the detailed models described above (4.1 4.5). Besides, a pressure loss reflecting current state of the art technology was used. This will also be updated later on 6 Copyright © 2011 by ASME Table 2 – Performance results of the IGCC power plant with and without CO2 capture GT power out ST shaft power HRSG pumping power AGR turbine power out AGR pumping/ compr. power req. ASU compression power req. Gasification power req. CO2 compression power req. Net power out Net IGCC efficiency (LHV) IGCC w. 324.07 166.30 3.54 3.42 11.39 40.88 4.96 18.06 414.96 37.40 IGCC w.o. 309.39 211.43 3.13 0.2 37.14 4.50 476.86 47.20 output. Since the HRSG in this study has still not been optimized the genuine improvement using undiluted syngas is to be determined. The initial results have though confirmed that without considering any any modifications of the GT and keeping the efficiency constant, the power output from the engine could increase with as much as 30 MW (compared to the same GT fired with natural gas). The big differences in fuel composition between natural gas, hydrogen-rich syngas and cleaned syngas will most probably result in different designs of the combustion system as well as compressor and turbine to maintain stable combustion and to keep the pressure ratio for the different mass flow ratios in turbine and compressor. The extent of these changes or requirements will be revealed within the project in a near future and will be implemented in the GT model, giving the opportunity to optimise the processes for the various cases. However, Table 3 summarizing the two different fuel compositions directly indicates that two different combustor designs might be essential given the huge differences in the properties, which are difficult to be covered in a single design. The resulting difference in turbine inlet flow due to the huge difference in fuel flow will either require a compressor design with high efficiency over a wider range of IGV positions, or also two different designs. This topic, which is closely connected to transients and operation at off-design, will be addressed during the next steps within the project. The turbine outlet temperature (562°C and 588°C respectively) as well as the turbine flow (700 kg/s and 749 kg/s respectively) is higher for both IGCC cases compared to natural gas (576°C /698 kg/s), which favours the steam bottoming cycle. However, there is an important difference in terms of extraction of BFW and steam along with returning condensate and steam from different parts of the IGCC power plant for the two cases investigated. This will have a major impact on the investment costs if the targeted fuel flexibility ranging from natural gas to cleaned syngas is going to be met. The further optimization of the two cases (with and without CO2 capture) should thus be performed taking into consideration to reduce these distinctions to the greatest extent possible. In addition some aspects of changed conditions for component lifetime need to be evaluated since the lifetime due to the above mentioned increases i.e. the gas temperature of the un-cooled blade rows of the GT under certain operating conditions and could if not designed for have certain negative impacts on plant availability and costs. The current overall CO2 capture rate for the hydrogen rich case is 88.6 mol%, although the removal rate in the AGR unit is approximately 96.3 mol%. The reason for this significant difference is due to CO2 lost in the H2S absorber. The current outline of the AGR unit has not been optimized; hence a minimization of absorbed CO2 in the first stage of the AGR will be further investigated by finding a more convenient combination of number of flashes as well as the extent of solvent pre-loading. Currently there is also a deviation in pressure loss in the H2S absorber for the two cases due to pressure limitations in IPSEpro for pure gaseous streams which MW MW MW MW MW MW MW MW MW % order to perform the WGS reaction. The IP steam produced in the gasifier island has a pressure of 50 bara, thus the BFW extracted for this purpose is pumped to appropriate pressure and heated by utilizing a small part of the heat generated in the HT part of the WGS. The assumptions made for the HRSG calculation are presented in Table A5 (Annex 1). In the case without CO2 capture the HP BFW for the gasification island is extracted in the same manner as in the case with CO2 capture, however all the HP steam produced is returned back to the HRSG and superheated to 500°C. The IP BFW for is extracted similarly as for the CO2 capture case and the small amount IP steam not needed in the gasification island is used for regenerating the solvent in H2S removal unit. Since the IP steam needed in the H2S removal is higher than the amount produced in the gasification island the additional required is bled from the HP/IP crossover. The IP SH/RH temperature has likewise the HP SH temperature for the CO2 venting case been lowered with 30°C to 500 °C to accomplish the superheating of all steam produced in the gasifier as well as the steam no needed for the WGS. All other assumptions for the HRSG are presented in Table A5 in Annex 1. 5 RESULTS AND DISCUSSION The performance of the IGCC power plant with and without CO2 capture based on the calculation using the models as previously described are presented in Table 2 and the composition of the syngas for the two cases are given in Table 3. The IGCC without CO2 capture has a somewhat lower efficiency, even though the syngas in this work is not diluted, than a similar case presented last year by Kreutz et al [17]. The main reason for this is that the reference GT used in this work is less efficient than the General Electric 9 FB even though the TIT was de-rated to 1327°C in the previous work. Nevertheless, the syngas considered was highly pre-heated and the HRSG fully optimized, which are issues within the scope of future activities within this project. The net efficiency of the case with CO2 capture and undiluted hydrogen rich syngas is on the contrary demonstrating a higher efficiency compared to the same publication. This is due to a slightly difference in the steam-to- CO ratio between the present study and the one presented in [17]. In addition the higher heating value of undiluted syngas results in a significantly higher GT power 7 Copyright © 2011 by ASME HP IGCC IP LP mol NOx SOx SOA SP ST TIT WGS wt limits the pressure, to 35 bara, in the case where the syngas is sent for further removal in second stage. This has an impact on the removal of CO2, since physical absorption is favoured at higher partial pressures. Table 3 – Composition (wt%) and characteristics after AGR of the hydrogen-rich and cleaned syngas respectively (undiluted) Hydrogen-rich syngas Cleaned syngas CO 0.0448 0.7857 CO2 0.1078 0.0716 H2 0.3595 0.0262 N2 0.4879 0.1165 Fuel flow (kg/s) 17.67 70.78 LHV (kJ/kg) 43641 11100 Temperature °C 25.6 25.24 Pressure (bara) 34.5 42.4 High pressure Integrated gasification combined cycle Intermediate pressure Low pressure Molar Nitrogen oxide Sulphor oxide State-of-the-art Subproject Steam turbine Turbine inlet temperature Water-gas- shift Weight REFERENCES [1] Dennis, R.A., Shelton, W.W., Le, P., 2007, Development of baseline performance values for turbines in existing IGCC applications. ASME paper GT2007-28096. ASME Turbo Expo, Montreal, Canada. [2] Huth, M., Heilos, A., Gaio, G., Karg, J., 2000, Operation experiences of Siemens IGCC gas turbine using gasification products from coal and refinery residues. ASME paper 2000-GT-26. ASME Turbo Expo, Munich, Germany. [3] Hannemann, F., Koestlin, B., Zimmermann, G., Morehead, H., García Peña, F., 2003, Pushing forward IGCC technology at Siemens. Gasification technology conference, San Francisco, California, USA, [4] Brdar, R.D., Jones, R.M., 2000, GE IGCC technology and experience with advanced gas turbines. General electric report. GER-4207. [5] Oluyede, E.O., Phillips, J.N., 2007, Fundamental impact of firing syngas in gas turbines. ASME paper 2007-27385. ASME Turbo Expo, Montreal, Canada [6] Lee, J.J., Kim, Y.S., Cha, K.S., Kim, T.S., Sohn, J.L., Joo, Y.J., 2009, Influence of system integration options on the performance of an integrated gasification combined cycle power plant. Applied Energy 86, pp. 1788–1796. [7] Kim, Y.S., Lee, J.J., Cha, K.S., Kim, T.S., Sohn, J.L., Joo, Y.J., 2008, Analysis of gas turbine performance in IGCC plants considering compressor operating condition and turbine metal temperature. ASME paper GT2009-59860. ASME Turbo Expo, Orlando, Florida, USA. [8] Pruschek, R., Oeljeklaus, G., Brand, V., Haupt, G., Zimmermann, G., Ribberink, J.S., 1995, Combined cycle power plant with integrated coal gasification, CO shift and CO2 washing. Energy Conversion Management 36(6–9), pp.797–800. [9] Chiesa, P., Consonni, S., 1999 Shift reactors and physical absorption for low- CO2 emission IGCCs. Journal of Engineering for Gas Turbines and Power 121(2), pp. 295–305. 6 CONCLUSIONS As part of the EU-funded H2-IGCC project this work has described the establishment of two fairly conservative baseline IGCC cycles aimed for further investigations. The first IGCC power plant has been modelled with pre-combustion separation of CO2 while the second is without the application of CO2 removal resulting in two completely different syngas compositions. Both IGCC power plants are based on the GT Ansaldo Energia 94.3A without any dilution of the syngas. By performing new gasifier calculations including fly-ash recycle, optimizing the heat integration and implementing the characteristic GT data there is a potential to increase the net efficiencies of both plants beyond current values of 37.4% for the IGCC power plant with CO2 capture and 47.2% for the case with CO2 venting. The overall CO2 capture rate presented in this work, 88.6mol% is somewhat low due to lost of CO2 in the first AGR stage. A more favourable configuration of the H2S removal unit will be further investigated to demonstrate higher capture ratios. ACKNOWLEDGMENTS The authors wish to acknowledge Nuon and E.ON for their technical input and truthful discussions in the early phase of this work. The authors are also grateful to Han Raas at Nuon for performing the gasification simulations. The authors would also like to acknowledge the project partners in SP3 for providing the gas turbine performance data. NOMENCLATURE AGR Acid gas removal ASU Air separation unit BFW Boiler feed water CCS Carbon capture and storage CO2 Carbon dioxide DLE Dry low NOx emission EOS Equation of state GT Gas turbine H2 Hydrogen H2S Hydrogen sulfide 8 Copyright © 2011 by ASME [10] Chiesa, P., Lozza, G., 1999, CO2 emissions abatement in IGCC power: plants part B—with air blown combustion and CO2 physical absorption. Journal of Engineering for Gas Turbines and Power 121(4), pp.642–648. [11] Descamps, C., Bouallou, C., Kanniche, M., 2008, Efficiency of an Integrated Gasification Combined Cycle (IGCC) power plant including CO2 removal. Energy 33, pp. 874–881. [12] Chisea, P., Lozz, G., 1999, CO2 emission abatement in IGCC power plants by semiclosed cycles: Part A — with oxygen-blown combustion. Journal of Engineering for Gas Turbines and Power 121 (4), pp. 635-641. [13] Lozza, G., Romano, M., 2009, Thermodynamic Performance of IGCC with Oxy-combustion CO2 capture. International Conference on Sustainable Fossil Fuels for Future Energy - S4FE2009. Rome, Italy. [14] Ordorica-Garcia, G., Douglas, P., Croiset, E., Zheng, L., 2006, Technoeconomic evaluation of IGCC power plants for CO2 avoidance. Energy Conversion Management 47, pp.2250–2259. [15] Kanniche, M., Bouallou, C., 2007, CO2 capture study in advanced integrated gasification combined cycle. Applied Thermal Engineering 27, pp.2693–2702. [16] Mondol, J.D., McIlveen-Wright, D., Rezvani, S., Huang, Y., Hewitt, N., 2009, Techno-economic evaluation of advanced IGCC lignite coal fuelled power plants with CO2 capture. Fuel 88, pp. 2495– 2506. [17] Kreutz, T., Martelli, E., Carbo, M., Consooni, S., Jansen, D., 2010, Shell Gasifier-Based IGCC with CO2 Capture: Partial Water Quench vs. Novel WaterGas Shift. ASME paper GT2010-22859. ASME Turbo Expo, Glasgow, UK. [18] Gasification Technologies Council (GTC), 2008, Gasification: redefining clean energy. [19] Liu, H., Ni, W., Li, Z., Ma, L., 2008, Strategic thinking on IGCC development in China, Energy Policy 36, pp. 1–11. [20] IEA Greenhouse Gas R&D Programme ( IEA GHG), 2008, Geologic Storage of Carbon Dioxide Staying Safely Underground. [21] CO2CRC, www.CO2CRC.com.au [22] Ninth International Conference on Greenhouse Gas Control Technologies, GHGT 9, Washington D.C., November 2008, Conference Summary. [23] Low emission gas turbine technology for hydrogenrich syngas. Under the 7th Framework Programme FP7-239349. Project website: www.h2-igcc.eu [24] Aspen Plus, 2009. Aspen Plus Version 7.1. Aspen Technology Inc., Cambridge, MA, USA. [25] IPSEpro v.4.0, 2003, Simtech Simulation Technology (Simtech), Graz, Austria. [26] Shell Global Solutions, The Shell Gasification Process For Sustainable Utilisation of Coal. [27] Sipöcz, N., Jonshagen, K., Assadi, M., Genrup, M., 2010, Novel High-Performing Single Pressure Combined Cycle with CO2 Capture. Paper GT201023259, ASME Turbo Expo, Glasgow, UK. ANNEX A TECHNICAL ASSUMPTIONS USED IN THE MODELLING Table A1 – Technical assumptions for the ASU Delivery pressure/temperature of O2 and N2 by ASU 1.2/10 Main air compressor polytropic efficiency 87 GOX compressor polytropic efficiency 87 HP PGAN compressor polytropic efficiency 87 Inter-cooling temperature 40 9 bara/°C % % % °C Copyright © 2011 by ASME Table A2 – Technical assumptions for the Shell gasification island including the syngas conditioning downstream to the wet scrubber exit Dried coal moisture content Gasification pressure/temperature Shifted syngas for drying Steam/coal ratio O2/coal ratio HP PGAN/coal ratio Power requirement Heat loss to membrane wall Carbon conversion (single pass/overall) Syngas cooler pinch-point HP evaporator Syngas cooler pinch-point IP evaporator Heat exchanger heat loss Pressure drop syngas cooler (gas side) Pressure drop wet scrubber Water pump mechanical efficiency Steam-to-CO ratio at WGS inlet 2 45/1600 2.2 0.061 0.7839 0.241 112 2.5 99.3 30 64 0 0.33 1 85 2.4 wt% bara/°C wt% (of total flow) kg / kg coal (ar) kg / kg coal (ar) kg / kg coal (ar) kJel/kg coal (ar) % coal LHV % °C °C % bar bar % Table A3 – Technical assumptions used for the AGR unit CO2 capture No CO2 capture Syngas pressure/temperature at H2S absorber inlet 39.1/25 43.96/25 CO2 co-absorbed in H2S absorber 9.5 8.5 Syngas pressure/temperature at CO2 absorber inlet 35/25.7 Pressure loss in 1st/2nd absorber 4.1/0.5 0.5 H2S stripping duty 13.6 10 H2 co-absorbed (overall) 0.35 0.1 CO co-absorbed (overall) 1.2 0.2 Solvent pumps polytropic efficiency 70 70 Compressor isentropic efficiency (recycle gas) 85 85 Hydraulic expander isentropic efficiency 85 85 Mechanical and electrical efficiency 99 99 Solvent temperature at absorber inlet 25 25 bara/°C wt% (of inlet) bara/°C bar MWth wt% (of inlet) wt% % % % % °C Table A4 – Technical assumptions used for the gas turbine Ambient air pressure 1.013 bara Ambient air temperature 15 °C Moisture in air 60 % TIT 1331 °C GT outlet pressure 1.08 bara (total) Pressure ratio 18.2 (target natural gas) Electrical/mechanical efficiency 99/99.5 % Table A5 – Technical assumptions used for the HRSG HP/IP/LP 140/43/4 bara SH and RH temperature 530* °C SH LP steam 300 °C HP/IP/LP ST isentropic efficiency 88.5/89/91 % ST and generator mechanical efficiency 99.5 % Gas side HRSG pressure drop 0.04 bara Generator electrical efficiency 98.2 % Pump polytropic efficiency 70 % Pump mechanical efficiency 95 % Evaporator pinch point IP/LP 10/10 °C Super heater pinch point 32 °C Economizer pinch point 10 °C Approach point temperature 5 °C Condenser pressure 0.04 bara * The superheating/reheat temperature for the case without CO2 capture is 500°C, all other assumptions are the same. 10 Copyright © 2011 by ASME Paper II An EU initiative for future generation of IGCC power plants using hydrogen-rich syngas: Simulation results for the baseline configuration Mohammad Mansouri Majoumerd, Sudipta De, Mohsen Assadi, Peter Breuhaus Published in Applied Energy, Vol. 99, p. 280-290, June 2012 133 Author's personal copy Applied Energy 99 (2012) 280–290 Contents lists available at SciVerse ScienceDirect Applied Energy journal homepage: www.elsevier.com/locate/apenergy An EU initiative for future generation of IGCC power plants using hydrogen-rich syngas: Simulation results for the baseline configuration Mohammad Mansouri Majoumerd a,⇑, Sudipta De b, Mohsen Assadi a, Peter Breuhaus c a Department of Mechanical and Structural Engineering and Materials Science, University of Stavanger, 4036 Stavanger, Norway Department of Mechanical Engineering, Jadavpur University, Kolkata 700032, India c International Research Institute of Stavanger (IRIS), Postbox 8046, 4068 Stavanger, Norway b h i g h l i g h t s " A baseline IGCC power plant with and without CO2 capture is presented. " Burning of undiluted hydrogen-rich syngas in the gas turbine is assumed. " A significant efficiency penalty is associated with the CO2 capture system. a r t i c l e i n f o Article history: Received 13 February 2012 Received in revised form 23 May 2012 Accepted 25 May 2012 Available online 22 June 2012 Keywords: IGCC CO2 capture Gas turbine H2-rich fuel a b s t r a c t In spite of the rapid development and introduction of renewable and alternative resources, coal still continues to be the most significant fuel to meet the global electricity demand. Emission from existing coal based power plants is, besides others, identified as one of the major sources of anthropogenic carbon dioxide, responsible for climate change. Advanced coal based power plants with acceptable efficiency and low carbon dioxide emission are therefore in sharp focus for current development. The integrated gasification combined cycle (IGCC) power plant with pre-combustion carbon capture is a prospective technology option for this purpose. However, such plants currently have limitations regarding fuel flexibility, performance, etc. In an EU initiative (H2-IGCC project), possible improvements of such plants are being explored. These involve using premix combustion of undiluted hydrogen-rich syngas and improved fuel flexibility without adversely affecting the availability and reliability of the plant and also making minor modifications to existing gas turbines for this purpose. In this paper, detailed thermodynamic models and assumptions of the preliminary configuration of such a plant are reported, with performance analysis based on available practical data and information. The overall efficiency of the IGCC power plant with carbon capture is estimated to 36.3% (LHV). The results confirm the fact that a significant penalty on efficiency is associated with the capture of CO2. This penalty is 21.6% relative to the IGCC without CO2 capture, i.e. 10.0% points. Estimated significant performance indicators as well as comparisons with alternative schemes have been presented. Some possible future developments based on these results and the overall objective of the project are also discussed. Ó 2012 Elsevier Ltd. All rights reserved. 1. Introduction Use of energy is closely related to the development of an economy. Often per capita consumption of energy is considered as an index of the living standard of the people of a country. Though the efficiency of energy usage has a strong impact on energy consumption, the demand for energy is always expected to increase with the growth in population and living standards. The most useful form of energy in the modern world is electricity. Thus the efficient conversion of primary energy to electricity is, besides its ⇑ Corresponding author. Tel.: +47 45 39 19 26; fax: +47 51 83 10 50. E-mail address: [email protected] (M. Mansouri Majoumerd). 0306-2619/$ - see front matter Ó 2012 Elsevier Ltd. All rights reserved. http://dx.doi.org/10.1016/j.apenergy.2012.05.023 efficient use, critical for human civilization [1]. In terms of the economical aspects of available reliable technology, coal is still the major source of electric power [2]. It is also available in different parts of the world, safe to store and easy to transport over a long distance. Thus coal has emerged as the most widely used fossil fuel for large-scale power generation, though natural gas (NG) use is also increasing mostly in localities of availability due to the fact that it is more environmentally friendly [3]. Conventional pulverized fuel (PF) fired thermal power plants have been the most prevalent technology worldwide over a long period. These plants are mostly used for large-scale electricity supply through the grid. Climate change due to anthropogenic greenhouse gas (GHG) emissions is identified as the greatest threat to mankind [4]. The Author's personal copy M. Mansouri Majoumerd et al. / Applied Energy 99 (2012) 280–290 281 Nomenclature AGR Ar ASU a.r. BFW CCS CMD CO COS CO2 DEPG DLN EOS EU GHG GOX GT HHV H2 H2S HP acid gas removal argon air separation unit as received boiler-feed-water carbon capture and sequestration coal milling and drying carbon monoxide carbonyl sulfide carbon dioxide di-methyl ether of polyethylene glycol dry low NOx emission equation-of-state European Union greenhouse gas gaseous oxygen gas turbine higher heating value hydrogen hydrogen sulfide high pressure major source of these GHGs is carbon dioxide emission, and the power sector is identified as the single largest sector contributing to this emission. According to the International Energy Agency, the CO2 emissions from electricity and heat production were about 41% of total global emissions from fossil fuels in the year 2009 [5]. The present challenge for the power sector is to meet the ever increasing demand for electricity and simultaneously mitigate the GHG emissions, principally CO2. Besides drastically increasing the energy efficiency, one possible option is to replace fossil fuel based power plants by renewable sources (say, solar, hydro, biomass, geothermal, etc.). Unfortunately, available technologies for producing electricity from renewable sources are still not wholly mature and/or not installed to the extent to meet the present demand fully in an economic and feasible way. Renewable sources are undoubtedly the only option for the future, but the estimated timescale for the complete transformation from fossil fuels to renewable resources is not definite and is likely to be a significant time away [3]. Thus the development of suitable technology for large-scale power generation using coal during this transition is urgently needed. The major challenge for future generation coal based power plants is to minimize the emissions of CO2 to the atmosphere while maintaining acceptable overall plant efficiency. One way of passively reducing this emission per MW power generation is to continue to further increase the efficiency of conversion. However, incorporating some active measures to reduce CO2 emissions is also necessary if targets for 2050 are to be met. Several routes have been identified for this purpose [6–11]. Capturing CO2 from the exhaust flue gas mixture before it is vented to the atmosphere is known as ‘post combustion carbon capture’. Solutions are usually used to absorb CO2 from the flue gas mixture [12]. Processes based on solids to capture CO2 from the flue gas mixture are described in [13,14]. The small fraction of CO2 in the flue gas, which is mixed with other combustion products and a large fraction of nitrogen from atmospheric air, makes capture difficult. An alternative technology is oxy–fuel combustion. This is to use pure oxygen for the combustion of coal, resulting in mostly CO2 in the exhaust flue gas, which is easier to capture and transport directly for geological storage. Large-scale separation of oxygen from the air, which is an energy-intensive process, is needed and results in high penalties HRSG IGCC IP LHV LP MAC NG NOx PF PGAN RH SCOT SGC SGS SH ST SWGS TIT TEG TOT VIGV heat recovery steam generator integrated gasification combined cycle intermediate pressure lower heating value low pressure main air compressor natural gas nitrogen oxide pulverized fuel pure gaseous nitrogen reheating Shell Claus off-gas treating syngas cooling syngas scrubbing superheating steam turbine sour water–gas shift turbine inlet temperature tri-ethylene glycol turbine outlet temperature variable inlet guide vane on efficiency. Also the gas turbine has to be redesigned for this process [15]. Significant development of this process at the laboratory level is reported in the literature [16,17]. Pre-combustion carbon capture is another good alternative technology [18–21]. Coal is gasified to produce syngas (primarily a mixture of H2 and CO), and the carbon monoxide produced in this process is converted to carbon dioxide by ‘water-shift reaction’ [22]. CO2 is then separated from the syngas before combustion. As CO2 partial pressure is higher in the gas mixture in this pre-combustion process, it is comparatively easier to capture. Also other pollutant gases can be removed in this gas cleaning process before combustion, resulting in minimum emission of pollutants. The resulting hydrogenrich syngas is subsequently used in a combined power plant with high thermodynamic efficiency. Such integrated gasification combined cycle (IGCC) power plants with pre-combustion carbon capture appear to be promising for using coal and meeting the environmental standards [23]. However, the overall plant efficiency is reduced, and complex plants for coal gasification and gas treatment/cleaning may lead to frequent shutdown and reduced reliability. Though high-scale integration may improve the efficiency of the plant during operation [24], it might also reduce the reliability of the power supply, according to the practical experience of operating similar equipment in integrated configurations such as the Buggenum plant operated by Vattenfall. Determining the optimum degree of integration to obtain acceptable efficiency and reliable power supply is, therefore, another objective for future plants. In the H2-IGCC project (refer to Section 2), the overall objective is to enable the stable operating conditions of the gas turbine with combustion of undiluted H2-rich syngas, and to increase the ability to operate on a variety of fuels (such as cleaned syngas, and natural gas), a feature known as ‘fuel flexibility’, without adversely affecting the reliability and availability of the plant. Besides, minor modification of existing GTs is one of the project’s goals. In this paper a detailed thermodynamic model is presented, as well as the performance analysis of the integrated gasification combined cycle power plant based on practical flow-sheet and realistic performance indicators verified by the operators of similar, relevant plants. Further investigations for an optimum configuration, based on the results of this study, are also discussed. Author's personal copy 282 M. Mansouri Majoumerd et al. / Applied Energy 99 (2012) 280–290 2. H2-IGCC project Current technologies for coal gasification and the use of the syngas as fuel in combined cycle power plants suffer from two main limitations. The wide variation of fuel composition (i.e., wide variation of the heating value) causes several difficulties during operation using available gas turbines (GTs). Furthermore, the syngas is rich in H2 due to pre-combustion carbon capture resulting in challenges for using the premix burners. These burners are the stateof-the-art technology for dry low NOx (DLN) combustion in natural gas fuelled GTs. Higher reactivity of H2 compared to that of NG causes problems for using these burners in IGCC plants. Often this problem is overcome by using conventional diffusion burners resulting in high emissions of NOx, besides diluting the fuel with either N2 or water/steam to reduce the effect of the higher adiabatic flame temperature when burning H2-rich fuel. In November 2009 the H2-IGCC project was started with the overall goal to develop and demonstrate technological solutions to overcome the above-mentioned drawbacks while burning H2rich fuels. The developed technology therefore may allow burning undiluted H2-rich syngas with low NOx emissions, comparable with that of the state-of-the-art technologies with NG as fuel. The goal of the project is also to develop an optimized plant layout that will not only maximize efficiency but also allow fuel flexibility as well as reliability of power supply. Both options are also to be explored: with CO2 capture or without since access to CO2 transport, injection and storage infrastructure is not yet guaranteed. Twenty-four different partners including academia and manufacturers as well as plant operators from ten European countries are working together to achieve the above-mentioned goals. Four major research areas are targeted namely combustion, materials, turbomachinery and system analysis. Results of these activities should support: Developing and demonstrating a safe and low emission premixed combustor technology for the undiluted hydrogen-rich syngas from coal gasification with pre-combustion carbon capture. Developing and demonstrating improved materials with advanced coatings for the turbine blades and combustor. The target is to achieve lifetimes similar to those of the latest natural gas fired gas turbines for identical run time in spite of the potentially more aggressive temperature and composition of the exhaust gas. Providing required design for the compressor/expander aerodynamics as well as the cooling of hot gas path components in order to cope with increased mass flow rate, due to the higher fuel flow and changed gas properties of the exhaust gas, which causes changed heat transfer conditions at all surfaces exposed to the hot gas. Evaluating and optimizing the best IGCC plant configuration as well as to provide guidelines for optimized full-scale integration in order to satisfy the above-mentioned requirements. Moreover, a detailed systems analysis will be performed to generate realistic techno-economic results for IGCC plants with pre-combustion carbon capture. The results are to be compared with a natural gas fired plant for benchmarking. 3. System overview In this section the thermodynamic model of the baseline configuration of the IGCC power plant consisting of several sub-systems is described. The detailed model includes many sub-systems with reasonable assumptions based on either commercially available technology or data provided by other subgroups of the project. Significant sub-systems with relevant assumptions and issues are discussed. The thermodynamic model of the baseline IGCC power plant was based on commercially available technologies as follows: Cryogenic air separation unit (ASU); Oxygen-blown, entrained flow coal gasifier based on Shell technology; Sour water–gas shift (SWGS) Carbonyl sulfide (COS) hydrolysis unit for the case when no capture of CO2 took place; Acid gas removal (AGR) unit using physical absorption by SELEXOLTM system; CO2 compression and dehydration unit; and power generation block consisting of a 300 MW single-shaft gas turbine based on the Siemens/Ansaldo Energia 94.3A technology and a conventional triple-pressure bottoming steam cycle. Theoretical description and integration methods of similar subsystems have been addressed by several studies [21,22,25–31]. Therefore, in this study special emphasis is placed on a practical plant (Fig. 1) to estimate realistic performance indicators, verified by project team members with relevant plant operating experiences. The specifications of each sub-system as well as assumptions and boundary conditions are described in the following sub-sections. 3.1. Coal feed The assumed coal was a bituminous coal which was a mixture of various trade coals on the world market. The composition of the coal (wt.% a.r.) is summarized in Table 1. The amount of coal required was determined by the thermal power demand of the gas turbine which was within the range of 1005–1112 MWLHV. 3.2. Air separation unit (ASU) The cryogenic air separation process, which is currently the most reliable technology for large-scale production of oxygen and nitrogen [25], was considered as a stand-alone unit. The purity of oxygen was set to 95 mol% (2% N2 and 3% Ar) as obtained from the techno-economic evaluation of such units utilized in real plants. Ambient air was initially compressed by the main air compressor (MAC). Although integration of the ASU and the GT would lead to a higher efficiency, the most appropriate degree of integration needs to be decided. Better operational safety and greater availability of the plant would be the result of low or no integration [26]. Experience from the real IGCC plant in Buggenum promoted a non-integrated approach for improved plant availability [27]. The MAC was a three-stage intercooled compressor with a discharge pressure of 5.5 bar. The delivery pressures of the pure gaseous nitrogen (PGAN) and gaseous oxygen (GOX) from the MAC were 5 and 1.2 bar, respectively. The discharge pressure of the PGAN which was used for coal feeding to the gasifier was 80 bar, while the gaseous oxygen (GOX) was compressed further up to 55 bar and fed to the gasifier. Both compressors for the GOX and the PGAN were six-stage intercooled compressors. It is worth noting that the lower number of inter-cooled stages used here compared to other studies, as well as the lower component efficiencies, represent ‘‘common practices’’ in the currently existing power plants. Further technical assumptions for the ASU are shown in Table 2 below. Author's personal copy M. Mansouri Majoumerd et al. / Applied Energy 99 (2012) 280–290 283 Fig. 1. The schematic configuration of the IGCC power plant with carbon capture. Table 1 Composition (% by weight) and heating values of the bituminous coal. C H N O S Cl F 64.10 3.90 0.70 7.21 1.50 0.09 20 ppm Moisture Ash 10 12.50 HHV LHV kJ/kg 26,195 25,100 Table 2 General assumptions for the ASU. Delivery pressure/temperature of O2 by ASU (bar/°C) Delivery pressure/temperature of N2 by ASU (bar/°C) Main air compressor polytropic efficiency (%) GOX compressor polytropic efficiency (%) HP PGAN compressor polytropic efficiency (%) Inter-cooling temperature (°C) 1.2/10 5.0/10 85 78 78 40 3.3. Gasification, syngas cooling and scrubbing Gasification of coal took place in the Shell gasifier [28]. The milled and dried coal was gasified in the presence of intermediate pressure (IP) steam and oxygen. The gasifier was of single pass type, and the remaining fine particles that were not captured by the ceramic filters as fly ash left the bottom of the gasifier as vitreous slag. One of the major sources of inaccuracies in theoretical studies presented in open literature is due to the non-realistic model of the gasification unit. The gasification plant model used in this study was based on the existing plant in Buggenum [27], and the gas analysis obtained from the model was validated against real plant data. The raw syngas was first cooled to 900 °C by recycling the cooled, ash-free syngas stream and then further cooled to 340 °C in syngas coolers by generating high pressure (HP) and intermediate pressure (IP) steams, as shown in Fig. 1. After passing through the dry particulate filters and recycling a part of the syngas stream for the aforementioned cooling purpose, the rest of the syngas was sent to the wet scrubber. The quenched and cleaned syngas entering the SWGS unit had a temperature and pressure of 165 °C and 43 bar, respectively. Further technical assumptions and results are presented in Table 3 below. The syngas composition at the inlet of SWGS unit is presented in Table 4. 3.4. Sour water–gas shift The water–gas shift process was a catalytic reaction converting the CO of the raw syngas to CO2 (Eq. (1)). This was prior to acid gas removal and was therefore termed as sour water–gas shift. This reaction was carried out in two sequential reactors. kJ ð44moleÞ COðgÞ þ H2 OðgÞ $ CO2ðgÞ þ H2ð gÞ ð1Þ The dry-feed characteristics of the Shell gasifier required the injection of a considerable amount of steam to ensure adequate CO to CO2 conversion rate during the SWGS. In order to protect Author's personal copy 284 M. Mansouri Majoumerd et al. / Applied Energy 99 (2012) 280–290 Table 3 General assumptions for the Shell gasification block including the syngas conditioning downstream to the wet scrubber. Dried coal moisture content (wt.%) Gasification pressure/temperature (bar/°C) Steam/coal ratio (kg/kg coal a.r.) O2/coal ratio (kg/kg coal a.r.) HP PGAN/coal ratio (kg/kg coal a.r.) Power requirement (kJel/kg coal a.r.) Heat loss to membrane wall (% coal LHV) Carbon conversion (single pass/overall) (%) Syngas cooler pinch-point HP evaporator (°C) Syngas cooler pinch-point IP evaporator (°C) Heat exchanger heat loss (%) Pressure drop syngas cooler (gas side) (bar) Pressure drop wet scrubber (bar) Water pump mechanical efficiency (%) Shifted-desulfurized syngas for CMD in the case with CCS (% of total flow) Shifted-desulfurized syngas for CMD in case of CCS unit trip (% of total flow) 2 45/ 1600 0.061 0.7839 0.241 112 2.5 99.3 30 64 0 0.33 1 85 1.7 1.5 Table 4 Syngas composition (mole fraction) at the inlet of SWGS unit. Components Raw syngas CO CO2 H2 H2O N2 H2S COS (ppmv) NH3 (ppmv) 0.4895 0.0305 0.2268 0.1751 0.0739 0.0042 341 87 the catalytic bed from carbon deposition as well as to increase the equilibrium conversion of CO and steam to H2 and CO2, the steamto-CO ratio was set to 2.4. The IP steam for this purpose was partly supplied from the syngas cooler and the rest was provided from the HP/IP steam turbine crossover. The inlet temperatures of both reactors were set to 250 °C. The high temperature syngas leaving the first reactor was quenched by saturating HP and IP boilerfeed-water (BFW) flows, while the warm syngas leaving the second reactor was cooled by preheating the raw syngas entering the first reactor and preheating HP and IP BFWs and generating low-pressure (LP) steam. The resulting overall adiabatic conversion of CO to CO2 in the SWGS process was 98% (molar basis). The total pressure loss of the syngas from the exit of the wet scrubber to the exit of the demister was 7.7%. It is worth noting that one of the advantages of this unit is the simultaneous conversion of carbonyl sulfide (COS) to hydrogen sulfide (Eq. (2)) [29] with shift reaction. COSðgÞ þ H2 OðgÞ $ 3.6. Acid gas removal (AGR) unit During the gasification process, the sulfur content in the raw coal was converted to H2S and COS. However, most of the COS (more than 98%) was converted to H2S during the SWGS reaction. The pressure of the system, which was dictated by the gasification process, resulted in high partial pressure of CO2 (around 15.5 bar). Therefore, two-stage physical absorption of acid gases, using dimethyl ether of polyethylene glycol (DEPG) also known as SELEXOL, was favorable for the AGR unit. High stability, high absorption capacity as well as low corrosive effect, are the favorable features of SELEXOL. H2S was removed from the shifted gas in the first stage. The rich solvent exited at the bottom of the absorber column. Since the concentration of CO2 in the syngas leaving the SWGS unit was high, and the order of magnitude of solubility of H2S and CO2 in SELEXOL was similar, a considerable amount of CO2 content was co-absorbed with H2S [31]. Having the appropriate content of H2S (more than 35% molar basis) in the inlet stream of the Claus unit, which was used to oxidize H2S to elemental sulfur, a concentrator unit was considered after the H2S absorber tower. A part of the fuel gas (2.5%) produced in the AGR unit was recycled back to the concentrator column as a stripping agent. The rich solution exiting at the bottom of the concentrator column was then stripped off in a regenerator for which heat was provided by the LP steam generated in the SWGS unit. The regenerated solvent was cooled to 5 °C and recycled back to the H2S absorber. The separated H2S was sent to a sulfur recovery unit including a Claus plant and a Shell Claus off-gas treating (SCOT) plant for tail gas clean-up. In the case of running the gas turbine with cleaned syngas (i.e. CCS unit trip and without the SWGS unit) the H2S concentrator column was bypassed, since the concentration of CO2 was low in the syngas leaving the COS hydrolysis unit. Fig. 2 illustrates the configuration of IGCC power plant without carbon capture unit. Syngas leaving the H2S absorber, after extraction of a small part of it for coal drying purpose, entered the second stage for CO2 removal. The removal process was similar to that in the first stage. The rich CO2 solvent was passed through four flash drums connected in series, where CO2 was released as a result of lowering the pressure. The lean solvent leaving the last flash drum was cooled to 5 °C to increase the absorption efficiency. However, this cooling increased the inherent loss of energy [29]. The cooled solvent was then re-circulated back to the absorber tower. The gas leaving the first flash drum was recycled back to the absorber tower. The CO2 released in flash drums two to four was sent for compression. The CO2 removal rate in the AGR unit was 93.65% (molar basis), while the overall CO2 capture rate as defined in Eq. (3) was 89.80% (molar basis). Capture rate ¼ kJ ð33:6moleÞ syngas, LP steam generation, and IP BFW saturation. The conversion of COS to H2S in this reaction was 99.8% (molar basis). H2ð gÞ þ CO2ðgÞ ð2Þ 3.5. Carbonyl sulfide hydrolysis unit In order to remove more than 99.99% of the sulfur content in the produced syngas, it was necessary to add a COS hydrolysis unit to convert COS to H2S in the case of CCS unit trip (Fig. 2), according to Eq. (2) [30]. In this case, the scrubbed syngas was preheated to 220 °C before entering the COS hydrolysis reactor. The syngas leaving this reactor was cooled down by preheating the scrubbed CO2sent to compression þ C A þ C S 100 CF ð3Þ where CA, CS, and CF are carbon content in fly ash, slag, and feed coal, respectively. The solidification of fly ash and slag took place in the plant and this was the reason for the relocation of these two terms from denominator to numerator in the above equation (Eq. (3)). For cases when CO2 was not captured, the syngas leaving the COS hydrolysis unit and the demister entered the H2S absorber. The rich solution leaving the bottom of the tower was regenerated and the sulfur was stripped off using LP steam produced after the COS hydrolyser unit. The H2S-free hydrogen-rich syngas exiting at the top of the absorber was passed to the GT combustor. The Author's personal copy M. Mansouri Majoumerd et al. / Applied Energy 99 (2012) 280–290 285 Fig. 2. The schematic configuration of the IGCC power plant without carbon capture. Table 5 General assumptions and results of both AGR units with and without CO2 capture. Syngas pressure/temperature at H2S absorber inlet (bar/°C) Solvent pumps polytropic efficiency (%) Compressor isentropic efficiency (recycle gas) (%) Mechanical and electrical efficiencies (%) Coefficient of performance for refrigeration pump Solvent temperature at absorber inlet (°C) Pressure loss in 1st/2nd absorber (bar) H2S stripping duty (MWth) H2S removal efficiency (%) CO2 co-absorbed in H2S absorber (mol% of inlet) Overall H2 co-absorption (mol% of inlet) Overall CO co-absorption (mol% of inlet) CO2 removal efficiency(mol% of inlet) CO2 capture Without CO2 capture 39.7/ 25 70 85 98 2.2 5 0.5/0.5 44.7 99.99 1.32 2.19 3.26 93.65 39.7/25 70 85 98 2.2 5 0.5/– 22.0 99.99 12.62 0.02 0.06 12.62 general assumptions and results of the AGR units for both cases, i.e. with and without CCS, are presented in Table 5 below. 3.7. CO2 compression The CO2 released from the last three flash drums in the CO2 separation process was compressed in a seven-stage intercooled compressor to 60 bar, liquefied and then pumped up to a final pressure of 150 bar. In order to reduce the corrosion risk in the transport pipeline, a dehydration unit using tri-ethylene glycol (TEG) was considered. The upper limit of 20 ppm (mass basis) for water con- tent in the CO2 stream was specified according to Ref. [32]. The compressor isentropic efficiency and pump polytropic efficiency have set to 80% and 70%, respectively. 3.8. Gas turbine model The gas turbine was modeled using internal project information exchange focusing on turbomachinery. This information included initial performance calculation results of a lumped turbomachinery model of the GT, Ansaldo Energia 94.3A, the compressor map and some turbine data. All information used was based on a natural gas fuelled engine. The control algorithm for burning undiluted H2-rich syngas and cleaned syngas was without any major modifications, i.e. the same as for natural gas operation. The turbine inlet temperature (TIT) was fixed and set to 1331 °C, and the model adjusted the pressure ratio due to the increased fuel flow. The current GT model was built up accordingly: Compressor model: The generated compressor characteristics using a lumped GT model were implemented with variable inlet guide vane (VIGV) opening positions for ISO condition (i.e., 15 °C, 1.01325 bar, 60% relative humidity). Combustor model: The composition of fuel to the combustor was calculated using the models described above (Sections 3.2– 3.6). Furthermore, a pressure loss reflecting current state-of-theart technology for dry low NOx combustors was used. Turbine model: A simplified expander model was used, assuming a constant flow through the turbine. The influence of cooling air entering the turbine at different rows was considered, using a virtual/mixed turbine inlet temperature as well as virtual mixed polytropic efficiency according to the following equations: Author's personal copy 286 T t mixed i ¼ M. Mansouri Majoumerd et al. / Applied Energy 99 (2012) 280–290 Pshaft þ T to _ total cp m ð4Þ and gt polytropic mixed ¼ C p lnðT tmixed i =T to Þ RD lnðpti =pto Þ ð5Þ _ is mass flow rate, cp is specific where T is temperature, P is power, m heat, g is efficiency, R is gas constant, p is pressure, and subscriptions i, o, and t are expander inlet, expander outlet and total condition, respectively. The general assumptions for the GT including NG operating conditions are listed in Table 6 below. 3.9. Heat recovery steam generator Downstream of the GT was a three-pressure heat recovery steam generator (HRSG) with reheat. The superheating (SH) temperature was set to 530 °C in order to meet both the GT exhaust temperature and the required amount of HP steam needed to be superheated. Potential exists for further increasing the HRSG effectiveness in order to maximize the net electrical output. However, the economic feasibility of such optimization should not be disregarded. The IP level was set to meet the pressure of the syngas leaving the wet scrubber, i.e. 43 bar, since a considerable amount of IP steam was extracted from the HRSG and mixed with the raw syngas in order to perform the SWGS reaction. For the case without CO2 capture, the required amount of IP steam is considerably lower compared to the cycle with CCS, due to the bypassing of SWGS unit. The HP superheating temperature was lowered to 500 °C to accomplish the superheating of the entire steam produced in the gasifier as well as the extra IP steam which is not required in the process. The general assumptions made for the HRSG calculation are listed in Table 7. Table 6 General assumptions used for the gas turbine. Ambient air pressure (bar) Ambient air temperature (°C) Moisture in air (%) TIT (°C) GT outlet pressure (bar (total)) Pressure ratio Electrical/mechanical efficiency (%) NG mass flow (kg/s) GT power output fuelled with NG (MW) Turbine outlet temperature (NG fuelled) (°C) 1.013 15 60 1331 1.08 18.2 99/99.5 14.88 292 577 4. Simulation tools To obtain reliable results and to utilize the possibility of incorporating detailed component characteristics later, a combination of the following simulation tools was used for modeling the IGCC power plant: Enssim: Simulation tool developed by Enssim Software [33]; ASPEN Plus: Commercial process engineering software by AspenTech [34]; and IPSEpro: Commercial heat and mass balance programme by SimTech [35]. Data exchange between software tools was performed manually to find the optimal match. The main reason for utilizing three software tools was the specific capabilities of each tool to model a certain sub-system. To simulate each aforementioned sub-system (Section 3.1), the relevant one of these three software tools was used as described below. Detailed modeling of the Shell gasification process, including components such as coal milling and drying (CMD), gasification, raw syngas cooling (SGC) and scrubbing (SGS), was performed by Vattenfall (Nuon) using the Enssim modeling tool. It is worth noting that the gasification model was validated against real plant operational data. The air separation unit (ASU) was modeled using ASPEN Plus. The Peng-Robinson properties method was selected as the equation-of-state (PR EOS). The sour water–gas shift (SWGS) reaction was modeled in ASPEN Plus using PR EOS. The acid gas removal (AGR) unit was modeled in ASPEN Plus. Two different equations-of-state, i.e., Peng-Robinson and Perturbed-Chain Statistical Associating Fluid Theory (PC-SAFT), were used for simulation. However, based on a benchmarking study with one of the industrial partners, the simulation using PC-SAFT equation-of-state was selected. For cases without CO2 capture, the carbonyl sulfide (COS) hydrolysis unit and H2S removal (i.e. AGR unit) was modeled in ASPEN Plus using PR EOS and PC-SAFT EOS, respectively. The compression of captured CO2 and dehydration of CO2 stream was modeled in ASPEN Plus using PR EOS, and Schwarzentruber and Renon (SR polar) equation-of-state, respectively. The power block including the GT, and the triple-pressure steam cycle were modeled in IPSEpro. 5. Results and discussion Table 7 General assumptions used for the HRSG. HP/IP/LP (bar) SH and RH temperature (°C) SH LP steam (°C) HP/IP/LP ST isentropic efficiency (%) ST and generator mechanical efficiency (%) Gas side HRSG pressure drop (bar) Condenser pressure (bar) Generator electrical efficiency (%) Pump polytropic efficiency (%) Pump mechanical efficiency (%) Evaporator pinch point IP/LP (°C) Super heater pinch point (°C) Economizer pinch point (°C) Approach point temperature (°C) 140/43/4 530a 300 88.5/89/91 99.5 0.04 0.04 98.2 70 95 10/10 32 10 5 a The superheating/reheating temperature for the case without CO2 capture is 500 °C; all other assumptions are the same. The overall objective of the H2-IGCC project is to enable the premix combustion of undiluted H2-rich syngas in IGCC power plants. Developing an optimized plant layout that not only maximizes efficiency but also increases fuel flexibility by enabling the burning of cleaned syngas with variable composition is another goal. The system analysis research group aims to evaluate and optimize the IGCC plant configuration. As an initial step toward optimizing the configuration of the plant, this group has established a realistic baseline process layout. A detailed thermodynamic model using a combination of three simulation tools is presented in this paper. Performance analysis of the IGCC plant based on practical flowsheet and realistic performance indicators is reported in this paper. Simulation results of the baseline IGCC plant for two different cases, i.e. with or without CO2 capture (referred to here as Case A and Case B, respectively), based on calculations using models as described in Sections 3 and 4 are presented. Estimated Author's personal copy 287 M. Mansouri Majoumerd et al. / Applied Energy 99 (2012) 280–290 Table 8 Syngas composition (mole fraction) and characteristics prior to the GT burner. Components H2-rich syngas Cleaned syngas CO CO2 H2 H2O N2 Pressure (bar) Temperature (°C) LHV (kJ/kg) HHV (kJ/kg) Mass flow (kg/s) Mole flow (kmole/s) 0.0117 0.0403 0.8583 0.0004 0.0893 38.71 30.0 33255.55 39211.07 23.30 3.67 0.5984 0.0334 0.2774 0.0005 0.0904 39.21 30.0 11084.33 11656.48 70.92 3.33 performance indicators as well as specific CO2 emissions in both cases are also reported. Performance indicators such as gas and steam turbine power outputs, auxiliary power demands, and efficiencies of processes were validated against the results of feasibility studies conducted by industrial partners of the project and the results of published literature. The syngas compositions for both cases are also reported. These compositions were validated against published data. Some adverse effects of fuel change and the possible measures for those are also briefly discussed. The composition and other properties of the corresponding fuel gas in the two cases in this study, i.e. H2-rich syngas (Case A) and cleaned syngas (Case B) prior to the gas turbine burner, are presented in Table 8. Estimated performance parameters of this simulation for Cases A and B together with corresponding operating conditions (points in Figs. 1 and 2) are shown in Table 9. The gas turbine power outputs in both cases are higher than the power output of the NG fuelled GT (referred to here as Case C, see Table 6) which is approximately 292 MW [36]. This is due to greater hot gas flow in Cases A and B than the Case C. It is worth noting that the current GT model in all cases was using the compressor map based on NG as the fuel, and the component efficiencies were kept constant. The steam turbine power outputs for Cases A and B show a significant difference. IP steam consumption decreases in the absence of SWGS for Case B. This additional IP steam expands in the steam turbine to increase power output of the steam turbine by 39 MW. Higher integration of the HRSG and the SWGS in Case A results in 12.4% increase of the HRSG pumping power demand compared to Case B. Simulation results confirm that the highest auxiliary power consumption is in the ASU for both cases (refer to Fig. 3). Solvent flow in the AGR unit for Case A is higher due to CO2 capture. This causes approximately 8.5 MW higher power demand for solvent circulation. Moreover, the higher solvent flow needs 6.8 MW more power for its refrigeration. The total power demands for pumping, compression and refrigeration for H2S removal in both cases are relatively small. These power demands are 7.65 MW and 3.61 MW (about 0.36% and 0.69% of the respective gross thermal Table 9 Performance results and operating conditions of the IGCC power plant with and without CO2 capture (Fig. 1 and 2). Point # IGCC plant with CCS (Case A) IGCC plant without CCS (Case B) T (°C) P (bar) _ (kg/s) m T (°C) P (bar) _ m(kg/s) 15.0 15.0 125.8 98.4 164.7 250.0 276.7 25.0 12.4 12.4 33.8 30.0 15.0 419.8 1331.0 563.3 530.0 530.0 241.6 29.1 314.0 338.1 337.0 30.1 31.3 104.8 1.01 1.01 55.00 80.00 43.00 41.72 40.48 39.71 39.21 39.21 150.00 38.71 1.01 19.02 19.02 1.08 140.00 43.00 4.00 0.04 43.00 143.00 140.00 50.00 141.00 1.04 150.09 44.31 36.74 10.68 95.71 177.69 177.69 120.62 119.13 2.00 93.19 23.30 683.01 614.71 638.22 706.52 145.62 95.47 114.67 114.67 78.39 35.52 130.82 21.62 95.30 706.52 15.0 15.0 125.8 98.4 164.7 220.0 220.4 25.0 9.2 9.2 4.4 30.0 15.0 424.7 1331.0 583.3 500.0 500.0 206.7 29.1 263.2 338.1 337.0 257.4 329.8 66.5 1.01 1.01 55.00 80.00 43.00 42.50 42.00 39.71 39.21 39.21 39.71 39.21 1.01 19.48 19.48 1.08 140.00 43.00 4.00 0.04 50.00 143.00 140.00 50.00 43.00 1.04 136.74 40.11 33.26 9.67 86.64 86.63 86.63 73.47 72.03 1.11 121.92 70.92 682.96 607.84 678.76 753.89 118.62 153.98 150.51 150.51 3.25 118.42 118.42 19.61 118.62 753.89 Performance indicators Case A Case B GT power output (MWe) ST power output (MWe) HRSG pumping power demand (MWe) AGR pumping and compression power demand (MWe) AGR refrigeration power demand (MWe) ASU compression power demand (MWe) CO2 compression power demand (MWe) Gasification power demand (MWe) Net power out (MWe) Net IGCC efficiency (% LHV) Overall CO2 capture (%) Specific CO2 emissions (g CO2/kWh) 329.22 172.91 3.53 9.12 9.78 50.02 20.83 4.96 403.89 36.32 89.80 78.57 311.27 211.95 3.14 0.66 2.95 45.45 0.00 4.48 466.53 46.34 0.00 716.01 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 Author's personal copy 288 M. Mansouri Majoumerd et al. / Applied Energy 99 (2012) 280–290 Fig. 3. The shares of auxiliary power consumptions for both cases (IGCC with and without carbon capture). Table 10 The main specification and performance results of published studies. Sub-system/performance indicators Kreutz et al. [38] Kanniche et al. [32,37] Chiesa and Consonni [22] Present study Gasifier Shell technology O2 blown, dry fed based on PRENFLO technology 27 bar 100% integration with GT Sweet SELEXOLTM 150 bar to storage 85% Capture Siemens V 94.3 O2 blown, slurry fed based on Texaco 60 bar Non-integrated Sour SELEXOLTM 80 bar to storage 91.7%% Capture Generic F technology Shell technology Diluted with steam for IGCC without CCS Diluted with N2 and steam Pre-heating (125 °C) Triple pressure level Triple pressure level 47.7% 43.9% 45.9% Triple pressure level 46.3% 36.6% 29.9% 38.8% 36.3% ASU WGS type CO2 capture system GT technology 38.5 bar N2 for dilution Sour SELEXOLTM 150 bar to storage 93% Capture GE 9FB Diluted with N2 and small amount of steam HRSG Overall efficiency of IGCC without carbon capture Overall efficiency of IGCC with carbon capture Pre-heating (350 °C for IGCC w/o CO2 capture & 200 °C for IGCC plus capture) Triple pressure level inputs) for Cases A and B, respectively. The total power demand for CO2 capture and compression for Case A is approximately 32.1 MW, which is about 2.88% of the gross thermal input for that case. The net IGCC efficiency is 10% (absolute value) or 21.6% (relative value) less for Case A than for Case B. This significant efficiency penalty for capturing CO2 is due to the auxiliary power demand of the SWGS unit and the CO2 capture and compression units. However, this loss in efficiency may be justified in future IGCC plants by more stringent environmental regulations for CO2 emissions. Simulation results of some configurations of IGCC plants are reported by other authors [22,32,37,38]. A brief comparison of the results of this work with a few others available in literature is described and discussed in the following. The similarities and deviations in results are explained for the validation of the present work as well as to gain insight for future improvements. Table 10 shows a brief comparison of the specifications of sub-systems and some performance parameters of this study with some others available in literature. Even though the syngas used in this work is not diluted with N2 as assumed by Kreutz et al. [38], Case B of this study has about 1% lower efficiency. The cleaned syngas fuel was strongly (up to 350 °C) pre-heated before the combustor and the HRSG were fully optimized in Kreutz’s study. However, the net efficiency for Case A is closer to that reported by them. Some factors 43 bar Non-integrated Sour SELEXOLTM 150 bar to storage 89.8% Capture Siemens/Ansaldo Energia 94.3A Undiluted fuel Saturation with steam have had increasing effects on the reported efficiency in the present study compared to Ref. [38]. These factors include: (a) Higher power output from the GT due to using undiluted syngas; (b) lower steam-to-CO ratio in the SWGS, which results in lower steam consumption and higher steam bottoming power; (c) lower CO2 capture rate which implies lower loss; and (d) lower power demand in gasification block. On the contrary, the lower optimization/integration level of the HRSG in the current study is likely to cancel the increasing effects of the aforementioned factors. The differences in efficiencies are not significant when being compared with the overall plant efficiency. In another study, although full integration between the GT and ASU was considered (i.e. 100% of the air feeding the ASU is extracted from the GT), lower net efficiency (LHV basis) in both cases (6.4% for Case A and 2.4% for Case B) has been reported by Kanniche et al. [32,37]. The steam injection into the GT for controlling NOx formation results in an efficiency penalty in both cases. Having a similar low heating value compared to that produced in Case B, the dilution with N2 in Case A has been considered, which results in efficiency reduction. Also, the lower pressure of the gasification block (27 bar) results in lower carbon capture efficiency and a higher energy penalty in the CCS unit. However, lower carbon capture efficiency results in lower steam injection into the SWGS and a lower penalty for the bottoming cycle. Another study conducted by Chiesa and Consonni [22] reported Author's personal copy M. Mansouri Majoumerd et al. / Applied Energy 99 (2012) 280–290 a net efficiency of about 45.9% for Case B which shows similar values to this study. On the contrary, the net efficiency of Case A in Chiesa’s study is approximately 2.5% higher compared to this study. One reason is the utilization of the hydraulic expander for recovery of solvent pumping power from CO2-rich solvent before first flash drum in the AGR unit. Using a slurry fed gasifier at higher pressure (60 bar), which results in lower injection of IP steam to the SWGS is also another reason for this efficiency difference. The scientific literature confirms that the composition of the cleaned syngas based on Shell technology shown in Table 8 is within the range of those obtained from commercial gasifiers [30,39]. The similar lower heating value of H2-rich syngas in the current study and that of Ref. [22] (33.255 MJ/kg and 34.663 MJ/kg, respectively) shows a good agreement for every sub-system upstream of the GT. Even though in the study conducted by Zheng and Furinsky [30], the higher O2-to-coal ratio (0.9 instead of 0.78 in this study) and the higher O2 content in the coal result in lower CO in the cleaned syngas, the higher gasification temperature employed in Zheng and Furnisky’s study (2000 °C instead of 1600 °C in this study) led to similar CO and CO2 contents in both studies. Due to the lower H2 content in cleaned syngas (Table 8), this fuel has lower HHV and LHV compared to H2-rich syngas. The big difference in composition, especially in H2 content, will certainly demand different combustor designs to maintain stable combustion. In addition, the large difference in the cleaned syngas flow compared to the H2rich fuelled GT (70.9 kg/s compared to 23.3 kg/s), leads to the higher turbine inlet flow and consequently higher back pressure. Closing the variable inlet guide vane (VIGV) of the compressor will solve this problem to some extent. However, keeping a reasonable surge margin in the compressor and an acceptable efficiency over a wider range of VIGV positions will require compressor modifications. The turbine outlet temperature (TOT) is higher (583 °C) for Case B compared to Cases A (563 °C) and C (577 °C), which favor the steam bottoming cycle. However, the higher TOT for the cleaned syngas fuelled GT than that of the NG fuelled one raises one critical design concern, i.e. the lifetime of turbine components. It may lead to a considerable reduction in the lifetime, especially of the last and penultimate (un-cooled) stage blades of the turbine. This problem may be solved in several ways, such as by modification of the compressor and/or expander flow path, by blowing off a part of the compressed air and by modification of the operating condition (i.e. different TIT and VIGV position). Some changes in the design of the combustor and turbomachinery block are inevitable in order to accommodate the switching of fuels (say, from H2rich syngas to cleaned syngas) and the associated problems of the reduced lifetime of turbine blades. These may evolve with the future progress of the project. 6. Conclusion The overall objective of the H2-IGCC project is to enable the premix combustion of undiluted H2-rich syngas in IGCC power plants with carbon capture. The object of the system analysis group of the project is to evaluate and optimize the IGCC plant configuration. As an initial step, simulation of a baseline configuration with a detailed thermodynamic model, using realistic assumptions and internal information from other partners of the project, is reported in this paper. This simulation will set the framework for technoeconomic analysis in the next step for the commercial feasibility assessment of the concept. The estimated overall efficiency of the IGCC power plant without carbon capture is 46.3%. For the plant with carbon capture, the figure is 36.3%. This confirms the fact that a significant penalty on efficiency is associated with the capture of CO2. This penalty is 21.6% relative to the IGCC without CO2 capture. However, stricter 289 environmental regulations regarding CO2 emissions as well as the requirement for a secured energy supply and the lack of mature alternatives may justify the IGCC technology with CCS in future. Through comparison with other published studies, more integration of sub-systems indicated some potential for better efficiency but with lesser reliability. Using undiluted syngas in the GT improves GT power significantly. However, some challenges related to the unstable operating condition of the GT combustor and compressor as well as reduced lifetime of the blades of the existing gas turbines when using undiluted H2-rich syngas have to be addressed. Thus optimization of the plant needs more investigation. This study identifies these areas for future investigation and sets the framework for techno-economic analysis in the next step of optimization involving commercial feasibility. 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Paper III Estimation of performance variation of future generation IGCC with coal quality and gasification process – Simulation results of EU H2-IGCC project Mohammad Mansouri Majoumerd, Han Raas, Sudipta De, Mohsen Assadi Published in Applied Energy, Vol. 113, p. 452-462, August 2013 147 Author's personal copy Applied Energy 113 (2014) 452–462 Contents lists available at ScienceDirect Applied Energy journal homepage: www.elsevier.com/locate/apenergy Estimation of performance variation of future generation IGCC with coal quality and gasification process – Simulation results of EU H2-IGCC project Mohammad Mansouri Majoumerd a,⇑, Han Raas b, Sudipta De c, Mohsen Assadi a a b c Faculty of Science and Technology, University of Stavanger, 4036 Stavanger, Norway Asset Development Division, Vattenfall, Westervoortsedijk 73, 6827 AV Arnhem, The Netherlands Department of Mechanical Engineering, Jadavpur University, Kolkata 700 032, India h i g h l i g h t s Coal quality effects on the performance of four commercial gasifiers are reported. The overall IGCC performance indicators using various coals are presented. Dry-fed gasifiers are relatively insensitive to the coal quality. Slurry-fed gasifiers are not suitable for the gasification of low-rank coals. a r t i c l e i n f o Article history: Received 14 January 2013 Received in revised form 17 June 2013 Accepted 21 July 2013 Available online 23 August 2013 Keywords: IGCC Gasification Dry-fed Slurry-fed Coal quality Performance a b s t r a c t The integrated gasification combined cycle (IGCC) power plant delivers environmentally benign power from coal. The overall objective of the European Union (EU)’s H2-IGCC project is to develop and demonstrate technological solutions for future generation IGCC plants with carbon capture. As a part of the general goal, this study evaluates the effects of coal quality and the selection of gasifiers on the overall performance of the baseline configuration of the IGCC plant. Four commercially available gasifiers i.e., Shell, GE, Siemens, and ConocoPhillips gasifiers are considered for this comparative study. The effects of three different types of coals on the gasification processes have been investigated, as well as the overall performance of the plant. Simulation results show that slurry-fed gasifiers are not suitable for lignite coal, while dry-fed gasifiers are less sensitive to coal quality. Coal quality has the greatest effect on the GE gasifier. The ConocoPhillips gasifier demonstrates the highest cold gas efficiency using bituminous coal. The coal rank and the gasification process have relatively less effect on gas turbine power output, while steam turbine power output varies significantly with these. Although steam turbine power output increases with a reduction in coal quality, especially for slurry-fed gasifiers, the air separation unit power demand offsets this increase. The highest overall plant efficiency is 37.6% (LHV basis) for the GE gasifier and coal B. The lowest overall efficiency penalty with coal quality is 5% (LHV basis) for the Shell gasifier with input changed from bituminous to lignite. Moreover, simulation results show that GE’s gasification technology has the highest CO2 emissions for lignite coal, i.e. 158 g/kWh. Ó 2013 Elsevier Ltd. All rights reserved. 1. Introduction The rapid growth of industry and population coupled with improved living standards has led to an ever-increasing demand on world energy, more specifically for electric power. Fossil fuels, mostly coal, have been catering to most of this demand for some decades. However, the ‘climate change’ problem [1] has forced the development of new technologies for fossil fuel based power and utility heat supply. According to the International Energy ⇑ Corresponding author. Tel.: +47 45391926; fax: +47 51 83 10 50. E-mail address: [email protected] (M. Mansouri Majoumerd). 0306-2619/$ - see front matter Ó 2013 Elsevier Ltd. All rights reserved. http://dx.doi.org/10.1016/j.apenergy.2013.07.051 Agency (IEA), CO2 emissions from the electricity and heat supply sector amounted to about 41% of total global CO2 emissions from fossil fuels in the year 2010 [2]. However, the IEA’s New Policies Scenario suggests a 25% increase in coal consumption in the year 2035 compared to the 2009 level. This increase will be 65% based on the current policies scenario [3]. One of the key players within these policies is ‘Carbon Capture and Sequestration’ (CCS) according to the European Energy Roadmap 2050 [4]. The deployment of CCS in coal-fired power generation will ensure the growing share of the coal consumption among other fossil fuels in the coming years with more restricted emissions regulations. Author's personal copy M. Mansouri Majoumerd et al. / Applied Energy 113 (2014) 452–462 453 Nomenclature AGR Ar ASU C CCS CCU CH4 CMD CO COS CO2 EU GE GT HHV HP HRSG acid gas removal argon air separation unit carbon carbon capture and sequestration combined cycle unit methane coal milling and drying carbon monoxide carbonyl sulfide carbon dioxide European Union General Electric gas turbine higher heating value high pressure heat recovery steam generator Integrated gasification combined cycle (IGCC) has been identified as an attractive coal technology which offers less expensive pre-combustion carbon capture than conventional plants with post-combustion capture. Moreover, the IGCC technology provides opportunities for the production of steam, H2, and synthetic chemicals such as Fischer–Tropsch fuels [5]. Effort is devoted to develop IGCC technology as a possible good alternative power using coal but lower CO2 emissions. Thermodynamic estimation of possible improvements of the performance of an IGCC plant with an entrained-flow, dry-fed, oxygen-blown gasifier with hot gas desulfurization in comparison with conventional process has been discussed by Giuffrida et.al. [6]. They also reported thermodynamic performance estimation vis-à-vis comparison through simulation between air-blown and oxygen-blown gasifiers for IGCC applications [7]. Cost effectiveness of power from IGCC plants with respect to conventional coal fired plants and nuclear power plants against the backdrop of penalty of CO2 emission has been exhaustively explored [8]. Results show relative advantages and disadvantages depending on several conditions of operation as well as regulations. With rapid growth of renewable energy, future coal based power plants may have to accommodate wide range of ratio of renewable and non-renewable power mix with efficient use of excess power for some other utility using IGCC power plants. Simulation results of an IGCC plant integrated with CaO based CO2 absorption using Shell and Texaco gasifiers are analyzed to estimate the expected performance [9]. It was noted that though plant efficiency may be low (30–33%), CO2 capture may improve (97%). Two innovative options for reducing the penalty in efficiency of shell coal IGCC plants during CO2 capture are simulated and optimized by Martelli et al. [10]. With a distinct view towards the development of IGCC technology, the European Union has sponsored a well-integrated and coordinated research endeavor under its FP7 Framework Research Program. Fifteen academic and nine industrial partners of the EU are involved in this H2-IGCC project to develop and demonstrate a future generation IGCC plant with pre-combustion CO2 capture [11]. Four different sub-groups are working in well-defined and coherent work packages towards this common goal. The simulation sub-group is working not only to achieve optimization through detailed system analysis at different stages of development but also to ensure a realistic techno-economic evaluation. Gasification plays the key role in an IGCC plant [12,13]. It not only makes it possible to use coal or other solid fuels in an efficient H2 H2O H2S IEA IGCC IP LHV NOx N2 O2 PFD SCGP SFG SOx ST SWGS hydrogen water hydrogen sulfide international energy agency integrated gasification combined cycle intermediate pressure lower heating value nitrogen oxides nitrogen oxygen process flow diagram Shell Coal Gasification Process Siemens Fuel Gasification sulfur oxides steam turbine sour water–gas shift combined power cycle but also provides opportunities to capture most of the pollutants, including CO2, efficiently. Employing proper gasification technology is essential for optimizing the operation of a future generation IGCC plant. Moreover, gasification performance is significantly affected by coal quality. This quality varies widely depending on the geographical location of coal source [14]. High ash, sulfur, chlorine, alkali metals etc. in addition to low heat value and ash melting point are some typical characteristics of low quality coals [15]. Unfortunately, about 53% of global coal reserves are of low rank, i.e. sub-bituminous and lignite [16]. Thus to explore a useful real-life future generation IGCC plant, the effects of the gasification process, as well as that of coal quality, on the performance of the plant must be investigated. Several previous studies [17–21] have reported on IGCC plants using bituminous coals without any reference to low rank coals. In an effort to evolve the optimum IGCC plant configuration based on data provided by other sub-groups of the H2-IGCC project, the simulation sub-group previously reported detailed simulation results for a baseline configuration of the IGCC plant as developed in this project [22]. In this paper, subsequent simulation studies on the effects of the gasification process as well as of coal quality on the performance of that baseline configuration are reported. Comparative performance evaluations of the gasification process of three different types of coal, viz. bituminous, sub-bituminous and lignite in four different commercially available gasifiers are reported in this paper. Two coals typically represent low rank coal and the results for these are compared with that for bituminous coal as reference. Subsequently, the performance evaluation is extended to the whole plant using the same coals and gasification technologies. The results of this work show some distinct implications for the optimum configuration of the future IGCC plant that may evolve through subsequent studies of different subgroups of the project. 2. Gasification and gasifiers for power generation Conventional gasification is the process of conversion of a solid or liquid through sub-stoichiometric reaction with oxidants, either air or O2 at a temperature exceeding 700 °C to produce a synthetic gaseous product [23]. Compared to conventional pulverized coal firing, gasification offers great opportunities for both higher efficiency and improved capture of pollutants. According to the flow geometry, the commercial gasification technologies can be classi- Author's personal copy 454 M. Mansouri Majoumerd et al. / Applied Energy 113 (2014) 452–462 fied into three categories, viz. entrained-flow, fluidized bed, and moving bed gasification technologies [24]. However, the need of modern power plants for large capacity gasifiers demands the shortest residence time and hence entrained-flow gasifiers are the most favored for this purpose. Entrained-flow gasifiers allow high operating pressures (20–80 bar) and temperatures (1200– 1600 °C). High operating temperatures enable a favorable slagging process to remove ash and render gasification almost tar-free. These conditions are very desirable for large-scale power generation. Hence, almost all the commercially useful coal gasifiers deployed for large-scale power generation are of the entrained-flow type. Although entrained-flow gasifier can process many varieties of feedstock e.g., high/intermediate/low quality coals, and heavy liquid fuels [12,25], the feedstock characteristics significantly influence the gasification performance and consequently the performance of the whole IGCC plant [12,24,26]. The existing gasifiers show a substantial increase in cost combined with a drastic reduction in performance when operating on low-rank feedstock e.g., lignite coals [19]. Nevertheless, the utilization of such types of coals can improve flexibility of supply and consequently improve the security of the energy supply [15]. The main parameters for the selection of coal type for IGCC plant are ash content, slag viscosity, and coal reactivity. The feedstock can be fed either wet (using slurry water) or dry (using N2 as a conveying gas) into the entrained-flow gasifier. The high pressure and temperature environment of the gasifier facilitates the gasification of the fed coal [27]. The released heat results in the melting of the ash content and the production of molten, inert slag. Meanwhile, the carbon content in the coal is converted mainly to CO and H2 rather than to the normal products of combustion, CO2 and H2O, due to the reducing environment of the gasifier. The content of these products in the syngas depends heavily on the gasifier lambda value (the fraction of stoichiometric O2 demand of the reactor when conceived as a partial oxidation burner). Due to the high operating pressure and other advantages of the entrained-flow regime, this type of gasifier provides a high H2/CO ratio syngas and an inert slag. In the case of high rank coal, steam is added to the gasifier to moderate the temperature of the process while maintaining good carbon conversion. Under the extremely hot condition, coal devolatilizes (pyrolysis) almost instantaneously into gaseous elements like CH4, aromatics, CO2, CO, and solid char residue (C).The volatiles formed are immediately combusted with the supplied oxygen leading to an enormous rise in temperature. 1 Volatiles þ x þ y O2 ! xCO2 þ yH2 O 2 ð1Þ Depending on the oxidant factor of the gasification process, either the volatiles consume all O2 in the equation or some excess O2 is left. In the case of there being no oxygen left after combustion of the volatiles, the following endothermic gasification reactions (Eqs. (2)–(4)) of residual char with the oxidants CO2 and H2O (so called moderating agents) take place. C þ H2 O $ CO þ H2 ð2Þ C þ 2H2 O $ CO2 þ 2H2 ð3Þ C þ CO2 $ 2CO ð4Þ These moderation reactions are relatively slow compared to the devolatilization reaction (Eq. (1)) and cause a temperature drop. In the case where there is excess O2 after combustion of the volatiles, some of the residual char will be completely (Eq. (5)) or partially combusted (Eq. (6)) and release heat prior to moderation. These reactions (i.e. Eqs. (5) and (6)) are exothermic irreversible reactions. C þ O2 ! CO2 ð5Þ 1 C þ O2 ! CO 2 ð6Þ Another important reaction is the gasification’s CO-shift reaction (Eq. (7)), which is an exothermic reaction to convert CO to CO2. CO þ H2 O $ CO2 þ H2 ð7Þ The methane content of the produced syngas is increased through reactions (8) and (9) [23]. These are exothermic methanation reactions (below); however, they are more prevalent in gasifiers operating at lower temperatures. A higher gasifier pressure also increases the methane content. In addition to the mentioned reactions, most of the sulfur content in the coal is converted to H2S, with a small fraction being converted to COS. Moreover, nitrogen is converted to ammonia in the reducing environment of the gasifier. This ammonia also breaks down into N2 and H2 in the high temperature environment. A small amount of hydrogen cyanide is also produced. CO þ 3H2 $ CH4 þ H2 O ð8Þ C þ 2H2 $ CH4 ð9Þ 2.1. Gasifiers assumed for this simulation The gasification of coal has gained special significance in the context of future generation IGCC plants. Several industrial research groups are developing coal gasifiers, specifically those of the entrained-flow type, on a commercial scale. Some of the leading companies in the power sector have patented their technologies in this field. To assess the significance of the process of gasification on the performance of future generation IGCC plants, four common commercially-matured gasifiers with known specifications have been used for this simulation. These are Shell Coal Gasification Process (SCGP), General Electric (GE) gasifier (formerly Texaco), Siemens Fuel Gasification (SFG), and ConocoPhillips (EGas™) gasifier. The main characteristics of these gasification technologies are shown in Table 1. All of these gasifiers are oxygenblown and entrained-flow type, each having some specific features as discussed below. 2.1.1. Shell Coal Gasification Process (SGCP technology) The SCGP gasifier typically operates at around 45 bar, with a temperature range of 1400–1600 °C, well above the ash melting point to ensure that molten ash has a low viscosity to flow easily out of the gasifier [28,29]. Since it has a dry-fed system, no water must be evaporated in the gasifier leading to high cold gas efficiencies compared to (single stage) slurry-fed entrained flow gasifiers [29]. Coal is pulverized and dried to 2% residual moisture in a roller mill system featuring a hot drying gas recycle loop. Drying heat is supplied by an in-line burner in a hot drying gas recirculation loop, burning a small fraction of the cleaned syngas flow downstream the syngas desulphurization unit (1–2%). The dry, pulverized coal is subsequently pressurized using a lock-hopper system. The pressurized coal is pneumatically fed to the gasifier in dense phase mode using pure nitrogen as a conveying gas. Gasifier lambda value is low (0.30–0.33) which, at least for hard coal gasification, would lead to both unacceptably high gasifier working temperatures and low carbon conversion. To solve this problem, intermediate pressure (IP) moderation steam is admixed to the gasifier oxygen feed in a ratio of typically 0.1 (kg steam/kg coal dust feed). When gasifying lignite, lambda values are high such that external moderation steam supply is not required. The raw syngas leaving the gasifier is first rapidly cooled to around 900 °C by recycling Author's personal copy 455 M. Mansouri Majoumerd et al. / Applied Energy 113 (2014) 452–462 Table 1 The main characteristics of investigated gasifiers. Specification Shell Coal Gasification Process (SCGP) GE (formerly Texaco) Siemens fuel gasification (SFG) Conoco-Philips (E-Gas™) Flow regime Type of ash Oxidant Dry/slurry Feed type Pressurization Entrained-flow Slag O2-blown Dry-fed Pulverized coal Lock hopper (pneumatic feeding) Single Lock-hopper (bottom) Entrained-flow Slag O2-blown Slurry-fed Pulverized coal Slurry pump Entrained-flow Slag O2-blown Dry-fed Pulverized coal Pneumatic feeding Entrained-flow Slag O2-blown Slurry-fed Pulverized coal Slurry pump Single Lock-hopper (bottom) Single Lock-hopper (bottom) Double Continuous pressure let-down system (bottom) [23] Upward flow Side-fired Quenching with recycle gas and radiant cooler Membrane-wall type reactor [29] 78–83% [29] Downward flow Top-fired Full water quench, radiant cooler, and radiant/convective coolers Refractory-lined reactor Downward flow Top-fired Built-in full water quench Upward flow Side-fired Two-stage gasification Refractory-lined reactor 70–75% Both membrane-wall type reactor and refractory-lined reactor [31] 75–80% [15] 78–83% Above 99% [29] Above 96% Above 98% [31] Above 99% [35] Tar free 92%/96% [36] Tar free 88–90% (availability) [19] Tar free 90%/94%[32] Tar free 92% (availability) Number of stages Slag removal system (position) Flow direction Boiler position Quenching type Reactor type Cold gas efficiencya Carbon conversion Tar formation Availability/ Reliability targets a The definition of cold gas efficiency is presented in Section 5. cooled, ash-free syngas. This cooling process is called dry quenching. The purpose of this type of quenching is to solidify the slag particles and it is essential to reduce the fouling risk in the downstream syngas cooler. The syngas is then further cooled to 340 °C while generating high pressure (HP) and IP steam. Downstream the syngas cooler, the syngas is thoroughly dedusted in a filter system consisting of a cyclone and a ceramic candle filter in series. Part of the dedusted syngas (<10 mg/N m3 residual dust) is recycled to the dry quench section. The rest of the syngas is sent to a wet scrubber upstream of the acid gas removal (AGR) unit for removal of halogens (Cl and F compounds), trace elements, and fine particulate matter. The produced, fully dedusted and dehalogenized syngas is then sent to downstream sub-systems in the IGCC plant. There is currently one IGCC plant in operation using SCGP technology: the Vattenfall Buggenum IGCC plant in the Netherlands. 2.1.2. General Electric gasifier Similar to the SCGP, the GE gasifier uses pulverized coal. However, in this case pulverized coal is mixed with water to produce a slurry feed. The typical range of slurry (ratio of solid to whole mixture) varies from 35 to 70 wt% depending on the coal’s characteristics [25,28,30]. The slurry type of gasifiers utilize a slurry pump to feed the slurry into the gasifier enabling the process to have a higher operating pressure compared to dry-fed systems (up to 70 bar). Lambda value is relatively high (0.40) caused by the fact that some CO and H2 burning is required to vaporize the slurry water. The syngas therefore shows relatively high contents of the products of combustion (i.e. CO2 and H2O). The main disadvantage of this technology is the limited lifetime of the refractory and the associated cost due to refractory replacement. Therefore, such plants are designed with a spare gasifier to enable them to achieve 90% target availability [19]. Contrary to shell process, slag and syngas leave the gasifier co-currently at 1260–1480 °C. Application of a dry quench system is not possible due to the large amount of slag that should be solidified. Instead, a radiant syngas cooler is applied followed by a convective syngas cooler. Both syngas coolers raise saturated HP steam. In between both types of syngas coolers, the solidified slag is separated using a water quench bath for further quenching. Finally, the solidified slag is sluiced out of the gasification system. Syngas leaving the convective syngas cooler then enters the scrubber before being sent to the AGR unit. In the current study, this type of cooling is used in simulations. The type of syngas cooling described above is just one way of cooling for GE gasifier produced syngas. Often GE type gasification systems are designed based on a so-called wet quench system where syngas and slag leaving the gasifier are directly quenched in a wet quenching system. The wet quench design consists of a large water pool that cools the syngas and removes slag and ash particles. The quenched raw syngas then enters a wet scrubber. The dry syngas cooling type of heat recovery results in a higher overall plant efficiency and steam turbine (ST) power output compared to the wet quench design. However, a gasification system based on a radiant/convective cooler is considerably more expensive than a wet quench design (by a factor of two). The higher operating pressure compared to dry-fed gasification system results in a smaller sized CO2 removal system and reduces the corresponding cost. The water content of the syngas leaving the wet scrubber is relatively high compared to dry-fed gasifiers. The produced syngas needs a certain level of water content to carry out the CO-shift conversion at the sour water–gas shift (SWGS) unit and this level is controlled by the steam extraction from the heat recovery steam generator (HRSG) of the combined cycle unit (CCU). This extraction is, therefore, lower compared to dry-fed gasifiers [19]. There is presently one IGCC plant using the GE gasifier: the Tampa Electric Polk IGCC power station in the USA. 2.1.3. Siemens gasifier (SFG technology) Similar to the SCGP, the SFG technology features a dry-fed system which results in high cold gas efficiency [15]. Coal milling and drying and pulverized coal dry-fed systems are similar to the one described for the SGCP process. This technology is commercially Author's personal copy 456 M. Mansouri Majoumerd et al. / Applied Energy 113 (2014) 452–462 available with both reactor types, refractory-lined for lower ash content (<2%) and membrane-wall for higher ash content (>2%) [31]. The gasification temperature range is 1450–1750 °C [32] and the operating pressure is approximately 40 bar [33]. The SFG utilizes full wet quenching which results in a simple process compared to radiant or convective coolers and ensures optimal conditions for CO-shift conversion in the subsequent process unit (i.e. SWGS). In the current study, the quenching process is based on the direct wet quench type. The cooled and saturated raw syngas leaves the gasification island for the SWGS unit at a temperature of 220–230 °C [15]. Though there is currently no full-scale SFG for IGCC application, the power market is increasingly showing interest in this type of gasifier [31]. (1) Air separation unit (ASU): the cryogenic ASU is a stand-alone unit generating O2 (95% purity) from air supplied by an intercooled main air compressor for the gasification of coal. This compressor is not integrated with the gas turbine of the CCU. (2) Gasification island and syngas cooling and scrubbing: the gasification of the coal takes place in various O2-blown, entrained-flow gasifiers using technologies described in Section 2. (3) Sour water–gas shift (SWGS) reaction unit: the SWGS process is the reaction used to convert the CO in the raw syngas to CO2 by shifting the CO with water over a catalytic bed (usually alumina supported cobalt molybdate) according to the following equation: MJ 2.1.4. ConocoPhillips (E-Gas™) gasifier Similar to the GE gasifier, this E-Gas™ gasifier is a slurry-fed type [19]. However, this type of gasification has two stages of gasification and incorporates a proprietary slag removal system, char recycle and syngas cooling schemes. Both gasification stages are fed with coal slurry and are provided with refractory inner walls. The operating pressure is around 40 bar [34]. Operating conditions of the first stage gasifier resemble the one for the GE gasifier. However, instead of co-current flow of slag and raw syngas in GE gasifier, the major part of the slag is kept separated from the raw syngas flow by letting the slag flow to be quenched in a water bath located beneath the gasifier. In the second stage of gasifier, only a very little amount of oxygen is applied. Most of the gasification of the entering slurry is accomplished by the moderating agents, CO2 and H2O, present in relatively high concentration in the entering syngas from the first stage of the gasifier. Since gasification using CO2 and H2O as the main gasifying agents is endothermic, the gasification of the slurry feed results in a large syngas temperature drop (from >1300 to 900 °C). This temperature drop also causes fly ash particles still present in syngas flow from the first stage gasifier to solidify, alike in the dry quench section of the SGCP. Therefore, this second stage gasifier is sometimes denoted as chemical quench. The chemical quench results in a lower overall lambda value and an improvement of cold gas efficiency. On the other hand, it reduces the available sensible heat transfer in the downstream syngas cooler [23]. Therefore, a radiant cooler is no longer needed. The second stage gasifier is less effective in carbon conversion than the first one. Therefore, a lower carbon conversion is assumed for the second stage. A filter downstream the convective syngas cooler removes the ash particles and unconverted carbon. Because of its high carbon content, the separated ash flow is recycled to the first gasification stage in order to be gasified. There is currently one IGCC plant using the E-Gas™ gasifier: the Wabash River IGCC plant in the USA. 3. IGCC plant for this simulation The impact of coal quality on the gasification process has been investigated for the four assumed gasifiers. However, the principal objective of the simulation sub-group of the H2-IGCC project is to explore optimized configuration of the plant through simulation and using data available in open literature or from other group partners. Hence, the effects of coal quality and the gasification process on the performance of the baseline configuration of the plant, as reported in [22], are also investigated subsequently. The schematic of the IGCC configuration using the GE gasifier is shown in Fig. 1. Details of this scheme (except the gasification unit) may be obtained from [22]. However, a brief outline of the scheme is also presented here. The plant consists of seven major sub-systems as discussed below: 44kmol COðgÞ þ H2 OðgÞ $ CO2ðgÞ þ H2ðgÞ ð10Þ (4) Acid gas removal (AGR) unit: a two-stage SELEXOL system for H2S removal and CO2 capture is used. Due to the high partial pressure of acid gases, physical absorption of H2S and CO2 is preferred to chemical, amine-based absorption processes. (5) CO2 compression and dehydration unit: the CO2 captured from the process (90% capture rate) is compressed by an intercooled compressor, aftercoooled, liquefied and finally pumped up to a final pressure (150 bar). In order to reduce the corrosion risk in the transport pipeline, a dehydration unit using tri-ethylene glycol is considered (H2O water content in the captured CO2 line is less than 20 mg/kg). (6) Gas turbine (GT): the GT block including compression, combustion, and expansion generates electric power using a generator. Simulation has been performed using characteristics and boundary conditions of a gas turbine which is designed for combustion of the H2-rich fuel produced from sub-systems 1–4. (7) Heat recovery steam generator (HRSG) and steam cycle: downstream of the GT is a triple pressure HRSG (140 bar/ 530/530 °C) and steam turbine to generate steam and power. 4. Simulation tools and methods In this study the performance of various gasification technologies (refer to Section 2) using three different types of coal have been investigated. To obtain reliable results, the following software tools based on their specific capabilities were utilized for simulation of the entire IGCC plant: Enssim: simulation tool developed by Enssim Software [37]; ASPEN Plus: commercial process engineering software developed by AspenTech [38]; and IPSEpro: commercial heat and mass balance program developed by SimTech [39]. Data exchange between software tools was performed manually to find the optimal match. The simulation of all sub-systems (refer to Section 3) except gasification block was performed using commercial tools, i.e. ASPEN Plus and IPSEpro. The relevant one of these two software tools was used as described below: The ASU and SWGS reaction were modeled using ASPEN Plus. The Peng-Robinson properties method was selected as the equation-of-state (PR EOS). The AGR unit was modeled in ASPEN Plus with Perturbed-Chain Statistical Associating Fluid Theory (PC-SAFT) as the equationof-state. Author's personal copy 457 IP Steam Feed water HP steam Water Coal Make-up water M. Mansouri Majoumerd et al. / Applied Energy 113 (2014) 452–462 SWGS Particulate removal Slurry tank CO+H2O→ CO2 +H2 Convective cooler GE Particulates Syngas Feed water (CO, H 2) Slurry pump H2 -rich syngas SELEXOL HP steam ASU Air AGR, CO2 capture, compression & dehydration CO 2 to storage O2 Slag Generator Sulfur by-product Air HRSG Stack Generator Fig. 1. The schematic configuration of the IGCC power plant with carbon capture (using GE gasifier). The compression of captured CO2 and dehydration of CO2 stream were modeled in ASPEN Plus using PR EOS, and Schwarzentruber and Renon (SR polar) equation-of-state, respectively. The power block including the GT, and the triple-pressure steam cycle were modeled in IPSEpro. The simulation of the gasification block was carried out using the Enssim tool. All simulations were static design calculations for all equipment. Gasification modeling started from a purely thermodynamic analysis of the process. Gasification kinetics was not included in the calculations. Nevertheless, chemical equilibrium is attained for the most important equilibrium reactions due to the high operating temperatures at entrained flow gasifiers. Non-equilibrium conditions are taken into account by temperature differences between actual and equilibrium temperatures for the various simultaneous gasification reactions. Realistic design data and data for chemical equilibrium deviations for the Shell gasifier have been deducted from the design and operational data of the well-known Nuon (Buggenum) IGCC plant. It is worth noting that the dry-fed gasification model (based on the Shell technology) using this in-house tool was validated against real plant operational data and design data for the Magnum plant gasifier (refer to Table 3). In Tables 2 and 3 below, common input variable data for validation of the model and a comparison of results provided by the gasification technology licensor and the Enssim tool are given. As seen in Table 3, calculated syngas compositions are quite close. There is a relatively small difference in calculated GOX to dry coal dust ratio. The relative difference in calculated gasifier cold gas efficiency is even smaller. Therefore, Enssim tool is Table 2 Common input variable data for validation of the Shell gasification model. Input data Value Remarks Coal designation Moisture content dried coal (kg/kg) Dry coal dust feed temperature (°C) Coal dust conveying N2 ratio (kg/kg) Drayton 0.02 Bituminous Australian coal O2 purity (mole%) O2 temperature (°C) Moderator steam/ burner feed ratio (kg/kg) Gasification temperature (°C) Relative heat transfer to membrane wall (%) Carbon conversion (%) 80 0.07 0.07 kg N2 needed to transport 1 kg of dry coal dust (in pneumatic dense phase mode) 99.5 200 0.0769 1650 2.0 As a percentage of gasifier coal feed thermal flow (LHV based) 99.3 regarded as a reliable tool for fitting gasification data provided by the licensor. The simulation of SCGP using this tool is given here as an example. For the SGCP process the Enssim tool was used to analyze the subset of conceptual process flow diagram (PFD) consisting of coal milling and drying section (CMD), the dry pulverized coal feeding section and the gasification section. The latter section consisted of gasifier, dry quench section, syngas cooler section, dedusting section, and wet scrubber section. Author's personal copy M. Mansouri Majoumerd et al. / Applied Energy 113 (2014) 452–462 Table 3 Comparison between gasification technology licensor and Enssim results for gasifier calculation. Quantity Licensor result Gasifier syngas composition (mole fraction) H2O 0.0205 H2 0.2851 CO 0.6327 0.0107 CO2 CH4 118a H2S 0.00313 N2 0.0462 Ar 885a HCl 99.5a NH3 120a COS 343a CS2 – S2 – HCN 120a C2H4 – GOX to dry coal dust ratio (kg/kg) 0.798 Gasifier cold gas efficiency (%) 79.8 a Enssim result 0.0201 0.2802 0.6350 0.0112 101a 0.00317 0.0488 834a 99a 102a 244a 2a 5a 110a 9a 0.754 80.4 The reported values are based on ppmv. Calculations of the PFD for CMD included secant iteration blocks for: Drying gas purge temperature, O2 content and relative humidity. Blending coal with fluxing agent in the CMD such that the approach to the flow point of the resulting slag in the gasifier (100 K) was maintained. Calculations of the gasifier were carried out using the following input design parameters: gasifier working temperature and pressure, carbon conversion, relative (to pulverized coal thermal input) heat transfer of the membrane wall or refractory wall. The chemical gasifier calculations first start with a calculation of slag, ash composition, and a first estimate of syngas composition. It also takes into account the amount of CO2 resulting from calcination of limestone or dolomite if these minerals were added as fluxing agents in the coal milling and drying unit. Subsequently, Table 4 Composition and thermal properties of investigated coals. Coal sample code Coal A (Bituminous) Coal B (Subbituminous) Coal C (Lignite) Proximate analysis (wt%, dry basis) Moisture 10 Ash 12.50 Volatile matter 27.00 Fixed carbon 50.50 LHV (kJ/kg) 25,100 HHV (kJ/kg) 26,195 27.40 4.50 31.40 36.70 19,691 20,469 31.24 17.92 28.08 22.76 14,127 14,682 Ultimate analysis (wt%, a.r.) C 64.10 H 5.02 N 0.70 O 16.09 S 1.50 Cl 0.09 50.25 3.41 0.65 13.55 0.22 0.02 36.27 2.42 0.71 10.76 0.64 0.04 Main ash composition (wt%) SiO2 55.00 Al2O3 24.00 Fe2O3 5.50 CaO 4.50 33.40 16.30 5.20 21.50 56.96 19.01 3.49 8.39 Table 5 Technical variables for various gasification technologies. Coal sample code Coal A Coal B Coal C Shell Coal Gasification Process (SCGP) Operating temperature (°C) Operating pressure (bar) Specific O2 demand (kg/kg coal a.r.) Specific moderator steam demand (kg/kg coal a.r.) Specific N2 demand (kg/kg coal a.r.) Carbon conversion (%) 1550 45.0 0.773 0.060 0.232 99.3 1550 45.0 0.549 0.000 0.186 99.3 1550 45.0 0.419 0.000 0.170 99.3 GE gasifier Operating temperature (°C) Operating pressure (bar) Slurry solid contents (wt%) Specific O2 demand (kg/kg coal a.r.) Carbon conversion (%) 1450 60.0 64.5 0.881 99.0 1450 60.0 56.0 0.708 99.0 1450 60.0 45.0 0.721 99.0 Siemens fuel gasifier (SFG) Operating temperature (°C) Operating pressure (bar) Specific O2 demand (kg/kg coal a.r.) Specific moderator steam demand (kg/kg coal a.r.) Specific N2 demand (kg/kg coal a.r.) Carbon conversion (%) 1550 45.0 0.770 0.060 0.160 99.0 1550 45.0 0.554 0.039 0.132 99.0 1550 45.0 0.418 0.000 0.126 99.0 ConocoPhillips (E-Gas™) gasifier Operating temperature (°C) 1st stage Operating temperature (°C) 2nd stage Operating pressure (bar) Slurry solid contents (wt%) Specific O2 demand (kg/kg coal a.r.) Carbon conversion 1st stage (%) Carbon conversion 2nd stage (%) 1450 991 43.0 64.5 0.712 99.0 95.0 1450 991 43.0 56.0 0.548 99.0 95.0 1450 991 43.0 45.0 0.586 99.0 95.0 sixteen simultaneous homogeneous equilibrium reactions also including sulfurous and nitrogenous compounds are used to equilibrate the initial syngas composition. These equilibrium calculations are carried out in a secant iteration block which determines the gasifier lambda value to arrive at the design gasifier heat transfer for the given gasifier design operating temperature. For a number of reactions, non-equilibrium situations were simulated using approaches to the equivalent equilibrium temperature. Following the gasifier computations all equipment downstream the gasifier is analyzed. In the end, the code outputs the syngas composition at the outlet of the wet scrubber and outputs a list of ratios of the quantities demand mass flow rates, required and produced heat rates, power demands, production mass flow rates, and produced power and the quantity fuel flow rate (as received) to the CMD. To investigate the effect of coal characteristics on the performance of gasifiers as well as the power plant, three coals with various characteristics including bituminous, sub-bituminous and lignite coals are considered in this work. It is evident from Table 4 that these coals differ significantly in moisture, ash content, and heating value. As previously mentioned, four different gasification technologies such as SCGP, GE, SFG, and E-Gas™ were selected to assess Cold gas efficiency (%) 458 90.0 80.0 SCGP 70.0 GE 60.0 SFG 50.0 E-GAS 40.0 30.0 Coal A Coal B Coal C Coal type Fig. 2. Effects of coal rank on cold gas efficiencies. Author's personal copy M. Mansouri Majoumerd et al. / Applied Energy 113 (2014) 452–462 the gasification performance for different coals for the IGCC plant with CO2 capture. The operating conditions and technical assumptions used for simulation of investigated gasification technologies are given in Table 5. It is worth noting that the GT has been recently optimized for a hydrogen-rich fuel produced by the Shell Coal Gasification Process under the H2-IGCC project’s framework. Hence, GT characteristics (e.g. turbine inlet temperature, compressor and expander’s isentropic efficiencies, combustion efficiency, compressor map, etc.) for all aforementioned gasification technologies are the same as the optimized GT for the Shell system. Thus, the fuel mass flow rates (for the GT) and consequently pressure ratios vary depending on the fuel composition produced by each gasification technology. As seen in Table 5, the operating pressure of the GE gasifier is significantly higher than the one of the other gasifiers. To maintain the GT fuel at a pressure level similar to that of the other IGCC plants using different gasifiers, an expander downstream of the AGR unit has been assumed for the IGCC plant using the GE gasifier. 5. Results and discussion Based on the objective of this work, results obtained from simulation as described above are presented in this section in different subsections to describe the effects of coal quality and type of gasifiers on the process of gasification as well as possible overall performance of the baseline configuration of the plant [22]. 5.1. Effects of coal quality on gasification Coal properties that have significant effects on the gasification process are mostly ash content, slag viscosity, and coal reactivity. A coal with low ash content is favorable for the IGCC power plant since it produces smaller amounts of fly ash and bottom slag. It reduces the risk of the plugging of exit pipes and the fouling of downstream heat transfer surfaces [12]. Moreover, it also reduces coal feed for the same amount of produced gas. The slag viscosity directly determines the operating conditions of a gasifier. Although the calculation of slag viscosity for the three coals assumed in this simulation is a part of the gasification model, the detailed investigation of this topic is outside the scope of the present work. In this regard, the slag viscosity is set to 25 Pa.s for the calculation of the amount of fluxing agent which, depending on the ash composition of the coal to be gasified, is either basic limestone or refractory, acidic fly ash. The amount of oxidant agent is directly influenced by the gasification temperature which is determined by coal reactivity. To evaluate the effects of coal quality on the gasification process, two principal characteristics viz., cold gas efficiency and the properties of produced syngas including its composition have been investigated. 5.1.1. Coal quality and cold gas efficiency of gasifiers One of the main parameters used to describe gasifier performance is cold gas efficiency. This parameter indicates how much of the energy input has been recovered as chemical energy in syngas [12]. The gasification efficiency (cold gas efficiency) is defined as: ggasifier ¼ LHV sg Q sg LHV f Rf ð11Þ where ggasifier is the cold gas efficiency of gasification (%), LHVsg is the lower heating value of the syngas (kJ/m3), Qsg is the volumetric flowrate of the syngas (m3/s), LHVf is the lower heating value of the coal input (kJ/kg), and Rf is the gasifier coal consumption rate (kg/s). 459 The comparison between cold gas efficiencies for the investigated gasification technologies using three different coals is shown in Fig. 2. According to Fig. 2, the coal quality significantly influences the gasification efficiencies of slurry-fed gasifiers i.e. GE and E-Gas™ gasifiers. Amongst slurry-fed gasifiers, the coal quality has the greatest impact on the GE gasifier. The cold gas efficiency of the GE gasifier with lignite coal is 29% lower than that of the same gasifier with bituminous coal. However, it is noted from Fig. 2 that utilization of the second-stage gasification in the E-Gas™ gasifier resulted in higher cold gas efficiency compared to the other slurry-fed gasifier, i.e. GE gasifier. Although the ash content of coal affects the cold gas efficiency of slurry-fed gasifiers, the lower ash content of coal B could not offset the lower dry solid content of the slurry compared to coal A. Therefore, the cold gas efficiency is lower for coal B than for coal A. As observed from Fig. 2, cold gas efficiencies of dry-fed gasifiers are relatively insensitive to the coal quality which is a significant advantage compared to slurry-fed gasifiers. The higher cold gas efficiency for coal B than that for coal A in SCGP and SFG gasifiers may be due to the lower ash content of coal B. 5.1.2. Coal quality and properties of raw syngas from gasifiers The composition and characteristics of raw syngas produced by different gasification technologies are presented in Tables 6 and 7. The presented data correspond to upstream of the sour water–gas shift unit. Results of the simulation show that raw syngas from dry-fed gasifiers has higher CO and lower CO2 content compared to slurry-fed gasifiers. The higher water content in the slurry-fed gasifier results in conversion of CO to CO2 and H2 through CO-shift reaction (refer to Eq. (7)). In addition, the higher rate of oxygen consumption in the GE gasifier (refer to Table 5, Section 4) compared to SFG and SCGP, caused by the need to evaporate the slurry water in the gasifier, yields higher carbon dioxide in the raw syngas. Even though the O2 consumption for bituminous and sub-bituminous coals is lower in the E-Gas™ than that in the SFG and SCGP, the CO2 content is higher in the raw syngas produced by the former gasifier. This is caused by more intense CO-shifting (refer to Eq. (7)) during gasification at a lower employed temperature in the case of the E-Gas™ technology. Results in Tables 6 and 7 show another important difference between slurry-fed and dry-fed gasifiers for low-rank coals. The produced syngas from gasification of lignite coal in slurry-fed gasifiers shows a very low heat value. Therefore, it demands higher feedstock consumption to produce the same energy input for the downstream GT block compared to other coals. Thus, slurry-fed gasifiers are unsuitable for lignite coal. On the other hand, the capability of the dry-fed gasifiers to produce syngas from lignite coal with relatively closer energy density to that from bituminous coal obviously establishes them as better options for low-rank coals. The CH4 content from Shell, GE, and Siemens gasifiers is very small (ppm level). On the contrary, methane formation within the E-Gas™ gasifier is prominent. This is a result of the lower temperature employed in the second stage of this gasifier that favors exothermic methanation reactions (refer to Eqs. (8) and (9)). Unlike the other gasification technologies, the E-Gas™ gasifier also produces some ethylene caused by the lower temperature of the second stage of gasification. 5.2. Effects of coal quality and gasifier on overall performance of the plant Estimated performance parameters of the simulation for various gasification technologies using different coal quality are shown Author's personal copy 460 M. Mansouri Majoumerd et al. / Applied Energy 113 (2014) 452–462 Table 6 Composition and properties of produced syngas by SCGP and GE gasifiers (prior to the SWGS unit). Component (mol%) Ar H2 CO H2O CO2 H2S COS NH3 N2 CH4 Pressure (bar) Temperature (°C) HHV (MJ/kg) LHV (MJ/kg) a SCGP Parameter GE Coal A Coal B Coal C Coal A Coal B Coal C 0.71 23.29 50.04 16.38 2.45 0.42 436a 203a 6.56 237a 43.0 161.4 10.14 9.64 0.66 23.80 50.92 15.46 2.05 794a 84a 213a 6.78 781a 43.0 159.1 10.34 9.83 0.67 20.35 48.61 18.29 3.62 0.31 353a 193a 8.07 781a 43.0 165.7 9.19 8.77 0.70 22.97 34.16 30.23 10.78 0.04 250a 152a 0.66 651a 58.1 199.7 7.93 7.43 0.62 20.67 25.43 39.25 13.31 608a 28a 34a 0.62 239a 58.1 212.2 6.29 5.85 0.62 10.61 9.82 59.94 18.18 0.17 73a 47 0.64 7a 58.1 232.7 2.66 2.44 GT power (MW) ST power (MW) Expander powera (MW) Generator power output (MW) Gasification power demand (MW) ASU compression power demand (MW) Syngas compression and pumping power demand (MW) AGR refrigeration power demand (MW) CO2 compression power demand (MW) HRSG pumping power demand (MW) Auxiliary power demand (MW) Net power output (MW) The reported values are based on ppmv. Table 7 Composition and properties of produced syngas by SFG and E-Gas™ gasifiers (prior to the SWGS unit). Component (mol%) Ar H2 CO H2O CO2 H2S COS NH3 N2 CH4 C2H4 Pressure Temperature HHV (MJ/kg) LHV (MJ/kg) a Table 8 Performance results of IGCC plants using SCGP and GE gasifiers. SFG E-Gas™ Coal A Coal B Coal C Coal A Coal B Coal C 0.45 14.23 32.27 49.07 0.53 0.21 779a 134a 2.56 339a 0.00 43.3 210.7 6.90 6.57 0.41 14.97 30.87 49.29 1.69 0.04 135a 147a 2.64 205a 0.00 43.3 211 6.70 6.36 0.42 12.85 30.14 50.59 2.40 0.15 587a 134a 3.33 106a 0.00 43.3 212.1 6.15 5.86 0.53 20.83 26.99 35.28 11.81 0.37 93a 984a 0.75 2.30 1.01 41.7 192.7 8.34 7.75 0.51 20.73 25.86 36.91 12.33 669a 16a 936a 0.69 2.01 0.79 41.7 194.8 7.83 7.27 0.51 14.85 12.80 55.00 15.51 0.18 31a 631a 0.87 0.20 150a 41.7 213.7 3.87 3.55 The reported values are based on ppmv. in Tables 8 and 9. It is observed from these tables that the GT power output does not vary much either with coal type or gasification technology. This is due to using the same GT technology with fixed characteristics in simulations. The major difference in the generator power output between different plants (i.e. using different gasification technology and coal quality) comes from the power produced by the steam turbine. The higher ST power outputs in GE and E-Gas™ technologies are due to the type of gasification process, i.e. slurry-fed. The higher water content of the produced syngas from these gasifiers not only reduces the steam extraction from the steam cycle required to achieve the desired CO conversion within the SWGS unit but also produces more steam in the syngas cooler. Although the water content in the produced syngas from the Siemens gasifier is high due to the direct water quench, the ST power output is not as high as slurry-fed gasifiers. The reason is the production of HP steam within slurry-fed gasifiers which is absent in the SFG technology. It can also be seen from Tables 8 and 9 that the ST power outputs for both dry- and slurry-fed gasifiers are increased by the reduction in coal quality. The combination of higher gasifier raw syngas flow rates and the higher moisture content of slurry (by reduction in coal quality) results in a higher steam production in syngas coolers downstream of the gasifiers. However, an exception SCGP GE Coal A Coal B Coal C Coal A Coal B Coal C 324.0 176.6 0.0 500.6 323.61 163.79 0.0 487.4 326.3 177.8 0.0 504.1 317.6 221.7 1.0 540.3 318.60 273.49 1.0 593.1 334.2 330.2 1.2 665.5 4.9 6.1 8.5 4.0 5.6 12.9 48.9 46.4 54.7 54.5 61.0 142.3 10.8 10.7 11.3 9.0 9.2 16.0 8.5 11.3 11.3 11.1 11.2 25.8 20.4 20.2 21.6 20.6 21.8 36.3 3.7 3.9 3.4 3.43 4.33 4.2 97.0 98.1 111.1 103.2 113.1 237.4 403.6 389.4 393.0 437.1 480.1 428.1 a This value is related to the output power of the gas expander upstream of the GT for the GE IGCC. Table 9 Performance results of IGCC plants using SFG and E-Gas™ gasifiers. Parameter GT power (MW) ST power (MW) Generator power output (MW) Gasification power demand (MW) ASU compression power demand (MW) Syngas compression and pumping power demand (MW) AGR refrigeration power demand (MW) CO2 compression power demand (MW) HRSG pumping power demand (MW) Auxiliary power demand (MW) Net power output (MW) SFG E-Gas™ Coal A Coal B Coal C Coal A Coal B Coal C 320.3 170.0 490.3 320.5 174.5 495.0 321.1 183.5 504.6 318.6 186.3 504.9 318.46 201.22 519.7 330.5 287.9 618.3 7.6 9.8 14.5 3.8 5.0 9.1 47.0 45.5 52.0 43.6 43.6 84.0 10.6 10.8 11.3 11.5 11.7 15.1 19.4 20.4 49.8 10.5 10.7 22.8 20.0 20.0 21.5 20.1 20.5 27.3 2.4 2.4 2.4 3.0 107.0 108.9 151.6 92.4 94.5 162.0 383.3 386.2 353.0 412.6 425.2 456.3 2.94 3.6 is the SCGP for coal A and coal B. According to Table 6 (previous section), due to the lower water content of the produced syngas from coal B, the steam extraction from the steam cycle should be more compared to coal A to fulfill the SWGS reaction. This extraction results in a lower ST power output in the case of coal B utilization. The increase of ST power output for lower quality coal, however, could not compensate for the increase of auxiliary power demand, more specifically for slurry-fed gasifiers. The higher moisture content combined with the increased ash content of coal C compared to coal A in slurry-fed gasifiers results in higher oxygen demand to maintain the gasifier temperature. Therefore, ASU power demand is drastically increased for coal C compared to coal A. Results in Tables 8 and 9 confirm that the auxiliary power is in- Author's personal copy M. Mansouri Majoumerd et al. / Applied Energy 113 (2014) 452–462 Fig. 3. Oxygen consumption of different gasification technologies with various coal qualities. 461 Fig. 5. Effects of coal rank and gasification technology on the CO2 emissions of the IGCC plant. Fig. 5 shows CO2 emissions from the IGCC plant using different gasification technologies and for various coal qualities. Although the carbon content of the coal principally determines CO2 emissions from the IGCC plant, the use of dry-fed gasifiers and the EGas™ shows a relatively constant trend for different coal qualities. In terms of CO2 emissions of the plant, the GE technology, amongst various gasification technologies, does not appear to be the correct option for gasification of lignite coal (i.e. coal C). 6. Conclusions Fig. 4. Effects of coal rank and gasification technology on the IGCC plant efficiency and heat rate. creases with low coal quality. This is primarily due to the increasing oxygen demand but also because of the increasing CO2 content which should be captured and compressed. The oxygen consumption, which is an important factor to give an indication of the capital cost of the ASU, is shown in Fig. 3. The effect of coal rank and gasification technology on the thermal efficiency and the net heat rate (the reciprocal of net efficiency) of the IGCC plant with CO2 capture is shown in Fig. 4. It is obvious that the coal quality significantly influences the overall plant efficiency. It is noted from Fig. 4 that the slurry-fed GE gasifier is more affected by the low-rank coal C compared to dry-fed systems (i.e. SCGP and SFG). The other slurry-fed gasifier, the E-Gas™, is less sensitive to the coal quality. This is due to better utilization of the input feedstock with the second gasification stage. As mentioned previously, the lower overall plant efficiency for various gasification technologies using coal C is primarily due to decreased gasification efficiencies. It can be seen from Fig. 4 that the overall plant efficiency for coal B is higher than that for coal A in both GE and E-Gas™ gasifiers. Multiple reasons contribute to the mitigation of the impact of the relatively lower cold gas efficiency for coal B compared to coal A (refer to Fig. 2) on power plant net efficiency. These are as follows: (a) The ash content of coal B is lower compared to coal A, which results in a low difference between the dry and ash-free solid content of both coals. It should be noted that this fraction of coal, i.e. the dry and ash-free solid content, provides the required energy to vaporize the slurry water; (b) coal B raises more HP steam in the syngas cooler than coal A; and (c) the produced syngas from the gasification of coal B is more pre-CO-shifted than syngas from coal A due to the higher water content. This leads to less exergy loss in the SWGS section. The higher CO conversion (refer to Eq. (7)) also results in higher plant efficiencies for coal B in slurryfed gasifiers compared to dry-fed gasifiers. The EU’s H2-IGCC project is aiming to develop and demonstrate technological solutions for future generation IGCC plants with carbon capture. In the current study, under the framework of the project which aims for the evaluation and optimization of the best plant configuration, the effects of coal quality and the selection of gasifiers on the overall performance of the baseline configuration of the IGCC plant have been reported. Four commercially available gasifiers from Shell, GE, Siemens, and ConocoPhillips have been considered for this comparative study. The effects of three different types of coals on these gasifiers, as well as on the overall performance of the IGCC plant, have been investigated. Given the fact currently there is not any operating IGCC power plant with carbon capture, the validation of the overall system performance is not feasible. However, utilization of validated tools and models against existing plant data for simulation of different IGCC sub-systems in this study has resulted in more reliable results. Several conclusions can be inferred from the results as follows: (1) The coal quality considerably influences the cold gas efficiency for slurry-fed gasifiers i.e. GE and ConocoPhillips gasifiers. Amongst slurry-fed gasifiers, the coal quality has the greatest impact on the GE gasifier. The cold gas efficiency of the GE gasifier gasifying lignite coal is 29% lower than gasifying bituminous coal. On the contrary, dry-fed gasifiers are relatively insensitive to the quality of the input coal. (2) Results confirm that one of the main advantages of dry-fed gasifiers compared to slurry-fed types is a relatively constant quality of produced syngas even when low-rank coal is gasified. (3) The higher water content of the produced syngas from slurry-fed gasifiers increases the ST power output due to reduction of the steam extraction from the steam cycle for the SWGS reaction. However, this power increase cannot compensate for the increase of ASU power demand and results in lower system efficiency for low-rank coal. (4) The overall performance of the whole IGCC is slightly affected by the GT performance using different syngas compositions from various gasification technologies. However, Author's personal copy 462 M. Mansouri Majoumerd et al. / Applied Energy 113 (2014) 452–462 paper findings including characteristics of the inlet syngas to the gas turbine are very important in terms of the GT design. (5) Summarizing, slurry-fed gasifiers in this study, i.e. GE and ConocoPhillips, are suitable for bituminous and sub-bituminous coals, while dry-fed gasifiers, i.e. Shell and Siemens, show a relatively constant behavior for a wider range of coal quality. Acknowledgments The authors are grateful to the European Commission’s Directorate-General for Energy for financial support of the Low Emission Gas Turbine Technology for Hydrogen-rich Syngas (H2-IGCC) project. References [1] IPCC. IPCC fourth assessment report: climate change 2007 (AR4); 2007. <http://www.ipcc.ch>. [2] IEA. IEA Statistics 2012 Edition: CO2 emissions from fuel combustion highlights. Paris: International Energy Agency; 2012. [3] IEA. World Energy Outlook 2011. Paris: International Energy Agency; 2011. [4] EU Energy roadmap 2050, European Union, European Commission; 2012. [5] Tremel A, Haselsteiner T, Kunze C, Spliethoff H. Experimental investigation of high temperature and high pressure coal gasification. Appl Energy 2012;92:279–85. [6] Giuffrida A, Romano MC, Lozza GG. Thermodynamic assessment of IGCC power plants with hot fuel gas desulfurization. Appl Energy 2010;87(11):3374–83. [7] Giuffrida A, Romano MC, Lozza GG. 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Paper IV Fuel change effects on the gas turbine performance in IGCC application Mohammad Mansouri Majoumerd, Mohsen Assadi Presented at 13th International Conference on Clean Energy (ICCE 2014), Istanbul, Turkey, June 2014 161 FUEL CHANGE EFFECTS ON THE GAS TURBINE PERFORMANCE IN IGCC APPLICATION Mohammad Mansouri Majoumerd1, Mohsen Assadi1,2 1Faculty 2International of Science and Technology, University of Stavanger, 4036 Stavanger, Norway Research Institute of Stavanger (IRIS), P.O. Box 8046, 4068 Stavanger, Norway E-mail: [email protected]; [email protected] ABSTRACT Improved security of energy supply by utilizing clean coal technology with and without CO 2 capture results in changed fuel composition at integrated gasification combined cycle (IGCC) plants. Gas turbine modifications might be therefore necessary to cope with such changes. As part of the H2-IGCC project, a European Union co-funded project, this study presents a detailed analysis of the effect of using various fuel(s) compositions on the performance of the selected gas turbine in IGCC plants considering different operating conditions. For realistic analysis of the gas turbine behavior, component characteristic maps were generated and implemented into a detailed thermodynamic model in a commercial heat and mass balance program, IPSEpro. The fuels studied in this paper are undiluted hydrogen-rich syngas (i.e. 87 mol% H2 content), clean syngas (without CO2 capture), and natural gas. The impact of the fuel change on the gas turbine performance has been investigated and the results are presented and discussed in this paper. Moreover, technical solutions for realization of the targeted fuel flexibility under certain limitations and boundary conditions are presented. Calculation results show that for the given boundary conditions, the surge margin of the compressor was slightly reduced when natural gas was replaced by H2-rich syngas. The use of clean syngas instead of H2-rich syngas resulted in a considerable reduction of the surge margin and elevation of the turbine outlet temperature at design point conditions, when keeping the turbine inlet temperature and compressor inlet mass flow unchanged. In order to maintain the exhaust temperature and improve the surge margin, when operating the engine with clean syngas, a combination of adjustment of variable inlet guide vanes and reduced turbine inlet temperature was finally considered. Results of this study confirm that using clean syngas requires major gas turbine modifications such as air bleed from compressor outlet and multiple fuel feed systems. Key words: IGCC, gas turbine, performance analysis, fuel flexibility, hydrogen-rich syngas, clean syngas 1. INTRODUCTION The world’s demand for electricity is ever increasing mainly due to the population growth and improved living standards. Currently, the share of electricity generation is 37% of the global primary energy consumption. In 2012, the global electricity production was 22,126 TWh [1] with an annual average growth rate of 2.95 % from 1990 [2]. Fossil-based electricity production accounted for 68 % of the total generation and coal, the most carbon-intensive fossil fuel, was the largest contributor (41%) to the electricity supply in 2012 [1]. For future, electricity demand is projected to grow more rapidly than the total energy consumption [3, 4]. This demand will be almost 70 % higher in 2035 than the current demand [5]. On the other hand, needs to reduce greenhouse gas (GHG) emissions require considerable efforts to be directed towards the utilization of clean power generation technologies. The emissions of CO2 from the electricity and heat supply sector using fossil fuels were about 42% of the total global CO2 emissions in the year 2011 [6]. Several options should be considered in a comprehensive package to reduce the global GHG emissions per unit of energy consumption. Amongst those options are energy conservation and efficiency improvement, transformation/replacement of carbon-intensive fossil fuels by cleaner technologies (such as switch from coal to natural gas (NG), enhanced use of renewable energy sources and utilization of nuclear energy) and reduction of CO2 emissions using carbon capture and storage (CCS) for fossil-based energy. The integrated gasification combined cycle (IGCC) has been one of the most promising coal-derived technologies in terms of higher efficiency and lower environmental impact, compared to conventional pulverized coal plants [7]. In addition, the well-established high temperature coal gasification technology may facilitate the control and reduction of gaseous pollutants ( e.g. NOx and SOx) to the level of NG-fuelled plants [8]. Furthermore, using IGCC provides one of the least costly approaches for CO2 abatement through pre-combustion carbon capture [8, 9]. However, one of the largest barriers towards widespread utilization of the IGCC technology is its higher capital costs compared to a conventional pulverized coal plant [10, 11]. In addition, the high H2 content in the syngas derived from coal gasification (more specifically when a pre-combustion CO2 capture unit is considered in the cycle) complicates the application of pre-mixed burners, which is the current state-of-the-art (SOA) technology in NG-fired gas turbines (GTs) [12]. The restriction of using such burners is the flammability limits of H2-rich fuels, which are much larger than that for natural gas [13]. Moreover, high hydrogen content syngas has higher adiabatic flame temperature, higher flame speed, and higher flashback potential compared to NG, which complicate its pre-mixed combustion [14, 15]. For this reason, high NOx emitting diffusion burners have been employed for the existing IGCC power plants, which require the hydrogen-rich syngas to be diluted with nitrogen or water/steam to control the higher adiabatic flame temperature. The other persistent challenge in the IGCC plants is the variation in composition and heating value of the produced syngas, which needs to be combusted in the downstream GT. This variation is mainly due to the varying feedstock quality [16], and the process and operational causes (e.g. switch from a plant with CO2 capture to a noncapture mode). 1 Several studies highlighted the effect of varying composition of a specific type of fuel. Nag et al. investigated the effects of using different compositions of liquefied natural gas (LNG) on gas turbine operation. They found that change of lower heating value (LHV) and composition of the concerned fuel (i.e. LNG) may lead to increased emissions and different component lifetime [17]. Chishty mainly studied the combustion and corresponding design challenges in the combustor when using different fuels [18]. Experiences concerning the continuous use of different fuel composition, rather than switching fuels during operation, have been also investigated in various papers from original equipment manufacturers (OEMs) [19-21]. In addition to the areas covered in the publications mentioned above, the operation of an IGCC plant with pre-combustion CO2 capture, burning undiluted hydrogen-rich syngas, raises other matters of increased importance, such as the requirement for secure electricity production, which could be threatened by various disturbances. Compared to standard combined cycles, a H2-rich fuelled IGCC power plant has a complex plant layout with an increased number of components. Consequently, a higher probability of disturbances, such as failure or planned maintenance of the components/sub-systems of the cycle could be expected in such a plant. A changed operational window might also be caused by economic reasons, e.g. when CO2 capture is not beneficial due to low prices on the CO2 trading markets resulting in the bypassing of the CO2 capture unit. Furthermore, bypassing the CO2 capture unit will result in an overall higher power output, which requires efficient operation of the plant under these operating conditions. As a consequence, the GT should cover a wide range of fuel types from undiluted H2-rich fuel (as the design fuel) to low-LHV gaseous fuels (in the case of burning clean syngas) and also natural gas (as the back-up fuel) [21]. These fuels have different composition and LHV, which result in a different volume flow and consequently the mass flow into the combustor to reach the same order of turbine inlet temperature (TIT) and thereby similar efficiency level for a given compressed air flow [22]. Change of fuel flow rate affects the compressor/expander matching [13], induces higher back pressure to the compressor [12], and reduces available surge margin [22] if no adjustments are implemented to compensate for the mass flow change. Therefore, it is necessary to adjust the operational parameters of the gas turbine in such a way that a safe operation with reasonable performance can be offered. Given all these technological challenges, a secure provision of electricity using a fuel-flexible gas turbine with high operational flexibility is an essential need in IGCC power plants [23]. In 2009, the H2-IGCC project was co-funded by European Union to develop knowledge that would allow the use of SOA gas turbines in the next generation of IGCC power plants with deployment of CO2 capture. The overall objective of the project was to enable the stable operating conditions of the GT with pre-mixed combustion of undiluted H2-rich syngas. The secondary objective was to increase the fuel flexibility without adversely affecting the reliability and availability of the entire system by minor modifications to existing GTs [24]. As part of the H2IGCC project, this work presents the consequences of fuel change on the performance of the gas turbine at various operating conditions. The main objective is to see whether the targeted fuel flexibility or ability to operate on a variety of fuels (i.e. H2-rich syngas, non-captured clean syngas and natural gas) is achievable under presumed boundary conditions and limitations or not. In this paper, the baseline configuration of the selected IGCC plant with and without CO2 capture unit is briefly presented to provide an overview of the entire cycle’s layout. This will assist the readers for better understanding of how the fuel properties are affected by different operational/process changes (or disturbances). The effects of fuel change on the performance of the selected gas turbine, as an isolated sub-system, are then assessed. Accordingly, different operating conditions and adjustments to mitigate the negative effects of fuel change are thoroughly investigated and discussed followed by necessary modifications/strategies to minimize the negative effects of fuel change during the lifetime of a gas turbine in IGCC application. 2. THE SELECTED IGCC CONFIGURATION In order to investigate the impact of fuel change on the gas turbine performance, it is essential to have the expected fuel properties and composition prior to the GT. For this purpose, a baseline IGCC plant with and without CO2 capture unit has been established and thermodynamically analyzed. For better understanding of the process change from the IGCC plant with CO2 capture to a plant without capture, the plant description is briefly presented in this section. However, detailed technical assumptions and specification for modeling of the entire IGCC plant may be obtained from authors previous publication [25]. It should be noted that the fuel compositions in both cases, i.e. the plant with capture (H2-rich syngas) and the plant without capture have been adopted from a previous study [25]. 2.1. The selected IGCC plant with CO2 capture The block flow diagram of the IGCC plant with capture unit is shown in Fig. 1. The feedstock considered for the selected IGCC plant is bituminous coal. The plant consists of seven major sub-systems as explained below: (1) Air separation unit (ASU): the cryogenic ASU is a stand-alone unit generating O2 with 95% purity from air supplied by an intercooled main air compressor (MAC) for the gasification of coal. The main advantage of nonintegrated ASU is higher plant availability, operability, and flexibility. However, notably is that the overall plant efficiency increases with the degree of integration between ASU and the gas turbine compressor due to the higher isentropic efficiency of the GT compressor [26]. Nevertheless, lower efficiency of the non-integrated GT-ASU case could be balanced with selection of an intercooled MAC. Often for IGCC plants either syngas dilution with N2 or steam or syngas saturation with water is considered to control the NOx emissions from diffusion flame burners. However, here this strategy has been 2 eliminated due to the use of undiluted pre-mixed combustion of the H2-rich syngas. As there is no need for injection of diluent gaseous nitrogen into the GT for dry-low NOx combustion, heat integration between the GT compressor bleed air and diluent nitrogen from the ASU is not an option in order to enhance the overall plant efficiency. To Sulfur recovery Coal Gasification Shift reaction Acid gas removal CO2 O2 Air Slag To atmosphere CO2 compression & dehydration CO2 capture Air separation unit Heat recovery steam generator H2-rich syngas Stack HP IP/LP Gas turbine Air Fig.1. The block flow diagram of an IGCC power plant with CO2 capture (2) Gasification island and syngas cooling and scrubbing: the gasification of coal takes place in an entrained-flow, oxygen-blown, dry-fed gasifier based on the Shell Coal Gasification Process (SCGP). Such a technology was selected due to its high cold gas efficiency and its operating pressure level. A key parameter governing the overall plant pressure is the operating pressure of the GT combustor. The pressure prior to the combustion chamber was fixed at about 30 bar to overcome the pressure loss over the fuel valves and required turbulent conditions for premixed combustion. The pressure of the gasification block was then calculated to be at 45 bar considering all pressure losses from the gasifier to the combustion chamber for eliminating any supplementary syngas compression. The selection of the SCGP technology was also justified by availability of a validated gasification model provided by the operator of the Buggennum IGCC plant within the H2-IGCC project consortium. The validation results are available in [27]. (3) Sour water-gas shift (SWGS) reaction unit: the SWGS process converts the CO in the raw syngas to CO2 by shifting the CO with water over a catalytic bed according to the following reaction: (44 𝐶𝑂(𝑔) + 𝐻2 𝑂(𝑔) ↔ 𝑀𝐽 ) 𝑘𝑚𝑜𝑙𝑒 𝐶𝑂2 (𝑔) + 𝐻2 (𝑔) (1) (4) Acid gas removal (AGR) unit and CO2 capture unit: a two-stage SELEXOL system for H2S removal and CO2 capture was used. Due to the high partial pressure of acid gases, physical absorption of H 2S and CO2 is preferred to chemical, amine-based absorption processes. The H2S is removed by a counter-current flow of solvent in the first stage. The syngas leaving the H2S absorber enters the second stage where the CO2 is captured. The overall CO2 capture rate is approximately 90% (molar basis). (5) CO2 compression and dehydration unit: the CO2 captured from the process is compressed by an intercooled compressor, aftercooled, liquefied and finally pumped up to a final pressure of 110 bar. In order to reduce the corrosion risk in the transport pipeline, a dehydration unit using tri-ethylene glycol is considered resulting in water content in the captured CO2 line less than 20 mg/kg. (6) Gas turbine: the GT block including compression, combustion, and expansion generates electric power using a generator. The GT model is further discussed in Section 3. (7) Heat recovery steam generator (HRSG) and steam cycle: downstream of the GT is a triple pressure level HRSG with reheat (140bar/530/530°C) and a steam turbine to generate steam and power. 2.2. The selected non-capture IGCC plant In the plant without CO2 capture, the water-gas shift reaction is bypassed and the raw syngas leaving the wet scrubber is passed through a COS hydrolysis unit before entering the H2S absorber. Fig.2 illustrates the block flow 3 diagram of the non-capture IGCC plant. In order to remove more than 99.9% of the sulfur content in produced syngas, it is necessary to add the COS hydrolysis unit to convert the COS to H2S [8]. In addition to this change, few other sub-systems of the plant with capture should be out of operation such as CO2 capture unit (i.e. the 2nd absorption stage), CO2 compression and dehydration unit. The H2S-free syngas exiting the top of the H2S absorber is then sent to the GT combustor. To sulfur recovery To atmosphere Coal Gasification O2 COS hydrolysis Acid gas removal Heat recovery steam generator Non-captured, clean syngas Slag Stack Air Air separation unit HP IP/LP Gas turbine Air Fig.2. The block flow diagram of an IGCC power plant without CO2 capture 3. METHODOLOGY This work aims to investigate the effects of fuel change on the performance of a selected gas turbine under various operating conditions in IGCC application. It should be noted that the consequences of fuel change and necessary adjustments to the IGCC plant are not covered in this study. However, it was necessary to simulate the entire IGCC system with and without capture unit to reach the composition of different fuels upstream of the gas turbine. For this purpose, simulation results of the selected IGCC plant available in the recent publications by the authors have been used [25, 27]. Detailed modeling of the gasification process, based on the Shell Coal Gasification Process (SCGP) including coal milling and drying, gasification, raw syngas cooling and scrubbing, has been performed by Vattenfall (Nuon) using an in-house model in the Enssim software, which validated against operational data from Buggenum power plant [28]. The modeling of upstream and downstream units of the gasification block, such as the air separation unit, the sour water-gas shift reaction unit, the acid gas removal unit, the CO2 compression and dehydration unit, and the COS hydrolysis unit has been performed using ASPEN Plus [29]. Details of the thermodynamic models of the aforementioned units are also available in [25, 27]; hence, are not repeated here. A special emphasis is dedicated to the gas turbine in this study. The thermodynamic model of the GT has been established using IPSEpro, a heat and mass balance software [30]. This model is briefly discussed in the following sub-section. 3.1. Gas turbine model In order to investigate the effects of fuel change from NG, which is the design fuel for the GT, to undiluted H2-rich syngas for the IGCC plant with CO2 capture and clean syngas for the non-capture IGCC plant, a reference GT design should be selected. Accordingly, a Siemens SGT5-4000F/Ansaldo Energia V94.3A type of gas turbine was selected as the manufacturers being partners of the H2-IGCC consortium. Using a one-dimensional lumped model, detailed engine specifications including the main GT components characteristics maps were generated for NG as fuel and made available for the system modeling and simulation. An advanced thermodynamic GT model in IPSEpro software was then modified followed by model validation against performance data published by the manufacturer [31]. The main components of the gas turbine model are described below: (1) Compressor model: The compressor map generated by aforementioned lumped model, provided by Roma Tre University (refer to Fig.3), has been implemented into the thermodynamic compressor model in IPSEpro software tool as look-up tables. The axes’ labels in Fig.3 are not shown for reasons of confidentiality. The look-up table contains the changes of pressure ratio, corrected inlet mass flow, and isentropic efficiency based on corrected rotational speed. The effect of the variable inlet guide vane (VIGV) on aforementioned parameters (i.e. look-up table’s parameters) was also considered. However, the limited dimensions (i.e. number of rows and columns) of such a table, implemented in IPSEpro, are among limiting factors affecting the accuracy of the information retrieval from the look-up table. 4 Isentropic efficiency (%) Pressure ratio [-] Pressure ratio Corrected mass flow [-] IGV 100% IGV 70% IGV 47% IGV 90% IGV 60% IGV 100% IGV 70% IGV 47% IGV 80% IGV 50% (a) IGV 90% IGV 60% IGV 80% IGV 50% (b) Fig.3. The compressor characteristics maps, (a) pressure ratio versus corrected mass flow and (b) isentropic efficiency versus pressure ratio In terms of compressor stability, surge margin calculation has been incorporated into the compressor model. Surge is defined as a transient condition involving reverse flow through the compressor path and can occur when the pressure ratio increases beyond a safety margin. The surge margin is defined as: 𝑃𝑅𝑠𝑢𝑟𝑔𝑒 −𝑃𝑅𝑜𝑝𝑒𝑟𝑎𝑡𝑖𝑜𝑛 𝑆𝑢𝑟𝑔𝑒 𝑚𝑎𝑟𝑔𝑖𝑛 (%) = × 100 (2) 𝑃𝑅𝑜𝑝𝑒𝑟𝑎𝑡𝑖𝑜𝑛 (2) Combustor model: The fuel composition entering the combustor was obtained from system simulation reported in previous publication [25] based on the IGCC plant described in Section 2. To achieve realistic results, pressure losses reflecting the current SOA combustor technology were used. (3) Expander model: Once H2-rich syngas or non-captured syngas is used as the GT fuel in the existing GT (i.e. SGT5-4000F/Ansaldo Energia V94.3A) designed for NG operation, the operating conditions and performance of the GT deviates from the original design. Therefore, an off-design analysis was required in order to provide information about necessary changes. A simplified off-design model has been considered for modeling the expander. The turbine off-design operation was modeled assuming a constant swallowing capacity at choking condition, which is a reasonable assumption for heavy duty gas turbines: Swallowing capacity = Constant = 𝛾 𝜅 =√ 𝑖( 𝑅𝑖 2 ) 𝑚̇𝑖 √𝑇𝑖 (3) 𝜅 𝐴 𝑖 𝑝𝑖 𝛾𝑖 +1 𝛾𝑖 −1 (4) 𝛾𝑖 +1 As shown in Eq.3, the syngas flow rate at the expander inlet is proportional to the square root of the temperature. In a GT designed for NG, once the fuel flow rate is increased due to the change of fuel composition and LHV different components and operating conditions might be affected such as expander lifetime and the compressor stability. The influence of the cooling air entering the turbine at different rows was considered using a virtual/mixed turbine inlet temperature and a virtual/mixed polytropic efficiency according to the following equations: 𝑇𝑡𝑚𝑖𝑥𝑒𝑑 𝑖 = 𝑃𝑠ℎ𝑎𝑓𝑡 𝑚̇𝑡𝑜𝑡𝑎𝑙 𝑐𝑝 𝜂𝑡 𝑝𝑜𝑙𝑦𝑡𝑟𝑜𝑝𝑖𝑐 𝑚𝑖𝑥𝑒𝑑 = + 𝑇𝑡𝑜 (5) 𝑇𝑡𝑚𝑖𝑥𝑒𝑑 𝑖 ⁄𝑇 ) 𝑐𝑝 𝑙𝑛( 𝑡𝑜 𝑝 𝑅𝑜 𝑙𝑛( 𝑡𝑖⁄𝑝𝑡0 ) (6) In order to simplify the GT model, the effects of fuel change on the amount of cooling flows required to maintain the blade wall temperature at certain level was not considered at this stage. Therefore, it was assumed that the cooling flows were unchanged when the fuel composition was altered. 5 Table 1. Technical assumptions for GT modeling at design condition Parameter Unit Value Air flow at the compressor inlet kg/s 685 Pressure ratio 18.2 Cooling flow 1st expander stage kg/s 83.7 Cooling flow 2nd expander stage kg/s 52.7 Cooling flow 3rd expander stage kg/s 26.9 Shaft cooling kg/s 13.7 Compressor isentropic efficiency % 88.2 Combustor outlet temperature ᵒC 1500 Turbine inlet temperature ᵒC 1266 Expander isentropic efficiency % 92.1 Expander total inlet pressure bar 17.9 Expander static outlet pressure bar 1.1 Mechanical efficiency % 88.7 Generator electrical/mechanical efficiency % 99/99.5 Sizing of the entire IGCC plant is governed by the gas turbine as it requires a specific amount of fuel depending on the fuel properties and composition. The operating condition of the GT is determined by matching the operating characteristics of the compressor and the expander. Thus, if the gas flow rate varies at the expander inlet, e.g. due to the change of syngas composition, the operating condition of the GT adapts to this change. This could result in change of pressure ratio even at similar firing temperature. The technical assumptions for GT modeling at its design condition (NG-fired) are presented in Table 1. 3.2. Boundary conditions For modeling of the gas turbine, ISO standard conditions have been considered. The ambient air conditions and composition are shown in Table 2. Table 2. Ambient air composition and conditions Components Unit Value H2O wt% 0.63 N2 wt% 75.10 O2 wt% 23.01 Ar wt% 1.21 CO2 wt% 0.05 Ambient air pressure bar 1.013 Ambient air temperature °C 15 Relative humidity % 60 The investigated fuels in this study included (A) natural gas, (B) H 2-rich syngas, and (C) clean (non-captured) syngas. The corresponding composition and characteristics of each fuel based on the previously described plants’ layouts and thermodynamic models in sections 2 and 3 are given in Table 3. Table 3. Composition a and characteristics of investigated fuels Components Fuel A Fuel B Fuel C (NG) (H2-rich syngas) (clean syngas) wt% mol% wt% mol% wt% mol% CO 0.0 0.0 5.4 1.2 79.7 60.4 CO2 0.4 0.1 24.1 3.3 5.6 2.7 H2 2.6 17.9 28.9 86.8 2.7 28.1 H2O 0.0 0.0 0.1 0.0 0.0 0.0 N2 0.0 0.0 41.5 8.7 12.0 8.8 CH4 93.0 80.6 0.0 0.0 0.0 0.0 C3H8 4.0 1.3 0.0 0.0 0.0 0.0 Pressure (bar) 30 30 30 Temperature (°C) 30 30 30 LHV (MJ/kg) 49.7 35.3 11.3 To evaluate the impact of the fuel change on the selected gas turbine technology in IGCC application, various simulation setups with different boundary conditions such as TIT, turbine outlet temperature (TOT), etc. have been considered, as shown in Table 4. As mentioned earlier, the reference GT was chosen as being NG fuelled. However, it should be mentioned that the target of the H2-IGCC project is a plant operated with H2-rich fuel (without major changes to the original gas turbine design) and NG operation is only considered as backup. The clean syngas (non-captured) operation is considered as an off-design alternative when the carbon capture unit is bypassed. 6 Table 4. Different setups for investigation of the fuel change effects on the gas turbine performance Parameter Case I Case II Case III Case IV Case V TIT (°C) 1266 Calculated 1266 Calculated Calculated VIGV Fully open Fully open Calculated Fully open Calculated PR Calculated a 18.2 18.2 Calculated 18.2 TOT (°C) Calculated Calculated Calculated 577 577 In addition to those parameters marked as ‘Calculated’ in Table 4, other variable parameters including GT gross power, GT efficiency, and the surge margin were also studied. The simulation results are presented and discussed in the next section. 4. RESULTS AND DISCUSSION The main focus of this study was evaluation of the impact of fuel change on the GT performance. In this section, A, B, and C represent different fuels, namely NG, H2-rich syngas, and clean (non-captured) syngas, respectively. The effects of different parameter setups listed in Table 4 are the same for the NG-fired gas turbine, as these parameters are the design parameters of the reference engine. Therefore, the effect of varying operating conditions on NG-fired GT is only reported as Case A. 1.2 1.1 5 Inlet air flow Gross power SM TIT TOT Fuel flow PR GT efficiency 4.5 4 1 0.9 3 0.8 2.5 2 0.7 Relative fuel flow Relative value 3.5 1.5 0.6 1 0.5 0.5 0.4 0 Case A Case BI Case CI Fig.4. Effect of fuel change on relevant performance parameters at fully open VIGV and constant TIT Fig.4 shows the effect of fuel change on relevant performance parameters, such as pressure ratio, gross GT power, TOT, fuel flow, and surge margin when the TIT is kept constant and the VIGV is fully open. Change of fuel from NG to H2-rich syngas, when keeping the VIGV fully open and TIT constant (A to BI), increases the pressure ratio by 0.6 over the compressor. The pressure ratio of Case CI increases by 1.3 compared to the reference Case A. The reasons for pressure increase in both cases are the higher fuel mass flow in combination with unchanged compressor air flow, which leads to an increased total mass flow through the turbine, to maintain the TIT unchanged. When using H2-rich syngas, the power output increases compared to the NG operation due to the higher hot gas flow rate through the expander at a constant TIT (i.e. 1266 °C). This is because of the higher enthalpy drop through the expander due to the higher H2O content in the H2-rich syngas and also in the flue gas according to [13]. Comparison of the gross power output for all cases, presented in Fig.4, shows that operating with H2-rich fuel (Case BI) results in the highest power output, 311.6 MW, which is 7% higher than the NG-fired case, i.e. 291.2 MW. Operating with the clean syngas at a similar setup (Case CI) shows 5% higher gross power output than for the reference case. Nevertheless, Case CI delivers 6 MW less power compared to Case BI due to changing hot gas composition and properties, such as lower H2O content. One of the major design concerns for the engine lifetime is the TOT. This indicator is not affected very much by the fuel change from NG to H2-rich syngas. However, the marginally lower TOT for Case BI compared to that for Case A will result in an insignificant drop of power output from the steam cycle downstream of the GT. Despite the increased pressure ratio for Case CI compared to the NG-fired GT (A), 10 °C higher TOT (587 °C) is observed for Case CI. Higher TOT would lead to considerable reduction of the lifetime of the last expander stage. The fuel flow increases with fuel change from NG to H2-rich syngas from 14.9 kg/s to 21.9 kg/s due to the lower calorific value of the H2-rich fuel compared to NG. The fuel mass flow difference becomes significantly higher for the case with clean syngas fuel reaching 69.3 kg/s. Referring to the IGCC cycle, where the CO2 capture unit 7 has been bypassed, the syngas production rate increases even though the amount of coal remains unchanged. This is mainly related to changed details inside the overall fuel gas treatment/preparation process. Concerning the surge margin, which is mandatory to ensure stable operation of the compressor, a relative reduction of 22% is observed when using H2-rich fuel instead of NG. However, the remaining surge margin would still be sufficient. Operation of the engine with clean syngas at the same operating setup (i.e. CI) results in a relative reduction of the surge margin by 50%, which brings the compressor close to the surge limit. αIGV MControl PR TOT Fuel ṁf Ballast VIGV Mc1 Me Mc2 Compressor Expander Mc3 Air Exhaust gas To ASU Fig.5. Different gas turbine modifications to reduce fuel change effects In remedy of the main problems caused by switching from NG to clean syngas (and to some extent to H2-rich syngas), such as unstable operation and reduced lifetime of the turbine blades, various options might be considered. These options are illustrated in Fig. 5 and described below. Modification of the control rules Running the GT safely under different combinations of VIGV, pressure ratio, TIT and TOT is usually an appropriate option. In order to solve the problem of increased pressure ratio and reduced surge margin when the GT is operated on H2-rich and clean syngas, the second and third parameter setups, i.e. Case II and III (refer to Table 4) are considered. The corresponding results to the fuel change effect on various performance indicators using aforementioned simulation setups are shown in Fig.6. Keeping the pressure ratio at its design value (i.e. 18.2) and VIGV fully open results in significant reduction of TIT and thereby GT efficiency drop, which is more pronounced for Case CII compared to that for Case BII. As shown in Fig.6, the gross power output for both H2-rich syngas and clean syngas operations decreases for parameter setup II. The gross power outputs of Case BII and Case CII are reduced by 8.6 and 57.1 MW, respectively compared to that of NG-fired GT (Case A). The negative effect of this parameter setup is not limited to the GT block alone. The TOT also significantly drops for Case BII (533 °C) and Case CII (522 °C) compared to Case A (577 °C) leading to lower overall plant efficiency due to the reduced steam cycle efficiency and power output. 8 1.1 Inlet air flow TOT TIT GT efficiency PR SM 5 Gross power Fuel flow 4.5 1 4 3.5 3 0.8 2.5 0.7 2 Relative fuel value Relative value 0.9 1.5 0.6 1 0.5 0.5 0.4 0 Case A Case BII Case BIII Case CII Case CIII Fig.6. Effect of fuel change on relevant performance parameters (at fixed PR) Parameter setup III (fixed TIT and PR), which is considered to see the effect of VIGV position on the performance of the GT, shows no improvement. It is also evident that such a setup is not useful to keep the necessary margin to the surge condition (refer to Case BIII and Case CIII in Fig.6). Compared to Case A, the surge margin is reduced by 30% and more than 50% even though the VIGV is closed by 9% and 20% for cases BIII and CIII, respectively. In addition, TOT increases considerably at setup III for both H2-rich syngas and clean syngas by 4 and 20 °C, respectively. To avoid unstable operational conditions, to reduce power output, and to eliminate the risk of reduced lifetime of the expander last stage blades in Case C (clean syngas), the parameter setups IV and V (refer to Table 4) are also considered. The TOT of the GT is fixed at its design value for NG-fired case (i.e., 577 °C). It should be noted that simulation results for Case BIV and Case BV are not shown in Fig.7 since none of them offer better performance compared to BI. However, the results relevant to clean syngas operation are shown in Fig.7. Obviously, parameter setup IV would be a better solution due to the increased surge margin and power output compared to setup V. Although, the gross power output of the GT increases for Case CIV compared to Case A, the surge margin is still very low and shows 42% reduction compared to the NG-fired GT. 1.1 Inlet air flow TIT PR Gross power TOT GT efficiency SM Fuel flow 5 4.5 1 4 3.5 3 0.8 2.5 0.7 2 Relative fuel value Relative value 0.9 1.5 0.6 1 0.5 0.5 0.4 0 Case A Case CIV Case CV Fig.7. Effect of fuel change on relevant performance parameters (at fixed PR and TOT) Modification of the compressor flow path In order to reduce the air mass flow, while keeping the pressure ratio close to the design value, the following alternatives (shown as Mc in Fig.5) could be considered: 9 Mc1: Modification of the first compressor stator vanes to reduce the air mass flow. This modification would also change the last stage height rather extensively. Moreover, a ballast flow (N2 or steam) has to be injected when H2rich syngas is used as fuel (which has a higher LHV compared to non-captured syngas) into the combustor. The flow of the ballast needs to be reduced, when the LHV of the fuel gas decreases and the syngas flow increases (e.g. at clean syngas operation). Mc2: The addition of one or more rear stages to the compressor with adapted clearances to allow the reduction of the compressed air mass flow rate when the pressure rises. An intrinsic internal flow control would be required to maintain the high pressure while the mass flow reduces. However, it would result in reduced compression efficiency and consequently in reduced GT efficiency. In general, this option would result in a lower penalty to the GT efficiency and stable operating conditions. However, this requires major modifications to the compressor and expander as well as adjustment of the vanes’ and blades’ cooling paths. Mc3: In order to compensate for the increased fuel mass flow when a syngas with low calorific value is used, a fraction of the compressed air could be discharged at the compressor outlet. A loss of efficiency is foreseeable if an internal use of compressed air is not considered. The most efficient use of the bleed stream is in the ASU. The integration of the GT compressor and ASU would reduce the power demand of the main air compressor and slightly increase the overall plant efficiency. However, as mentioned previously, this integration has not been considered within the H2-IGCC project as it results in reduced plant availability. Modification of the expander flow path The other option to reduce the effect of fuel change is to modify the expander. The expander nozzle guide vanes (NGVs) could be re-staggered (shown as Me in Fig.5) to increase the swallowing capacity of the expander. The vane and blade cooling paths should be modified accordingly. However, this might also result in a reduction of the peak efficiency. Adoption of such an option reflects the fact that industry prefers modifications to the expander side. Nevertheless, extensive modifications to the expander should be also avoided as it will be costly. Other secondary alternatives In order to compensate for the increased clean syngas flow, supplementary firing of a portion of the fuel could be considered to increase the total power output of the entire plant. It means in the case of trip of CCS unit, excess cleaned syngas not needed in the GT could be used for supplementary firing leading to increased overall power output of the combined cycle. Another option to combust the extra fuel together with some air blown off at the compressor exit is the utilization of a second expander. Nevertheless, techno-economic evaluations are required to predict the penalties imposed by the use of a second combustor or expander. The results will mainly depend on the expected operating hours of this additional unit, as well as fuel costs. 5. CONCLUSIONS The effect of fuel change (i.e. from NG to H2-rich syngas and clean syngas) on the selected GT was reported in this paper. Based on the results, focusing only on the gas turbine as a stand-alone unit, operation with H2-rich fuel is feasible if a reduced surge margin would be acceptable. The clean syngas operation (in non-capture IGCC plant) results in significantly lower surge margin and higher turbine outlet temperature compared to the reference case especially at off-design conditions, which requires engine modification. Results confirm that running the engine with H2-rich fuel without significant changes compared to the NG-fired engine can be carried out from a turbomachinery point of view. However, it should be noted that the challenges concerning pre-mixed combustion of the H2-rich fuel and different heat transfer rate to the expander materials when operated with H2-rich fuel are not covered in this paper. When operating with a fuel with low calorific value, such as clean syngas, expected operational hours are very important for the selection of appropriate operating conditions or modification options. Although several modification options as well as operating strategies have been suggested in case of clean syngas operation, reduced efficiency and compressor stability range could be tolerated for limited operational hours with clean syngas. Nevertheless, the best combination of the GT power output and efficiency has to be searched for, taking into account the whole IGCC performance as well as investment and maintenance costs, when clean syngas operation is one of the requirements of the plant. Moreover, it was demonstrated that altered VIGV angle doesn’t provide acceptable surge margin for the selected GT. In order to have only minor modifications to the GT for clean syngas operation compared to the design case, decreasing the TIT and maintaining similar TOT as for the reference case (NG-fired GT) with fully open VIGV could be a plausible option. However, results showed significant reduction of efficiency and power output for this specific option. It should be highlighted that using clean syngas requires major modifications to the GT including additional compressor stages, air bleed from compressor outlet, and re-staggering of the expander nozzle wanes. Therefore this option was omitted from the list of possible alternatives for the H2-IGCC project. ACKNOWLEDGMENT The authors are grateful to the European Commission’s Directorate-General for Energy for financial support of the Low Emission Gas Turbine Technology for Hydrogen-rich Syngas (H2-IGCC) project. The authors also wish to acknowledge Han Raas at Vattenfall for performing the gasification simulations. Constructive discussions and data exchange with Professor G. Cerri and his group at Roma Tre University are also acknowledged. 10 NOMENCLATURE A cross-sectional area AGR acid gas removal ASU air separation unit CCS carbon capture and sequestration CO carbon monoxide COS carbonyl sulfide CO2 carbon dioxide cp specific heat GHG greenhouse gas GT gas turbine HRSG heat recovery steam generator H2 hydrogen H2S hydrogen sulfide IGCC integrated gasification combined cycle LHV lower heating value LNG liquefied natural gas LP low pressure MAC main air compressor ṁ mass flow rate NG natural gas NOx nitrogen oxide N2 nitrogen OEM original equipment manufacturer O2 oxygen P power p pressure PGAN pure gaseous nitrogen PR pressure ratio R gas constant SCGP Shell Coal Gasification Process SOA state-of-the-art SOx sulfur oxide SWGS sour water-gas shift T temperature TIT turbine inlet temperature TOT turbine outlet temperature VIGV variable inlet guide vane Greek Letters γ specific heat ratio κ choked flow coefficient η efficiency Subscripts i expander inlet o expander outlet t total condition REFERENCES 1. 2. 3. 4. 5. 6. 7. 8. 9. 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Siemens, Siemens gas turbine SGT5-4000F, 2008, Siemens AG: Erlangen, Germany. 12 Paper V Techno-economic evaluation of an IGCC power plant with carbon capture Mohammad Mansouri Majoumerd, Mohsen Assadi, Peter Breuhaus Presented at ASME Turbo Expo 2013, San Antonio, Texas, USA, June 2013 175 Proceedings of ASME Turbo Expo 2013: Turbine Technical Conference and Exposition GT2013 June 3-7, 2013, San Antonio, Texas, USA GT2013-95486 TECHNO-ECONOMIC EVALUATION OF AN IGCC POWER PLANT WITH CARBON CAPTURE Mohammad Mansouri Majoumerd1, Mohsen Assadi1,2, Peter Breuhaus2 1 2 Faculty of Science and Technology International Research Institute of Stavanger (IRIS) University of Stavanger Postbox 8046 4036 Stavanger, Norway 4068 Stavanger, Norway Abstract Nomenclature Most of the scenarios presented by different actors and organizations in the energy sector predict an increasing power demand in the coming years mainly due to the world’s population growth. Meanwhile, global warming is still one of the planet’s main concerns and carbon capture and sequestration is considered one of the key alternatives to mitigate greenhouse gas emissions. The integrated gasification combined cycle (IGCC) power plant is a coalderived power production technology which facilitates the pre-combustion capture of CO2 emissions. AGR ASU BEC BOP CCF CCS CEPCI CF COE CO CO2 EPCC After the establishment of the baseline configuration of the IGCC plant with CO2 capture (reported in GT201145701), a techno-economic evaluation of the whole IGCC system is presented in this paper. Based on publicly available literature, a database was established to evaluate the cost of electricity (COE) for the plant using relevant cost scaling factors for the existing sub-systems, cost index, and financial parameters (such as discount rate and inflation rate). Moreover, an economic comparison has been carried out between the baseline IGCC plant, a natural gas combined cycle (NGCC), and a supercritical pulverized coal (SCPC) plant. GHG GT HHV HRSG H2 H2O IGCC LHV NG NGCC NOAK OECD The calculation results confirm that an IGCC plant is 180% more expensive than the NGCC. The overall efficiency of the IGCC plant with CO2 capture is 35.7% (LHV basis), the total plant cost (TPC) is 3,786 US$/kW, and the COE is 160 US$/MWh. O2 O&M SCGP SCPC ST SWGS 1 Acid gas removal Air separation unit Bare erected cost Balance of plant Capital charge factor Carbon capture and sequestration Chemical Engineering Plant Cost Index Capacity factor Cost of electricity Carbon monoxide Carbon dioxide Engineering, procurement, and construction cost Greenhouse gas Gas turbine Higher heating value Heat recovery steam generator Hydrogen Water Integrated gasification combined cycle Lower heating value Natural gas Natural gas combined cycle nth-of-a-kind Organization for Economic Co-operation and Development Oxygen Operation and maintenance costs Shell coal gasification process Super critical pulverized coal Steam turbine Sour water-gas shift Copyright © 2013 by ASME TASC TOC TPC TS&M Total as-spent cost Total overnight cost Total plant cost Transport, storage, and monitoring water-gas shift and the capture system, there is currently no full-scale IGCC power plant built with CCS. Therefore, further investigation of the various methods to increase the availability of the system, to evaluate the associated operational risks, and to reduce the efficiency penalty and the cost of CO2 avoidance in IGCC plants is necessary. 1. Introduction The global financial situation during the past few years has resulted in falling investments in the power sector, especially in OECD (Organization for Economic Co-operation and Development) countries [1]. However, global energy demand is steadily increasing, mainly due to the world’s population growth. A greater part of this increasing demand comes from non-OECD countries. It is assumed that electricity generation will be the largest source of primary energy consumption in the coming decades [2]. Among various fossil fuels, coal had the fastest consumption growth rates in 2011 compared to 2010 [3]. According to the International Energy Agency’s “new policies” scenario, coal consumption in the year 2035 will have a 25% increase compared to 2009. However, based on the “current policies” scenario, this increase will be 65% compared to the level of 2009 [4]. The main reasons for this are the abundant resources of coal (more than 100 years with current proved reserves) and its widespread availability compared to the other fossil fuels [3, 5-7]. Besides technical issues, economic figures play a major role in the commercialization of a technology. The commercial investment in an IGCC plant requires competitive cost of electricity (COE) compared to other competing power generation technologies [13]. To find out the COE for the IGCC plant, a techno-economic investigation is vital. However, the economic analysis of this plant is more complicated than for other power generation technologies e.g. natural gas combined cycle (NGCC), because of the large number of components used in an IGCC plant. Moreover, there are several alternative sub-systems to select, e.g. for the gasification block (e.g. Shell, GE, Siemens, etc.) with their own specific costs and characteristics. Therefore, an IGCC plant is not considered as a standardized commercial technology with well-established costs [14]. Moreover, other factors such as market situation, fuel price, CO2 allowances cost and currency fluctuations increase the level of uncertainty in cost estimation. The necessity to abate greenhouse gas (GHG) emissions will result in the deployment of carbon capture and sequestration (CCS) in the power production sector. CCS will play a key role in curbing CO2 emissions, according to the European Energy Roadmap 2050 [8]. Moreover, the deployment of CCS in coal-fired power production will ensure that coal will have its share in fossil fuel consumption in future years with more restricted emissions’ regulations, even though the CO2 emissions from coal combustion are significantly higher than those for natural gas (NG). Though the prediction of the investment costs for the IGCC plant is a difficult task, this study attempts to provide a rough estimate in order to illustrate the plant’s economic status. The objectives of this study are to analyze the economic indicators of the IGCC plant with CO2 capture and to compare them with other fossil fuel power generation technologies, i.e. NGCC and supercritical pulverized coal plant (SCPC) with CCS. Since the emphasis in this work has been dedicated to the economic evaluation of the selected IGCC plant, the detailed description of thermodynamic modeling is not repeated here. The description of simulations using Enssim software [15], ASPEN Plus [16], and IPSEpro [17] could be found in references [12, 18]. During the last two decades, the integrated gasification combined cycle (IGCC) has been assumed to be one of the most attractive coal-based technologies for generating electricity from coal in terms of low environmental impact [9-11]. Although each of the major sub-systems of the IGCC system has been widely used in industrial applications, their integration in the IGCC plant is not well-matured yet, and such a plant is considered to be complex from the plant owner’s perspective. This complexity may prevent investments in IGCC plants due to higher risk for low availability and consequently higher cost of electricity compared to other fossil fuel-based power technologies. 2. IGCC configuration The integrated gasification combined cycle plant with CO2 capture (refer to Fig. 1) comprises the following sub-systems: Cryogenic air separation unit (ASU) to provide O2 for the gasification process and N2 as the conveying gas. Shell coal gasification process (SCGP) to produce syngas from coal using O2 and intermediate pressure steam [19]. Sour water-gas shift (SWGS) reaction unit to convert CO and steam to CO2 and H2 using exothermic catalytic reaction [20]. Incorporating a water-gas shift reaction unit into the IGCC plant facilitates the pre-combustion capture of CO2 [11, 12]. However, due to the associated efficiency penalty imposed by CO2 capture and the high investment cost of 2 Copyright © 2013 by ASME Acid gas removal (AGR) unit to remove the H2S content of the syngas using physical solvent (SELEXOL) [18]. CO2 capture unit to remove the CO2 content of the syngas. CO2 compression and dehydration unit to ensure the final CO2 conditions for transport and storage. Gas turbine (GT) to produce electricity by combustion of H2-rich syngas [18]. Heat recovery steam generator (HRSG) to utilize the energy in the hot exhaust gas from the GT for steam and electricity production. Steam turbine (ST) to produce electricity from steam produced in the HRSG. The main technical specifications for simulation of the whole IGCC system are shown in Table A.1 (Appendix I). Reference [18] contains further technical assumptions. Fig. 1: The schematic figure of the IGCC power plant with CO2 capture 3) Operation and maintenance (O&M) costs 3.1) Fixed costs e.g. labor cost 3.2) Variable costs e.g. chemicals, solid waste handling, CO2 emissions cost, etc. 4) CO2 transport, storage and monitoring costs 3. Plant economics The methodology used for cost estimation for the IGCC plant is based on the “Quality Guidelines for Energy System Studies” by the United States’ National Energy Technology Laboratory (NETL) [21]. An estimation of the COE for an IGCC plant with CCS comprises the following items: The following sub-sections describe the aforementioned cost components. 1) Capital costs 2) Fuel cost 3 Copyright © 2013 by ASME 3.1. Capital costs EPCC The capital costs have been defined based on the following five different cost levels: The EPCC for all major components of the IGCC plant are about 8% of the BECs of the corresponding components [22]. 1) Bare erected cost (BEC): This cost comprises process equipment items, supporting facilities (e.g. labs, roads, etc.), and the direct and indirect labor required for the construction and installation of equipment items. 2) Engineering, procurement and construction cost (EPCC): This cost comprises the BEC plus the cost of the engineering, procurement and construction services. 3) Total plant cost (TPC): This cost comprises the EPCC plus project and process contingencies. 4) Total overnight costs (TOC): This cost comprises the TPC plus owner’s costs. 5) Total as-spent cost (TASC): This cost is the sum of all capital expenditures as they are incurred during the capital expenditure period including their escalation. TASC also includes interest during construction. TPC The project and process contingencies to calculate TPC are assumed to be 18% and 5% of the BECs, respectively [22]. TOC The sum of the TPC and the owner’s costs is the total overnight cost of a plant. The assumptions for owner’s costs are shown in Table 1 below. Table 1: Assumptions for owner’s costs Parameter Pre-production costs BEC The estimation of the BEC for the major components of the IGCC plant (except the gas turbine) is derived from the detailed study of NETL [22]. Inventory capital The cost of the gas turbine is derived from the 2009 Gas Turbine World Handbook [23]. Since the GT in this study has some add-on options such as a new burner design to combust H2-rich fuel (instead of natural gas), new cooling air flow design, and sophisticated materials for the expander section, a 15% cost increase is assumed here. Although a GT with these characteristics is not available on the market, the cost for a mature nth-of-a-kind (NOAK) GT was considered. Initial cost for catalyst and chemicals Plant site area Other owner’s costs Financing costs The overnight cost of a component ( ) with specific size ( ) based on a reference component ( ) with reference size ( ) is shown by the following Eq. 1: a Comment 6 months’ operating labor costs 1 month’s maintenance materials cost at 100% CFa 1 month non-fuel consumables at 100% CF 1 month waste disposal 25% of 1 month fuel cost at 100% CF 2% of TPC 60-day supply of fuel and non-fuel consumables at 100% CF 0.5% of TPC (spare parts) US$7413/hectare for a land (greenfield without seismic consideration) with area of 121 hectares 15% of TPC 2.7% of TPC Capacity factor TASC (Eq. 1) This cost vary based on the capital expenditure period and the financing scenario (for further information refer to [22]). The interests during the construction period are included in the TASC. The ratio of TASC/TOC for the IGCC plant with CO2 capture for five years of construction is set to 1.140. where is the number of equally sized equipment trains operating at 100%/n, is the cost scaling exponent for multiple trains of the component, and is the cost scaling factor. Adjustments of costs (except for the GT) have been carried out using the Chemical Engineering Plant Cost Index (CEPCI) of April 2012 [24]. The graph of the simple cycle price change available in reference [25] has been used for the fluctuation of the gas turbine price. 3.2. Other assumptions It should be noted that all costs are limited to “within the fence line”, except the costs of CO2 transport, storage and monitoring (TS&M). Other economic assumptions employed for the cost estimation are shown in Table 2. 4 Copyright © 2013 by ASME sensitivity analysis, illuminating the impact of cost/price variations. Finally, results of economic evaluation for various power plants i.e. IGCC, NGCC, and SCPC plants are presented and discussed. Calculation of the cost of electricity is based on the following Eq. 2: (Eq. 2) where is the capital charge factor, is the sum of all fixed annual operating costs, is the sum of all variable annual operating costs, and is annual net megawatt-hours of power generated at 100% capacity factor (CF). 4.1. Thermodynamic results The performance indicators of the IGCC plant with CO2 capture are given in Table 3. Table 3: Performance indicators of the IGCC power plant with carbon capture Table 2: Economic assumptions Parameter Coal price1,2 NG price3 IGCC capacity factor NGCC capacity factor SCPC capacity factor NGCC net power output SCPC net power output NGCC overall efficiency SCPC overall efficiency NGCC CO2 capture rate SCPC CO2 capture rate NGCC plant site area SCPC plant site area TASC/TOC for NGCC TASC/TOC for SCPC CCF4 for IGCC and SCPC CCF for NGCC CO2 allowances cost5 CO2 TS&M for IGCC6 CO2 TS&M for NGCC CO2 TS&M for SCPC Labor work Operating labor cost7 Discount rate Inflation rate Real escalation rate Value 110 32.79 80 85 85 473.6 550.0 47.5 29.5 90.7 90.2 1/3 1 1.078 1.140 0.124 0.111 7.36 4.3 3.2 5.6 50 31.18 12 3 0 Unit US$/tonne US$/MWh % % % MW MW % LHV % LHV % % of IGCC land similar to IGCC €/tonne of CO2 US$/MWh US$/MWh US$/MWh h/work.week US$/h.capita % % % Performance indicators GT shaft power output ST shaft power output Generator power output ASU compression power demand Gasification power demand Syngas cleaning compression and pumping demand Syngas cleaning refrigeration power demand CO2 compression power demand HRSG pumping power demand Total auxiliary power demand Net power output Overall IGCC efficiency (%LHV) MW 324.0 177.4 501.4 49.8 5.0 10.9 9.2 20.8 3.4 99.1 402.2 35.7 Fig. 2 shows the share of auxiliary power demands for the IGCC plant. Simulation results confirm that the ASU has the largest auxiliary power demand with 50.3% of the total auxiliary power demand. Gasification power demand 4 % 5 % ASU compression power demand 21 % AGR pumping and compression power demand 9 % 50 % 1 Coal price is based on API N2, 6000 kCal NAR (CIF) [26]. The USD to Euro exchange rate is 0.7527 [27]. 3 NG price is based on Zeebrugge price [26]. 4 Capital charge factor 5 The cost of CO2 emissions is based on European Union emission trading scheme [26]. 6 This cost is derived from reference [22], adjusted using CO2 captured and assumed to be constant and free of fluctuations (from 2007 to 2012) due to the technology improvement. The captured CO2 is transported 80 km. 7 Labor cost have been updated based on EU Labor Cost for EU27 countries from European Commission reports [28, 29]. 2 11 % AGR refrigeration power demand CO2 compression power demand HRSG pumping power demand Fig. 2: The share of auxiliary power consumptions 4.2. Cost estimations The results of the estimation of overnight costs for major components of the IGCC plant with CO2 capture using (Eq.1) and reference [22] are shown in Table 4. It should be mentioned that the uncertainty of this type of cost estimation is about ±30%. It is worth noting that the information given in Table 4 is based on June 2007 US$, without incorporating 4. Results and discussion In this section, results of thermodynamic simulation are presented followed by results of the plant’s economic and 5 Copyright © 2013 by ASME has been adjusted to April 2012. Moreover, the GT price which is given in Table 4 is the price for 2009. As it was mentioned in Section 3.1, all of these costs have been adjusted using relevant cost indexes. the installation labor cost. Given the same labor cost for the installation of a component with two different sizes, this cost has been considered to be the same as in reference [22]. However, using the US Bureau of Labor Statistics (BLS), data for chemical manufacturing, the installation labor cost Table 4: Capital costs for major components of the IGCC power plant # 1 2 3 4 5 6 7 8 9 10 11 12 13 14 Plant component Coal handling, preparation and feed Gasifier and accessories ASU Gas clean-up CO2 compression and drying GT1 HRSG, ducting and stack ST generator, condenser, aux. Cooling water, aux. Feed water and miscellaneous BOP Ash and slag handling Instrumentation and control2 Building and structures Other (improvements to site, accessory electric plant) Scaling parameter Coal input (tonne/h) Coal input (tonne/h) O2 production (kmol/h) Syngas flow rate (tonne/h) Compression power (MWe) GT net power (MWe) ST gross power (MWe) ST gross power (MWe) ST gross power (MWe) Ash content of the coal (tonne/h) Plant net power (MWe) Plant net power (MWe) 3 211040 211040 4642 575 30.2 464 209.4 209.4 209.4 21.1 496.9 496.9 0.67 0.67 0.67 0.67 0.67 0.67 0.67 0.67 0.67 0.67 1 0.67 0.67 3 16461 180256 173504 95090 17811 161436 161436 4004 439 20.8 39499 33914 19404 16678 20018 13026 6461 47953 324 177.4 177.4 177.4 20.2 402.2 402.2 13756 150635 154999 79346 13852 73373.6 31052 30344 17362 14922 19410 13026 5608 41622 1 The price for the GT was derived from Gas Turbine World handbook [23] and the reference GT for this study is Siemens/Ansaldo Energia V94.3A. 2 A similar cost has been used for instrumentation and control cost. 3 All costs (i.e. C and C) in US$×1000. Table 5 shows results of the economic analysis for the IGCC plant with CCS, based on the information given in Table 4 and assumptions described in Section 3. plant owners, confirm the range of TPC reported in this study. Table 5: Various cost indicators for the IGCC plant In order to evaluate the sensitivity of the economic results to variations in the inputs, a sensitivity analysis has been performed to identify the parameters which have the strongest impact on the results. Results highlight possible drivers which may influence market attention on this technology. Parameter Total plant cost (TPC) Total overnight cost Total as-spent cost (TASC) COE (base year-2012) COE (1st year of operation-2017) 4.2.1. Economic sensitivity Unit US$*1000 US$/kW 1,523,051 3,786 1,881,257 4,677 2,144,633 5,332 US$/MWh 160 186 Table 6: Economic parameters and their variation range for sensitivity analysis Parameter Coal price Capacity factor CO2 allowances cost The TPC for the IGCC plant with CO2 capture has been reported to be in the range of 1,414-2,513 in references [3032]. The range of COE has been reported to be 54-95.8 US$/MWh [30-32]. The above-mentioned reported figures are far below the range of COE and TPC calculated in the current study. This difference may be due to the different coal price, power plant size, capacity factor and financial assumptions used. However, the Electric Power Research Institute (EPRI) report [33] on IGCC shows a TPC of 3,683 US$/kW, which is very close to the number reported in Table 5. Moreover, personal communications with power Absolute range 60 ‒ 160 US$/tonne 40 ‒ 90% 3.7 ‒ 11.0 €/tonne Relative range -45.5 ‒ 45.5% -50 ‒ 12.5% -50 ‒ 50% Three parameters which are usually considered as the most uncertain parameters for calculation of the COE were selected. These parameters and their variation for sensitivity analysis are shown in Table 6. The results of the sensitivity analysis are presented in Fig. 3. 6 Copyright © 2013 by ASME is the coal price, while the impact of CO2 allowances cost is negligible. The minimal effect of the CO2 price is due to the low absolute value of CO2 allowances cost. However, its influence will change depending on the CO2 market development and change in global mitigation policies. 80.0 70.0 COE Change (%) 60.0 50.0 40.0 30.0 20.0 4.2.2. Results of the comparative plant economics 10.0 0.0 ‐10.0‐60.0 ‐40.0 ‐20.0 0.0 20.0 40.0 Using assumptions presented in Table 2, Fig. 4 shows results of the comparative study of various plants’ capital cost items. 60.0 ‐20.0 Capacity Factor Parameter Variation (%) Fuel Cost CO2 Allowances cost The TOCs of IGCC, SCPC, and NGCC plants are 4677, 4065, and 1669 US$/kW, respectively. According to Fig. 4, the highest capital cost is required for the IGCC plant. The TOC and TASC for the IGCC plant are 15% higher than the corresponding values for the SCPC plant (the basis for comparison is the SCPC). Fig. 3: Sensitivity response on COE for the IGCC plant under variation of fuel cost, capacity factor, and CO2 allowances cost It is evident from Fig .3 that the capacity factor has the largest influence on the COE. The second ranked parameter 5331.7 TOC and TASC, US$/kW (2012$) 6000.0 4633.6 5000.0 4000.0 3000.0 1799.7 2000.0 1000.0 0.0 Total overnight cost (TOC) TASC TOC IGCC TASC TOC SCPC TASC NGCC Total as‐spent cost (TASC) Owner's cost Process contingency Project contingency Engineering, procurement, and construction cost (EPCC) Bare erected cost (BEC) Fig. 4: Plant capital costs for IGCC, SCPC, NGCC plants with CO2 capture The TOC and TASC for the IGCC plant are 180% and 196% higher than corresponding values for the NGCC plant (the basis for comparison is the NGCC). Even though there is a large gap between the IGCC and the NGCC, the future investment in the IGCC plant is very plausible due to the security of energy supply. Despite the higher cost for the IGCC plant compared to the SCPC plant, investment in such a plant may be beneficial in the coming years with more stringent environmental regulations due to: a) advantages of gasification such as easier control of gaseous pollutants, and b) advantages of the pre-combustion capture, such as high CO2 concentration and smaller equipment size because of high fuel gas pressure. 7 Copyright © 2013 by ASME plant, as well as relevant assumptions, calculation methods, and economic figures. Results of the COE for the IGCC, SCPC, and NGCC plants are shown in Fig. 5. The total COEs for IGCC, SCPC, and NGCC plants are 160, 148, and 114 US$/MWh, respectively. The COE for the IGCC plant is 8% and 41% higher than COEs for SCPC and NGCC plants (bases for comparisons are COEs of the SCPC and NGCC, respectively). The COE for the IGCC plant with CCS is 160 US$/MWh. It should be noted that all economic results are strongly dependent on presented assumptions. A sensitivity analysis was also carried out showing that the most influential parameter on the COE was the capacity factor. The fuel price was the second ranked parameter, while the effect of CO2 allowances cost was negligible due to the low cost of CO2 emissions. Finally, a comparative study was carried out to highlight the cost difference between various power generation technologies i.e. IGCC, SCPC, and NGCC plants with CCS. The total overnight costs for IGCC, SCPC, and NGCC are 4677, 4065, and 1669 US$/kW, respectively. The results of the COE for the IGCC, SCPC, and NGCC are 160, 148, and 114 US$/MWh, respectively. Even though the investment cost in the IGCC plant is more than double that for the NGCC plant, the security of the energy supply may encourage investors to select IGCC plants. 180.0 COE, US$/MWh (2012$) 160.0 140.0 120.0 82.8 67.7 24.9 100.0 80.0 60.0 40.0 5.8 3.2 13.4 10.4 18.0 11.0 76.6 51.3 44.1 20.0 3.2 5.6 4.3 0.0 IGCC SCPC Capital costs Fixed costs Fuel costs CO2 TS&M Moreover, it was shown that with the higher capacity factor and CO2 allowances cost, which is plausible in the coming years, the IGCC plant could attract more investments compared to the SCPC plant. Furthermore, income from poly-generation applications might also improve the economic status of future IGCC plants. NGCC Variable costs Fig. 5: COE for IGCC, NGCC, and SCPC plants with CO2 capture Acknowledgment As mentioned before (refer to Fig. 3), one of the most effective solutions for reducing the difference in COEs for IGCC and SCPC plants is to increase the capacity factor of both IGCC and SCPC plants so that they have a similar value. The authors are grateful to the European Commission’s Directorate-General for Energy for financial support of the Low Emission Gas Turbine Technology for Hydrogen-rich Syngas (H2-IGCC) project. The combination of this increase and the increased CO2 allowances cost may improve investment in an IGCC plant where coal is the most available fuel for power production. The COE for both plants is equal when the capacity factors of both plants and the CO2 allowances cost are set to 90% and 74 €/tonne of CO2, respectively. References 5. Conclusion 1. Birol, F., The impact of financial and economic crisis on global energy investment, 2009, IEA: G8 Energy Ministers' Meeting. 2. BP energy outlook 2030, 2012, British Petroleum Company. 3. BP Statistical Review of World Energy, 2012, British Petroleum Company. The aim of this paper was to carry out a techno-economic analysis for a specific IGCC plant configuration with CO2 capture, and to compare the COE for this plant with competing technologies which are NGCC and SCPC plants. The main objective was to generate a database using publicly available literature to calculate the COE for this plant. 4. IEA, World Energy Outlook 2011. International Energy Agency, 2011: Paris. 5. The initial part of the paper describes the configuration of the IGCC plant. The second part of the paper describes the methodology used for the economic evaluation of the Chiesa, P., Consonni, S, Kreutz, T, Williams, R, Coproduction of hydrogen, electricity and CO2 from coal with commercially ready technology. 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ASME Turbo Expo, Vancouver, Canada. 27. Universal currency converter. 2012; Available from: http://www.xe.com. 28. Labour cost index. 2012; http://epp.eurostat.ec.europa.eu. 13. Rosenberg, W.G., Alpern, D.C., Walker, M.R., Deploying IGCC in this decade with 3 party covenant financing, 2004: John F. Kennedy School of Government, Harvard University. Available from: 29. Eurostat newsrelease- Euro indicators, 2012, Eurostat press office, 134/2012. 30. Rubin, E.S., Chen, C., Rao, A.B, Cost and performance of fossil fuel power plants with CO2 capture and storage. Energy Policy, 2007. 35: p. 4444– 4454. 14. Rosenberg, W.G., Alpern, D.C., Walker, M.R., Financing IGCC – 3party covenant, 2004: John F. Kennedy School of Government, Harvard University. 31. Chen, C., Rubin, ES, CO2 control technology effects on IGCC plant performance and cost. Energy Policy, 2009. 37: p. 915-924. 15. Enssim®, 2009, Enssim Software: Doetinchem, The Netherlands. 16. 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Journal of 9 Copyright © 2013 by ASME Appendix I: Table A.1: The main technical specifications of the IGCC plant Air separation unit O2 purity: 95% Main air compressor: Three-stage inter-cooled to 5.5 bar Gaseous O2 compressor: Six-stage intercooled to 55 bar Pure gaseous N2 compressor: Six-stage intercooled to 80 bar Acid gas removal unit and CO2 capture Solvent type: physical Solvent: SELEXOL Number of absorption stages: 2 Solvent inlet temperature to the absorber: 5 °C CO2 capture rate: 90% (molar basis) Feedstock properties Type: Bituminous coal HHV: 26195 kJ/kg LHV: 25100 kJ/kg CO2 compression and dehydration Final pressure: 150 bar Drying agent: Tri-ethylene glycol Final water content in the CO2 stream: 20 ppm (mass) Gasifier Type: SCGP (O2-blown, entrained flow, dry-fed) Pressure: 45 bar Temperature: 1600 °C Gas turbine Sour water-gas shift reaction unit Heat recovery steam generator Pressure level: 140/43/4 bar Superheating/reheat temperature: 530/530 °C Reaction: CO H O CO H Compressor pressure ratio: 18.2 Firing temperature: 1440 °C Compressor isentropic efficiency: 92.3% Expander isentropic efficiency: 89.2% GT outlet pressure (bar (total)): 1.08 bar Electrical/mechanical efficiency: 99/99.5% Inlet syngas temperature to the reactor: 250 °C steam-to-CO ratio: 2.4 10 Copyright © 2013 by ASME Paper VI Techno-economic assessment of fossil fuel power plants with CO2 capture ‒ Results of EU H2-IGCC project Mohammad Mansouri Majoumerd and Mohsen Assadi Published in International Journal of Hydrogen Energy, Vol. 39, p. 16771-16784, September 2014 187 i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y 3 9 ( 2 0 1 4 ) 1 6 7 7 1 e1 6 7 8 4 Available online at www.sciencedirect.com ScienceDirect journal homepage: www.elsevier.com/locate/he Techno-economic assessment of fossil fuel power plants with CO2 capture e Results of EU H2-IGCC project Mohammad Mansouri Majoumerd a,*, Mohsen Assadi a,b a b Faculty of Science and Technology, University of Stavanger, 4036 Stavanger, Norway International Research Institute of Stavanger, Postbox 8046, 4068 Stavanger, Norway article info abstract Article history: In order to address the ever-increasing demand for electricity, need for security of energy Received 25 June 2014 supply, and to stabilize global warming, the European Union co-funded the H2-IGCC Received in revised form project, which aimed to develop and demonstrate technological solutions for future gen- 6 August 2014 eration integrated gasification combined cycle (IGCC1) plants with carbon capture. As a part Accepted 10 August 2014 of the main goal, this study evaluates the performance of the selected IGCC plant with CO2 Available online 8 September 2014 capture from a techno-economic perspective. In addition, a comparison of technoeconomic performance between the IGCC plant and other dominant fossil-based power Keywords: generation technologies, i.e. an advanced supercritical pulverized coal (SCPC2) and a nat- Techno-economy ural gas combined cycle (NGCC3), have been performed and the results are presented and IGCC discussed here. Different plants are economically compared with each other using the cost Pulverized coal of electricity and the cost of CO2 avoided. Moreover, an economic sensitivity analysis of NGCC every plant considering the realistic variation of the most uncertain parameters is given. CO2 capture Copyright © 2014, Hydrogen Energy Publications, LLC. Published by Elsevier Ltd. All rights reserved. Cost of electricity Introduction World total primary energy consumption was 12,470 Mtoe in 2012 [1]. Global population, global economy, energy-intensity of the global economy, and living standard are the main drivers of the world's energy demand [2]. Except for decreasing energy-intensity (energy consumption per capita) [3], other fundamental drivers of energy demand will grow continuously in the coming decades [4e6]. Nevertheless, improved energy efficiency cannot outpace the effects of other drivers, resulting in a growing energy demand over the coming decades [5e7]. Currently, about 37% of global primary energy is consumed by electricity generation. In 2012 global electricity generation stood at 22,126 TWh [8], with an annual average growth rate of 3.0% from 1990 to 2012 [1]. Fossil fuel-based electricity generation accounted for 68% of the total generation and coal, the most carbon-intensive fossil fuel, was the largest contributor to the supply of electricity in 2012. Ever- * Corresponding author. Tel.: þ47 453 91 926; fax: þ47 51 83 10 50. E-mail addresses: [email protected], [email protected] (M. Mansouri Majoumerd). 1 Integrated gasification combined cycle. 2 Advanced supercritical pulverized coal. 3 Natural gas combined cycle. http://dx.doi.org/10.1016/j.ijhydene.2014.08.020 0360-3199/Copyright © 2014, Hydrogen Energy Publications, LLC. Published by Elsevier Ltd. All rights reserved. 16772 i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y 3 9 ( 2 0 1 4 ) 1 6 7 7 1 e1 6 7 8 4 Nomenclature AGR ASU BFD BUA CCS CEPCI COE DCF EBTF EPCC EU FP7 GHG GT HHV HRSG IGCC LHV MEA NGCC NPV O&M SCGP SCPC SCR SOTA ST SWGS TDA TDPC TPC acid gas removal air separation unit block flow diagram bottom-up approach carbon capture and storage Chemical Engineering Plant Cost Index cost of electricity discounted cash flow European Benchmarking Task Force engineering, procurement, and construction costs European Union Seventh Framework Programme greenhouse gas gas turbine higher heating value heat recovery steam generator integrated gasification combined cycle lower heating value monoethanolamine natural gas combined cycle net present value operation and maintenance Shell Coal Gasification Process supercritical pulverized coal selective catalytic reduction state-of-the-art steam turbine sour wateregas shift top-down approach total direct plant costs total plant costs increasing world demand for electricity represents the largest driver of demand for primary energy consumption. Electricity demand is projected to grow more rapidly than total energy consumption over the next few decades [5,6]. In 2035, the demand for electricity will be almost 70% higher than the current demand [9]. The growing use of fossil-fuel power plants has resulted in many environmental concerns over the past decade. The power sector is identified as the single largest sector contributing to the emission of CO2, the most important greenhouse gas (GHG4). Carbon dioxide emissions from the electricity and heat supply sector were about 42% of total global CO2 emissions from fossil fuels in the year 2011 [10]. Minimizing the negative effects of growing GHG emissions resulted in the development of environmentally-friendly technologies for electricity production. The share of renewable energies, therefore, has been growing significantly, thanks to governmental supports and subsidies around the globe. However, the estimated timescale for the complete transformation to renewable resources is likely to be a substantial time away [11] and fossil fuels are forecasted to steadily cover a major part of the energy mix. Thus the development of suitable technologies such as clean fossil fuel-based power technologies is urgently needed during this transition phase. Natural gas (NG5) power generation offers less CO2 emissions compared to coal-based systems. Increasing shale gas exploration and production in the United States has meant a shift in the U.S. energy market towards higher natural gas and lower coal consumption for the electricity generation sector [12]. This shift resulted in more coal export from U.S., cheaper price of coal in other continents, e.g. Europe, and consequently higher coal consumption. In addition, wide geographical distribution, abundant reserves, convenient transportation and storage of coal are still maintaining the level of coal consumption in this sector [13]. Nevertheless, in both coal- and NG-based power plants, CO2 emissions need to be mitigated by means of carbon capture and storage (CCS6) in order to achieve targeted global GHG emissions [14]. The deployment of CCS in fossil-fired power plants can prevent the sharp reduction of the fossilfuel consumption in the coming years with more restrictive emissions regulations and higher renewable energy share. The integrated gasification combined cycle is currently one of the most promising technologies for the efficient use of coal. IGCC technology benefits from its widely known environmental credentials such as low emissions of SO2 and NOx [15]. Although this technology suffers from high capital costs and is perceived to be more complex than other technologies e.g. pulverized coal plants, its significantly better emissions performance is interesting for future large-scale deployment [16,17]. In addition, the IGCC technology offers the opportunity for co-gasification of biomass, good performance with lower grade coals and other feedstock [18], and the co-production of H2 and electricity [19]. Moreover, IGCC technology is technically well suited to CO2 capture. If CCS becomes necessary for the next generation of fossil-based power plants, precombustion carbon capture methods can be easily incorporated into the IGCC system. The additional cost due to the capture unit will be significant, but probably lower than for pulverized coal combustion systems [20]. With a distinct view towards the development of IGCC technology, the European Union has sponsored the H2-IGCC project under its Seventh Framework Programme (FP77). This project aims to develop and demonstrate a complete design of a burner for the combustion of hydrogen-rich syngas for future generation IGCC plant with pre-combustion CO2 capture in 2014 [21]. In an effort to evolve the new generation of IGCC plant configuration, the simulation sub-group of the H2-IGCC project previously reported detailed simulation results for a baseline configuration of the IGCC plant as developed in this project [22]. In another paper, subsequent simulation studies on the effects of various gasification processes, as well as of coal quality on the performance of the selected configuration, were reported [23]. In addition to favorable technical performance, the viability of the IGCC technology strongly depends on the overall economic figures compared to other competing technologies. The commercial investment in an IGCC plant requires a competitive cost of electricity (COE8) [24]. An IGCC plant is not 5 6 7 4 Greenhouse gas. 8 Natural gas. Carbon capture and storage. Seventh Framework Programme. Cost of electricity. i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y 3 9 ( 2 0 1 4 ) 1 6 7 7 1 e1 6 7 8 4 considered as a standardized commercial technology with well-established costs compared to e.g. natural gas combined cycle [25]. However, several researchers and energy organizations assessed the COE for power generation by IGCC technology [26e32]. In spite of massive economic assessments, the breakdown of the costs and assumptions is clear and well documented in only a few of them [27,28]. In addition, the majority of open literature did not touch upon a consistent comparison with other fossil fuel-based technologies. Moreover, the sensitivity of the calculated COE to the variations of most important input parameters is missing in most of the recently published studies. Such plausible changes may result in improved competitiveness of the IGCC technology compared to other fossil-based power generation technologies and should be clearly addressed in economic evaluations. The main purpose of this study is to present the results of a techno-economic assessment of the selected IGCC technology with carbon capture performed using a tool developed by the simulation sub-group of the H2-IGCC project. Such a tool has provided the opportunity to modify or change the input parameters during economic assessment. The assessment is based on a practical flow-sheet and realistic technical/economic performance indicators verified by the plant's operators. The other objective is to make a consistent and reliable comparison between the selected IGCC plant and other fossil fuel-based competing technologies, i.e. an NGCC and an SCPC plant based on the same sort of economic assumptions. The natural gas plant was selected for its wide utilization during past years and for its bright future in a low gas price regime due to the widespread unconventional gas production in coming years [11]. The pulverized coal plant was selected since it has been the most prevalent coal technology worldwide over a long period [17]. Moreover, an analysis based on a literature review has been performed to collect realistic economic data of the aforementioned state-of-the-art (SOTA9) technologies as new-built plants on a commercial scale. Calculations of the COE were performed using a set of parameters to ensure that the comparison is made in a consistent and fair way. All assumptions and sources of data, more specifically those for economic assessment, have been carefully gathered and listed in this work. Note that the results for the IGCC plant are generally based on the realistic performance of a series of SOTA components/ sub-systems. However, to achieve more realistic results, these performance indicators have been justified and verified by the operators of similar plants. The degree of confidence in the presented results for the NGCC and SCPC is significantly higher due to the larger number of plants in operation. Nevertheless, the lack of full-scale capture plants in operation and the lack of data validation should be assumed as sources of uncertainties when considering the presented results for all plants. i.e. an advanced SCPC power plant and an NGCC plant both with and without CO2 capture. This section concisely presents the selected IGCC plant configuration. Further details concerning the selected IGCC plant can be obtained from a previous study [22]. The configurations of the SCPC and NGCC plants are also briefly described here. IGCC configuration The block flow diagram (BFD10) of the selected IGCC configuration with capture unit is shown in Fig. 1. The thermodynamic model of the selected IGCC power plant was based on commercially available technologies representing various sub-systems. A cryogenic air separation unit (ASU11) is considered as a stand-alone unit generating O2 (95% purity) from air supplied by an intercooled main air compressor for the coal gasification. The gasification of the coal takes place in an O2-blown, dry-fed, entrained-flow gasifier based on the Shell Coal Gasification Process (SCGP12). A sour water-gas shift (SWGS13) reaction unit is used to convert the CO content in the raw syngas to CO2 by shifting the CO with steam over a catalytic bed. The acid gas removal (AGR14) unit is based on a double-stage SELEXOL system for H2S removal in the first absorption-regeneration stage and for CO2 capture with a rate of 90% in the second absorption stage. The physical absorption was selected over the chemical, amine-based process due to the high partial pressure of CO2 in the syngas downstream of the SWGS unit. In the case of a non-capture IGCC plant, a COS hydrolyzer is considered to convert the COS content of the raw syngas to H2S which will be removed in the downstream AGR unit without CO2 capture stage. The CO2 captured from the process (90% capture rate) is pressurized by an intercooled compressor, aftercoooled, liquefied and finally pumped up to a final pressure (110 bar). A dehydration unit using tri-ethylene glycol is considered (H2O content in the captured CO2 line is less than 20 mg/kg) to prevent the corrosive effects on the transport pipeline. The gas turbine (GT15) block including compression, combustion, and expansion generates electric power using a generator. Gas turbine modeling has been performed using the characteristics and boundary conditions of a gas turbine which is designed for the combustion of the H2-rich fuel produced from upstream sub-systems. The heat recovery steam generator (HRSG16) is based on a triple pressure level with reheat (140 bar/530 C/530 C) and a steam turbine (ST17) is considered to generate power from the steam produced at the HRSG. Advanced SCPC configuration As mentioned previously, the thermodynamic characteristics of the advanced SCPC plant has been adopted from Ref. [28]. The BFD of the supercritical pulverized coal power plant is Power plant configurations 10 The principal objective of this study is to present the results of a techno-economic assessment of the selected IGCC plant with CO2 capture. The final goal is to provide a fair and consistent comparison with other competing technologies, 11 12 13 14 15 16 9 State-of-the-art. 16773 17 Block flow diagram. Air separation unit. Shell Coal Gasification Process. Sour wateregas shift. Acid gas removal. Gas turbine. Heat recovery steam generator. Steam turbine. 16774 i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y 3 9 ( 2 0 1 4 ) 1 6 7 7 1 e1 6 7 8 4 Compressed CO2 Fuel Raw Gas syngas cleaning Gasification O2 Air H2S removal SWGS CO2 capture To atmosphere Slag ASU Heat recovery steam generator Stack HP Air IP/LP Gas turbine Condenser Fig. 1 e The block flow diagram of the selected IGCC plant with CO2 capture. Steam/water to and from capture plant Feedwater heater system Air Ammonia Coal Limestone Oxidation air Flue gas Electrostatic precipitator Pulverized coal boiler Water Coal and ash handling DeNOx plant Flue gas Pre-heated air Compressed CO2 CO2 product FGD CO2 Capture Bottom ash Fly ash Effluent HP turbine IP turbine LP turbine Gypsum Condenser Flue gas Stack Fig. 2 e The block flow diagram of the advanced SCPC plant with CO2 capture. shown in Fig. 2. The plant consists of a steam turbine, steam generator with coal bunker bay and central switch gear. The steam cycle consists of a triple pressure level with reheat (300 bar/600 C/620 C) with extraction points for regenerative heating of feed water and condensate. The steam boiler is based on the SOTA Doosan Babcock two-pass single reheat BENSON boiler. The boiler is equipped with an SOTA combustion system comprising 30 Doosan Babcock low NOx axial swirl burners and an in-furnace air-staging system for primary control of NOx emissions. A selective catalytic reduction (SCR18) unit to control NOx emissions located between the boiler's exit and the air heater inlet. In addition, electrostatic precipitators and the desulphurization plant (wet limestone base) are placed before the flue gas stack. The CO2 removal 18 Selective catalytic reduction. unit is based on SOTA post-combustion capture technology using chemical absorption with a capture rate of 90%. The chemical solvent is based on a 30 wt% aqueous solution of monoethanolamine (MEA19). Further details can be found in Ref. [28]. NGCC configuration The selected NGCC with CO2 capture unit is based on a heavy duty F-class gas turbine, the Siemens SGT5-4000F, a 300 MW single-shaft gas turbine as topping cycle [33]. This GT is directly connected to a 50 Hz air-cooled generator running at a fixed speed of 3000 rpm. Downstream of the GT is a triple pressure level HRSG with reheat (120 bar/560 C/560 C). The 19 Monoethanolamine. i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y 3 9 ( 2 0 1 4 ) 1 6 7 7 1 e1 6 7 8 4 16775 GT block has been modeled similarly to that presented for the GT in the selected IGCC plant. However, compressor and expander characteristics and the boundary conditions of the GT are based on the original design, i.e. natural gas operation. The BFD of the NGCC is illustrated in Fig. 3. The CO2 capture unit is similar to the SCPC plant, an SOTA post-combustion unit using standard MEA (30 wt%) with 90% capture rate. In addition to the capture unit, an exhaust gas condenser is considered in which the flue gas is cooled before entering the capture unit. Moreover, a flue gas blower is considered to compensate for pressure losses in the subsequent capture unit. In the current study, it is also assumed that seawater at a temperature of 15 C is available to satisfy the needs for cooling in both the capture process and the compression stage. Methodology In the current section, various simulation tools and assumptions made for thermodynamic modeling of the selected power plants are briefly described. This section presents the methodology, assumptions, and the scope of the economic evaluation used. Thermodynamic modeling In order to obtain reliable results and to utilize the possibility of incorporating detailed component characteristics, a combination of different simulation tools was used for modeling the selected IGCC power plant. Enssim tool [34] has been used for the modeling of coal milling and drying, the gasification process, raw syngas cooling and scrubbing. The modeling of ASU, AGR, SWGS, CO2 compression and dehydration has been performed using ASPEN Plus [35]. The power block including the GT, and the triple-pressure steam cycle were modeled in IPSEpro [36]. Further details concerning simulation works can be found in Refs. [22,23]. The list of assumptions for each subsystem of the selected IGCC plant is not repeated here and can be found in Ref. [22]. Avoiding repetition of the simulation works and utilizing previous EU20 projects' findings, the technical performance specifications of the advanced SCPC have been adopted from the European Benchmarking Task Force (EBTF21) report [28]; hence, the thermodynamic modeling has not been performed in this work. Preliminary calculations performed by the simulation sub-group of the H2-IGCC project have shown that the coal characteristics used for the H2-IGCC project have a negligible effect on the performance of the SCPC plant. Hence, technical performance indicators of the advanced SCPC remained the same as those reported by Ref. [28]. All performance data refer to plants operating at nominal full load, in new and clean conditions. The detailed models of the selected IGCC and NGCC plants include many sub-systems with reasonable assumptions based on either commercially 20 21 22 23 European Union. European Benchmarking Task Force. Lower heating value. Higher heating value. Fig. 3 e The block flow diagram of the NGCC power plant with CO2 capture. available technology or data provided by other subgroups of the project. The modeling of the gas turbine in IGCC and NGCC power plants has been performed using ISO standard conditions (1.013 bar, 15 C, 60% relative humidity). The ambient air composition together with the characteristics of bituminous coal and natural gas used for simulation works are shown in Table 1. The modeling and simulation of the NGCC was performed using IPSEpro. The model used for CO2 capture simulation is based on the calculation model proposed by Kohl and Nielsen € ller [38]. A detailed description of the [37] and developed by Mo model is not further presented here and can be found in Refs. [39,40]. The specifications of the power block in the NGCC plant are presented in Table 2. The model acquires some input data such as information about the exhaust gas characteristics (e.g. composition and flow rate) and the pressure needed for the prediction of the reboiler requirements. Due to the upper pressure limit in IPSEpro for gaseous streams, simulation of the CO2 compression and dehydration unit has been performed using ASPEN Plus. Table 3, which follows, shows the assumptions made for the simulation of the post-combustion CO2 capture unit in the NGCC plant using IPSEpro software tool. Economic assessment The cost estimation methodology for all investigated plants with and without CO2 capture is described in this section. The economic evaluation comprises different stages including estimations of capital investment, fixed and variable operation and maintenance (O&M24) costs and fuel costs to calculate the cost of electricity. A publicly available report has been initially selected as a database for economic calculations [28]. The benefit of choosing this study is that the figures used reflect the cost of electricity in the European power market. Furthermore, the 24 Operation and maintenance. 16776 i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y 3 9 ( 2 0 1 4 ) 1 6 7 7 1 e1 6 7 8 4 Table 1 e Ambient air composition, composition and thermal properties of bituminous coal and natural gas. Table 3 e Assumptions made for simulation of the postcombustion CO2 capture in the NGCC plant. Feed Value Parameter 0.63 75.10 23.01 1.21 0.05 CO2 capture rate Absorber pressure drop Regeneration temperature Reflux ratio Reboiler approach temperature Lean/rich amine heat exchanger approach temperature Absorber solvent inlet temperature Solvent Heat of reaction Inlet CO2 pipeline pressure Water content in the CO2 pipeline Air Coal Natural gas Parameter/component Unit H2O wt% N2 wt% wt% O2 Ar wt% wt% CO2 Proximate analysis (dry basis) Moisture wt% Ash wt% Volatile matter wt% Fixed carbon wt% kJ/kg LHV22 kJ/kg HHV23 C3H8 wt% wt% CH4 wt% CO2 wt% N2 LHV kJ/kg 10 12.50 27.00 50.50 25,100 26,195 4.02 95.53 0.40 0.05 49,702 level of the technical performance of different plants, more specifically the advanced SCPC, is closer to existing power plants in Europe. A set of assumptions have been considered in order to analyze the economic indicators of different cycles based on a consistent basis. A Microsoft Excel-based model has been developed containing cost data for different power generation technologies as well as assumptions made for economic evaluation. Such a tool provided the opportunity to modify or change input parameters during the economic assessment. The economic viability of the selected cycles has been assessed through the cost of electricity and the cost of CO2 avoided. Due to the volatility of some input parameters, a number of sensitivity analyses have been carried out to disclose the effect of those parameters on the economic attributes of the cycle. Table 2 e Technical specifications of the power island in the NGCC. Parameter Unit Compressor inlet air flow rate Pressure ratio Cooling percentage to the compressor inlet air flow Temperature increase for 1st cooling flow Temperature increase for 2nd and 3rd cooling flow Fuel flow Combustor outlet temperature Expander inlet pressure Exhaust gas temperature Exhaust gas flow rate to HRSG GT gross efficiency Triple pressure level HRSG Steam superheating/reheat temperature HRSG pressure drop (hot side) HP steam turbine isentropic efficiency IP steam turbine isentropic efficiency LP steam turbine isentropic efficiency kg/s e % 685.4 18.2 23.8 C 0 C 20 kg/s C bar C kg/s % bar C bar % % % Value 14.9 1500 17.9 577 700.3 39.5 120/27/4.6 560 0.04 91 90 89 Unit Value % bar C moleH2 O =moleCO2 C C 90 0.15 120 1.0 10 10 40 MEA 85 110 20 C 30% kJ=moleCO2 bar mg/kg The COE is a standard indicator (metric) employed in the assessment of project economics which represents the revenue per unit of product that must be met to reach break-even over the life time of a plant. It is, hence, the selling price of electricity that generates a zero profit. For this purpose, the net present value (NPV25) computation has been performed to determine the COE. The cost of CO2 avoided is also a standard cost metric indicating the cost of CO2 avoidance, which is defined as: Cost of CO2 avoided½V=tCO2 ¼ COECapture COEref ½V=MWh CO2specific CO2specificcapture ½tCO2 =MWh (1) ref where COE is cost of electricity generation, CO2specific is tonne of CO2 emissions to the atmosphere per MWh (based on the net capacity of each power plant), and the subscripts “capture” and “ref” refer to plants with and without capture unit, respectively. Even though the cost of CO2 avoided should contain costs associated with transport and storage, these costs are omitted in this study. However, the omitted costs have no impact on the comparison outcome as applied to all power plants in a consistent basis. Furthermore, it should be noted that the reference plant is a similar plant to the one with capture unit; e.g., the reference plant of the NGCC with capture unit is the non-capture NGCC plant. The selection of a similar reference plant has been made assuming that all investigated technologies have a similar chance to be built in future under a no carbon constraint scenario. The economic assessment is based on the commercial installation of each power plant (or nth-of-a-kind technology) and does not cover the costs for the demonstration plants. The following considerations have also been taken into account: All economic assessments are based on the reference year 2013. Cost estimation represents a complete power plant on a generic greenfield site, and site-specific considerations are not taken into account. The plant boundary is defined as the total power plant facility within the “fence line”. 25 Net present value. i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y 3 9 ( 2 0 1 4 ) 1 6 7 7 1 e1 6 7 8 4 Costs associated with CO2 transport, storage, and monitoring are not included in the reported capital cost and O&M costs, while the CO2 compression cost is included. All taxes with the exception of property taxes (property taxes are included with the fixed O&M costs) are excluded. Any labor incentives are excluded. Each power plant is designed to operate at base load operation. The costs associated with the plant's decommissioning are excluded. It should be clearly highlighted that the techno-economic analysis presented in this article cannot provide an absolute result, since i) there is no full-scale carbon capture unit for power generation application, ii) the used cost data for equipment cost calculations have some uncertainties, and iii) assumptions made for cost calculations (e.g. capacity factor, fuel prices, etc.) are market-dependent and uncertain by nature; they can change a great deal as a function of time and geographic location. However, the results of this work will provide a good comparative insight highlighting the competitiveness of different fossil-based power generation technologies. Capital costs The capital cost assessment for the selected IGCC and NGCC plants is based on a bottom-up approach (BUA26), while, for the advanced SCPC plant, it is based on a top-down approach (TDA27). The BUA is the step-count exponential costing method using dominant parameters or a combination of parameters derived from the mass and energy balance simulation. The BUA for capital costs assessment has three levels, i.e. total direct plant costs (TDPC28), engineering, procurement and construction costs (EPCC29), and total plant costs (TPC30) as shown in Fig. 4(a). The TDA is based on equipment supplier estimates of entire EPC costs. The capital costs calculations for the advanced SCPC are also shown in Fig. 4(b). The cost estimate for the advanced SCPC plant without CO2 capture is based on the TDA, while the cost estimate for the capture unit is based on the BUA. The overall EPCC of the plant is formed by the sum of the EPCC for the plant without CO2 capture and the EPCC for capture unit. The calculation of the equipment costs for a certain process unit, based on utilization of the cost data for different components' sizes, was performed using the following equation: f Ci ¼ Ci;ref Si Si;ref $IR (2) where Ci is the cost of a component (sub-system), Ci,ref is the known cost of a reference component (sub-system) of the same type and of the same order of magnitude, Si is the scaling parameter, f is the reference cost scaling exponent, and IR is the cost index ratio. The term (f) incorporates economies of 26 27 28 29 30 Bottom-up approach. Top-down approach. Total direct plant costs. Engineering, procurement and construction costs. Total plant costs. 16777 scale in the equation and indicates that the percentage change in cost is smaller than the percentage change in size for each major component. Typical values of the scaling exponent are reported in Ref. [41]. The typical values for power utilities vary between 0.6 and 0.7, and the value used in this study, based on internal discussions, is 0.67. All economic assessments are based on the reference year 2013 and the IR was adopted from the Chemical Engineering Plant Cost Index31 (CEPCI) [42] to incorporate the economic ups and downs (market fluctuations) in the cost assessment. In the economic calculations carried out in this study, all figures extracted from the literature given in U.S. dollars (US$) were recalculated to European Euros (V) using the universal currency conversion XE rates [43]. Assumptions made for economic assessment The assumptions made for the estimation of the capital costs, O&M costs, and fuel costs for different power generation technologies, i.e. the selected IGCC, the advanced SCPC, and the NGCC power plants are presented here. Table 4, which follows, shows the economic assumptions made for the evaluation of capital costs for different plants within the H2IGCC project. The assumptions made to estimate the O&M costs for different power generation technologies are listed in the following Table 5. The coal price is 2.5 V/GJ, while the NG price is 7.3 V/GJ. The fuel prices are for September 2013 and based on data available in Ref. [46]. The coal price is based on API N2, 6000 kCal NAR (CIF) while the NG price is based on the Zeebrugge price. Results and discussion The main objective of this study is to assess the competitiveness of various fossil-based power generation technologies from a techno-economic point of view. The final aim is to differentiate between these competing technologies by means of the plant's performance and cost of electricity defined by capital investment and production cost. Accordingly, thermodynamic performance indicators of the selected IGCC, advanced SCPC, and NGCC power plants using the assumptions mentioned above are presented in the current section. It should be observed that technical performance indicators of the advanced SCPC plant have been adopted from the EBTF report [28]. The second part of this section is dedicated to the economic indicators of concerned power plants based on the economic assumptions presented in Section methodology. Thermodynamic performance The overall efficiency as well as the net and gross power outputs of the IGCC, advanced SCPC, and NGCC power plants with and without CO2 capture is illustrated in Fig. 5. It should be noted that the technical performances of the IGCC and NGCC are based on the assumptions presented in Section methodology and the simulation carried out by the system 31 32 Chemical Engineering Plant Cost Index. Discounted cash flow. 16778 i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y 3 9 ( 2 0 1 4 ) 1 6 7 7 1 e1 6 7 8 4 Fig. 4 e Capital costs levels and their elements for (a) the selected IGCC and NGCC plants and (b) the advanced SCPC plant. analysis sub-group of the H2-IGCC project, while data for the advanced SCPC plant are adopted from Ref. [28]. As shown in Fig. 5, regarding the overall efficiency of the non-capture plants (or reference plants), the NGCC is the most efficient plant, while the advanced SCPC plant is the least efficient plant with 12.5 percentage points difference. This trend is the same for the plants with capture unit, although the difference between the NGCC and the advanced SCPC is larger with 15.3 percentage points. The relative efficiency penalty associated with the capture deployment (compared to the reference plant of each technology) is 24%, 27%, and 16% for the IGCC, advanced SCPC, and NGCC plants, respectively. The following Table 6 shows the other performance indicators for the IGCC and NGCC power plants. Further information concerning the advanced SCPC is available in Ref. [28]; hence, it is not repeated here. Economic performance In the current section the results of capital costs estimation, O&M costs, fuel costs, COE, cost of CO2 avoided, and economic sensitivity for the selected IGCC, advanced SCPC, and NGCC Table 4 e Assumptions made for capital costs calculations of different power plants with CO2 capture. Parameter Base year Equipment costsa Scaling exponent (f in Eq. (1)) Escalation of equipment cost Installation costs Escalation of installation costs The average currency exchange rate for September 2012 Construction period Capital investment distribution Indirect costsb Project contingency Process contingency Owners' costsc Discounted cash flow32 (DCF) rate Inflation rate a Assumption 2013 Adopted from Refs. [27,28,44] 0.67 CEPCI Proportional to the equipment costs Same as inflation rate V0.7485/US$ [43] 4 years for IGCC and SCPC with capture 3 ½ years for non-capture IGCC and SCPC 3 years for NGCC þ CCS 2 ½ for non-capture NGCC 4 years: 20%, 30%, 30%, 20% 3 ½ years: 20%, 35%, 35%, 10% (for last half a year) 3 years: 40%, 30%, 30% 2 ½ years: 40%, 40%, 20% (for last half a year) 14% of TDPC 15% of the EPCC for the IGCC with capture 10% of the EPCC for the SCPC and NGCC with capture, and non-capture IGCC 5% of the EPCC for the non-capture SCPC and NGCC 5% of the EPCC for all plants 5% of EPCC for all plants 8% (real discount rate) 3% It should be mentioned that additional costs for the GT modifications due to the combustion of H2 rich syngas in the IGCC plant with CO2 capture is assumed to be 15%. Nevertheless, the increase in capital cost for the modified GT would have little impact on the total plant costs of the IGCC plant with CO2 capture. b The indirect costs are associated with the costs for yard improvement, buildings, sundries, and engineering services. c This cost includes pre-production costs, inventory capital, and other owners' costs (excluding any financing costs). i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y 3 9 ( 2 0 1 4 ) 1 6 7 7 1 e1 6 7 8 4 16779 Table 5 e Assumptions made for O&M costs calculations of different power plants with CO2 capture. Parameter Unit Capacity factora % Plant life timeb Labor costc Number of labors per shift Year V/h Person Escalation of the variable O&M costs Maintenance cost % % EPC Property taxes and insurance cost CO2 allowances price % TPC V/t CO2 Assumptions 1st year of operation for IGCC and SCPC: 40 2nd year of operations for IGCC and SCPC: 65 Rest of plant's operational life time: 80 for IGCC and 85 for SCPC 1st year of operation for NGCC: 65 Rest of plant's operational life time for NGCC: 85 30 for coal-based and 25 for NG-based plants 43.8 [28,45] 30 for IGCC 25 for SCPC 22 for NGCC þ CCS 3 1.5 for IGCC and SCPC with capture 1.3 for non-capture IGCC and SCPC 1.25 for NGCC with capture 1.0 for non-capture NGCC 1.5 for all plants 0 a This percentage shows the operating hours of the power plant in a year at full load. It should be noted that 80% is a conservative assumption for the capacity factor of the IGCC plant. Historical data from current IGCC plants (without CCS) showed successful operational hours up to this level. b This period starts from commissioning and extends up to decommissioning. c Although the labor rate seems rather high, this cost includes overheads, training, etc. power plants are presented. It should be highlighted again that the cost estimation performed includes a level of uncertainty (±30%) given the fact that there is no power plant with a CO2 capture unit in operation and based on the methodology selected for cost assessments, i.e. using available equipment cost data. Capital costs Fig. 6 illustrates different components of the total plant costs for the selected IGCC, advanced SCPC, and NGCC power plants with and without CO2 capture unit. As shown in Fig. 6, the lowest capital investment is required for the NGCC plant without CO2 capture unit. Even with the CO2 capture feature, the NGCC requires less capital investment compared to the cheapest coal technology, i.e. the advanced non-capture SCPC. The results also show one important advantage of the IGCC cycle compared to the other coal technology, the advanced SCPC plant, when the CO2 capture is incorporated into the system and that is less capital requirement for CO2 capture deployment. The following Table 7 shows different cost indicators such as total plant costs and specific investment for the concerned power plants. The updated cost figures for the advanced SCPC plant are also given in Table 7 based on the assumptions presented in Section methodology. As mentioned, the calculations of capital costs for the selected IGCC and NGCC plants are based on a bottom-up approach. In contrast, the capital costs calculation for the SCPC is based on a top-down approach. Therefore, the total equipment costs and installation costs are not explicitly given for the advanced SCPC plant. As shown in Table 7, the highest absolute capital investment is required for the SCPC plant with CO2 capture. However, it should be noted that the production capacity (or power output) of the advanced SCPC is higher than those for the IGCC and NGCC plants. As shown in Fig. 6, a better indicator is the specific investment of a certain plant, in which the capacity of the plant is embedded in the value. Please note that indirect costs, owner's costs and contingencies are based on the assumptions given in Section methodology, and these cost indicators for the SCPC plants (with and without capture) have been calculated backward using the updated EPC costs. O&M costs and fuel costs Fig. 5 e The overall plant efficiency and power output of various fossil-based power plants. Table 8 presents the calculated operation and maintenance costs for the selected IGCC plant, advanced SCPC, and NGCC power plants. The calculated labor costs seem on the high side. However, it should be mentioned that any training, holidays, pension, overheads, etc. are included in the assumed labor costs. Since the details of variable O&M costs were not available for the advanced SCPC, the variable cost items have been escalated using the same rate as the inflation rate from the year of cost data to the base year of this study (i.e. 2013). Amongst plants with capture, the selected IGCC 16780 i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y 3 9 ( 2 0 1 4 ) 1 6 7 7 1 e1 6 7 8 4 Table 6 e Thermodynamic performance indicators of the IGCC and NGCC plants with(out) CO2 capture. Parameter Gross plant's power output Net plant's power output Overall efficiency Fuel flow Gas turbine net power output Steam turbine net power output Total auxiliaries - HRSG pumping power - Gasification power demand - ASU compression power demand - AGR pumping and compression power demand - AGR refrigeration power demand - CO2 compression power demand - CO2 capture plant including blower, etc. Specific CO2 emissions Unit MW MW %LHV kg/s MW MW MW MW MW MW MW MW MW MW t CO2/MWh plant has the highest specific fixed O&M costs, while the NGCC has the lowest costs. This trend is similar for the non-capture plants. The advanced SCPC in both capture and non-capture cases requires 5% and 13% less fixed O&M costs compared to the corresponding IGCC cases, respectively. With respect to the variable O&M costs, the advanced SCPC with and without capture unit has the highest costs. Similarly to the fixed O&M costs, the NGCC in both cases (capture and non-capture) has the lowest costs compared to the corresponding capture or non-capture cases in other plants. The fuel costs for the selected IGCC, advanced SCPC, and NGCC power plants with and without CO2 capture are illustrated in Fig. 7. Please note that the amount of fuel (or annual fuel costs) from capture case to non-capture case only changes for the IGCC plant, as the capture takes place upstream of the GT. The estimation results of the fuel costs shown in Fig. 7 confirm that the specific fuel costs (V/MWh net) are more than two times higher for the NGCC plant than for other technologies in both capture and non-capture cases. Fig. 7 also shows that clean fossil fuel-based power generation (i.e. plants with capture unit) will cause increased primary energy consumption (i.e. an increased CO2 production) but a Fig. 6 e The breakdown of the specific total plant costs for various power plants. IGCC NGCC Non-capture Capture Non-capture Capture 521.5 461.7 47.0 39.1 304.4 217.1 59.8 2.7 4.4 43.5 0.7 8.5 e e 0.70 490.7 394.4 35.7 44.0 314.0 176.7 96.3 3.4 4.9 48.9 10.8 8.5 19.7 e 0.08 429.4 428.0 58.0 14.9 288.6 140.8 1.3 1.3 e e e e e e 0.35 384.7 359.3 48.7 14.9 288.6 96.1 25.4 1.3 e e e e 11.3 12.8 0.04 lower CO2 emission compared to corresponding non-capture plants. Costs of electricity generation and CO2 avoidance As mentioned before, the cost of electricity in this study is calculated as the break-even point for the electricity selling price. Fig. 8, which follows, shows the breakdown of the cost of electricity into different cost elements for various investigated power plants, viz. the selected IGCC, the advanced SCPC, and the NGCC power plants. As shown in Fig. 8, the cost of electricity for the advanced SCPC plant with capture unit is higher than the corresponding values for the selected IGCC and NGCC plants with capture unit. The COE for the noncapture NGCC plant is the highest among other non-capture plants. The difference in the COE between the most expensive non-capture technology (i.e. the non-capture NGCC) and the cheapest power generation technology (i.e. the advanced SCPC without capture unit) is only 4%. The difference between the most expensive and cheapest technologies with capture plants is only 6%. Nevertheless, supporting any decision against or in favor of one of the concerned technologies based purely on the estimated COE is not wise as the difference between the COEs is marginal (when plants from one category, i.e. either with capture or without, are compared together). The other important aspect which is not shown in Fig. 8 is the share (percentage) of each cost element in the COE for a certain technology. The highest capital costs share is related to the IGCC plant without capture unit (~55% of the COE). The share of fuel costs is about 60e70% of the cost of electricity for the NGCC plant (with and without capture unit), while it is approximately 30% of the COE for the other power plants. The highest fixed O&M costs share is related to the selected IGCC plant with capture unit (~15% of the COE), while the COE for the advanced SCPC with capture has the highest share of variable O&M costs (~8% of the COE). The cost of CO2 avoided is also calculated based on the equation presented in Section methodology. The cost for CO2 avoided is in fact the break-even price for CO2, where it starts to make economic sense to build plants with carbon capture. 16781 i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y 3 9 ( 2 0 1 4 ) 1 6 7 7 1 e1 6 7 8 4 Table 7 e The capital costs for the selected IGCC, SCPC, and NGCC plants with(out) CO2 capture. Cost components a TPC þ DCF (8%) TPC Owner's costs and contingencies EPCC Indirect costs TDPC Total equipment costsb Installation costsb Specific investment (gross) Specific investment (net) a b Unit MV MV MV MV MV MV MV MV V/kW gross V/kW net IGCC SCPC NGCC Non-capture Capture Non-capture Capture Non-capture Capture 1094 899 150 750 M 657 356 302 1725 1948 1392 1144 229 916 112 803 427 376 2332 2902 1697 1434 187 1247 153 1093 e e 1750 1901 2066 1699 283 1416 174 1242 e e 2482 3091 347 304 40 264 32 232 136 96 708 710 729 619 103 515 63 452 237 215 1608 1723 This value is to consider the escalation during the construction period. This value is not available for the advanced SCPC plant since it is based on a top-down approach. This cost for different technologies with capture unit when compared to similar reference plants without capture unit is illustrated in Fig. 9. Please note that the costs associated with transport and storage are excluded from the cost of CO2 avoided. The specific CO2 emissions for each technology with or without CO2 capture unit are also shown in Fig. 9. The reason for such a high avoidance cost for the NGCC is the low specific emissions from the plant without capture unit which, according to Eq. (1) (presented in Section economic assessment), results in a high CO2 avoided cost. The CO2 avoided cost shown in Fig. 9 might be a better indicator compared to the COE to support which technology is better for CO2 mitigation. However, it should be noted that costs associated with transport and storage will increase the presented cost of CO2 avoided and will change the trend shown in Fig. 9. Economic sensitivity In order to evaluate the sensitivity of the COE to variations in the inputs for each plant, an economic sensitivity analysis has been performed to identify the most influential parameter with the strongest impact on the results. Two parameters are considered as the most uncertain parameters for the calculation of the COE. These parameters are the capacity factor (or load factor) of the plant and the fuel price. The variation range of capacity factor is 40e90%. The upper limit is selected based on the technical limitations such as minimum time required for any overhaul and maintenance activities. The lower limit is selected based on the experience during recent years which confirms decreasing electricity production form fossil-based plants. It is assumed that the load of power plants remains constant at the design condition. The fuel prices also vary 50% from the prices presented in Section methodology. The results of the sensitivity analysis under the variation of the plant's capacity factor and the fuel price are shown in Fig. 10(a) and (b), respectively. Please note that the capacity factor for the IGCC plant (with and without capture) is 80%, while it is 85% for the other technologies. Please also note that each plant is compared to its reference COE (at mentioned capacity factor or fuel price in Section methodology). Results in Fig. 10 highlight possible drivers which may influence market attention on different technologies. It is evident from this figure that the COE for both NGCC plants (with and without capture unit) is less sensitive to changes of capacity factor compared to other plants. The COE for the advanced SCPC is the most sensitive amongst concerned technologies. As shown in Fig. 10(b), the change of fuel price has a significant effect on the COE for the NGCC with and without capture unit. Any reduction in the NG price will change the market tendency towards higher electricity production from NGCC plants compared to coal-based technologies, even at a similar reduction in the coal price. It should be highlighted that economic sensitivity analysis could be performed based on variation in the cost of CO2 allowances. However, the impact of CO2 allowances cost on the COE would be negligible (more specifically for the plant with capture unit as most of the carbon emissions were already Table 8 e The operation and maintenance costs for the IGCC, USCPC, and NGCC plants with(out) CO2 capture. Cost item Fixed O&M costs Labor costs Maintenance costs Property taxes and insurance costs Total fixed O&M costs Specific fixed O&M costs Variable O&M costs Total variable O&M costs Specific variable O&M costs Unit MV/a MV/a MV/a MV/a V/kW gross/a MV/a V/MWh net IGCC SCPC NGCC Non-capture Capture Non-capture Capture Non-capture Capture 9.6 9.9 13.7 33.1 63.5 11.5 13.8 17.2 42.5 86.6 7.7 16.2 21.5 45.4 55.4 9.6 21.2 25.5 56.3 82.2 6.5 2.7 4.6 13.8 32.2 8.4 6.5 9.3 24.3 63.1 4.0 1.2 5.2 1.9 10.7 1.9 28.4 6.9 2.8 0.9 4.7 1.7 16782 i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y 3 9 ( 2 0 1 4 ) 1 6 7 7 1 e1 6 7 8 4 Fig. 7 e Annual fuel costs and specific fuel costs for different power plants. Fig. 10 e Sensitivity response of the COE for different power plants under variation of (a) the capacity factor and (b) fuel price. Fig. 8 e The breakdown of the cost of electricity for the selected IGCC, the advanced SCPC, and the NGCC power plants with(out) CO2 capture. captured from the plants), as the absolute value of CO2 allowances cost is very low (about 5.5 V/t CO2 [46]) and currently any large variation could not be expected. Nevertheless, its influence will change depending on the CO2 market development and changes in global mitigation policies. Conclusion Fig. 9 e The cost of CO2 avoided, COE, and specific CO2 emissions for the selected IGCC, advanced SCPC, and NGCC. The thermodynamic performance indicators of various power plants including IGCC, advanced supercritical pulverized coal and natural gas combined cycle power plants were presented in this article. The NGCC is the most efficient plant, while the advanced SCPC plant is the least efficient plant amongst noncapture cases. This trend is similar for the plants with capture unit. The relative efficiency penalty associated with the capture deployment (compared to the reference plant of each technology) is 24%, 27%, and 16% for the IGCC, advanced SCPC, and NGCC plants, respectively. A comparative study was also conducted, comparing the COE and the cost of CO2 avoided for the mentioned fossil-based power plants. The economic performance indicators of each plant were estimated using the developed model and the i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y 3 9 ( 2 0 1 4 ) 1 6 7 7 1 e1 6 7 8 4 results are presented and thoroughly discussed. It should be highlighted that the estimation is highly dependent on the selected assumptions. It is also important to note that technoeconomic analysis cannot provide an absolute result, since the cost data and assumptions are uncertain by nature. The COE for the IGCC plant with and without capture is 91 and 59 V/ MWh, respectively. The COE for the advanced SCPC is 96 and 59 V/MWh for the capture and non-capture cases, respectively. The COE for the NGCC with and without capture is 61 and 91 V/ MWh, respectively. The results show that the less capitalintensive plant is the NGCC plant without CO2 capture. However, the high fuel costs for this plant decrease the gap between the COE for this plant compared to that for the other plants. The COE for the NGCC technology was the most sensitive to changes in the fuel price amongst other COEs for different technologies. However, the COE for the NGCC technology was also the least sensitive to variations of the plant's capacity factor. The estimated costs of CO2 avoided for the IGCC, SCPC, and NGCC technologies are 51, 57, 99 (V/t CO2 avoided). Results highlighted that, based purely on the COE for different plants, it cannot be concluded which technology is better and more cost-effective than other technologies, considering the level of uncertainty in the economic results of this study (±30%). Other main drivers such as proven technology and operational flexibility will, therefore, play an important role in the widespread utilization of these technologies. Acknowledgment The authors are grateful to the European Commission's Directorate-General for Energy for financial support of the Low Emission Gas Turbine Technology for Hydrogen-rich Syngas (H2-IGCC) project with the grant agreement number of 239349. The authors wish to acknowledge Chris Lappee at Vattenfall for sharing constructive opinions about the selection of cost estimating methodology as well as results and discussion of this article. 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