COAL - ENERGY, ENVIRONMENT AND SUSTAINABLE DEVELOPMENT

TWENTY - SIXTH ANNUAL INTERNATIONAL

PITTSBURGH COAL CONFERENCE

ABSTRACTS BOOKLETSeptember 20 - 23, 2009

The Westin Convention CenterPittsburgh, PA USA

Hosted By:

University of Pittsburgh Swanson School of Engineering

Sponsors

A NOTE TO THE READER

This Abstracts Booklet is prepared solely as a convenient reference for the Conference participants. Abstracts are arranged in a numerical order of the oral and poster sessions as published in the Final Conference Program. In order to facilitate the task for the reader to locate a specific abstract in a given session, each paper is given two numbers: the first designates the session number and the second represents the paper number in that session. For example, Paper No. 25-1 is the first paper to be presented in the Oral Session #25. Similarly, Paper No. P3-1 is the first paper to appear in the Poster Session #3. It should be cautioned that this Abstracts Booklet is prepared based on the original abstracts that were submitted, unless the author noted an abstract change. The contents of the Booklet do not reflect late changes made by the authors for their presentations at the Conference. The reader should consult the Final Conference Program for any such changes. Furthermore, updated and detailed full manuscripts are published in the CD-ROM Conference Proceedings will be sent to all registered participants following the Conference. On behalf of the Twenty-Sixth Annual International Pittsburgh Coal Conference, we wish to express our sincere appreciation to Ms. Heidi M. Aufdenkamp, Mr. Yannick Heintz and Mr. Laurent Sehabiague for their invaluable assistance in preparing this Abstract Booklet. Thank you, Badie I. Morsi, Editor Professor and Executive Director of the Conference Copyright © 2009 Pittsburgh Coal Conference

TABLE OF CONTENTS Oral Sessions Page 1: Gasification: General Session – 1 ..................................... 1 2: Sustainability and Environment: Policy ............................ 2 3: Carbon Management: Pre-combustion – 1 ........................ 3 4: Combustion: Oxy-Combustion – 1 ................................... 4 5: Coal-Derived Products: Chemicals and Materials from

Coal ................................................................................... 5 6: Coal-Derived Products: Coal-to-Liquids:

Technology – 1 ................................................................. 5 7: Gasification: General Session – 2 ..................................... 6 8: Sustainability and Environment: GHG/GWP ................... 7 9: Carbon Management: Pre-Combustion – 2 ....................... 7 10: Combustion - 1.................................................................. 8 11: Coal Science: Coal Beneficiation - 1 ................................ 9 12: Coal-Derived Products: Coal-to-Liquids: Catalysts ........ 10 13: Gasification: Underground Coal Gasification - 1 ........... 11 14: Gasification: Fundamentals - 1 ....................................... 11 15: Carbon Management ....................................................... 12 16: Combustion: Chemical Looping – 1 ............................... 13 17: Coal Science: Coal Beneficiation - 1 .............................. 14 18: Coal-Derived Products: Coal-to-Liquids:

Technology – 2 ............................................................... 15 19: Gasification: Underground Coal Gasification - 2 ........... 16 20: Gasification: Fundamentals - 2 ....................................... 17 21: Carbon Management: Post-Combustion - 1 .................... 18 22: Combustion: Oxy-Combustion – 2 ................................. 19 23: Coal Science: Coal Chemistry - 1 ................................... 20 24: Coal-Derived Products: Carbon Management for Coal

Conversion ...................................................................... 20 25: Gasification: Underground Coal Gasification - 3 ........... 21 26: Gasification: Fundamentals - 3 ....................................... 22 27: Carbon Management: Post-Combustion - 2 .................... 23 28: Combustion: Chemical Looping – 2 ............................... 24 29: Coal Science: Coal Geoscience – 1: Coal Fires .............. 25 30: Coal-Derived Products: Substitute Natural Gas (SNG) .. 25 31: Gasification: Synthesis Gas Cleaning - 1 ........................ 27 32: Gasification: Fundamentals - 4 ....................................... 28 33: Carbon Management: Sequestration - 1 .......................... 29 34: Combustion: Mercury ..................................................... 30 35: Coal Science: Coal Chemistry - 2 ................................... 31 36: Coal-Derived Products: Hydrogen Production - 1 .......... 31 37: Gasification: Synthesis Gas Cleaning - 2 ........................ 32 38: Gasification: Advanced Technologies - 1 ....................... 33 39: Carbon Management: Sequestration - 2 .......................... 34 40: Combustion: Oxy-Combustion – 3 ................................. 35

Oral Sessions Page 41: Coal Science: Coal Geoscience – 2 ................................ 36 42: Coal-Derived Products: Hydrogen Production - 2 .......... 37 43: Gasification: Co-Gasification and Low-Rank Coal - 1 ... 38 44: Gasification: Advanced Technologies - 2 ....................... 39 45: Sustainability and Environment: General - 1 .................. 39 46: Combustion - 2 ............................................................... 40 47: Coal Science: Coal Geoscience – 3 ................................ 41 48: Coal-Derived Products: Syngas Utilization (Gas Turbines,

Fuel Cells) ....................................................................... 41 49: Gasification: Co-Gasification and Low-Rank Coal - 2 ... 43 50: Gasification: Advanced Technologies - 3 ....................... 44 51: Sustainability and Environment: General - 2 .................. 45 52: Combustion: Flue Gas Clean Up .................................... 46 53: Coal Science: Coal Geoscience – 4 ................................ 46 54: Coal-Derived Products: Coal Co-Conversion with Other

Feedstocks ...................................................................... 46 Poster Sessions Page 1: Combustion ..................................................................... 47 2: Gasification ..................................................................... 49 3: Sustainability and Environment ...................................... 50 4: Carbon Management ....................................................... 50 5: Coal-Derived Products .................................................... 54 6: Coal Science ................................................................... 56

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SESSION 1 GASIFICATION: GENERAL SESSION – 1

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Performance and Cost Comparison of Four Alternate CO2 Capture Technologies for IGCC Power Generation

John Plunkett, David Gray, Charles White, Noblis; Kristin Gerdes, DOE-NETL, USA

Potential regulatory requirements for CO2 capture will impact both performance and cost of coal-fired electric power generating facilities. Penalties associated with CO2 capture will include the capital cost and additional parasitic power of technologies needed to separate CO2 from process streams and compress the CO2 to a pressure suitable for sequestration, and the costs of transportation, storage and monitoring. The U.S. Department of Energy (DOE) National Energy Technology Laboratory (NETL) estimates a 60-90 percent increase in the levelized cost of electricity (COE) for a coal-fired power plant with carbon capture and storage compared to a greenfield pulverized coal plant without carbon capture. In order to reduce this increase in COE, NETL funds research to develop technologies that will achieve 90 % carbon capture while minimizing the impact on COE. This funded research includes multiple technology approaches for CO2 separation as well as enabling technologies for inclusion in an integrated gasification combined cycle (IGCC) plant. Two promising emerging CO2 separation technologies are syngas chemical looping (SCL) and high temperature hydrogen membranes (HTHM). This paper examines the potential impact on efficiency and COE of four alternate process configurations in the context of IGCC power generation with carbon capture and storage. The four process configurations, all incorporating an advanced hydrogen turbine and coal feed pump, are: • IGCC with conventional physical solvent acid gas removal • IGCC with warm gas cleanup (WGCU) and conventional physical solvent for

CO2 removal • IGCC with WGCU and SCL for CO2 separation • IGCC with WGCU and HTHM for CO2 separation This paper evaluates these four IGCC plant configurations in terms of overall efficiency of coal to power, capital and O&M cost, and levelized COE. Although they are in early stages of development, the SCL and HTHM technologies represent two promising pathways for achieving DOE’s goals for emission-free power generation at an affordable cost. 1-3

Design of IGCC Power Plants with Carbon Capture: Concept Simplification Impacts on Efficiency, Availability and Economics

Karsten Riedl, E.ON Engineering GmbH; Johannes Eckstein, Hans Rainer, E.ON Energie AG; Mathias Rieger, Freiberg Energy Consultants GmbH;

Bernd Meyer, TU Bergakademie Freiberg, GERMANY Carbon emissions of coal fired power stations are a big issue for E.ON as one of the largest private utility companies worldwide. Research and development in the field of low carbon IGCC concepts is a contribution to cut E.ON’s specific carbon emissions. For pre combustion carbon capture activities cooperation with the Institute of Energy Process Engineering and Chemical Engineering (IEC) of TU Bergakademie Freiberg was established as IEC has wide expertise in gasification technology and in cycle modelling. It is the aim of the collaboration project to design and model IGCC concepts with several carbon capture levels in order to study technical and economical parameters. Today IGCC plants with carbon capture could not be established in the market despite their thermodynamic and technological advantages. The presented analysis is supposed to make a contribution to discuss the main influences on IGCC economics from a technology point of view and to present effects of a disintegrated IGCC layout on efficiency, investments and availability. In order to compare available gasification technologies two IGCC concepts (dry feed gasifier with water quench and slurry feed gasifier with water quench) are designed and modelled. Additionally, three scenarios of carbon capture (maximum, bulk, no capture) are considered for each concept to analyse the influence on the plant. An IGCC concept of a dry feed gasifier with water quench is discussed as the base case and technical constraints are exposed. The thermodynamic figures of the example are analysed, in particular efficiency losses due to carbon capture are in the focus. Moreover, economic results of defined economic constraints are presented and the main cost drivers for Cost of Electricity (CoE) are quantified. The CoE sensitivity analysis emphasises that specific investment costs and availability are the key factors to improve IGCC plant economics while plant efficiency is of less importance. Hence, the impact of IGCC concept simplifications on plant performance and economics are considered. The investigated simplifications include disintegration of

water and steam interfaces between gasification plant and combined cycle. In these concepts the scrubbed synthesis gas is the only interconnection. As a result, performance figures for a carbon capture IGCC reveal that – despite the significant simplifications in plant design – efficiency is only marginally reduced. Moreover, minimal integrated concepts will most likely offer an enhanced flexibility and availability. Finally, some savings of investments are expected, so that disintegrated concepts can help to bring carbon capture IGCC plants in the market. 1-4

IGSC – Retrofit Zero Emission Power Generation from Coal Stephen Scott, Jacobs, USA; John Griffiths, Mohan Karmarkar, Jacobs,

UNITED KINGDOM Integrated Gasification Steam Cycle (IGSC) is a novel method of generating electricity from coal without NOx, SOx, CO or particulate emissions and with 100% capture of CO2. It can be built as a stand alone facility or retrofitted to an existing coal plant utilizing some, or all, of the existing coal handling facilities, electrical transformers and switchgear, cooling water systems, and the steam turbine generator. This paper outlines the key technical and commercial advantages of this technology, which won the IChemE Shell Award for Innovation and Excellence in 2008. The IGSC technology gasifies coal to produce a raw syngas and then combusts the syngas in a Fired Expander fitted with a novel oxy-combustor. The oxy-combustor, developed by Clean Energy Systems inc. (Rancho Cordova, Ca) allows the raw syngas fuel to be fired in the expander using high purity oxygen. The burner outlet temperature is controlled by injecting water. The Fired Expander generates electricity and the exhaust gas, or “flue gas”, is a mixture of steam and CO2, together with small quantities of atmospheric gases. The “flue gas”, which is still at elevated pressure, is fed to a pressurized HRSG to recover the sensible heat to make clean, high pressure steam that is fed to a standard steam turbine generator set to produce more electrical power. The exhaust gas is finally cooled in a Jacobs Desaturator by direct contact with circulating water to condense all of the steam, leaving only the CO2 at 150 psig. The CO2 can be compressed and dried for sequestration or utilized in an EOR (Enhanced Oil Recovery) application. The ash in the coal is converted to a vitreous non-leachable slag in the gasifier and solid waste streams are minimized. There are no regular air emissions. The IGSC technology can operate on all ranks of coal, using any of the commercial gasification technologies and can be sized to retrofit an existing steam turbine generating set, or an entire site. 1-5

Conversion of Domestic Coal and Biomass Resources into Power with Net Zero Lifecycle Greenhouse Gas Emissions

Michael Matuszewski, DOE-NETL, USA Recent concern of Greenhouse Gas (GHG) emissions from coal-fired power plants, specifically carbon dioxide (CO2), has prompted the power generation industry to explore new ways to reduce carbon dioxide emissions while maintaining current levels of power plant efficiency and output. The National Energy Technology Laboratory (NETL) initiated this study to analyze the impact of reducing the GHG emissions from coal-fired power plants by co-feeding switchgrass along with coal into an Integrated Gasification Combined Cycle (IGCC) plant. Co-firing biomass along with coal has been demonstrated and may allow coal, the most abundant and secure energy resource in the United States, to maintain its role in the US power supply but in a more advantageous, environmentally friendly way. This study shows that, at demonstrated levels of biomass feed percentage, a net zero limited lifecycle GHG footprint is viable for coal and switchgrass power generation when using state of the art technology. Co-firing biomass with coal allows the CO2 emissions caused by burning biomass to be considered GHG-neutral. The photosynthetic process removes atmospheric CO2 and fixes it to a growing biomass feedstock; therefore CO2 emissions from biomass combustion do not contribute to the net accumulation of atmospheric CO2. However, the cultivation, harvesting and delivery processes to provide both coal and biomass feedstocks utilize fossil fuels and so produce emissions that cannot be considered GHG-neutral. These fossil fuel-related emissions must be considered when evaluating lifecycle greenhouse gas emissions to gain a thorough understanding of the GHG footprint of power generation. This study examines the emissions of CO2 and other GHGs resulting from the production, transportation and combustion of the coal and biomass fuel to provide a limited GHG lifecycle analysis of the process. This report provides an assessment of the technical, economic and environmental performance of coal and biomass-fed IGCC plants. Each case in the study will use varying proportions of Illinois #6 or Montana Rosebud Powder River Basin coal and switchgrass as feed to produce approximately 550 MW of GHG-neutral power.

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SESSION 2

SUSTAINABILITY AND ENVIRONMENT: POLICY

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Legislative and Financial Climate Change Developments and their Impact on the Sustainable Use of Coal

Scott D. Deatherage, Thompson & Knight LLP, USA Over the course of 2009, developments in Congress and the White House as well as numerous state capitals indicate a greater likelihood that climate change legislation and greenhouse gas controls will be imposed on industry and the economy at least in many states and very likely on a national basis. Greenhouse gas reporting requirements will go into effect at the national level, setting up the foundation for a greenhouse gas cap-and-trade program. A cap-and-trade system with carbon allowances and offsets will apparently be at the heart of a future greenhouse gas regulatory system. As we think about these changes, the scientific institutions in the United States and other countries have concluded that human generated greenhouse gases are affecting the climate on the planet. As a result, the policy makers at the state, federal, and international level are proposing a global greenhouse gas control program. As we try to figure out the most economic means of controlling greenhouse gases, we have to understand that human systems and natural systems must be rethought in a way that they began to work together to achieve sustainable industrial activities. The human economic systems must work to sustain the natural systems, whether ecological or climactic. This is not a philosophical step, but a necessary step to preserve our way of life. Human systems must be a recognized part of the climate system and carbon cycle, and we must adjust our economic systems so that profit can be derived from steps taken to manage and reduce carbon dioxide and other greenhouse gas emissions. The new thinking is that human beings become part of the climate management system, not just a bystander or a contributor to climate change. On the other hand, maintaining human economic and social systems is necessary to preserve the well being of the billons of people on the planet. In turning to coal, because its use produces so much carbon dioxide, business as usual does not fit meet the requirements of this new approach. Thus, governments have established a cap-and-trade system that provides the first step in developing a greenhouse gas management system necessary to preserve the natural climate cycle and thereby both our natural ecosystems and human social and economic systems. Where reductions in greenhouse gases can be monetized in the form of carbon credits, human activity will find, and demonstrably has found, the least expensive ways to achieve sustainable use of fossil fuels, renewable energy, energy efficiency, and other steps to reduce greenhouse gases. However, cap and trade does not fully achieve the sustainable use of coal. Another important step, is to bridge the gap between the price of a carbon credit and the cost per ton to remove carbon dioxide from the flue gas of a plant that burns coal. To fully implement the sustainable use of coal, incentives must be introduced by government to make the process more economic. This paper will discuss the background of how and why we are approaching a cap-and-trade system in the United States through legal developments that have occurred and continue to occur. In addition, the paper will discuss the tax credits, grants, bonds, and other financial incentives that have been established at the federal level to contribute to the financial ability to begin capturing and storing carbon dioxide emissions from coal-fired power plants. As we move toward a new approach to the carbon cycle, climate, and greenhouse gas emissions, legal developments and government action will be a necessary start to solving these issues, but human ingenuity, innovation, and the emergence of new technology and practices that reduce costs and drive profits will ultimately lead to the sustainable use of coal. This process is just beginning as the country and the planet move toward a different economy in which the ability to emit greenhouse gases or “carbon” is greatly constrained, and new ways of burning and using coal and other fossil fuels becomes the norm. This shift will be perhaps as great as the first industrial revolution, perhaps this will be seen as the second industrial revolution. Thus, massive shifts in laws and economics will occur starting with new climate legislation and new financial and economic systems to allow the emergence of this new sustainable relationship between natural and human systems. 2-2

The Partnership for CO2 Capture Brandon M. Pavlish, Scott G. Tolbert, University of North Dakota Energy &

Environmental Research Center, USA The Energy & Environmental Research Center (EERC) has put together a program called the Partnership for CO2 Capture, which focuses on conducting pilot-scale demonstration testing of selected CO2 separation and capture technologies for fossil fuel- and biomass-fired systems. The overall goal of the project is to provide key technical and economic information to examine the feasibility of technologies as a function of fuel type and system configuration. The technologies to be evaluated in the project include solvent scrubbing, oxygen-fired combustion, and gas separation membranes for selected fuels. The scope of work involves 1) integrating a high-efficiency, flexible scrubber system with existing pilot-scale combustion and emission control systems to evaluate the performance of scrubbing solvents in flue gas streams derived from selected fossil fuels, biomass, and blends; 2) testing oxygen-fired

combustion for selected fuels and blends in EERC pilot-scale units with the capability to test supercritical, ultrasupercritical, and advanced radiant heat exchangers; 3) evaluating emerging CO2 capture technologies; and 4) performing systems engineering modeling to examine efficient and cost-effective integration of CO2 capture technologies. The paper to be presented at the Pittsburgh Coal Conference will cover the status and preliminary results of the project. 2-3

Taking Action to Adapt Your Organization to Compete in a Carbon Constrained World

Mary Ann Ferris-Young, Tony Gale, Ecology & Environment, Inc., USA Companies are looking for ways to green their offices and reduce their carbon footprint while still being profitable. The largest contributors to US emissions continue to be industry (25%), buildings (43%) and transportation (32%), the majority of which can be addressed by and reduced with greening strategies including web-based energy demand reduction solutions for both buildings and transportation. This presentation provides an overview of GHG emission reduction programs and best practices used to green companies using real-world examples. GHG reduction programs involve managing diverse factors that influence decision making, including changes at various levels of government, voluntary/corporate programs and shareholder concerns. Major contributors of GHG emissions continue to be the electricity and transportation fields, which dominate and produce about seventy percent of US GHG emissions. These staggering numbers present both challenges and opportunities that can be addressed using a step-by-step approach designed to achieve quick and low cost wins for companies engaging in green behaviors. Business opportunities for climate friendly technologies can include the development of efficient vehicle components and building supplies, low carbon coal power, geologic storage of CO2, along with green energy development in wind power, solar power and biofuels. Specific attention will be spent on the green office initiative implemented by Ecology and Environment, Inc. (E & E) through its focus on building and transportation and its approach in design, operations, and behavior of its employees. It includes how carpooling can be used to reduce emissions and vehicle miles traveled and how the results can be measured to demonstrate reductions in electricity, natural gas, employee commuting and their effect on GHG emissions. Office greening initiatives involve identifying focus areas and then implementing an approach centered on design, operations, and behavior. Benefits from this approach can include reductions in GHG, electricity use, natural gas use, and vehicle miles traveled through carpooling which in turn can lead to financial savings and employee wellness. For E&E these initiatives led to E & E’s 20 year old corporate headquarters in Western New York being recognized as the world’s oldest LEED EB Platinum building when it was certified in 2008 and the creation of an energy demand management solution called GreenMeter (www.greenmeter.com). They have also enabled E & E and its employees to reduce over 32 million vehicle miles traveled and prevent thousands of tons of GHG from entering the atmosphere since the company implementing its own internal GreenRide (www.greenride.com) rideshare program in 1973 which is now used by urban areas, large employers and campuses throughout the country. 2-4

Pennsylvania’s Carbon Sequestration Network Database: Where Policy Meets Geology

Kristin M. Carter, Clifford H. Dodge, Thomas G. Whitfield, Jaime Kostelnik, PA DCNR Bureau of Topographic & Geologic Survey, USA

In accordance with Pennsylvania Legislative Act 129 of 2008, the Pennsylvania Department of Conservation and Natural Resources (DCNR) has been delegated the task of identifying “suitable geological formations…for the location of…a carbon dioxide sequestration network established on lands owned by the Commonwealth, or lands on which the Commonwealth has acquired the right to store carbon dioxide, that have been designated by [DCNR] for the storage of carbon dioxide.” To this end, DCNR is establishing carbon sequestration policy measures to effectively implement Act 129 and to ensure a technically, logistically and environmentally sound carbon management program for years to come. As part of this process, DCNR’s Bureau of Topographic & Geologic Survey (the Survey) has implemented a digital database to map and responsibly screen prospective locations for the geologic sequestration of point-source carbon. The digital carbon sequestration network database incorporates location, ownership and related data for prospective sites suggested by the Commonwealth and potential industry partners into a Geographic Information Systems (GIS) environment. Using the database, the Survey can perform desktop evaluations of sites from a geologic perspective using the digital mapping and remote sensing tools at our disposal. We provide examples of this workflow using geologic data compiled by the Survey for two of the better-known saline aquifers in Pennsylvania—the Lower Silurian Medina Group (and correlative Tuscarora Sandstone) and the Lower Devonian Oriskany Sandstone. The overall intent of this database approach is to provide the Commonwealth with the quantitative geologic information needed as part of a larger, integrated sequestration site analysis. The end result is intended to match carbon sources to sinks and

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effectively implement geologic sequestration at both pilot-scale and commercial-scale levels. 2-5

Trends in U.S. Recoverable Coal Supply Estimates and Future Production Outlooks

Mikael Höök, Kjell Aleklett, Uppsala University, SWEDEN The geological coal resource of the U.S. is abundant and proved coal reserves are listed as the world’s largest. However, the reserves are unevenly distributed and located in a small number of states, giving them major influence over future production. A long history of coal mining provides detailed time series of production and reserve estimates, which can be used to identify historical trends. Compilation of data from United States Geological Survey, Energy Information Administration, U.S. Bureau of Mines and others reveal how the recoverable volumes have been decreased since before the 1950s. The exact cause of this reduction is probably a multitude of factors, including depletion, changes in economic conditions, land-use restrictions, environmental protection and social acceptance. In reviewing the historical evolution of coal reserves, one can state that the trend here does not point towards any major increases in available recoverable reserves; rather the opposite is true due to restrictions and increased focus on environmental impacts from coal extraction. The development of new even stricter regulations and environmental laws is also a reasonable assumption and this will further limit the amount of recoverable coal. Future coal production will not be entirely determined by what is geologically available, but rather by the fraction of that amount that is practically recoverable. Consequently, the historical trend towards reduced recoverable amounts is likely to continue into the future, with even stricter regulations imposed by increased environmental concern. Long-term outlooks can be created in many ways, but ultimately the production must be limited by recoverable volumes since coal is a finite resource. Various models, such as the logistic, Hubbert or Gompertz curves, can be used to provide reasonable long-term outlooks for future production. However, such long-term life-cycle projections should not be used as a substitute for meticulous economic studies to forecast perturbations in coal production over the next few years or decades. Based on a logistic model, using the recoverable reserves as an estimate of what is realistically available for production, results in a coal output of around 1400 Mt by 2030 through the rest of the century. The geologic amounts of coal are of much less importance to future production than the practically recoverable volumes. The geological coal supply might be vast, but the important question is how large the share that can be extracted under present restrictions are and how those restrictions will develop in the future. Production limitations might therefore appear much sooner than previously expected.

SESSION 3

CARBON MANAGEMENT: PRE-COMBUSTION – 1

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Effective Utilization of Hydrogen Membranes for CO2 Capture Doug Jack, Carl Evenson, David Anderson, Damon Waters, Eltron Research

& Development, USA The Department of Energy and industry have numerous technology initiatives for clean energy from coal. Hydrogen membranes continue to be developed for applications in gasification and reforming. Eltron has demonstrated and continues to develop and scale-up high flux membranes for economical capture of CO2 and production of hydrogen from water-gas shift feed streams in integrated gasification combined cycle (IGCC) and carbon capture and storage (CCS) applications. Eltron’s Membrane System enables economical and clean power generation from coal by providing improved carbon capture, greater efficiencies and a material cost reduction over conventional technologies. Eltron is also exploring other membrane applications utilizing syngas from coal feed streams as well as opportunity fuels such as biomass and petroleum coke. These applications typically expose membrane to higher sulfur content gas streams and require integration of membranes with gas cleaning technologies and / or development of sulfur tolerant membranes. The most recent results in the development of these membrane and reaction systems will be presented in this paper. Results will be presented on sulfur-tolerant catalyst development as well as long-term membrane hydrogen flux data collected under simulated water-gas shift operating conditions. Comparative techno-economic modeling results will also be presented.

3-2 A Regenerative Process for CO2 Removal and Hydrogen Production in

Integrated Gasification Combined Cycle (IGCC) Processes Javad Abbasian, Illinois Institute of Technology; Armin Hassanzadeh-

Khayyat, Pyrophase, Inc., USA Advanced power generation technologies, such as Integrated Gasification Combined Cycles (IGCC) processes, are among the leading contenders for power generation conversion because of their significantly higher efficiencies and potential environmental advantages, compared to conventional coal combustion processes. Although the increased in efficiency in the IGCC processes will reduce the emissions of carbon dioxide per unit of power generated, further reduction in CO2 emissions is crucial due to enforcement of green house gases (GHG) regulations. In IGCC processes to avoid efficiency losses, it is desirable to remove CO2 in the temperature range of 300 to 500°C, which makes regenerable MgO-based sorbents ideal for such operations. In this temperature range, CO2 removal results in the shifting of the water-gas shift (WGS) reaction towards significant reduction in carbon monoxide (CO), and enhancement in hydrogen production. However, regenerable, reactive, and attrition resistant sorbents are required for such application. This paper discusses the development and evaluation of a highly reactive and attrition resistant regenerable MgO-based sorbent prepared by modification of, which can simultaneously remove carbon dioxide and enhance hydrogen production in a single reactor. The results of the experimental tests conducted in a high-pressure Thermogravimetric Analyzer (HP-TGA) and a high-pressure packed-bed reactor indicate that, in the temperature range of 300 to 500°C at 20 atm, more than 95 molar percent of CO2 can be removed from the simulated coal gas, and the hydrogen concentration can be increased to above 70 percent. Based on the physical and chemical analysis of the sorbent, a two-zone expanding grain model provides an excellent fit to the carbonation reaction rate data at various operating conditions. The modeling results indicate that more than 90 percent purification of hydrogen is achievable. The preliminary economical assessment of the MgO-based process indicates that this process can be economically viable compared to commercially available processes for combined CO2 removal and enhancement of hydrogen production. 3-3

The CO2 and H2 Permeability of Membranes Composed of Highly CO2-Philic Polymers

Mary Barillas, Robert Enick, University of Pittsburgh; Bryan Morreale, DOE-NETL; Philippe Buhlmann, Elizabeth Lugert, University of Minnesota, USA

Membranes could be an integral part of the coal gasification/water-gas-shift reaction process to transform coal, oxygen and water feed streams into hydrogen for fuel and CO2 for sequestration. The objective of this work is to design polymeric membranes that have very high CO2 permeability and high selectivity toward CO2 (i.e. very low H2 permeability). It is our hypothesis that the favorable thermodynamic interactions that enable certain polymers to dissolve in dense CO2 at extremely high pressure will also allow membranes composed of these polymers to exhibit high CO2 permeability at low pressure. Candidates include poly(dimethyl siloxane) (PDMS), perfluoropolyether (PFPE), polypropylene glycol (PPG), polyethylene glycol (PEG), and polyacetoxy oxetane (PAO). The membranes composed of these polymers will be tested as supported liquid membranes where the oligomers are supported onto a porous nylon support. These membranes will be tested in a constant pressure membrane system. The constant pressure experiments were conducted within a temperature range of 310 to 423 K and CO2 and H2 partial pressure gradients near atmospheric conditions. Permselectivity values were determined as the ratio of CO2 permeability to H2 permeability. The PPG, PEG and PFPE diacrylate liquids were cross-linked to form flexible membranes. Membranes composed of PFPE-plasticized Teflon AF were also assessed. These crosslinked films will be tested in a constant volume apparatus to determine the CO2 or H2 permeability value. These constant volume experiments were conducted at 295K and CO2 (or H2) partial pressure gradients no greater than 450 kPa. Ideal selectivity values were determined as the ratio of CO2 permeability to H2 permeability. 3-4

Novel CO2-Selective Membrane for Syngas Application Alvin Ng, Douglas E. Gottschlich, Membrane Technology

and Research, Inc., USA Industrial membrane separation technology is a two to three billion dollar industry, mostly in water separation such reverse osmosis and microfiltration. Gas separation constitutes approximately ten percent for the overall membrane market, mostly in O2/N2 separation and in the natural gas industry for CO2 removal. Current commercially available CO2-selective membrane used in the natural gas industry is not suitable for syngas application as it does not offer any appreciable selectivity of CO2 over H2. Hence, CO2 capture from syngas is largely dominated by physical absorption systems such Solexol and Rectisol or chemical absorption systems such as amines. MTR, a supplier of membrane-based separation systems has developed a novel membrane that preferentially permeates CO2 while rejecting H2 and CO. In addition to

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CO2 removal, this membrane also preferentially permeates H2S over other syngas components, ideal for bulk H2S removal. This novel membrane is capable of removing/recovering greater than 50-90+% CO2 at sufficiently high recovered-CO2 concentration, 80-90+ mol%. 3-5

Sorbent-Enhanced Water Gas Shift Reaction Studies Ranjani V. Siriwardane, Robert W. Stevens, Abolghasem Shamsi, DOE-

NETL; Stephen P. Carpenter, R.E.M. Engineering Services, USA An Integrated Gasification Combined Cycle (IGCC) is a power plant configuration that turns coal into synthesis gas. Impurities are removed from the coal gas before combustion, resulting in lower emissions and improved efficiency compared to conventional pulverized coal plants. Sorbents capable of capturing CO2 at the moderate temperature and high pressure of the IGCC process are necessary for an environmentally-friendly operation of the IGCC plant. In IGCC, the water gas shift (WGS) reaction, CO + H2O → H 2 + CO2, is typically used to upgrade the hydrogen content of the syngas stream but also produces CO2 as a product. CO2 capture/removal may take place either downstream to the WGS unit or within it. The latter offers the advantage of not only less unit operations within the plant, but also shifts the equilibrium of the WGS reaction itself as CO2 is removed from the gas phase, enhancing the conversion of CO. NETL researchers have developed novel CO2 capture sorbents for the moderate temperature application of the WGS reaction. The sorbents were evaluated for their ability to enhance the WGS reaction at temperatures of 300 – 600 °C, both in the presence and absence of catalyst. Testing at 500 – 600 °C in the absence of catalyst resulted in CO conversions of nearly 100% prior to sorbent saturation, surpassing the thermodynamic equilibrium CO conversion of the gas-phase WGS reaction under identical conditions. The sorbents were also tested during the WGS reaction at 400 °C and 150 psig in the presence of a Pt/Ce2O3 catalyst.

SESSION 4

COMBUSTION: OXY-COMBUSTION – 1

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Integrated Oxy-Coal Circulating Fluidized Bed Project Rick Victor, Dante Bonaquist, Minish Shah, Praxair, Inc.; Horst Hack, Foster

Wheeler North America Corp., USA A fully integrated carbon dioxide capture and storage (CCS) demonstration project based on oxy-coal combustion technology in a Circulating Fluidized Bed (CFB) is being developed for a municipal utility in New York State. This paper will give a status update on the project, which was submitted for funding under the US Department of Energy’s Clean Coal Power Initiative. Preliminary results from a FEED study currently underway will be discussed, including cost, design and integration issues. Also reviewed will be the test plan for the demonstration period, which must verify performance and operability issues of importance to utilities considering this technology. The nominal gross output of this combined heat and power facility is projected to be 54 MWe. Scope includes electrical power generation and district heating with near-zero emissions, CO2 capture, purification and underground storage. Advanced technologies for a Flexi-Burn (dual oxidant), circulating fluidized bed boiler (CFB), cryogenic air separation unit (ASU) and CO2 processing system are to be demonstrated in a commercial operation that will enable direct scale-up to 500 MW size utility power plants. The demonstration plant will replace existing coal fired generation capacity at the Board of Public Utilities’ Carlson Station located in southwestern New York State at Jamestown. An alliance of commercial and governmental organizations has been built around the project. Foster Wheeler will supply the CFB as well as combustion expertise. Praxair will provide gas processing technology including the ASU and CO2 processing unit. The captured CO2 will be purified and stored in underground saline formations near the site. 4-2

Cost Reduction and R&D Strategies for Advanced Oxyfuel Technologies Michael Matuszewski, DOE-NETL, USA

As it becomes increasingly likely that future CO2 emissions will be regulated in some fashion, new processes are being developed to capture CO2 from the flue gas of fossil fuel-fired power plants. One method to capture CO2 is to use oxygen rather than air as the oxidant in the combustion process, which yields a flue gas stream comprised primarily of CO2 and H2O. By removing the water, a nearly pure CO2 stream can be produced. This approach is known as oxyfuel or oxycombustion. Greenfield oxycombustion-based power plants, as they would be constructed with technology available today, were addressed in a 2008 NETL study, “Pulverized Coal Oxycombustion Power Plants” (Ciferno, et al., August 2008). The 2008 study found that in a state of the art oxyfuel system, the cost of electricity for nearly 100% carbon

capture increases by approximately 66% over a similar plant (i.e. identical boiler and steam conditions) without capture. The conceptual study presented within this paper builds upon the aforementioned 2008 study by theoretically upgrading the state of the art plant with a series of advanced technologies that will increase system efficiency and decrease the cost of electricity resulting from the oxycombustion process. The goal of this study is to provide a pathway for meeting NETL’s goal of supporting the development of technologies that meet or exceed 90% carbon capture while limiting the increase in cost of electricity over a baseline plant without capture to a maximum of 35%. The 2008 oxycombustion study revealed that the elimination of key bottlenecks in an oxy-fired system would significantly increase the efficiency of the plant, reduce costs and facilitate an approach to NETL’s carbon capture goal. The current study quantifies the technical, economic and environmental effects of eliminating these bottlenecks by assuming R&D successes will permit implementation of the following advanced technologies: 1.) Ultrasupercritical Steam Conditions, 2.) Boiler/Feedwater Integration with an Ion Transport Membrane for Oxygen Production, 3.) Co-Sequestration of CO2, SOx & NOx, 4.) Advanced Shock Compression Technology, 5.) Oxyfuel Boiler Designs, and 6.) Biomass Co-firing to reduce the need to capture CO2. This forward-looking study determines the individual benefits of implementing each technology on its own in order to guide research and development toward the technology areas with the most potential for meeting NETL’s carbon capture goals. This study also examines the cumulative effect of installing all technologies into the same plant, as well as any positive, or negative, technology synergies, assuming all R&D endeavors are a complete success. Therefore, this study also assesses the maximum potential for exceeding the performance of state of the art oxyfuel technology and for meeting NETL’s carbon capture goals. 4-3

A Thick-Film Wireless Metal Oxide Oxygen Sensor for Oxy-Fuel Powerplants

Wei Wu, David W. Greve, Irving J. Oppenheim, Carnegie Mellon University, USA

Measurement of the concentration and distribution of excess oxygen in the effluent of oxy-fuel power plants is important in order to minimize the amount of separated oxygen required. We are working to develop a multi-point sensor suitable for the measurement of oxygen concentration in oxy-fuel combustor exhaust. The sensor is based on semiconducting metal oxides that are sensitive to oxygen concentration and that can operate in the hostile high-temperature environment. The sensor is inductively coupled so that no penetrations for electrical connections are required, minimizing potential points for failure and air leakage. We will present the results of measurements of the oxygen sensitivity and resistivity at constant oxygen concentration for both ZnO and TiO2 and these observations will be related to the conduction mechanisms in these materials. We will also report on the fabrication and performance of inductively coupled sensors. 4-4

Pathway to Supercritical Flexi-Burn™ CFB Power Plant to Address the Challenge of Climate Change

Horst Hack, Zhen Fan, Andrew Seltzer, Archie Robertson, Foster Wheeler North America Corp., USA

A growing concern regarding air emissions and their effect on global warming is a key factor to be considered in developing and implementing new energy production solutions. Carbon-dioxide capture and storage (CCS) offers the potential for major reductions in carbon- dioxide emissions of fossil fuel-based power generation. Oxy-fuel combustion has been identified as one of the more economically favorable CCS technology options. Foster Wheeler AG Global Power Group companies (Foster Wheeler) are working to address the reduction of carbon-dioxide emissions of power plants with its integrated Flexi- Burn™ CFB (circulating fluidized-bed) technology. The proven high efficiency supercritical CFB technology, when coupled with air separation units and carbon purification units, offers a solution for carbon dioxide emissions reduction. CFB technology has some advantages over pulverized coal technology, including a more uniform furnace heat flux, increased fuel flexibility and offers the opportunity to further reduce carbon dioxide emissions by more readily cofiring coal with bio-fuels. Through proper configuration and design, the same CFB steam generator can be switched from air mode to oxy-fuel mode without the need for unit shutdown for modifications. Foster Wheeler is addressing the development of supercritical Flexi-Burn CFB steam generators and integration with their balance-of-plant systems, through a variety of programs. These include pilot plant testing, small-scale demonstration projects, medium-scale demonstration plants, and the design of a commercial-scale supercritical Flexi- Burn CFB. The present paper will provide an overview of Foster Wheeler’s recent work in these areas.

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4-5 Modeling and Testing of the 40 MWt Oxycoal™ Burner

T.K. Klajny, A. Duncan, S. Yousif, E.D. Cameron, Doosan Babcock Energy Ltd, UNITED KINGDOM

Oxyfuel firing, the combustion of fuel in a medium comprising injected oxygen plus recycled flue gas, offers a means of generating carbon dioxide rich flue gas requiring minimal treatment prior to sequestration or beneficial application. Doosan Babcock is leading a number of collaborative projects that are investigating the following pertinent items: • Oxyfuel combustion fundamentals and underpinning technologies • Demonstration of a full-scale (40 MWt) OxyCoal™ burner • Development of oxyfuel-fired power plant operating strategies The projects are part-funded by grants from the UK Government Department for Business Enterprise and Regulatory Reform (BERR). The project participants comprise Air Products plc, E.ON UK plc, RWE npower plc, BP Alternative Energy International Limited, University of Nottingham, Imperial College London, Scottish and Southern Energy plc, ScottishPower Energy Wholesale, EDF Energy plc, Drax Power Limited and DONG Energy A/S. Each project features different groupings of participants. Computational Fluid Dynamics (CFD) modelling represents an integral part of Doosan Babcock’s research and development philosophy. Here, CFD is being used to further the understanding of the effects of oxyfuel process parameters on gaseous emissions, coal burnout, flame stability and thermal performance. This paper presents preliminary results from the testing of a full-scale OxyCoal™ burner, relevant for both new build and retrofits application, and outlines the development of a modelling approach for oxyfuel firing. It goes on to make comparisons between air and oxyfuel firing in single burner test facility and utility furnace environments.

SESSION 5

COAL-DERIVED PRODUCTS: CHEMICALS AND MATERIALS FROM COAL

5-1

Upgrading of Low Rank Coal through Mild Solvent Treatment at Temperatures below 350°C

Ryuichi Ashida, Satoshi Umemoto, Yusuke Hasegawa, Kouichi Miura, Kyoto University; Kenji Kato, Koji Saito, Seiji Nomura, Nippon Steel Corporation,

JAPAN Treatment of brown coal in a non-polar solvent (1-methylnaphthalene) at below 350°C is proposed as an effective method to fractionate brown coal into several upgraded fractions having different chemical compositions and structures. When an Australian brown coal, Loy Yang (C%=66.7, O%=27.7), was treated for 3 h at 350°C in a batch extractor, it was converted into three upgraded fractions: the fraction soluble in solvent even at room temperature (Soluble; Yield:Y=0.267, average molecular weight: MW,a≈330, C%=83.0, O%=9.4), the fraction soluble at 350°C but insoluble at room temperature (Deposit; Y=0.111, MW,a≈500, C%=76.8, O%=17.2), and the solvent insoluble fraction (UC; Y=0.455, MW,a≈800, C%=78.8, O%=16.5). The rest of the brown coal was converted into either CO2 or H2O. This means that 83% of the brown coal was converted into high carbon and low oxygen content fractions having rather uniform molecular weight distribution under mild condition. The fractions had properties significantly different from those of the raw coal, suggesting their application to various purposes. Furthermore, the net heating value of the products, 26.5 MJ/kg-coal, is larger than the heating value of the parent coal, 25.4 MJ/kg-coal. This shows that the treatment of the brown coal by 1-methylnaphthalene is an endothermic process, suggesting the effectiveness of the method as a brown coal upgrading method. The proposed method will surely be one of novel and effective brown coal utilization methods. 5-3

Carbonization Properties of Coal Extract Prepared by Non-Hydrogenative Extraction of Coal – Application as an Additive for

Metallurgical Coke Making Maki Hamaguchi, Takahiro Shishido, Noriyuki Okuyama, Koji Sakai,

Nobuyuki Komatsu, Kobe Steel, Ltd.; Toshinori Inoue, Kobelco Research Institute, JAPAN

Carbonization properties of coal extracts prepared by methylnaphthalene extraction of a steaming coal were evaluated in view of application for metallurgical coke binder. Addition of the coal extracts to the coking coal blends results in the increase of coke strength, in particular for coke from a weakly coking coal. Nanoindentation measurement indicated that carbon derived from the coal extract exhibited a similar Young’s modulus to that of coke from a strongly-coking-coal. Improvement of coke strength by the coal extract addition was attributable to the facts that coke from the

extracts exhibits high strength, and the interaction between the coal extract and coal facilitates graphitization of the weakly-coking coal. 5-5

High Quality Transportation Fuels from Direct Coal Liquefaction John E. Duddy, James B. MacArthur, Axens North America, Inc., USA

Compared to conventional crude oils used today to produce high quality transportation fuels, raw coal liquids derived from Direct Coal Liquefaction are more aromatic, with higher nitrogen and oxygen contents, but very low sulfur content. Based on these characteristics of liquids from direct coal liquefaction, there are some key challenges for secondary processing (using conventional refining technologies) to meet all of the specifications required for the today’s clean fuel specifications. Extensive experimental and development work has been done Axens to characterize the raw coal liquids and to define secondary processing of raw coal liquids required to produce high quality transportation fuels. This presentation will describe the secondary processing of liquids from direct coal liquefaction and show that liquid fuels from direct coal liquefaction can be upgraded to meet the most stringent current specifications for clean liquid transportation fuels.

SESSION 6

COAL-DERIVED PRODUCTS: COAL-TO-LIQUIDS: TECHNOLOGY – 1

6-1

Secure, Clean Fuels from Coal: Indirect Liquefaction James Spivey, Adefemi Egbebi, Louisiana State University; Anthony Cugini,

Bryan Morreale, DOE-NETL; Chunshan Song, Pennsylvania State University; John C. Winslow, Leonardo Technologies, Inc., USA

Fuel independence, energy availability and reliability, economic sustainability, and global climate change are serious National concerns of the 21st century. Development of liquid transportation fuels from sources other than petroleum, coupled with carbon management practices, will help address these issues. Research and development efforts have been focused on the production of synthetic transportation fuels from indigenous carbonaceous feedstocks, such as coal, oil shale and biomass. Most recently, pure biomass and biomass in conjunction with coal has been the target of renewed interests. However, due to its abundance and low cost, coal will most likely be a key component for synthetic fuels in an effort to meet national economic and supply demands. Historically, several thermochemical pathways have been identified and practiced for the production of synthetic fuels from coal, falling into three general categories; indirect liquefaction, direct liquefaction and pyrolysis. The production of synthetic fuels from coal requires removing carbon or adding hydrogen to transform coal, with a low hydrogen-to-carbon molar ratio of coal (~0.8), to transportation fuels, with a hydrogen-to-carbon ration of ~2. The indirect liquefaction of coal is a multi-step, thermocatalytic process. First, a carbon based feedstock is reacted with steam in a partial oxidation environment at temperatures up to 1500oC and 8MPa to produce a gas stream rich in carbon monoxide and hydrogen, often referred to as synthesis gas or syngas. The highly energetic syngas stream undergoes further processing including particulate removal, gas cleaning, water-gas shift and sulfur polishing prior to the liquefaction process. The basis of the indirect liquefaction process is the thermocatalytic conversion of the clean syngas in the presence of Co- or Fe-based catalysts to produce a wide range of hydrocarbons. The indirect liquefaction reaction is highly exothermic, and generally utilizes a multi-phase slurry bubble column reactors on commercial scale for temperature management, although fixed-bed reactors have been used. The presentation will provide a historical perspective of the development of indirect liquefaction technologies, the catalysis and reaction pathways, and potential future directions. 6-2

High Efficiency Polygeneration through the Integration of CTL and IGCC

William S. Rollins, NovelEdge Technologies, LLC, USA To be viable in today’s world, coal plants must demonstrate low emissions, utilize carbon capture and sequestration (CCS), and still return favorable economics. This has proven to be a difficult task, even for state-of-the-art IGCC plants. Coal-to-liquids (CTL) plants prove to be excellent revenue generators in times of skyrocketing oil prices, but these plants have high capital costs and face opposition from environmental groups, even when CCS technology is an integral part of the plant. Now, through the integration of CTL and IGCC, using NovelEdgeTM Technology as the interlacing process, a step change in efficiency, environmental performance, and economics can be achieved. It is well known that Fischer-Tropsch (F-T) processes are highly exothermic, and typically generate large quantities of saturated steam. However, this saturated steam is not used to its potential in conventional CTL plants.

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Through a cooperative study with the DOE, a 50,000 bpd CTL plant with CCS (DOE published report DOE/NETL-2007/1260) was integrated with a highly-fired combined cycle process to superheat and reheat the large quantities of steam from the CTL plant. Using additional syngas to the power island, the export power was increased from 124 to 1088 MW. The incremental heat rate for this power was less than 6000 Btu/kWh, while estimated incremental capital costs were on the order of $1,000/kW. Compared to conventional DOE plants with equivalent output (the aforementioned CTL and 2 – 513 MW IGCC with CCS from DOE/NETL-2007/1281, Case 6), emissions of SOx and NOx were reduced by 90%, CO2 emissions were 17% less, and the CO2 to sequestration was reduced by 27%. Overall coal consumption was reduced by 17%. The net result from the cooperative report is the definition of a polygen facility with ultra-low emissions and a return on investment that is 150% greater than that of the conventional plants. Even with no charges of CO2 to the fuel production (all CO2 assigned to the power island), the CO2 emissions are half that of a modern natural gas fired combined cycle. 6-3

Performance, Cost and Emissions Analysis of Coal-To-Liquids Plants with Different Gasification Technologies, under Carbon Constraints

Hari Chandan Mantripragada, Edward S. Rubin, Carnegie Mellon University, USA

Coal-to-liquids (CTL) processes generate synthetic liquid fuels like gasoline and diesel fuel from coal. The process involves gasification of coal to produce synthesis gas which is then catalytically converted into liquid fuels in a Fischer Tropsch (FT) reactor. A variety of gasification technologies (GE/Texaco, Shell, EGas) can be used to convert coal into syngas. Similarly, FT technologies can be classified into high temperature (HTFT) and low temperature (LTFT) reactors which produce different liquid fuels from syngas. One main concern of coal liquids, however, is the large emissions of carbon dioxide (CO2) from the CTL process. These emissions can be mitigated using carbon capture and sequestration (CCS) technology. Two configurations are possible for CTL plants. In a typical commercial CTL plant, the unconverted syngas from the FT reactor is recycled to the reactor to increase the productivity of the liquids. In this work, such plants are called ‘liquids-only’ plants. The unconverted syngas from the FT reactor, instead of being recycled, can be combusted in a gas turbine steam turbine combined cycle power plant to generate electricity, which can be sold to the grid to add another stream of revenue. Plants with such configuration are called ‘poly-generation’ plants here. Different combinations of these component technologies (gasification, FT and CCS) and plant configurations (liquids-only or poly-generation) affect the performance, cost and emissions of a CTL plant. In this paper, CTL processes using different commercial gasification technologies (GE, E-GAS and Shell) are techno-economically evaluated. Effect of implementing CCS or carbon constraints that impose a price or cost on CO2 emissions is also studied. To study these effects, a comprehensive techno-economic assessment model of liquids-only and poly-generation CTL plants, capable of incorporating CCS is developed. To illustrate this model, a CTL plant producing 50,000 barrels/day of liquid products is considered as a case study. Capital costs ($/barrel/day) and cost of liquid products ($/barrel) are presented for a combination of different component technologies and plant configurations, under carbon constraints.

SESSION 7

GASIFICATION: GENERAL SESSION – 2

7-1

Cost and Performance Baseline for Fossil Energy Power Plants Low-Rank Coal to Electricity with CCS Jeff Hoffmann, DOE-NETL, USA

A substantial portion of the world’s coal resources are comprised of lower-rank subbituminous and lignite coals. The U.S. Department of Energy/Energy Information Administration (DOE/EIA) estimates that low-rank coals account for nearly fifty percent of all global estimated recoverable coal resources. In the United States, subbituminous and lignite coals represent more than fifty percent of all estimated recoverable coals. Globally, low-rank coals are an important energy resource and the continued use of this plentiful fuel in a clean and efficient manner can supplement a diverse and secure domestic energy portfolio. For example, in OECD Europe, these coals represent approximately seventy percent of recoverable coals, and in some European countries, such as Germany, subbituminous and lignite coals dominate domestic reserves. Advanced clean-coal technologies such as integrated gasification combined cycle (IGCC) plants have shown significant promise in enabling continued use of coal resources in a clean, highly efficient manner. In addition, pulverized coal (PC) and circulating fluidized bed combustion (CFBC) plants designed with increasingly higher pressure steam cycles are showing similar progress. However, continued interest in reducing the carbon footprint of coal-based power plants is resulting in a growing

impetus for the inclusion of carbon capture and sequestration (CCS) technologies. The inclusion of such technologies results in increased system complexity, lower overall plant efficiencies, and higher facility capital costs. The lower energy contents of subbituminous and lignite coals, compared to higher ranked bituminous coal, results in additional design and economic challenges for advanced clean coal plants, both with and without CCS. The low energy content, particularly for lignite, results in economic drivers to locate the plant near the fuel source. From the perspective of the United States, much of the low-rank coal resources are located in western, arid regions with limited water resources and high geographic elevations. The reduced air mass at elevation and limited water resources require further consideration in facility design and can result in higher capital costs and lower plant output. Ultimately, the combination of these technical and economic factors can influence technology selection (e.g., IGCC, PC or CFBC), and general conventions often considered for bituminous coal may not hold for low-rank coals. This study establishes performance and cost data for fossil energy power systems fueled by low-rank coals, specifically IGCC, PC, and CFBC plants at near-mine locations, all with and without CCS. The analyses are performed on a consistent technical and economic basis that accurately reflects current market conditions for plants starting operation in 2015. 7-2

Air Blown Fluidised Bed Gasification of High Ash Indian Coals - BHEL’s Experience in a 168 TPD PFBG

G. Viswanathan, R. Jayapal, R. Kannan, M. Selvakumar, S. Krishnamoorthy, Bharat Heavy Electricals Limited, INDIA

Bharat Heavy Electricals Limited (BHEL), India has installed a 6.2 MW IGCC plant in 1989, with a moving bed gasifier. Having established the feasibility of IGCC for high ash Indian coals and understanding the limitations of the moving bed gasifier, BHEL added a Fluidised bed gasifier in 1996. This paper gives a brief description of the Pilot Scale IGCC Demonstration plant and BHEL’s experience in gasification of the coals along with details of various systems incorporated and tested and the parametric variation studies during the tests to enhance the performance of the gasifier. The extent of improvement in carbon conversion with fly ash recycling adopting a non mechanical (seal pot) recycle system are presented. The effect of some of the parameters like the temperature of operation of the fluidized bed and the temperature of the air used for fluidisation and reaction on gas composition are detailed. Based on the experience, BHEL is working on a scale up design to 182 MW capacity. The basic details of the same are also presented. 7-3

Air-Blown Gasification Demonstration Facility – Alton, IL David W. Wakefield, Robert G. Jackson, Econo-Power International Corp., USA

Air-blown coal gasification has been used for many years in international markets for providing fuel gas from a variety of coals. EPIC’s Alton Demonstration Gasification Facility (ADGF) is under construction to provide a US-based air-blown gasification plant for demonstration with a variety of coals including coal and biomass mixtures. The ADGF will:

1. Provide fuel gas to a combined heat and power unit using gas reciprocating engines with waste heat recovery for an adjacent algae farm 2. Provide fuel gas for an adjacent steel mill 3. Provide H2S removal using iron oxide absorbent (JNT) 4. Provide ability to extract syngas at various points in the process to allow for syngas to alcohol production; syngas to liquids testing; investigation of CO2 capture technologies; utilization of discrete streams of CO2 in gasification; and test alternate H2S removal systems

The ADGF configuration will be: 1. Gasifier and coal feed 2. Gas clean up and tar reinjection system 3. Dry absorbent H2S removal 4. 2 x GE J620 engines 5. Industrial-scale CO=>H2 + CO2 (capture)

This paper will discuss the basic design and options of use of air-blown gasification at ADGF. 7-4

Prediction of Gasifier Performance with Loads for Korean 300MW IGCC Plant

Jin Hee Jeon, Bongkeun Kim, Jahyung Koo, Minsu Paek, Doosan Heavy Industries & Construction, KOREA

The gasifier’s heat and mass balance model developed by Doosan has predicted design parameters such as coal consumption, cold gas efficiency, carbon conversion rate and syngas compositions of a 300 MWe IGCC plant to be constructed in Korea. The heat conduction, convection, and radiation, and slag thickness in the gasifier have also been determined by a simple heat transfer module in the model. The heat and mass balance model has been developed based on the chemical equilibrium theory and the syngas

7

capacity was assumed to be more than 530 Gcal/hr. In the entrained-flow gasification process, slag behavior is one of the major operating parameters due to the ash deposition and dissolution of refractory liners. The slag thickness has been determined based on the predicted value of slag liquidus temperature with flux addition. From the modeling results of the heat and mass balance, the coal consumption was 104 ton/hr and the cold gas efficiency was 81-83 % with variations of oxygen to coal ratio and steam to coal ratio. Moreover, the operating temperature of the gasifier could be decreased by 350 °C with the flux addition of 12 wt%. 7-5

Optimal Integrated Design of Air Separation Unit and Gas Turbine Block for IGCC Systems

Ravindra Kamath, Ignacio E. Grossmann, Lorenz T. Biegler, Carnegie Mellon University; Stephen E. Zitney, DOE-NETL, USA

The Integrated Gasification Combined Cycle (IGCC) systems are considered as a promising technology for power generation. However, they are not yet in widespread commercial use and opportunities remain to improve system feasibility and profitability via improved process integration. This work focuses on the integrated design of gasification system, air separation unit (ASU) and the gas turbine (GT) block with the objective of minimizing the investment and operating costs. The ASU supplies oxygen to the gasification system and it can also supply nitrogen (if required as a diluent) to the gas turbine block with minimal incremental cost. Since both GT and the ASU require a source of compressed air, integrating the air requirement of these units is a logical starting point for facility optimization. Air extraction from the GT can reduce or avoid the compression cost in the ASU and the nitrogen injection can reduce NOx emissions and promote trouble-free operation of the GT block. There are several possible degrees of integration between the ASU and the GT. In the case of ‘total’ integration, where all the air required for the ASU is supplied by the GT compressor and the ASU is expected to be an elevated-pressure (EP) type. Alternatively, the ASU can be ‘stand alone’ without any integration with the GT. In this case, the ASU operates at low pressure (LP), with its own air compressor delivering air to the cryogenic process at the minimum energy cost. Here, nitrogen may or may not be injected because of the energy penalty issue and instead, syngas humidification may be preferred. A design, which is intermediate between these two cases, involves partial supply of air by the gas turbine and the remainder by a separate air compressor. These integration schemes have been utilized in some IGCC projects. Examples include Nuon Power Plant at Buggenum, Netherlands (both air and nitrogen integration), Polk Power Station at Tampa, US (nitrogen-only integration) and LGTI at Plaquemine, US (stand-alone). However, there is very little information on systematic assessment of air extraction, nitrogen injection and configuration and operating conditions of the ASU and it is not clear which scheme is optimal for a given IGCC application. In this work, we address the above mentioned problem using a systematic methodology that involves sequential modular optimization. A superstructure is proposed which incorporates all the integration schemes described above. The structural configuration of the ASU, which is commonly referred to as a cycle, depends on the product slate (production rate, purity and delivery pressure as gases or liquids) and thus indirectly on the integration scheme. The superstructure for the ASU includes most of the popular cryogenic cycles based on the dual column coupled with an integrated condenser and reboiler. Therefore, it can handle a variety of operating conditions and integration possibilities with the GT block. The superstructure is modeled using the Aspen Plus process simulator which has both simulation and optimization capabilities. The flowsheet for the ASU has a complex heat integration scheme which often leads to convergence problems as well violations of minimum temperature driving force constraints. In order to promote an easy evaluation of the flowsheet model at each iteration of the optimization, many interacting loops are torn and are matched externally in form of equality and inequality constraints by using an optimizer. The optimal structural configuration and operating conditions are presented for several case studies.

SESSION 8

SUSTAINABILITY AND ENVIRONMENT: GHG/GWP

8-1

The Strategic Role of Coal in the Fight Against Global Warming Alex Wormser, Wormser Energy Solutions, Inc., USA

A new approach to eliminating the CO2 emissions from both new and existing coalplants is described. It combines a new technology with a new funding model that enables the power industry to begin the wide scale elimination of CO2 emissions as soon as the new technology is demonstrated. In particular, it eliminates the delay inherent in the current system, which depends on the value of carbon credits to rise substantially before utilities can afford to implement carbon abatement programs.

8-3 Greenhouse Gas (GHG) Inventories Encourage

“Portfolio-ing” of Sustainability Steven M. Carpenter, Marshall Miller & Associates, Inc., USA

In an ever increasing “carbon” society; our awareness, management and growth will be measured by our carbon footprint (or output). Virtually all industries in today’s marketplace are under scrutiny of carbon, water and environmental “footprints”. The fundamental building-block for any business, strategic or management decision must be based on an understanding of one’s “footprint”. This understanding requires many “new ways” of thinking about the industrial sector. The very real likelihood that carbon footprints become common place for due diligence as part of merger & acquisition strategy, all new and retrofit construction completed to L.E.E.D. certification and the use of “Green-grid” are examples of the “new ways” the industrial sector will be forced to operate. The scrutiny is most stringent for the power producers and fuel suppliers in the energy market. An overview of currently acceptable standards, application of those standards and nuances (e.g. application of standards to Powder River Basin coal mining) experienced in collecting the data necessary to analyze and complete a company’s carbon footprint will be presented. Additional discussion will occur regarding the ancillary and ever growing “environmental footprint” that include water usage as a gauge to one’s overall impact to the environment. There is uncertainty in the marketplace due to a lack of regulation, the fear and expectation of new and ever constraining rules, regulation and a change in United States federal administration are a recipe for uncertainty, change and chaos. The international community (ISO, CSA, UNFCCC) is trying to put in place controls to afford consistent application of existing rules and afford industry a chance to plan and make forward thinking decisions without the fear of sudden change. The impact of these proposed changes and lack thereof will be discussed.

SESSION 9

CARBON MANAGEMENT: PRE-COMBUSTION – 2

9-1

Optimal Design of PSA Cycles for Pre-Combustion CO2 Capture using a Superstructure-Based Approach

Sree Rama Raju Vetukuri, Anshul Agarwal, Lorenz T. Biegler, Carnegie Mellon University; Stephen E. Zitney, DOE-NETL, USA

Pressure Swing Adsorption (PSA) is a well known technology for gas separation and purification. It has been widely used for H2 production from the effluent stream of a shift converter, which predominately comprises H2 and CO2, with other components in negligible amounts. Most of the commercial PSA cycles have been developed to recover H2 at an extremely high purity, and do not focus on enriching the strongly adsorbed CO2. Thus, a major limitation exists with the use of these conventional PSA cycles for high purity CO2 capture. Furthermore, multi-bed PSA systems are typically operated in a cyclic manner with each bed repeatedly undergoing a sequence of steps. Their complex dynamic behavior, together with the numerical difficulties of the model governed by partial differential and algebraic equations (PDAE), makes the evaluation and assessment of different operating steps and cycle configurations very difficult and time consuming. Therefore, a systematic methodology is essential to develop, evaluate and optimize PSA cycles to recover both H2 and CO2 at high purity. In this work, we present a systematic optimization-based formulation for the synthesis and design of novel PSA cycles for pre-combustion CO2 capture. Here, we propose a superstructure-based approach to simultaneously determine optimal cycle configurations and design parameters for PSA units. The superstructure consists of two beds, one of which acts as an adsorbing bed and the other as a desorbing bed. The interconnections between the two beds are governed by time-dependent control variables, such as fractions of the light and the heavy product recycle. The superstructure is rich enough to predict a number of different PSA operating steps (e.g., pressurization/depressurization, adsorption/desorption, pressure equalization, light and heavy product recycle), which are accomplished by varying these control variables. An optimal sequence of operating steps is achieved by solving an optimal control problem for the superstructure. Two different approaches to solve the optimal control problem are presented and discussed. Numerical results for case-studies related to pre-combustion CO2 capture from a feed mixture having hydrogen and carbon dioxide are presented. The case study aims at optimizing the superstructure to obtain an optimal PSA cycle which maximizes CO2 recovery while ensuring that a specified purity level for both H2 and CO2 is achieved. Preliminary results show that the superstructure can predict PSA cycles which can recover both H2 and CO2 at a substantially high purity of 94 % and 93 %, respectively. The superstructure approach is, therefore, quite promising and can be effectively used to assess the usefulness of PSA processes for CO2 capture.

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9-2 Carbon Capture Optimization for IGCC and PC Power Plants

Eric Grol, DOE-NETL, USA This study will examine the technical and economic implications of achieving a wide range of carbon capture and sequestration (CCS) goals for pulverized coal (PC) and integrated gasification combined cycle (IGCC) plants. Many recent studies have identified 90% capture as the carbon removal target. However due to regulatory uncertainty, the level of CCS required by new and existing plants is not known. Therefore, this study will consider carbon capture targets ranging from as low as 30%, and as high as 95%, for PC and IGCC applications. The optimum configuration in terms of cost and efficiency will be identified for PC and IGCC application for varying degrees of CCS. Carbon capture for the PC cases will be done using a slipstream approach. To accommodate lower levels of capture, a portion of the flue gas will bypass the acid gas removal system. Since an IGCC system is highly integrated, there are more choices for dealing with different degrees of capture. Some of the IGCC configurations discussed in this work will include process modifications to the water gas shift step (including no shift, or a reduced number of shift reactors), a bypass approach (similar to the approach used for the PC cases), and different CO2 separation technologies (physical versus chemical processes, which typically are associated only with carbon capture for PC applications). 9-3

Molecular Simulations of Pure and Mixed Gases Physical Absorption in Ionic Liquid (IL) of [hmim][Tf2N] for CO2/H2/Ar

Wei Shi, Parsons Corporation and DOE-NETL; Dan Sorescu, DOE-NETL, USA

Understanding the absorption mechanism of H2 and CO2 in ionic liquids is highly important for rational design of supported ionic liquid membranes used for CO2 pre-combustion capture applications. Recently, Noble et al. [1] and Maurer et al. [2] have determined experimentally the H2 solubility in [hmim][Tf2N], but the two sets of results present significant differences among each other. In this study, we used osmotic continuous fractional component (CFC) Monte Carlo simulations and Gibbs CFC technique [3] to calculate the absorption isotherms of CO2, Ar and H2 gases and the selectivity of the mixed H2/Ar gases. These simulation techniques have been shown to predict solubility in quantitative agreement with experiments for many solute gases such as CO2, N2, O2, SO2, NH3, and H2O [4]. Our simulations show that the H2 solubility in [hmim][Tf2N] is in good agreement with the experiment data obtained by Maurer et al. [2], but differ significantly from the results obtained by Noble et al. [1]. Energy analysis indicates that the interaction between H2 and the cation/anion pair is about six times smaller than that between CO2 and the same cation/anion system. Additionally, the heat of mixing for H2 absorption in [hmim][Tf2N] is very small, and in some instances it is even positive, implying that H2 absorption in this ionic liquid is endothermic. The absorption enthalpy at infinite dilution was found to be 3.0 ± 0.6 kJ/mol from simulations, close to the experimental value of 4.09 ± 0.05 kJ/mol obtained by Maurer et al. [2], but significantly different from the experimental one of 16.6 ± 1.5 kJ/mol obtained by Noble et al. [1]. Overall, our simulations suggest that the molar free volume of the ionic liquid is the determining factor in establishing the H2 solubility. We also studied the effect of H2 polarizability, different H2 molecular models, and different bond force constants on the H2 solubility. It was found that the polarizability and the bond force constants have a small effect, generally less than 10 % on the H2 solubility. The Ar gas has been widely used in the feeding and as a sweeping gas in the supported ionic liquid membranes [5]. Our simulations indicate that Ar has a higher solubility, about three times larger than H2 in [hmim][Tf2N]. The energy analysis shows that Ar interaction with the cation/anion pair is about three times larger than that between H2 and the same cation/anion pair. When the solubility of H2 and Ar are appreciable, we observed that H2 solubility in the mixed gas was decreased by about 20% relative to the solubility of pure H2 at the same temperature and fugacity conditions, due to the presence of Ar. This effect is due to the competing filling for the available free molar volume of the ionic liquid between H2 and Ar. These results indicate that in practical experiments performed at high pressures where both H2 and Ar have appreciable solubilities, the effect of Ar on H2 solubility needs to be considered for an accurate interpretation of the experimental data. [1] Noble R. D. et al., Ind. Eng. Chem. Res. 47, 3453 (2008) [2] Maurer G. et al., J. Chem. Eng. Data. 51, 1364 (2006) [3] Shi W. et al., J. Chem. Theory and Comput. 3, 1451 (2007) [4] Shi W. et al., J. Phys. Chem. B 112 2045 (2008) [5] Myers C. et al., Journal of Membrane Science, 322, 28 (2008)

9-4 Coal and Biomass Process for CO2 Reduction and CTL Production

Ebbe R. Skov, Terrance L. Stringer, Dennis C. England, ConvertCoal, Inc., USA

ConvertCoal, Inc has developed a pioneer enabling process technology for pretreatment of lowrank coal (LRC) that will now be expanded to include co-processing with biomass for the reduction of the GHG CO2 carbon footprint of PC-power plants. The process is continuous flow and large scale for projects corresponding to a coal-char-fuel demand of 500-MW.el and co-production of 7000-barrels-per-day synthetic crude oil (SCO) from LRC. The coal-char-fuel provides increased boiler efficiency due to water and off-gas removal, and therefore results in feed-coal and CO2 reductions of 6 – 13% depending on the feed-coal quality. Addition of biomass to the process, still subject to pilot plant demonstration, will further reduce the GHG CO2 profile of the power generation plant and coal-to-liquid (CTL) conversion that provides the economic platform for this process. In scope the CCI coal and biomass process is applicable to LRC resources worldwide and most existing and future PC-power plants. CCI does not at this time have a commercial plant in operation and is looking for project development venture partners and suitable project sites.

SESSION 10

COMBUSTION - 1

10-1

Corrosion Testing of Advanced-Ultrasupercritical Materials for Reduced CO2 Emissions

Michael S. Gagliano, Gregory J. Stanko, Horst Hack, Foster Wheeler North America Corp., USA

Coal is used extensively around the world as a primary fuel source for power generation due to its widespread availability and low cost; however, traditional coal combustion methods result in the release of relatively high levels of greenhouse gases and other pollutants. In an effort to reduce CO2 emissions from coal-fired power plants and increase cycle efficiency, the power generating industry is moving towards the use of advanced-ultrasupercritical steam cycles (A-USC), with steam temperatures approaching 760°C (1400°F) and operating pressures of 35 MPa (5000 psi). Since the materials currently used in conventional power plants do not possess the requisite high temperature strength and oxidation/corrosion resistance required for A-USC conditions, extensive research is being conducted on a global level to enable the construction of ultrasupercritical plants. In the United States, advanced materials research is being undertaken by a consortium of U.S. boiler manufactures, Oak Ridge National Laboratories, and the Electric Power Research Institute (EPRI). For the past several years, this extensive research and development program, which is co-sponsored by the United States Department of Energy through the National Energy Technology Laboratory (NETL) and the Ohio Coal Development Office (OCDO), and managed by Energy Industries of Ohio (EIO), has been aimed at thoroughly evaluating the materials properties and developing fabrication practices for several promising alloys for use in an A-USC plant. Continued work under this effort is focused on integrating A-USC steam cycles with oxycombustion technology for even greater reductions in CO2 emissions. As part of Phase I of the aforementioned program, several materials, including advanced high-strength austenitic stainless steels, nickel-based alloys, diffusion coatings and weld overlays/claddings, have been evaluated for fireside corrosion resistance through laboratory and field testing. Field testing was performed by assembling tubular coupon specimens onto air-cooled retractable corrosion probes and inserting the probes into the superheater/reheater areas of host utility boilers burning specific types of U.S. coals. The probes were designed to maintain metal temperatures within the range expected under A-USC conditions [roughly 650°C (1200°F) to 870°C (1600°F)] and remain exposed for up to 16,000 hours of operation. This paper provides an update on the field testing progress and offers comparisons of corrosion behavior at the different host sites after more than one and two calendar years of exposure. 10-2

Flame Emission Spectroscopy in a Coal - Biomass Co-Fired Boiler Thangam Parameswaran, Patrick Hughes, Richard Lacelle,

CANMETEnergy, NRCAN, CANADA Co-fifing biomass with coal is being explored in many research and industrial facilities as a means of reducing the consumption of coal and including renewable fuels. This report presents flame emission spectroscopy tests conducted in a 220 MW industrial boiler and discusses its application for burner performance monitoring and combustion optimization. The CANMET system is based on very small, robust, commercially available fiber coupled spectrometers and in- house developed methods for analyzing flame spectral profiles. During the testing period biomass was introduced in three of the fifteen burners in the boiler and the other burners were fired with enough coal to reach the desired load. Cooled fiber optic probes were installed in the access ports of

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the three test burners and flame spectra were collected at different loads and varying biomass flow rates. Flame spectral profiles from 100% biomass flames and co-fired flames collected in these tests, appeared generally similar and revealed the familiar emission peaks from sodium and potassium. Analysis of the data demonstrated that the variation of the spectral profiles with operating conditions can be learned and that this information can be processed to estimate air/fuel ratio, temperature and fuel flow rate at the test burners. The results obtained show that the flame emission spectroscopy approach as described here, is useful for identifying a of burner deviating from its designed values of parameters such as aft/fuel ratio and fuel flow rate and it has the potential to be implemented in a burner advisory system. 10-4

CO2 Reduction Potential and Co-Combustion Possibilities of the FBC-Boilers on the Czech Conditions

Dagmar Juchelkova, Helena Raclavska, Konstantnin Raclavsky, Jiri Bilik, Pavlina Pustějovská, VSB-Technical University of Ostrava,

CZECH REPUBLIC At present the task of minimizing carbon dioxide emissions in relation to its influence on environment belongs to the priorities of EU research activities. For achieving the best possible results it is necessary to focus attention on information concerning input materials character study of production as well as manufacturing processes and subsequent returning the products back to environment (anthroposphere). The problem is very extensive and covers many fields. Problem of CO2 reduction is one from the EU priority in longtime context (2010 and further). The aim of research in our University is large scale experiments in the fluidized-bed boilers. The experiments are carried out for Czech brown coal, wood, sewage sludge and wastes including analyses and recommendations for optimal thermal utilization and minimizing CO2 and harmful emissions. The next step is thermal analyses of coal, alternative fuel- wood pellets and sewage sludge from treatment plant. From the results of experiments it is clear that alternative fuels can be used in the large fluidized-bed boilers in the Czech Republic. 10-5

Integration of Coal Char Combustion Models and CFD-DEM Code in a Fluidized Bed

Daoyin Liu, Xiaoping Chen, Chuanwen Zhao, Changsui Zhao, Southeast University, CHINA

Fluidized bed combustion is a competitive technique for coal and biomass combustion. The efficiency of fuel utilization during combustion is dependent on both its transport and thermal conversion process. An adequate model which simulates both the transport and thermal conversion process of solid fuel in a fluidized bed can give detail insights into the complex phenomena. This study develops a numerical simulation model, in which the combustion models of coal char is incorporated into CFD-DEM code of a fluidized bed. DEM, including motion, heating and reaction, which is written in C progamming language, is successfully coupled with FLUENT through its UDF (User Defined Function). The developed CFD-DEM with char combustion model is an intrinsically simulation technique. At the aspect of the hydrodynamics of bubbling bed, it is simulated by a three dimensional CFD-DEM model, which is a start-of-the-art simulation technique. It employs Navier-Stokes equation for gas phase while determines the trajectory of each particle individually by integrating its Newtonian equations of motion. The CFD-DEM gives detail information about the trajectory and velocity of the char particle which is difficult to experimentally measure. At the aspect of the thermal conversion process, char combustion and carbon monoxide oxidation are modeled according to the literature. The momentum, heat and mass exchanged between the coal char particles and bed are computed by the two way coupling algorithm. The simulation of a pulsed jet case is validated. The phenomena of particle temperature variation, coal char and CO combustion are observed in the developed CFD-DEM with char combustion model. The model developed in the present work along with reliable experiamental results can be used to test different closures, including gas-solid drag force, gas-solid heat transfer, and coal combustion particle models in fluidized beds, which is helpful for better understanding and design of fluidized bed combustors.

SESSION 11

COAL SCIENCE: COAL BENEFICIATION – 1

11-1

Moisture-Induced Swelling of Coal Richard Sakurovs, Robyn Fry, Stuart Day, CSIRO Energy Technology, AUSTRALIA

The swelling behaviour of coal is an important issue when considering CO2 sequestration into coal seams or enhanced coalbed methane applications. However, coals may swell in moisture or shrink on drying and this will affect their gas

permeability. In this paper we examine the moisture swelling properties of coals from Australia and elsewhere. Results on the moisture uptake and corresponding swelling measurements are presented for 15 coals of various ranks (sub bituminous and bituminous) at 22°C and atmospheric pressure. Measurements were made by exposing sample blocks of coal (nominally 30 x 10 x 10 mm) to relative humidities ranging from 0 to 97 %. The length change of each block was measured with a screw gauge micrometer. In a separate experiment, a semi-automatic apparatus comprising a modified analytical balance and a digital camera was used to simultaneously measure the moisture uptake and swelling of a bituminous coal sample. Moisture uptake at 97 % relative humidity ranged from about 3 % to 17 %, db. Maximum linear strain associated with the moisture sorption (measured at 97 % rh) varied from about 0.2 % to 1.3 %, with lower rank coals showing the most swelling. In all cases, swelling was greater in the direction perpendicular to the bedding plane. These results correspond to volumetric swelling of about 0.5 % to around 3.5 %. Although exhibiting significant expansion, all of the samples returned to their original dimensions upon drying; i.e. the swelling was elastic. Moisture sorption and the amount of swelling induced were found to be strongly correlated by a single linear expression which held for all of the coals examined. It was further found that the volume of the water adsorbed was linearly related to the pore space within the coal, however, the results indicated that at 97 % rh, only about 70 % of the available pore space is occupied by water. 11-2

Online Analysis of Coal on a Conveyor Belt by Use of Machine Vision and Kernel Methods

Johan van Dyk, JHP van Heerden, M.J. Keyser, Sasol Technology R&D; C. Aldrich, G.T. Jemwa, University of Stellenbosch, SOUTH AFRICA

The application of machine vision systems to measure particle size distributions has among other been driven by sophisticated control systems used to monitor and control mills and other ore processing systems. Machine vision is non-intrusive and offers reliable online measurements in potentially harsh environments. Although considerable advances have been made over the last decade, reliability of measurements with segmentation algorithms is still an issue, particularly where lighting conditions may vary, fines are present or heterogeneous particle surfaces may result in irregular reflection of light. In practice the alternative to online measurement of particle size distributions is sieve analysis, which is slow and tedious, and not suitable for control purposes. The efficient preparation and quality control of coal are some of the key factors for stable, but also effective operation of the Sasol Fixed Bed Dry Bottom gasifiers. The operation of these gasifiers depend among other on melting properties and composition of the ash, thermal and mechanical fragmentation and caking properties of the coal, as well as the particle size distribution of the coal. Although many of these properties can be assessed in some way to expedite process improvement, particle size distributions are difficult to estimate beforehand from feedstocks, since these distributions may change significantly during the feeding process, or by insufficient screening, resulting in an access / increase of fine coal to gasification. The ability to measure these distributions online would therefore play a crucial role in continuous process improvement and real-time quality control. The objective of this project is to explore the use of image analysis to quantify the amount of fines (< 6 mm) present for different coal samples under conditions simulating the coal on conveyor belts similar to those being used by Sasol for gasification purposes. Quantification of the fines will be deemed particularly successful, if the fines mass fraction, as determined by sieve analysis, can be predicted with an error of less than 10%. In this paper, kernel based methods to estimate particle size ranges on a pilot-scale conveyor belt, as well as edge detection algorithms are considered. Preliminary results have shown that the fines fraction in the coal on the conveyor belt could be estimated with a median error of approximately 24.1%. This analysis was based on a relatively small number of sieve samples (18 in total) and needs to be validated by more samples. More samples would also facilitate better calibration and may lead to improved estimates of the sieve fines fractions. Similarly, better results may also be possible by using different approaches to image acquisition and analysis, but discussion of these falls outside the scope of the present report. Most of the error in the fines estimates can be attributed to sampling and to fines that were randomly obscured by the top layer (of larger particles) of coal on the belt. Sampling errors occurred as a result of some breakage of the coal between the sieve analyses and the acquisition of the images. The percentage of the fines obscured by the top layer of the coal probably caused most of the variation in the estimated mass of fines, but this needs to be validated experimentally. Preliminary studies have indicated that some variation in the lighting conditions have a small influence on the reliability of the estimates of the coal fines fractions and that consistent lighting conditions are more important than optimal lighting conditions.

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11-3 Comparison of Spiral and MGS for Recovery of Fine Coal from Slimes

Güven Önal, A.E. Yüce, O. Kangal, M. Özer, O. Kökkılıç, A. Güney, Istanbul Technical University, TURKEY

Coal washery have produced huge amount of fine tailings called slime. These tailings have also covered huge areas and this makes environmental pollution on site beside contains recoverable fine coals by using conventional and newly developed beneficiation units. In order to recover of fine coals from tailings as well as to rehabilitate of old tailings area, two washery tailings, Tuncbilek and Soma, subjected to this investigation. Spiral and multi gravity separator were used and optimum test results were reported in this paper. Results indicate that two different quality clean coals having low ash content can be obtained. It is possible to reduce ash content of original fine tailings from between 55-68% to 10% and 25% (second quality clean coal) by using gravity separation methods.

SESSION 12

COAL-DERIVED PRODUCTS: COAL-TO-LIQUIDS: CATALYSTS

12-1

Fischer-Tropsch Synthesis: A Comparison of Iron and Cobalt Burtron H. Davis, Shiqi Bao, Robert A. Keogh, Gary Jacobs, Center for

Applied Energy Research, University of Kentucky, USA Of the potential elements for a Fischer-Tropsch catalyst, only iron and cobalt have sufficient supply and properties to be considered for a commercial operation today. The early interest in Germany focused on the cobalt catalyst and this was the only metal used commercially through 1945. Following 1945, iron catalysts were utilized in commercial operations in both the United States and South Africa. The discovery of large quantities of oil in the Middle East led to the abandonment of the U.S. effort but Sasol successfully used iron catalysts to expand their production to about 150,000 bbl/day today. PetroSA currently produces about 35,000 bbl/day using iron catalysts. On the other hand, Shell utilizes cobalt catalysts to produce about 15,000 bbl/day and the Sasol operation in Qatar will also utilize a cobalt catalyst. Today the perception is that, at least for a natural bas based plant, cobalt is the preferred catalyst. Based on our lab data, we will compare the two catalysts on the basis of their catalytic activity and lifetime as well as their production of undesirable gaseous products (CO2 + C1-C4 alkanes) and high-molecular weight products. 12-2

Enhancing Gas Phase Fischer-Tropsch Synthesis Catalyst Design Debalina Dasgupta, Illinois Clean Coal Institute; Tomasz Wiltowski,

Southern Illinois University, USA This paper presents the results of research in the development of a Fe based catalyst with Co as a co-catalyst, and Ru and ZnO as promoters. The catalytic performance of these materials for FT synthesis was investigated in the gas phase employing a fixed bed reactor system. The Fe-Zn-K/ γ- Al2O3 catalyst performance was used as the benchmark. The data show that by varying the process conditions, it is possible to achieve a narrow distribution of the liquid products. The effect of reaction conditions on the product distribution and syngas conversion were analyzed. In the case of the Fe-Zn-K catalyst, an increase in pressure resulted in an increase in the chain length while an increase in temperature or the flow rate reversed the trend. The newly designed catalysts showed significantly high activity towards CO conversion (>70 %), along with low selectivity towards CO2 (5-15 %) and methane (ND – 3 %). The evaluation of the effect of process conditions on the performance of Fe-Co-Zn catalysts revealed that the effect of pressure on the carbon chain length was reversed. Fe catalyst groups containing different proportions of Co were also prepared. It was determined that a Fe:Co ratio of 4:1 is sufficient to obtain high CO conversions with a high selectivity towards liquid hydrocarbons. The hydrocarbon distribution, on the other hand, remained almost unchanged due to a change in the Co content. The use of silica, as opposed to alumina as the catalyst support, enhanced the CO conversion and the selectivity of the process towards liquid hydrocarbons. The methane and CO2

selectivities on both the supports remained unchanged. However, a significant difference in the liquid hydrocarbon distribution was observed. Addition of potassium to the catalyst resulted in an increase in the heavier hydrocarbons in the liquid hydrocarbon distribution. The results from a series of Fe4Co1Zn0.04 based catalysts for Fischer-Tropsch (FT) synthesis, in which the different amounts of Ru are incorporated showed that the addition of Ru suppressed the CH4 formation at the cost of increasing the CO2 selectivity.

12-3 Tailoring Gold-Mixed La/Ce-Oxide Catalysts for Water-Gas Shift

Yanan Wang, University of Pittsburgh; Shuang Liang, Götz Veser, University of Pittsburgh and DOE-NETL; Robert Thompson, Christopher Matranga,

DOE-NETL, USA The water gas shift reaction (WGS) is one of the key reactions in the production of liquid fuels or hydrogen from fossil and renewable resources. It is widely used to adjust the CO:H2 ratio in synthesis gas for the production of chemicals and liquid fuels, and to reduce the carbon monoxide content in order to produce hydrogen-rich streams for fuel cells. While WGS is at high temperatures limited only by thermodynamic equilibrium limitations, at lower temperatures (<400oC) the activity and stability of the catalysts is currently the limiting factor. In recent years, supported Au catalysts have widely been reported as a potentially highly active WGS catalyst, in particular in combination with a CeO2-based support. Building onto these reports, we are currently working on the synthesis of Au supported on mixed La/Ce oxides with wide range of La content (from 10% to 90%). Both CeO2 and La2O3 oxides have previously been shown to be effective (and active) support materials for noble metal-based catalysts in WGS. Moreover, some previous work also showed that the addition of rare earth additives can improve the properties of CeO2. However, very few systematic studies of La-doped CeO2 for WGS are available in the published literature. Here we report the synthesis of gold catalysts on mixed CeO2- and La2O3-based oxide supports with variable Ce:La ratio. By utilizing a reverse microemulsion-templated sol-gel synthesis route, nanostructured oxides with high surface area and good thermal stability were obtained. Mixed La/Ce- oxides solid solutions with cubic structures were obtained over the entire range of La-dopings up to 90% La content without phase separation. Au nanoparticles were deposited on these oxides by deposition-precipitation, and the resulting catalysts were characterized by a wide range of methods (XRD, ICP, TEM, TPR and BET). Water gas shift catalytic tests showed that appropriate addition of La can result in significantly increased activity of Au/CeO2. Correlations between structure and reducibility of the oxide support and catalytic properties of Au/CeO2-La2O3 catalysts will be discussed in detail in the presentation. 12-4

Catalyst Design for Coal-To-Liquid Processes: Iron-Cobalt Alloys for Fischer-Tropsch Enhancement

Panithita Rochana, Shela Aboud, Jennifer Wilcox, Stanford University, USA Living in a world of high energy demand, energy independence would be a promising option for surviving in the current economic difficulties. Coal remains the world’s largest abundant fossil fuel and coal reserves are more distributed around the world compared to oil or natural gas. Currently, more than 50% of the electricity in the United States is generated from coal-fired power plants. However, the application of coal utilization is not limited only to power generation, but also feedstock for various chemical productions such as synthetic fuels and olefin monomers via coal-to-liquid (CTL) processes. This alternative is essential for countries with high coal reserves, such as the US, China and India, and exists as a portion of the energy portfolio as countries remove their dependence on foreign oil. Synthesis gases, which comprises of carbon monoxide (CO) and hydrogen (H2), are obtained from coal gasification and further reacted via Fischer-Tropsch synthesis to produce various forms of liquid hydrocarbons. A novel catalyst for coal-to-liquid technology based on Fischer-Tropsch synthesis is modeled based on the binary Fe-Co alloys since they express their ability to enhance CO activity and resist poisoning. The chemical, physical, and electronic properties that associated with CO activation are studied by the density functional theory (DFT) approach incorporated in the Vienna ab initio Simulation Package (VASP). The range of computed adsorption energies from this work falls between the CO adsorption energies on pure Fe and Co surfaces. It is found that CO prefers to adsorb on Co-site rather than Fe-site on FeCo alloys, whereas pure Fe surface has stronger CO binding energy. This evidence implies that alloying of Fe and Co affects the physical and chemical properties associated with the CO adsorption process and the adsorption-site preference. Understanding the mechanisms related to the CO activation on FeCo alloys will elucidate how the alloys of material can alter the surface properties with respect to the CO adsorption. The analysis on the local density of states (LDOS) and charge density profile of the CO-adsorbed systems is further applied to examine the CO activation mechanism which is the key step in Fischer-Tropsch synthesis.

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SESSION 13

GASIFICATION: UNDERGROUND COAL GASIFICATION – 1

13-1

UCG Technical Risk Reduction through Lessons Learned and Simulation Elizabeth Burton, Souheil Ezzedine, Lawrence Livermore National

Laboratory, USA The two main technical risks in underground coal gasification are the risk that gasification operations do not produce economic quantities or qualities of gas and the risk of environmental damage, primarily groundwater contamination and surface disturbance. In both cases, proper selection of sites and of operations parameters is the key to reducing these risks. In other partially analogous subsurface operations, such as oil and gas extraction or mining, a rich history of lessons learned is available to set constraints on site selection and operations. For UCG, little well-documented history is available except for relatively small-scale pilot operations. At the same time, a nascent commercial UCG industry cannot afford the consequences of undertaking operations with high risk of failure. In spite of its limited applicability to framing risk at commercial scale, the previous R&D done at pilot-scale provides a rich database for developing an understanding of the sensitivity of outcomes to changes in site and operational parameters. This understanding can be developed through a program of UCG simulation designed to test how chemical and physical parameters impact technical risk. In particular, such a program can identify the dominant controlling parameters on key economic or environmental factors such as cap rock integrity, product gas composition or contaminant generation. This paper describes results of such simulations using initial data from Hoe Creek pilot studies and the sensitivities of key interrelationships between site and operational parameters, such as coal and rock properties and water influx and operating pressure. 13-2

Cougar Energy’s UCG Commercialisation Plan Len Walker, Cougar Energy Ltd, AUSTRALIA

The management of Cougar Energy has 25 years experience in evaluating UCG technology for commercial development, and was responsible for the successful Chinchilla UCG Pilot Burn which operated from 1999-2003. Since 1997, it has been working with Ergo Exergy Technologies Inc of Canada as its UCG technology supplier, focusing on commercial applications of the technology. Since its formation in 2006, Cougar Energy has been assembling a number of international projects based on the use of UCG gas as a fuel. While its initial focus has been in Australia, the Company is also evaluating the potential for projects in a number of other countries. Cougar Energy’s first proposed commercial project is in Queensland near the town of Kingaroy, where the Company has established a drilled resource of 73 million tones, and proposes to construct a UCG gas field sufficient to supply fuel to a 400MW combined cycle power plant over a 30 year life. The Pilot Burn to initiate the project is planned to commence in the third quarter of 2009, with completion of the first stage power plant of 200 MW late in 2012. Cougar Energy also maintains coal interests elsewhere in Queensland and in Victoria, each of which has a target resource potential of around 1 billion tonnes of coal. The Victorian project would involve gasification of brown coals of high moisture content, and would give a significant environmental benefit when compared with the current use of conventional of coal-fired power stations in that State. The Company is also developing project prospects in a number of international locations including India, Pakistan and Europe and looks forward to substantial progress towards commercialization of the UCG technology over the coming 12 months. 13-3

Rm-1 to Bloodwood Creek: A Status Report Burl E. Davis, Carbon Energy Pty Ltd, USA; Cliff Mallet, Carbon Energy

Pty. Ltd., AUSTRALIA Rocky Mountain 1 was completed in 1988 and demonstrated the technical feasibility of the Controlled Retracting Injection Point as an Underground Coal gasfication module configuration. Carbon Energy PL has installed a next generation commercial version of the RM-1 UCG CRIP module at their site at Bloodwood Creek, 50 km west of Dalby, Queensland Australia. They have demonstrated the commercial feasibility of the CRIP UCG process at Bloodwood Creek with a 100-day field trial with both air and oxygen/steam injection. The single module is capable of accessing 200,000 tonnes of coal during its operational life. The facility design is based upon the RM-1 experience with improvements that move the technology from an experimental stage to commercial reality. The trial is the first module of a commercial facility that will generate 1 PJ (petajoule) per annum of syngas with a module life of three years. Each module is expected to produce enough syngas to produce 20 MW of electricity in a state of the art combined cycle gas turbine power plant. The module is being held on a stand-by mode while surface facilities for commercial production are put in place.

13-4

Project Ramsay: Potential for Underground Coal Gasification with Carbon Capture and Storage (UCG-CCS)

in the North East England, UK L.K. Mudashiru, D. Roddy, Newcastle University, UNITED KINGDOM

North East England is historically an energy intensive region due to its proud industrial heritage and leading position in manufacturing, engineering and chemical processing industries. In the coming years, our world will continue to face economic, environmental and energy related challenges. In the short and medium term, increases in global demand for energy are unlikely to be satisfied in full by the emergence of renewable energy technologies, which presently supply only a small fraction of our energy budget. This paper makes a case for clean use of coal in response to the needs of our society and the world to meet energy security needs in the new global low-carbon economy. Although, a transformation from fossil fuels to renewable energy sources should be the long-term goal, fossil fuels still form the backbone of our energy infrastructure, their use is inevitable, and they will still be supplying the major part of the global energy needs for most of the 21st century. The emerging Underground Coal Gasification (UCG) technologies provide exciting opportunities to unlock the energy stored in coal seams in a sustainable and environmentally friendly manner when they are linked to carbon capture and storage (CCS). The syngas (or synthesis gas) produced from UCG is a flexible fuel which can be cleaned for use in industrial heating, power generation or further chemical conversion into energy carriers like hydrogen, methanol and substitute natural gas. Project Ramsay is seeking to create the world’s first commercial scale underground coal gasification and carbon capture storage (UCG-CCS) operation. This paper presents our feasibility study and the initial findings on assessing the suitability of coal seams in North East England for UCG linked to Carbon Capture and Storage. The broad conclusions from the feasibility study are that: previous estimates for UCG-compatible coal had been conservative; there are coal seams that appear to be usable for CO2 storage following UCG; and some of the end uses for syngas are potentially attractive. The most attractive options in financial terms are (1) to sell syngas, take back captured CO2 and store it for a fee, and (2) to sell decarbonised hydrogen and methane. It was concluded that a project could be done in phases, ramping up the scale over time in order to minimise technical risk and investor exposure. Such a project could deliver a positive return on investment, albeit on a longer timescale than more conventional energy projects.

SESSION 14

GASIFICATION: FUNDAMENTALS – 1

14-1

Gasification Fundamentals Research - Planning for the Future George Richards, Ron Breault, DOE-NETL;

Ke Liu, GE Global Research, USA No abstract available. 14-2

Chemical Reaction Kinetics for the Initial Stages of Entrained-Flow Coal Gasification

Stephen Niksa, Niksa Energy Associates, LLC; Donald Eckstrom, Ripu Malhotra, Al Hirschon, SRI International, USA

The tests and simulations in this study characterize the chemical structure of lab-scale pressurized premixed pulverized coal flames of eight density- and size-classified fractions of a Pit. #8 hv bituminous coal for stoichiometric ratios (S. R.) from 0 to 1.8 in a 1D turbulent flow reactor operating at 1600°C and MPa. In one test series, particle transit times were no longer than 300ms to characterize the initial stages of pressurized gasification and combustion; in another, transit times were extended to almost 2s under elevated partial pressures of steam and CO2. This paper focuses on the two lighter feed fractions, whose behavior is determined by the combustibles, whereas a companion paper characterized the Fe-mineral transformations with the two heavier fractions. Tests were run with hardly any O2; under reforming conditions with a nominal S. R. of 0.6; and under oxidizing conditions with a S. R. of 1.2. Tests without O2 determined the total volatiles yield and distributions of so-called secondary volatiles pyrolysis products. Secondary volatiles pyrolysis products are the volatiles and soot remaining after the primary volatiles from the coal are pyrolyzed further in hot gases. They consist of soot, oils, CH4, C2H2, CO, CO2, H2O, H2, H2S and N-species. As the inlet O2 level was progressively increased in succeeding tests, the process chemistry moved through oxidative pyrolysis, volatiles combustion, soot oxidation, and char oxidation. These stages exhibited considerable overlap, depending on the relative burning rates of the various fuels in the reaction system. They were resolved by depletion of the available O2; i.e., flows with higher inlet O2 levels progressed deeper into the sequence

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of chemical reaction stages before the flames were extinguished by the consumption of O2. Tests with injected steam and extended transit time determined the gasification rates under steam and CO2 with inhibition by H2 and CO. CFD simulations for every test were used to assign detailed processing conditions, which were subsequently used to quantitatively interpret the measured product distributions with the most comprehensive reaction mechanisms available: FLASHCHAIN® for devolatilization; CBK/E for char oxidation; and CBK/G for char gasification. Once validated, the reaction mechanisms were used to specify the rate parameters and stoichiometric coefficients for the simple quasi-global rate laws that are routinely used in CFD simulations. These rate parameters are reported along with the simplest chemical reaction schemes that accurately depict the tendencies among the major products in this system. 14-3

Comparison of Instantaneous, Local Equilibrium and Finite Rate Gasification Models in an Entrained Flow Coal Gasifier Armin Silaen, Ting Wang, University of New Orleans, USA

A coal gasification simulation model involves many sub-models and each of the sub-models needs to be investigated and verified. This paper will focus on investigating three different gasification reaction models inside a generic entrained-flow gasifier, varying from simple to complex: (a) instantaneous gasification model, (b) local equilibrium model, and (c) finite rate model. The simulations are carried out using the commercial CFD solver FLUENT. The Navier-Stokes equations and eight species transport equations are solved with three heterogeneous global reactions and three homogeneous reactions. The coal particles are modeled with Langrangian tracking method. Computation is conducted alternatively between the dispersed and continuous phases. In the instantaneous gasification model, the interphase exchange rates of mass, momentum and energy are assumed to be infinitely fast. This model is applicable under the condition when the flow is locally-homogeneous, and the interphase transport rates are infinitely fast. In this instantaneous gasification model, the dispersed phase can be simplified as the gas phase, and the complex two-phase flow is then treated as a single-phase flow. This model can significantly reduce the computational time but can only provide a qualitatively trend of gasification process. Comparison with the finite rate model will give a guidance of the values that could be extracted from the results of instantaneously gasification process. Although the instantaneous model is crude, it catches the effect of thermal-fluid field (including turbulence structure) on chemical reactions, which are not readily available from the zero-dimensional equilibrium method. In the local equilibrium model, the forward reaction rates are calculated from empirical correlations first, followed by the calculation of the backward reaction rate from the local equilibrium constant. However, the backward reaction rate is not applicable to heterogeneous process, which involves complex solid particle combustion and inter-phase transports. To capture the effect of turbulence on interphase transport, the stochastic tracking scheme is employed. The Chemical Percolation Devolatilization (CPD) model is used for the devolatilization process. The study compares the results obtained from each model as well as the values and pros and cons of each model are discussed. 14-4

Large Eddy Simulation of Near-Nozzle Region in an Entrained Coal Gasifier

Philip J. Smith, Jeremy Thornock, Charles Reid, Julien Pedel, The University of Utah, USA

In a turbulent coal jet in an oxygen-blown gasifier, liftoff can be used to assess the stability of a burner flame. Accurate prediction of the particle and velocity distributions are critical for predicting liftoff, and can yield detailed information on the spatial and temporal development of the standoff distance. The present work combines state of the art particle and turbulent reacting flow models to obtain standoff distances in the for a gasifier as a function of operating parameters. Large eddy simulations (LES) of the turbulent reacting coal jet are performed using the direct quadrature method of moments (DQMOM) to track the evolution of the local particle size distribution in the jet, and predictions of liftoff are presented. These results are compared with experimental data from a laboratory pilot-scale gasifier and with predictions from Reynolds-averaged Navier-Stokes (RANS) calculations. The DQMOM provides an Eulerian particle-tracking method with full particle statistics. This, combined with the spatial and temporal resolution provided by LES, yield a comprehensive statistical description of the injector region and liftoff. The present work identifies issues relevant to simulating the nearer injector region of entrained flow gasifiers using LES and DQMOM, and lays the groundwork for quantifying risk assessment and decision making by taking advantage of predictive simulation tools.

14-5 Modeling Entrained Flow Coal Gasifiers

Mike Bockelie, Martin Denison, Dave Swensen, Connie Senior, Adel Sarofim, Reaction Engineering International, USA

The coal gasifier is a critical piece of equipment within an Integrated Gasification Combined Cycle (IGCC) power plant. However, many problems continue to hinder the performance of entrained flow gasifiers. Computational models can provide insights that will allow improving gasifier performance for items such as fuel injector life, refractory wear, carbon conversion, fuel switching and slagging. Through funding from the DOE, Reaction Engineering International (REI) has developed Computational Fluid Dynamic (CFD) and process models for the commercially dominant systems. The gasifier models include sub-models that account for high pressure effects on reaction kinetics and radiation properties as well as sub-models for slagging walls, soot and tar production/destruction and ash vaporization. In this paper we will provide an overview of the models we have developed. Example calculations will be described that highlight the types of questions that can be addressed with the models.

SESSION 15

CARBON MANAGEMENT

15-1

The Opportunity to Improve the Efficiency of Existing Coal-fired Power Plants Christopher Nichols, Phil Dipietro, Kristin Gerdes, Gavin Pickenpaugh, Katrina

Krulla, DOE/NETL, USA In 2005, coal-fired power plants in the United States built before 1980 accounted for 26% of total U.S. CO2 emissions. Analysis of GHG mitigation policies indicates that for CO2 taxes under 30-40 $/mtCO2 many of the existing coal-fired power plants will choose to operate as they are and “pay the tax.” If so, they will operate under a greatly enhanced economic incentive for efficiency improvements. The average efficiency of the existing coal-fired fleet is 32.5%, while the top 10% achieves almost 38%, indicating that significant improvement is possible. This paper sets forth an estimate of the national-level aggregate CO2 emissions reductions that could be achieved through efficiency upgrades, based on a multivariate regression analysis of plant characteristics such as size, fuel heat content, emissions controls and operator type. Barriers to achieving these upgrades and potential solutions, as identified in a recent government/industry workshop will also be presented. 15-2

Pressure Swing Adsorption Technology for Post- and Pre-Combustion Carbon Dioxide Capture

James A. Ritter, Amol Mehrotra, Hai Du, Armin D. Ebner, University of South Carolina, USA

Fact: a viable separations technology has yet to be identified for the cost-effective pre-combustion or post-combustion carbon capture from coal gasification processes. Fact: viable absorption and adsorption technologies exist; but, they have not been examined extensively for these purposes and economics are largely unknown. Fact: Professor Ritter and his team have been obtaining some very promising results for the pre-combustion capture of CO2 from coal gasification processes using pressure swing adsorption (PSA). Fact: Professor Ritter and his team have also been obtaining some very promising results for the post-combustion capture of CO2 from flue gas using PSA in collaboration with the Eastman Chemical Company. Fact: Professor Ritter and his team are continuing to work on both problems with PSA as the principal carbon capture technology. Although similarities exist that will be used to quickly build the knowledge base, the differences between post-combustion and pre-combustion carbon capture by PSA are significant. For example, not only are the temperatures (25-70 °C versus 200-350 °C) and pressures (1 atm versus 20-35 atm) vastly different, but also the stream compositions are significantly different (~ 15% CO2 and low levels of SO2 versus ~ 30-40% CO2 and low levels of H2S); and to make matters worse, both streams contain about 8-10% H2O. In both cases, the trick is to find a suitable, hopefully commercial, adsorbent with sufficient working capacity for CO2 at the process conditions of interest, i.e., one for pre-combustion carbon capture at high temperature and pressure and one for post combustion carbon capture at near ambient temperature and pressure. For post-combustion carbon capture, one of the zeolite 10X or 13X molecular sieve adsorbents should suffice and is being explored. The problem is not so simple for pre-combustion carbon capture, because the temperature range is where most commercial adsorbents are regenerated or have insufficient CO2 capacity to be economical. The one advantage that has not been explored, however, is the high pressure associated with pre-combustion carbon capture. There are a number of commercial adsorbents that may exhibit sufficient working capacity for CO2 at 20-35 atm, despite the elevated temperatures. Professor Ritter and his team are currently exploring such materials. In addition to a suitable adsorbent, a suitable PSA cycle must also be devised. In fact, a viable PSA process has always been an intimate marriage between the adsorbent and the PSA cycle schedule, especially for multi-bed PSA processes envisioned for CO2

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capture, pre- or post-combustion, that will most likely mirror their H2 PSA process counterparts. The contention is that a well designed PSA cycle configuration utilizing a commercial CO2 adsorbent with just a reasonable CO2 working capacity will win economically over other separation processes. With this in mind, the heavy reflux (HR) PSA concept is being explored for both pre- and post-combustion carbon capture by PSA. The HR PSA concept has been largely missing from the PSA literature. The authors feel that the lack of information on and therefore the lack of understanding of the HR PSA concept for concentrating the heavy component from a feed stream, like CO2, has been the principal reason for many misconceptions that have perpetuated throughout the literature about the non-viability of PSA for CO2 capture. During this presentation, brief overviews will be given on the requirements of pre- and post-combustion carbon capture technology, the viability of PSA for these purposes, the HR PSA concept and why it is needed and will work, PSA cycle complexity and its increasing similarity with well-established H2 PSA technology, and the latest findings from Professor Ritter and his team at USC on using PSA for post- and pre-combustion CO2 capture for coal gasification processes. 15-3

Use of High-Pressure Oxy-Combustion in Coal-Fired Power Plants to Achieve Near Complete Carbon Capture and Storage

Keith Pronske, Roger E. Anderson, Clean Energy Systems, Inc., USA Clean Energy Systems, Inc. (CES) has developed high-pressure oxy-combustors that enable near complete carbon capture and storage (CCS) in coal-fired or other fossil or biomass-fueled power plants. Much of the early work focused on the use of natural gas but those efforts set the foundations for the evolution towards the use of the more plentiful and lower-cost coal and other problematic fuels such as petcoke and residuum. With the support of the California Energy Commission (CEC), a 110 kWt bench-scale high-pressure oxy-combustor was designed and tested during the period from 1999-2001. That combustor operated on oxygen, methane, and water producing steam-rich carbon dioxide (CO2) at pressures up to 300 psia and temperatures up to 2700 °F. During the period from 2000-2003, a 20 MWt oxy-combustor was designed and tested with support from DOE’s National Technology Laboratory (NETL). That oxy-combustor also operated on oxygen, methane, and water. It produced steam-rich CO2 at pressures up to 1540 psia at temperatures ranging from ~ 3000 to as low as 600 °F. With support from the CEC, the 20 MWt combustor was subsequently installed and integrated into CES’s Kimberlina Power Plant and test facility. During the period from 2004-2006 the entire oxy-combustion power plant was commissioned and its reliability and durability demonstrated. In a nine-month period the combustor operated more than 1300 hours with 95% availability and power was exported to the grid for more than 1200 hours. Under DOE’s Coal-Based Oxy-Fuel System Evaluation and Combustor Development program, the 20 MWt oxy-combustor was modified to operate on simulated coal syngas and hydrogen-depleted syngas (HDS). The modified unit was successfully tested on both of those fuels during 2006 at firing rates up to ~16 MMBtu/hr. This represents the first know application of high-pressure oxy-combustion to coal-based fuels. This unit was also modified slightly to demonstrate oxy-combustion of glycerol (a by-product of bio-diesel) and subsequently oxy-combustion of MSAR (a mico-atomized emulsion of residuum in water). The latter fuel is representative of problematic fuels (i.e., those containing significant quantities of sulfur, ash, and/or heavy metals). During 2007-2008 a nominal 200 MWt oxy-combustor system was designed, fabricated, and installed at the Kimberlina test facility. The initial unit is designed to operate on natural gas but under Phase 2 of the DOE Coal-Based Oxy-Fuel program the design of a unit to operate on coal-syngas was completed. The first unit is currently undergoing testing as a standalone system and in combination with a modified J79 gas turbine directly driven by the oxy-combustor system. The J79 represents a first-generation gas turbine retrofitted to operate without the compressor section on oxy-combustion drive gases. Second-generation retrofitted gas turbines based on high operating temperatures and retrofitted gas turbine combustors to operate as reheaters are currently being developed and third-generation gas turbines operating at >3000 °F are planned. Oxy-combustors operating on coal-syngas driving second and third-generation gas turbines enable high-efficiency coal-based power plants with nearly-complete CCS. Integration of oxy-combustion systems into several of the clean coal power generation schemes that embody oxygen-blown gasifiers or underground gasification are described, including R&D initiatives supported by the UK and Dutch governments. 15-4

Near and Longer Term Solutions to Carbon Capture and Sequestration Adel F. Sarofim, Philip J. Smith, Ronald J. Pugmire, Kerry E. Kelly, The

University of Utah, USA The University of Utah’s Clean Coal Program is pursuing interdisciplinary, cradle-to-grave research and development of coal technologies for electric power generation, with an emphasis on minimizing carbon footprints through the use of CO2 capture for sequestration. The Program includes studies on two near-term technologies for CO2 capture (gasification and oxy-fuel), two promising longer-term technologies (oxygen-transport membranes, and chemical looping), the effects of contaminants in CO2 on

sequestration structures, and environmental and legal issues related to carbon capture and sequestration. An overview of the program will be provided together with highlights of selected projects, particularly on the use of quantitative predictive simulation tools to help integrate experimental data and to speed innovation.

SESSION 16

COMBUSTION: CHEMICAL LOOPING – 1

16-1

Alstom’s Chemical Looping Combustion Coal Power Technology Development Prototype

Paul Thibeault, Herbert E. Andrus, John H. Chiu, Alstom Power Inc.; Charles Miller, DOE-NETL, USA

For the past several years, Alstom Power Inc has been developing a Chemical Looping Process that has the potential to capture nearly all of the CO2 from new or existing coal-fired plants. This new power plant concept is based on a hybrid combustion-gasification process utilizing high temperature chemical and thermal looping technology. The chemical and thermal looping technology can be alternatively configured as 1) a combustion-based steam power plant with CO2 capture, 2) a hybrid combustion-gasification process producing a syngas for gas turbines or fuel cells or 3) an integrated hybrid combustion-gasification process producing hydrogen for gas turbines, fuel cells or other hydrogen based applications while also producing a separate stream of CO2 for use or sequestration. The first three phases of this development work has been completed on a small pilot plant process development unit (PDU). Work has begun on the prototype design phase (Phase IV). Work in the first three phases validated the chemistry required for the Chemical Looping process and investigated the solids transport mechanisms and design requirements. Economics were evaluated based on the results of the first three phases and were found to be favorable. Phase IV work will concentrate on using the lessons learned in the first three phases to design and construct a prototype chemical looping facility that will integrate all of the equipment and systems required to operate the facility. Operation of the facility will be used to characterize performance and develop design information for future plants. 16-2

Investigation of the Reaction Kinetics of Oxygen Carriers in Chemical Looping Combustion

Richard Baraki, Gabor Konya, Edward M. Eyring, The University of Utah, USA

The Ni/NiO and Cu/CuO systems are useful oxygen carriers in Chemical Looping Combustion (CLC). The oxidation and reduction reactions of these metal/metal oxide couples were investigated with thermo gravimetric analysis (TGA) under both isothermal and non-isothermal conditions. From the observed reaction rates, kinetic parameters (e.g. activation energy) were calculated. The results are used to determine the optimal operating conditions for a CLC system. 16-3

Materials and Process for Chemical Looping Combustion of Coal Doug Jack, James White, Damon Waters, David Anderson,

Eltron Research & Development, USA The demand for approaches to reduce CO2 emissions from coal-based plants has dramatically increased. Among such approaches, chemical looping combustion (CLC) offers particular cost and performance advantages. However, the development of both oxygen carrier materials and the process offers challenges. Eltron Research & Development has developed carrier materials and accompanying processes for direct coal combustion and gasification (in indirect combustion). Both technologies are based on direct interaction of coal and oxygen carrier. Compared to other more complicated chemical looping processes, this process utilizes two beds (single loop). The oxygen carrier system is inexpensive and doubles as a thermal carrier. The most recent technical results and achievements in the development of this processes and associated oxygen carrier materials will be presented in this paper. A summary of the economic advantages over other low emission combustion approaches will be discussed.

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16-4 Dynamic Simulation and Advanced Controls

for Alstom’s Chemical Looping Process Xinsheng Lou, Carl Neuschaefer, Hao Lei, Abhinaya Joshi,

Alstom Power Inc., USA Alstom Power Inc. (Alstom) is collaborating with the U.S. Department of Energy (DOE) in a multiphase project developing an entirely new, ultra-clean, low cost, high efficiency power plant for the global power market. This new power plant concept is based on a process utilizing high temperature chemical and thermal looping technology. This chemical looping technology can be configured as a next generation power plant with a controlled stream of CO2 for use or sequestration. For coordination with the process development efforts, Alstom is investigating and developing advanced controls for this chemical loop system under the co-sponsorship of the DOE. A key part of this is development of a new computational approach to process dynamic simulations for use in the control work. A Phase I project focused on developing an early understanding of the basic transport process and the underlying process control dynamics. The project includes characterization of the chemical looping process, building solid transport models, and a dynamic simulation model to support control investigations. The simulator and experimental facilities were used in exploring advanced controls concepts such as model predictive control (MPC) for application to the chemical looping process. This paper summarizes the progress of this Phase I simulation and control project. It summarizes Alstom’s progress on the major tasks defined in the Phase I chemical looping control project. In Phase I, new computational approaches have been explored toward process dynamic simulations and application of advanced controls for the unique chemical process with emphasis on solid transport modeling, simulation and controls. A benchmark control system performance survey was completed with recommendations for future chemical looping power plant design to best support the power grid system. The overall approach to first principle modeling and simulation results are presented at a proper technical level. Facility tests and model validation are introduced with an illustration of comparisons between tests and simulations. A real-time simulator with closed loop controls is then introduced in the modeling and simulation section as well. Real-time advanced controls concepts were deployed and tested on the chemical looping solid transport test facility in Alstom’s Boiler Laboratories. Operational optimization along with advanced controls has been established as a key milestone for this future clean power generation plant research and development project. Further discussions are extended on the future phases of the project for integrated control and optimization designs along with Alstom’s clean fossil power system development. 16-5

Chemical Looping Combustion of Coal and Woody Biomass Hyung “Ray” Kim, Fanxing Li, Deepak Sridhar, Liang Zeng, Andrew Tong,

Nobusuke Kobayashi, Liang-Shih Fan, The Ohio State University, USA The majority of research and development in the Chemical Looping process have been used reducing gases such as methane, synthetic gas, or natural gas as a fuel. However, the price of natural gas has shown steady increase with the crude oil and the capital cost of gasifier for coal is too costly. Thus, direct use of solid fuels in the Chemical Looping process, for example, coal and biomass, is expected to improve the process economic, because it directly uses coal as a fuel and eliminates a costly gasifier unit. In this study, the adequate reactor scheme has been suggested and demonstrated for the efficient combustion of solid fuels with the oxygen carrier particle. The new reactor scheme enhances the conversion of solid fuels by dividing into two sections. Gaseous volatiles from the solid fuels are converted in the top part of reactor, whereas the tar and devolatilze char are carried down to the bottom section to react with the oxygen carriers. Prior to the comprehensive demonstration of counter-current moving, the proposed concept was studied in a thermogravimetric analyzer and a pre-heated packed bed. The preliminary study showed that the iron-based oxygen carrier is capable to convert the volatiles from coal/biomass to CO2. The result implied that the iron-based particle effectively cracked the hydrocarbons in volatile gases and tar. Also, the devolatized chars were gasified with the oxygen carrier particle in the inert environment. The effect of enhancing gases on the char gasification will be studied to improve the rate of char gasification in the moving bed reactor. In addition to the study of solid fuel conversion, the effect of contaminants such as sulfur and ash was studied. Particles were successfully regenerated and recycled in the system with the presence of such contaminants. 16-6

Design of the Syngas Chemical Looping Sub-Pilot Scale Unit Andrew Tong, Fanxing Li, Deepak Sridhar, Liang Zeng, Fei Wang, Hyung

“Ray” Kim, Liang-Shih Fan, The Ohio State University, USA The Syngas Chemical Looping (SCL) process converts gaseous fuels such as syngas and hydrocarbons into hydrogen with in-situ CO2 capture. A Fe2O3 based composite oxygen carrier particle is utilized in the SCL process to simplify the fuel conversion scheme while providing CO2 capture in an indirect but highly efficient manner. This process has been fully demonstrated in a semi-continuous 2.5 kWth bench-scale unit. In

this study, the design, construction, and preliminary testing results of a 25 kWth Sub-pilot unit are discussed. Leak tests, solid and gas flow control, and continuous solid circulation tests are performed and presented. Physical and hydrodynamic properties along with the attrition rates of the oxygen carrier particles are determined using the Sub-pilot Unit. A case study is then performed on a 1000 MWth SCL plant. It is concluded that the proposed SCL concept is feasible for commercial operation using the current oxygen carrier particles.

SESSION 17

COAL SCIENCE: COAL BENEFICIATION – 1

17-1

Extraction of High Grade Magnetic Material from Fly Ash and its Evaluation for Dense Medium Coal Cleaning Application

Baojie Zhang, Manoj K. Mohanty, Fan Yang, Richard Geilhausen, Southern Illinois University Carbondale; Joseph C. Hirschi,

Illinois Clean Coal Institute, USA On average, fly ash produced from burning high-sulfur coal in the U.S. contains 10 to 15% or more of magnetic materials, the majority of which are fine magnetite particles called fly ash derived magnetite (FAM). This study developed a proprietary processing scheme to economically extract high grade magnetite from high sulfur coal fly ash. A magnetite concentration of 17.5% (Davis tube measurement) in fly ash feed was enriched to 96% of magnetite in the FAM product. Feed solid content affected the FAM grade produced from the wet magnetic separator the most, whereas both feed solid content and water spray angle were equally important for magnetite recovery. The empirical models developed for both magnetite grade and recovery were validated and the highest grade of 96.5% was achieved at a reasonably high recovery of 83.7% by conducting tests at a feed solids content of 7% and a spray angle of 45o. In spite of the spherical shape and slightly coarser particle size distribution of the FAM particles in comparison to the NM particles, a relatively stable dense medium was successfully produced by the former apparently due to their lower density. The stability indices in the range of 30 to 40 for FAM medium densities from 1.3 to 1.6 compared favorably with those of NM based mediums. The coal cleaning performance, i.e., combustible recovery and ash rejection relationships, obtained from a 15-cm diameter dense medium cyclone using dense medium prepared from both FAM and NM, were quite similar. 17-2

Segragation of Coal Fines in Pulsating Gas Flow Eric Johnson, Bruce Kang, Jordan Musser, West Virginia University, USA

A preliminary experimental study was undertaken to determine if clean coal fines could be separated from dirty coal fines in a pulsating gas column. Clean coal is loosely defined as containing less pyrite than dirty coal. An experimental facility was constructed that was capable of producing a pulsating gas flow in a riser. The coal feed has a size range of 105 < dp< 210 µm and had a sulfur content of 1%. This coal has previously been cleaned. The small particle size and the small difference in densities made it impossible to segregate coal in the WVU riser system. Consequently a pulsating gas column was selected to simulate the flow characteristics in the WVU riser, which was capable of separating larger or heavier particles based on density or size difference. For frequencies of 1 or 2 Hertz, the product stream showed a reduction in sulfur as large as 20%. The typical yield was between 50% and 60%. 17-3

Abundance of FE-Bearing Species in Coal Extract and its Implications to the Iron Speciation in Raw Coal

Lian Zhang, Eleanor Binner, Sankar Bhattacharya, Monash University, AUSTRALIA; Toshimasa Takanohashi, National Institute of Advanced

Industrial Science and Technology (AIST), JAPAN Three Argonne Premium Coal Samples (APCS) and two Australian coals were extracted in a Japanese coal extraction process to generate ultra-clean extract (HyperCoal) that is potentially used in an advanced combustion system such as gas turbine to improve coal power generation efficiency. For a gas turbine fuel, the contents of inorganic impurities within it must be lower than 1000 mg/kg in total to avoid the turbine blade corrosion and/or erosion. How to exactly quantify the inorganic metals in a coal extract, especially their chemical species, is however beyond the capabilities of most the conventional analytical instruments. In this study, five raw coal samples were extracted by 1-methynaphthaelene (1-MN) or its mixture with indole (IN) at 360 °C and under 1 MPa nitrogen (cold) protection. Concentrations of inorganic elements and their chemical compositions in the resulting extracts were investigated. Inductively coupled plasma-optical emission spectroscopy (ICP-OES) was adopted for elemental quantification, whereas a variety of advanced instruments/methods was employed for chemical speciation, including electron spin resonance spectroscopy (ESR), transmission electron microscope (TEM) and

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sequential leaching. The results indicate that, irrespective of raw coal type (e.g. rank, location), Fe is the most prevalent metal in coal extract, accounting for more than half of the total inorganic metals. Black experiments without using coal precluded the contaminants from reaction and/or analytical systems employed in this study. Fe is also insoluble in any acids such as hydrofluoric acid (48%). In contrast, characterization using the advanced instruments clearly indicates that Fe in coal extract is mainly composed of two forms: octahedral Fe3+ complex associated with coal functional groups and nanometric Fe-bearing particles embedded deeply in the closed voids in coal matrix. These two species are also prevalent in the acid-washed coal samples, showing independence on coal rank. It is highly likely that they are biologically originated from ferritin ion in proteins and iron porphyrin complexes that have undergone complex transformation during coalification. The Fe-bearing species could be biomarkers in coal. To reduce their concentrations in coal extract is essential for a clean and safe combustion in gas turbine, which can be realized by washing either raw coal or coal extract with a chelating agent such as ethylenediaminetetraacetic acid (EDTA). 17-4

Segragation of Coal Fines in Jet Flow Eric Johnson, Bruce Kang, West Virginia University; Bryan M. Wimer,

NIOSH, HELD, ECTB, USA The separation of clean coal fines from dirty coal fines is a challenging problem. In order to develop a new approach to this problem, a circulating fluidized bed CFB riser system was modified to create conditions which have shown to segregate larger particles. The modified riser system was essentially concentric jets, with the center jet transporting the coal fines. The lighter coal fines migrated to the wall of the riser and were captured. The heavier fines continued up through the riser and were captured. The fined used in this research were in the size range of less than 210 µm and the coal that was crushed to produce the fines had previously been cleaned to a sulfur level of about 1%. The clean coal fines stream contained up to a 20% reduction in sulfur. The

SESSION 18

COAL-DERIVED PRODUCTS: COAL-TO-LIQUIDS: TECHNOLOGY – 2

18-1

Secure, Clean Fuels from Coal: Direct Liquefaction Anthony Cugini, Bryan Morreale, DOE-NETL; Chunshan Song,

Pennsylvania State University; James Spivey, Sivakumar Vasireddy, Louisiana State University; Edward Schmetz, John Winslow,

Leonardo Technologies, Inc., USA Fuel independence, energy availability and reliability, economic sustainability, and global climate change are serious National concerns of the 21st century. Development of liquid transportation fuels from sources other than petroleum, coupled with carbon management practices, will help address these issues. Research and development efforts have been focused on the production of synthetic transportation fuels from indigenous carbonaceous feedstocks, such as coal, oil shale and biomass. Most recently, pure biomass and biomass in conjunction with coal has been the target of renewed interests. However, due to its abundance and low cost, coal will most likely be a key component for synthetic fuels in an effort to meet national economic and supply demands. Historically, several thermochemical pathways have been identified and practiced for the production of synthetic fuels from coal, falling into three general categories; indirect liquefaction, direct liquefaction and pyrolysis. The production of synthetic fuels from coal requires removing carbon or adding hydrogen to transform coal, with a low hydrogen-to-carbon molar ratio of coal (~0.8), to transportation fuels, with a hydrogen-to-carbon ration of ~2. Direct liquefaction of coal involves its thermochemical conversion in the presence of high-pressure hydrogen, which adds hydrogen to the pyrolysis product. This conversion can be further classified based on the mechanism of hydrogen addition. The first method, generally referred to as hydroliquefaction or catalytic liquefaction, involves the direct addition of hydrogen gas to a slurry of coal, recycled coal-liquids, and catalyst, and stems from the original work by Bergius. The second method of hydrogen addition to the liquefaction process is conducted by the non-catalytic process using a “hydrogen donor solvent”, typically derived from coal-liquids. Although direct coal liquefaction is slightly exothermic (C+0.8H2CH1.6), the overall process efficiency suffers because hydrogen must be produced, e.g., by a separate process. The low-ash (<10%) bituminous and sub-bituminous rank coals suitable for liquefaction are abundant in the U.S. Regardless of coal feed, most direct coal liquefaction processes share many of the same technical barriers, such as product deashing, corrosion in distillation columns, and catalyst lifetime and activity. The National Energy Technology Laboratory’s research addressed many of these issues during development of the Synthoil process, patented in 1974, and promoted the ideas of a disposable catalyst and beneficiation of feed coal to minimize these issues. The current state of direct coal liquefaction technology is a two-stage process wherein the coal is sequentially hydrocracked and hydrotreated. The high quality products

generated from this process are compatible to those produced using current refinery technology. The presentation will provide a historical perspective of the development of direct liquefaction technologies, the catalysis and reaction pathways, and potential future directions. 18-2

Accelergy Corporation’s Integrated Coal to Liquids Technology Rocco A Fiato, Richard F Bauman, Steve Hua, Sam Zaczepinski, Youqi

Wang, Accelergy Corporation, USA Accelergy is a leader in the emerging global Coal-to-Liquids (CTL) industry, as a technology provider to commercial producers of clean fuels, chemicals, and lubricants. We are a world-class technology-driven company, commercializing unique technology to convert coal and biomass into clean products with the highest efficiency, lowest cost, and lowest GHG footprint versus other emerging options. Our market focus is coal and alternative resource monetization for clean fuels in China, South Africa and North America. Our proprietary technology utilizes coal plus biomass derived from process CO2 to produce ultra clean fuels and oxygenated fuel additives. This innovation allows us to practice CTL with a greenhouse gas footprint at or below parity with petroleum refining, and to generate the highest yield of liquids per ton of coal feed. An overview of our technology and some key aspects which allow us to achieve the high efficiency and low GHG footprint will be discussed in our presentation. Accelergy’s ICTL platform incorporates state-of-the-art direct coal liquefaction from its strategic partnership with ExxonMobil Research & Engineering, together with leading indirect conversion technology from its partnership with the Chinese Academy of Science Institute of Coal Chemistry. Our program is also complemented by alliance partnerships from leading universities and research institutes in the US, China and Europe. This approach enables us to create the most advanced CTL technologies possible, and to utilize the collective world class scientific and engineering expertise of our partners for further innovation. Accelergy ICTL – employs a novel approach for converting coal to liquid fuels in a manner that is economically viable, energy sustainable and environmentally responsive. The combination of these three critical properties has not been possible with other current or emerging CTL options. Our technology enables CTL to perform in a way that has heretofore not been possible – as a clean low GHG, ultra high yield, and cost effective way to produce liquid fuels – those fuels burning more cleanly and efficiently that current day petroleum based analogs. Economic Viability – engineering studies on ICTL show investment levels of 55-75$K per barrel day of capacity, over 30% lower than current or emerging options. This allows the process to deliver product to market at prices that are comparable to those from current day crude. Energy Sustainability – ICTL provides over 4 barrels of liquid products from a ton of dry ash free coal, well over two times the yield possible with current or emerging technologies. This would allow the resource owner to effectively double the useful lifetime of the resource in serving a given market. When operated in a mode to maximize jet fuel production, ICTL is capably of converting over 60% of the energy content of the feed into high performance JP8 jet fuel vs 20-25% possible with other CTL options. This has a significant effect on the strategic value of this technology to insure energy security and to help those such as the USAF achieve long term self sustainability of fuel supply from domestic coal resources. Environmental Responsiveness – ICTL is able to achieve an overall GHG footprint that is comparable or better than that achieved for petroleum refining to similar products. It does this in two ways: (1) higher carbon utilization efficiency in producing liquids in the direct and indirect conversion steps; (2) utilization of process CO2 to produce additional oxygenated fuel additives via algae production and conversion to liquid fuels. In the fully integrated mode, our process is able to covert over 80% of the energy contained in coal to liquid fuels products – nearly twice the efficiency of other current or emerging routes. 18-3

Production of Clean Gasoline from Coal: Exxonmobil Research and Engineering Company’s Methanol to Gasoline (Mtg) Technology

Samuel A. Tabak, Mitch Hindman, ExxonMobil Research and Engineering Company, USA

This paper will provide an update of a commercially proven route for converting coal to gasoline through coal gasification, methanol synthesis and methanol conversion to gasoline. ExxonMobil Research and Engineering Company’s (EMRE) Methanol-to-Gasoline process efficiently converts crude methanol to high quality clean gasoline. Both coal gasification and methanol synthesis are mature technologies and there are several commercially established routes for both steps. ExxonMobil discovered the methanol-to-gasoline (MTG) process in the 1970’s and commercialized a New Zealand plant in the mid-1980’s that produced MTG gasoline using natural gas as the feedstock. MTG gasoline is fully compatible with conventional refinery gasoline and with all gasoline engines.

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Both MTG and Fischer-Tropsch (F-T) can convert coal into liquid products through coal gasification. Also, coal can be converted to liquids through direct liquefaction. However, Fischer-Tropsch and direct liquefaction produce synthetic liquids requiring further refining processes to produce gasoline, diesel or other refined products. In contrast, MTG selectively converts methanol to a single liquid product; low sulfur, low benzene gasoline. The recent surge in CTL activities has renewed market interest in the MTG process. The current MTG technology is the result of a program initiated by ExxonMobil in the 1990's that reduces capital investment and operating expenses. Construction of the first 2nd generation MTG plant is nearing completion in China by the Jincheng Anthracite Mining Company (JAMG). The initial phase of the plant is designed for 100,000 t/a, but is expected to expand to 1,000,000 t/a for the second stage of the project. EMRE has also announced its first U.S. CTL project based on MTG technology. DKRW Advanced Fuels LLC has licensed EMRE’s MTG technology through its subsidiary Medicine Bow Fuel and Power LLC for a 15,000 BPD CTL plant in Medicine Bow, Wyoming. Both the JAMG and DKRW plants incorporate significant improvements beyond the original New Zealand plant, drawn from over ten years of operational experience. 18-4

Using Iron/Iodine Catalyst to Improve the Selectivity in Direct Liquefaction of Coal

Zhen Yuan, Yonggang Wang, Deping Xu, China University of Mining and Technology, CHINA

The behavior of Iron/Iodine based catalyst in the liquefaction of coal was examined by using an autoclave reactor to investigate the essential approach for promoting oil and gas yield. The liquefaction of coal in autoclave includes two-stage temperature increasing processes. First heating the reactor to 410°C for 80 min, then heating up to 440°C for 10 min. The autoclave reactor was keeping at 440°C for 60 min. The ferric oxide and iodine were mixed together with different ratio as catalyst in experiment. The results show that when the atomic ratio between iron and iodine reached 1:1, the yield of oil and gas increased to 83.11% and the yield of asphaltene and preasphaltene decreased to 0.43%. The products of gas and oil are obviously more valuable than those of asphaltene and preasphaltene, and the catalyst could selectively increase the yield of gas and oil and decrease the yield of asphaltene and preasphaltene in liquefaction of coal. Thus Iron/Iodine based catalyst would be very meaningful in the future.

SESSION 19

GASIFICATION: UNDERGROUND COAL GASIFICATION – 2

19-1

The ENN UCG Progress Feng Chen, ENN Sci.& Tech. Co.Ltd., CHINA

To achieve “zero” emission of greenhouse gases including CO2, ENN R&D Co., Ltd., has invested more than twenty million dollars in the foundation of ENN Coal-based Clean Energy "Zero Emission" Pilot Plants. As one of the most important parts, Underground Coal Gasification facility has characters of pressure (as high as 1.5 Mpa) and big scale (15m3 volume) and so on.. It simulated the coal seam, the overburden, water injection as the real geology situation. The data we get is very helpful for use in UCG simulation and commercial scale UCG sits. During the pure oxygen gasification experiment, we got the syngas which caloric value was between 2000 and 2500 kcal/Nm3, and in the gas carbon monoxide was at 25 to 35 percent, hydrogen was at 35 to 42 percent, methane is at 3 to 5 percent. In addition, we also recorded the whole UCG cavity growth process by our patented High Temperature Camera. These videos are the first UCG images in the history which could be used in many ways like the cavity shape and temperature distribution. ENN also has invested 20 million dollars alone for our commercial demonstration site. Our UCG site has continuously produced 150k m3/day syngas for more than nine month. The heating value of the syngas is promising to be used in power generation and chemical industry. 19-2

Modelling of Deep Lignite Seams for Conventional Production and Underground Coal Gasification in Turkey

S. Anac, S. Yurek, M. Ozdingis, B.S. Halicioglu, Turkish Coal Enterprises; B. Unver, E. Tercan, M.A. Hindistan, G. Ertunc, E. Akcan,

Hacettepe University, TURKEY Turkish Coal Enterprises (TKI) is the biggest state owned company in Turkish mining industry and has been producing lignite for more than a 50 years period. Majority of TKI’s production has been done by surface mining methods. However, the lignite resources suitable for surface mining are to be depleted in about 10 years. This suggests that lignite production in the near future be supplied by underground mining.

It is compulsory to develop new underground mines for maintaining safe supply of lignite in the country. TKI and Hacettepe University have been collaborating on 3D modeling of lignite seams and subsequent underground mine design. Soma, Tuncbilek and Yatagan lignite basins are selected for this purpose. Lignite seams in these basins are subject to severe tectonic movement. This will unfortunately lead to loss of some part of the deep seated seam(s) by underground mining methods. Hence, application of underground coal gasification technique to utilize these parts is evaluated as a viable alternative. This paper briefly describes tectonics and general characteristics of lignite seams together with essentials of conventional underground mining and coal gasification. 19-3

Long-Term Groundwater Monitoring for Environmental Risk Assessment: Lessons Learned from UCG Pilot Experiments

Souheil Ezzedine, Elizabeth Burton, Lawrence Livermore National Laboratory, USA

The fear of expensive and litigious groundwater contamination from underground coal gasification (UCG) is a major reason for the industry’s growing interest in environmental issues and methodologies for proactive management of contamination of water resources and their impact on human health. Failure to develop rational mitigation plans may result in negative responses from the public, environmental protection stakeholders, and regulatory agencies. UCG pilot studies conducted in the 70s and 80s have shown that the environmental consequences of a poorly designed experiment can have great and harmful consequences on the water quality of the overlying water aquifers. Groundwater monitoring is therefore required to assess human health and environmental risks of residual contaminants released during the UCG gasification and after (long term) the UCG activities are completed. Groundwater long-term monitoring (LTM) has become increasingly important and prevalent especially as active remediation concludes and the use of monitored natural attenuation increases. LTM can be costly given the large number of sampling locations (dozens to hundreds), frequency of sampling (as low as quarterly), and number of constituents monitored at a given site. Chemical, and physical data collected during monitoring should be relevant to site-specific monitoring and environmental clean-up objectives. Monitoring and clean-up of subsurface contamination has always proved costly economically and in public goodwill. The U.S. Department of Energy estimated that the total costs for monitoring at their superfund sites are approximately $100 million per year. The U.S. Navy estimated the costs of remedial active operation and LTM in its contaminated sites doubled within 5 years. Since LTM is required for scores of years, the cumulative costs can be significant. Site clean-up and monitoring for UCG pilots that caused contamination have run for decades and on the order of millions per year, but the potentially larger cost has been in loss of trust in the technology by regulators and the public. Therefore, environmental planning must optimize LTM through either statistical or mathematical methods to minimize monitoring costs while still capturing sufficient information about contaminant levels and plume movement and assuring that monitoring provides early warning of problems. Because the bulk of monitoring costs is from sampling, the goal is to reduce the number of sampling locations, the sampling frequency, and to narrow the list of contaminants that require sampling. The focus of this work is to illustrate mathematical and statistical optimization tools using environmental data collected at DOE’s Hoe Creek sites during and after UCG production. Uncertainty in the model and input parameters, causing errors in the predications and possibly unreliable optimal monitoring networks will be illustrated using hypothetical systematic measurement errors, limited site data or uncertain complex hydrogeological conditions. 19-4

Underground Coal Gasification Performance Predictions using Compartment Models

Sateesh Daggupati, Ramesh Naidu Mandapati, Sanjay M Mahajani, Anuradda Ganesh, Preeti Aghalayam, IIT Bombay; Sapru R.K., Sharma R.K., UCG

Group, IRS, ONGC, INDIA Underground coal gasification (UCG) involves the conversion of coal in the coal seam into a combustible gas thus avoiding the cost of mining and transportation. The product gas may be served as feed stock for petrochemical industry or fuel gas for power generation. It is potentially a clean method of conversion of coal into a high energy fuel gas and may be adopted to replace small coal fired power plants and to maximize the utilization of coal resources. A cavity is formed by the conversion of coal, and it grows three dimensionally in a non linear fashion as gasification proceeds. Mathematical modeling of the UCG reactor is a challenging task since several phenomena, including heterogeneous reactions, complex flow patterns of reactant gases, thermo-mechanical processes related to the structure of the seam, and so on, occur simultaneously in the UCG cavity. The non-ideal flow patterns in the cavity make a strong impact on the extent of homogeneous gas phase reactions, especially the water gas shift reaction, taking place in the cavity volume thereby influencing the product gas composition (H2/CO ratio) significantly. Thus, considerable computational efforts are required in order to obtain the UCG performance for any given set of input

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parameters. In this work, we have explore the new approach of compartment modeling that reduces the computational burden on process simulation. The compartment model developed in this exercise is based on the computation fluid dynamics (CFD) simulations and hence residence time distribution of UCG cavity. 19-5

Seismic - An Integral Part of UCG Project (A Case Study) Ashwani Lamba, P.P. Uniyal, Pankaj Bhuyan, R.K. Sharma,

D.K. Sharma, ONGC, INDIA Mapping of the faults and other structural anomalies accurately, is critical for the success of any UCG project. Even though the use of seismic in coal industry for exploration purpose is not very prevalent, ONGC took initiative and made use of the latest technology in petroleum industry, High Resolution Shallow Seismic (HRSS) survey in its UCG Pilot area for its characterization. Geological map prepared initially using data from 18 boreholes indicated the presence of faults. Borehole data along with seismic were used to refine the interpretation. Three known faults were accurately imaged by this technique. The locations of other faults were also successfully interpreted. The results will be used in optimally placing the underground gasifier. The inadequacy of use of borehole data alone is clearly highlighted in this case study. The study recommends high resolution seismic survey to be an integral part of any UCG Project.

SESSION 20

GASIFICATION: FUNDAMENTALS – 2

20-1

FE-Mineral Transformations during the Initial Stages of Entrained-Flow Coal Gasification

Stephen Niksa, Niksa Energy Associates, LLC; Donald Eckstrom, Ripu Malhotra, Al Hirschon, SRI International, USA

The tests and simulations in this study characterize the chemical structure of lab-scale pressurized premixed pulverized coal flames of eight density- and size-classified fractions of a Pit. #8 hv bituminous coal for stoichiometric ratios (S. R.) from 0 to 1.8 in a 1D turbulent flow reactor operating at 1600°C and 3 MPa. In one test series, particle transit times were no longer than 300 ms to characterize the initial stages of pressurized gasification and combustion; in another, transit times were extended to almost 2s under elevated partial pressures of steam and CO2. This paper focuses on the two heavier feed fractions, whose behavior is determined by Fe-mineral transformations, whereas a companion paper characterized the transformations of combustibles with the two lighter fractions. Tests were also run with pure pyrite suspensions to further clarify the release of S under strongly reducing atmospheres. Tests were run with hardly any O2; under reforming conditions with a nominal S. R. of 0.6; and under oxidizing conditions with a S. R. of 1.2. Tests without O2 determined the extents of S-release via devolatilization, which extended through the approach to wustite (FeS). As the inlet O2 level was progressively increased in succeeding tests, S-release stalled after wustite was produced because, apparently, the test conditions were not severe enough to remove more sulfur. However, tests in synthetic syngas under strongly reducing conditions promoted much more S-release. Evidently, elevated partial pressures of H2 are required to convert pyrite into mixtures of base Fe metal and wustite. This dependence was clarified in additional tests with pyrite suspended in H2/Ar mixtures and syngas with variable H2 concentrations. CFD simulations for every test were used to assign detailed processing conditions, which were subsequently used to quantitatively interpret the measured product distributions with newly proposed reaction mechanisms. Once validated, the reaction mechanisms were used to specify the rate parameters and stoichiometric coefficients the simple quasi-global rate laws that could be routinely used in CFD simulations. These rate parameters are reported along with the simplest chemical reaction schemes that accurately depict the tendencies among the major products in this system. 20-2

Investigation of Ash Deposition during Char-Slag Transition under Gasification Conditions

Suhui Li, Kevin Whitty, University of Utah, USA Ash deposition experiments of a pulverized bituminous coal were performed under gasification conditions using a laminar entrained-flow reactor and an uncooled deposition probe. Analysis on the deposit showed that the ash stickiness was a function of residence time (1-6 s) of the coal particle in the reactor. In particular, the ash stickiness increased dramatically at a residence time of 3 s. In order to clarify this phenomenon, ash formation experiments were conducted to collect char/ash particles by replacing the deposition probe with a water-cooled collection probe. The collected particles were presumably to have identical properties as the particles impacting the deposition probe in the ash deposition experiments. The properties of the collected particles including carbon content, internal surface area, and char structure and

morphology were determined by loss-on-ignition, isothermal gas adsorption and scanning electron microscopy, respectively. Results showed that the internal surface area of the particles decreased coincidently at the residence time of 3 s, which indicates a char-slag transition. The coincidence of the change in the stickiness and the surface area of the particle leads to a conclusion that the transformation from porous char to molten slag results in the dramatic increase in ash stickiness. A comparison of the structure and morphology of ash formation samples resulting from 1 s to 6 s residence times in the reactor confirms this conclusion and elaborates the previous study on the effect of residual carbon on ash stickiness. 20-3

Evaluation of Entrained Gasification Char for Recycling into Gasifier Yongseung Yun, Na Rang Kim, Seok Woo Chung,

Institute for Advanced Engineering, KOREA Main objective of commercial-size dry-feeding coal gasifier is to guarantee the carbon conversion of over 99% since the price to treat un-reacted fines in an environmentally sound way would be very costly when considering the amount of un-reacted 1% could reach 20-30 tons a day. If the remaining fines or char is classified as a hazardous material according to the local standard in some way, the cost can be easily reach one or two hundreds of dollars per ton in treatment. Most commercial gasifiers choose to melt the inorganic part into slag, which can provide a cheaper or sometimes a profitable way of treatment. Entrained fine particles from a dry-feeding coal gasifier generally contain 40-80% carbon. For more than 99% carbon conversion, captured fine particles must be returned into gasifier for further reaction. Many commercial coal gasifiers chose to recycle entrained particles into coal gasifier as much as 40-60%. Captured entrained particles can be fed into gasifier through a connected char feeding system or stored in a separate vessel and returned to the coal feeding hopper at atmospheric pressure. When the amount of entrained char remains less than 10% of the feed coal amount, feeding via a coal hopper can be a better option. Indonesian subbituminous coals were gasified in a 1 ton/day dry-feeding type coal gasifier at 8 bar and yielded less than 2 wt% entrainment of the fed coal. Fines exhibited a similar particle distribution pattern as raw feed coal, but an increased fraction of smaller size particles. Captured fines also showed a loose-packed aggregate pattern which would cause a different characteristic in recycling into coal gasifier. Fines were further analyzed to determine whether they might cause any feeding problem such as clogging or segregation with raw coal powder. Normally, there would be almost no technical problem when the added amount of fines to the coal feeding hopper is less than few percent. In the case of 10-15% of added recycled fines, detailed analysis should follow to prevent typical problems like clogging. In addition, understanding the shape and physical properties of capture fines is one of key factors in the design of recycling system. In a newly designed coal gasifier system in that 10-15% of fines are recyclable, suitability of entrained gasification char to recycle feeding system and any necessary pre-treatment were evaluated. 20-4

Slag-Refractory Interactions Larry Baxter, Brigham Young University, USA

This document charts the historical interest in gasification and makes the case that refractory-slag issues may represent a dominant consideration in both the technical and commercial success of gasifiers, in particular for power generation, followed by a review of refractory failure mechanisms. Gasification systems may never previously have had the same alignment of technical and business advantages that they currently enjoy and hence may be at an historic high point in probability of commercialization. One large remaining barrier for gasification generally and IGCC applications in particular is reliability, with refractory failure being one of the most common problems in this regard. This document charts the historical interest in gasification and makes the case that refractory-slag issues may represent a dominant consideration in both the technical and commercial success of gasifiers, in particular for power generation. 20-5

Modeling Slag Viscosity with Atmospheric Effects Marc A. Duchesne, Arturo Macchi, University of Ottawa; Ben Anthony,

Dennis Lu, Robin Hughes, David McCalden, CanmetENERGY, CANADA There is much interest in the prediction of slag viscosity to avoid gasifier plugging, as well as preventing corrosion and erosion of the reactor wall. The viscosity is mainly dependant upon slag composition, temperature and the surrounding gas atmosphere. Many semi-empirical models exist for the prediction of slag viscosity. However, inclusion of atmospheric effects on slag viscosity is limited. Parameters affecting slag viscosity are reviewed, models are compared and the literature on atmospheric effects is discussed. Artificial neural networks discriminating between different atmospheres were developed but failed to outperform a more general model. FactSage is introduced as a tool for predicting atmospheric effects and recommendations are made for future work.

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SESSION 21

CARBON MANAGEMENT: POST-COMBUSTION – 1

21-1

“Molecular-Basket” Sorbents for CO2 Capture from Flue Gas Xiaoliang Ma, Xiaoxing Wang, Chunshan Song,

Pennsylvania State University, USA One of the great challenges in carbon capture and sequestration (CCS) is to separate CO2 from flue gas more economically and energy efficiently. On the basis of the conventional amine scrubbing (absorption) technologies, the cost for CO2 capture and separation from flue gas was estimated by DOE to represent three fourths of the total cost of a carbon capture, storage, transport, and sequestration system. Accordingly, it is highly desired to develop a novel sorbent material and a process with high capacity, high selectivity, high regenerability, high energy efficiency and low cost for separation of CO2 from flue gas. The capacity, selectivity, regenerability, stability of sorbents, and energy consumption in the process are the important factors that directly influence the efficiency and economy of a practical CO2 separation process. The present paper reports our current progress in developing “molecular basket” sorbents (MBSs) for CO2 capture from flue gas. The advantages of MBSs in adsorption capacity, selectivity, regenerability, and sorption-desorption rate and energy consumption are analyzed and discussed in comparison with some typical absorbents/sorbents. Our study shows that the new generation of MBS has many significant advantages, including higher capacity: (140 mg-CO2/g-S at 15 kPa of CO2), high selectivity, no corrosion, high sorption/desorption rate due to high interface area (~80m2/g), good regenerability/stability, positive effect of moisture on the sorption performance, lower energy consumption, and ability to remove and recover SOx and NOx(17 mg-NO2/g-S at 0.2 kPa NO2, 7.3 mg-SO2/g-S at 0.05 kPa SO2). 21-2

An Efficient Membrane Process to Capture Carbon Dioxide from Power Plant Flue Gas

Xiaotong Wei, Tim Merkel, Bilgen Firat, Haiqing Lin, Jenny He, Richard Baker, Karl Amo, Hans Wijmans, Membrane

Technology and Research, Inc., USA Production of power from coal inevitably generates carbon dioxide (CO2) as a by-product. To mitigate global climate change, this CO2 must be captured and sequestered. With current technologies, separating CO2 from flue gas accounts for about 70% of the total cost for CO2 capture and sequestration. Among a number of emerging technologies that are being evaluated for CO2 capture, membrane technology is attractive because of its inherent advantages such as high energy efficiency, a small footprint, environmentally friendly operation (no chemicals), mechanical simplicity, and proven reliability. Working with NETL, MTR has developed new membranes and process designs to recover CO2 from power plant flue gas. The membranes have CO2 fluxes ten times higher than standard commercial membranes, combined with useful CO2/N2 selectivities. Based on our best current process design, these membranes offer the potential to capture 90% of the CO2 in the flue gas using about 12% of the power produced by the plant, at a cost of $20-$30/ton of CO2 captured. Successful commercialization will provide a technology that can be used in the near-term to reliably retrofit existing coal-fired power plants. Currently, MTR is working with Arizona Public Service (APS) to conduct a field test of this membrane CO2 capture process at APS’ Cholla, Arizona coal-fired power plant. The demonstration will process 250,000 scfd of real flue gas beginning at the end of 2009. Technical results to date, preparations for the field test, and future plans will be discussed in this presentation. 21-3

Update on RTI’s Dry Carbonate Process: Carbon Dioxide Capture from Power Plant Flue Gas

Thomas O. Nelson, Luke J.I. Coleman, Matthew L. Anderson, Joshua Herr, Maruthi Pavani, RTI International; José D. Figueroa, DOE-NETL, USA

The reversible reaction between sodium carbonate, carbon dioxide (CO2), and water vapor to form sodium bicarbonate can be used in a thermal-swing process to recover concentrated CO2 from coal-fired power plant flue gas for sequestration or reuse. A process based on this reaction - RTI’s Dry Carbonate Process - has been developed and is targeted as a retrofit CO2 capture technology for existing coal-fired power plants. In late 2009, RTI will begin a long-term pilot-scale testing program of a Dry Carbonate prototype unit capable of capturing at least 1 ton of CO2 per day. This presentation will highlight the activities being carried out in preparation for pilot-scale testing. RTI has made significant advancements to the Dry Carbonate process design and sorbent material. Improvements to the sorbent preparation have lead to a 7 fold increase in CO2 loading capacity compared to previous RTI-prepared sorbents while maintaining desired physical properties (e.g. attrition resistance). RTI has also collaborated with

Süd-Chemie, Inc. to prepare large quantities (hundreds of lbs) of its most promising sorbents in commercial manufacturing equipment. During a bench-scale field test in 2007, RTI observed that the CO2 capture rate of the Dry Carbonate Process was limited by heat transfer rates in the CO2 capture reactor. As a result, RTI’s process development efforts have since focused on gas-solid reactor designs capable of achieving high heat transfer coefficients and handling large sorbent quantities. RTI has constructed a bench-scale heat transfer evaluation system to collect the heat transfer data required to properly design and size a pilot-scale system. Experimental/modeling results from this effort will be presented in addition to results of other bench-scale R&D work – including solids handling and flow control, gas-solid separation, “cold-flow” testing, and kinetic evaluations. This work was accomplished under a cooperative agreement with the U.S. Department of Energy’s National Energy Technology Laboratory (DOE/NETL). The project is part of DOE/NETL’s Existing Plants, Emissions, and Capture Program which seeks to develop technologies capable of 90% CO2 removal with a potential to limit the power generation impact to a less than 35% increase in cost of electricity. 21-4

Low Cost Solid Sorbent for CO2 Capture on Existing Coal-Fired Power Plants,

Jeannine Elliott, Girish Srinivas, Robert Copeland, TDA Research, Inc., USA Coal currently accounts for nearly 56% of U.S. electric power generation, and since the U.S. has 25% of world’s coal reserves coal will continue to play an increasingly important role in meeting the Nation’s future energy needs. Concerns about global climate change could lead to future regulations on the emissions of CO2 produced by coal-fired power plants. Although advanced integrated gasifer combine cycle (IGCC) technologies will likely provide some of the projected 50% increase (from 300 GW to 450 GW) in electricity demand by 2030, the vast majority of the power will still be produced by pulverized coal (PC) plants. Therefore, if in the future CO2 emissions are regulated existing pulverized coal power plants will need to be retrofitted with a low cost CO2 capture technology that can efficiently remove CO2 from the dilute low-pressure flue gas stream. TDA Research, Inc is developing a low cost solid adsorbent that can cost effectively and efficiently capture CO2 from existing pulverized coal-fired power plants, using hardware that is comparatively easy to add in the confined space of the existing PC plant. TDA’s sorbent is a regenerable sorbent that can be rapidly cycled by steam regeneration at intermediate temperatures. Whereas most CO2 separation processes consume large quantities of energy and significantly increase the cost of generating electricity, TDA’s sorbent removal process can separate the dilute CO2 from the flue gas while inexpensively producing electricity. In fact, our preliminary economics show the process is able to capture 90% of the CO2 emissions with only a 31.7% penalty in the cost of energy. This work is a multi-year collaboration between with TDA Research, Inc, Babcock and Wilcox (B&W), Louisiana State Univerisity (LSU) and Western Research Institute (WRI). We are in the first year of the project with our current effort focused on demonstrating of an optimized sorbent in laboratory testing to show the cyclic lifetime, loading levels, and regeneration requirements. The sorbent cost is also being optimized by evaluating of various low cost raw materials sources. Sorbents are being screened for surface area, crush strength, volumetric density and CO2 loading. CO2 loading measurements for screening tests are done by thermogravometric analysis (TGA). Promising sorbent candidates are being scaled up for further testing in a 300 cc fixed bed reactor. This testing unit is fully automated for continuous data logging and unattended operation. Online analyzers continuously measure the outlet concentration of CO2. The apparatus can continuously cycle the sorbent at controlled absorption and regeneration conditions. With this equipement TDA measures the absorption and regeneration profiles and dynamic loading capacity at the reaction conditions of interest. Sorbent testing is being performed over as a wide range of temperatures, space velocities, and absorption and desorption cycle times. Sorbent testing of hundreds of cycles is being performed on promising compositions. In these tests we are also evaluating the CO2 capture performance sorbent under simulated flue gas conditions including evaluating the effect of moisture and SO2 levels. Additionally, in collaboration with LSU we are using an ASPEN simulation in our system analysis of the sorbent-based CO2 capture process design. Louisiana State University (LSU) will model the mass and energy balances for a commercial scale pulverized coal-fired power plant with our CO2 capture system using ASPEN and calculate the loss in plant efficiency. The experimental results and simulation data are being used in our engineering and economic analysis as we optimize this solid sorbent based post-combustion CO2 capture system. 21-5

The Hazelwood/H3 Capture Demonstration Projects Barry Hooper, The University of Melbourne; Tony Innocenzi, International Power Australia Pty Ltd; Craig Dugan, The Process Group, AUSTRALIA

In the first half of 2009 International Power and the Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) commissioned their respective, but interlinked, post combustion capture projects at the Hazelwood power plant in the Latrobe Valley in south eastern Australia. This has created a significant, and indeed

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unique, capture demonstration and research hub and represents a critical milestone on the pathway to large scale abatement of greenhouse gases by carbon dioxide capture and storage from fossils fuels and particularly Victorian brown coal. The first component of the research hub is International Power’s CO2 Capture Project, which was designed to initially capture 25 tonnes per day (and is expandable to 50 tonne per day) of CO2 from flue gas using an amino acid based solvent process. The CO2 is being used on site for neutralisation of ash water which replaces the current use of sulphuric acid and results in the formation of calcium carbonate in a form of mineral sequestration. The plant has a footprint of 24 m x 10 m and a height of up to 27 m and provides an imposing introduction of Carbon Capture and Storage (CCS) to the site. The second component of the research hub is the CO2CRC’s H3 Project which is being used to research novel and conventional CO2 capture techniques at a range of sizes. The H3 Project is testing solvent systems, the membranes processes of gas separation and gas absorption membranes and adsorbents processes using vacuum swing adsorption. The absorption/stripping processes are being tested in the HCCP initially with the amino acid solvents and then using potassium carbonate utilising patented technologies developed by the CO2CRC. The novel processes are being trialled in purpose built rigs designed specifically for the task. This paper provides background on the development of these projects and the technologies and equipment employed, discusses the commissioning process and provides initial data and analysis of the first stages of the work. Furthermore it outlines the opportunities and challenges these technologies face in progressing from laboratory through to eventual large scale commercial operation. The eventual aim of this work is to develop cost effective designs and flow sheets for both retrofit and new build configurations. Initial work on heat integration linked to these projects indicates significant improvements over current thinking for the parasitic energy of post combustion capture.

SESSION 22

COMBUSTION: OXY-COMBUSTION – 2

22-1

Effects of CO2 on Char Oxidation and Ignition during Oxy-Coal Combustion

Shengteng Hu, Dong Zeng, Andrew J. Mackrory, Alan N. Sayre, Hamid Sarv, The Babcock & Wilcox Company Research Center, USA

Oxy-coal combustion is a viable technology for curtailing greenhouse gas emissions from coal-fired power plants. Detailed knowledge of the effects of CO2 on char reactivity in oxy-coal combustion is important for the accurate determination of char burnout and implementation in predictive combustion models. In this work, we focus on the char oxidation process. An eastern bituminous coal and a western subbituminous coal are first pyrolyzed in an entrained flow reactor. Either coal or the collected char samples are then fed into a flat flame burner at certain excess oxygen levels. By switching between N2 and CO2 diluents, the differences in the oxidation rates and ignition delay between these two environments can be investigated. Char samples at different residence times are collected and their extent of burnout is determined using the ash tracer technique. A fiber-optic based two-color pyrometer is used to simultaneously acquire particle surface temperature, size, and velocity information. The ignition delay of the coal/char particles is also captured using an ICCD camera. The newly obtained data will be used to improve the oxidation kinetics in our existing char burnout sub-model. 22-2

Oxyfuel Combustion Properties Based on Horizontal Single Burner Furnace Tests

Toshihiko Mine, Takahiro Marumoto, Miki Shimogori, Babcock-Hitachi K.K. Kure Research Laboratory; Kenichi Ochi, Babcock-Hitachi K.K. Kure

Division; Hirofumi Okazaki, Hitachi Ltd. Energy & Environmental Systems Laboratory, JAPAN; Pauli Dernjatin, Fortum Service, FINLAND

The characteristics of combustion, heat transfer and ash deposition in oxy-fuel combustion were compared with air-combustion using a 4.0 MWth horizontal furnace with a single burner. As a results, it were confirmed that (1) The flame stability was very satisfactory using a Hitachi NR-3 burner at the period of changing from air combustion to oxy-fuel combustion and oxy-fuel combustion, (2) The radiation heat flux of oxy-fuel combustion was almost same as one of air combustion at inlet O2=28vol%-wet, (3) The composition of deposition ash of oxy-fuel combustion was same as one of air combustion.

22-3 High-Speed Camera Observation of a Bituminous Coal Combustion in

Air and O2/CO2 Mixtures and Particle Velocity Measurement Lian Zhang, Eleanor Binner, Sankar Bhattacharya,

Monash University, AUSTRALIA An advanced high-speed camera with a spatial resolution of ~20 μm and time scale of 1~2 ms was employed to observe coal particle combustion in a lab-scale drop-tube furnace. Combustion of a bituminous coal of 106~153 μm at the furnace temperature of 1000oC in air and O2/CO2 mixtures was photographed. Apart from the transient phenomena captured in each stage, dynamic information regarding burning coal particle velocity and its residence time was also obtained through analysis of multiple exposures. Combustion of coal char (attained from pyrolysis in N2) was also recorded. The results indicate the obvious variation of particle motion with reactor height and gas atmosphere. Volatiles released at the initial stage of coal combustion could be dominated by the heavy tarry hydrocarbons that preferentially combusted in the vicinity of particles, which in turn yielded a large buoyant force around particles and greatly reduced their falling velocities. Such a phenomenon was not observed during char combustion. The consumption/combustion rate of the released volatiles from bituminous coal further played an important role in char particle motion in the late stages. Replacement of air with 21% O2 + 79% CO2 increased the duration of volatile consumption on char surface, thus slowing particle motion over a relatively long period. Increasing the O2 fraction in CO2 fastened the volatile consumption rate. Particle velocity was improved consequently. These findings were not predicted by a conventional non-reacting particle motion model, bearing significance for understanding the kinetics of pulverized coal combustion as well as retrofitting of existing power generation plants with an oxy-fuel combustion technology that burns coal in O2/CO2 mixture. 22-4

Effects of O2 Partial Pressure on Flame Stability in Oxy-Coal Combustion

Jingwei Zhang, Kerry Kelly, Eric G. Eddings, Jost O.L. Wendt, University of Utah, USA

Oxy-fuel combustion of pulverized coal is one of the few technologies that may allow CO2 sequestration technologies to be applied to existing coal-fired boilers. One issue of interest is to understand and predict the effects of near burner zone environment consisting of O2 and CO2 (instead of N2). The purpose of this research is to better understand and to scale the effect of partial pressure of O2 and CO2, which becomes another degree of freedom, on coal jet ignition and flame stability. A novel methodology is developed to quantify the flame stability and flame length by introducing an image processing technique. Ultimately the experiment will provide data for simulation validation studies that can be used to predict how air fired combustors may be retrofitted to oxy-coal. Specifically the objective is to explore effects of the partial pressure of O2 and CO2 on coal jet flame stability, which is quantified by stand-off distance, the distance between burner tip and the base of the detached flame. The experiments are carried on in a 100 kW pilot-scale laboratory furnace outfitted with a coaxial burner (primary jet in the center pipe and secondary stream in the annular sleeve, no swirl, type 0 turbulent flame) and arrays of electrically-heated panels in the burner zone in order to control variations in near-burner heat loss. Currently no flue gas recirculation is introduced to provide a nearly pure CO2 stream. Instead, fresh, one-through CO2 and O2 streams are introduced to the burner. The furnace also has visual access to the burner zone through quartz windows, which allows for optical measurements. A special CMOS sensor based camera, which is more sensitive to the near infrared wavelength(responsivity: 1.4 V/lux-sec (550 nm)), is applied to capture Type 0 axial turbulent diffusion flame shape for the use of statistical studies of stand-off distance at different operational parameters, such as systematic variations of partial oxygen pressure in both transport and secondary oxidant stream. Statistical analysis is used to scale the effect of oxygen partial pressure in both transport and secondary stream on coal jet ignition and flame stability. Ultimately the statistics help to generate probability density function (PDF), which can be used to evaluate the experiment accuracy, reproducibility and to do model validation. 22-5

Evaluation of Effect of Particle Size on Oxy-Fuel Combustion of Pulverized Coal

M. Geier, E. Hecht, C. R. Shaddix, Sandia National Labs, USA Previous research has highlighted the important role of reduced oxygen diffusivity through the particle boundary layer during oxy-fuel combustion with flue gas recircula-tion (i.e. high CO2 environments). Single-particle modeling of this process also revealed that partial conversion of the carbon oxidation product CO in the particle boundary layer was important during oxygen-enhanced combustion for particles approximately 130 μm in diameter. In this study, the influence of oxy-fuel combustion conditions on char com-bustion rates is being investigated both experimentally and through detailed modeling, for several different characteristic pulverized coal particle sizes. Both a high-volatile bitu-minous coal (Utah Skyline) and a typical PRB low-

20

sulfur subbituminous coal (North An-telope) are being investigated. A combustion-driven entrained flow reactor equipped with an optical particle-sizing pyrometer is being used to determine the combustion kinetics of pulverized coal chars when burning in both reduced oxygen and oxygen-enriched atmos-pheres with either a N2 or CO2

bath gas. Preliminary calculations using the particle com-bustion code SKIPPY have shown that boundary layer conversion of CO becomes impor-tant for oxy-fuel combustion of char particles larger than 60 μm in diameter and, for a char particle reactivity characteristic of high-volatile bituminous coals, the boundary layer reactions result in over a 20% enhancement in the char burning rate for particle sizes between 70–80 μm in diameter.

SESSION 23

COAL SCIENCE: COAL CHEMISTRY – 1

This SESSION was canceled.

SESSION 24

COAL-DERIVED PRODUCTS: CARBON MANAGEMENT FOR COAL CONVERSION

24-1

Secure, Clean Fuels from Coal: Carbon Management Anthony Cugini, Bryan Morreale, DOE-NETL; Chunshan Song,

Pennsylvania State University; James Spivey, Louisiana State University, USA

Fuel independence, energy availability and reliability, economic sustainability, and global climate change are serious national concerns of the 21st century. Identification and development of energy conversion processes that utilize nationally abundant energy sources, coupled with carbon management practices, will help address these issues. Research and development efforts have been focused on the production of synthetic transportation fuels from indigenous carbonaceous feedstocks, such as coal, oil shale and biomass. Most recently, feedstocks such as pure biomass and biomass in conjunction with coal have been the target of renewed interests. However, due to its abundance and low cost, coal will most likely be a key component for synthetic fuels in an effort to meet national economic and supply demands. Historically, several thermochemical pathways have been identified and practiced for the production of synthetic fuels from coal, falling into three general categories: indirect liquefaction, direct liquefaction, and pyrolysis. Synthetic fuel production technologies have been demonstrated for decades on commercial scales, and have shown to be economical under various technoeconomic environments. However, global concerns with climate change have motivated industrial and governmental organizations to implement carbon management practices in developing energy conversion strategies, including synthetic fuel processes. Several strategies and processes are being developed to assist in carbon management practices of energy conversion processes, including CO2 capture (solvents, sorbents and membranes), CO2 sequestration in geological formations and CO2 re-use (enhanced oil recovery, feedstock to chemicals and fuels) and will be of focus in this presentation. 24-2

Calcium Looping Process Enhanced Coal to Liquid Technology Shwetha Ramkumar, Nihar Phalak, Zhenchao Sun, L. S. Fan,

The Ohio State University, USA The increasing energy demand and the necessity for energy independence have brought coal to liquid (CTL) technologies, which have the capability of near term implementation due to their compatibility with the existing infrastructure, to the forefront. Coal derived liquids are high quality, ultraclean fuels which result in lower particulate, sulfur and NOx emissions when compared to the petroleum derived fuels. Currently, the indirect production of coal derived liquid fuels is through the coal gasification and Fischer Tropsch (FT) process. It has been estimated that the carbon foot print of the coal to liquids process is at least 150 – 175% higher than petroleum based fuels. By the implementation of carbon capture and sequestration, the life cycle CO2 emissions for the coal to liquids process can be reduced by 20% compared to conventional fuel. The Calcium Looping Process (CLP) is capable of producing a sequestration ready CO2 stream by capturing all the CO2 emitted during the coal to liquids process. In addition to achieving carbon capture, the CLP improves the efficiency of the coal to liquids process by conversion of the Fischer Tropsch reactor’s off gases to hydrogen which is used to adjust the H2:CO ratio of the FT feed and for the product upgrader. The CLP is capable of reforming the hydrocarbons and shifting the unreacted syngas in the FT offgases in the presence of a calcium based sorbent and reforming catalyst while simultaneously capturing the CO2. It integrates the reforming of hydrocarbons,

water gas shift (WGS) reaction and in-situ carbon dioxide (CO2) removal at high temperatures in a single reactor while eliminating the need for excess steam addition, WGS reactor and catalyst, CO2 scrubber and a hydrogen purification system and reduces the overall foot print of the hydrogen production process. The CLP comprises of two reactors; the carbonation reactor where the thermodynamic constraint of the reforming and WGS reaction is overcome by the incessant removal of the CO2 product and high-purity H2 is produced and the calciner where the calcium sorbent is regenerated and a sequestration-ready CO2 stream is produced. The purity of H2 and the conversion of hydrocarbons are increased by a large extent when the carbonation reaction is integrated with the WGS reaction. The exothermic carbonation and WGSR convert the highly endothermic reforming of hydrocarbons into a heat neutral process thus simplifying the reforming process and reducing the temperature of reforming from > 900°C to 650°C. Experiments conducted in a bench scale facility have revealed that high purity H2 of >97% purity can be produced by the CLP with integrated CO2 capture. 24-3

Investigation on Carbonation and Regeneration of K2CO3/Al2O3 for CO2 Capture

Chuanwen Zhao, Xiaoping Chen, Changsui Zhao, Southeast University, CHINA

Recently, chemical absorption with dry alkali metal-based regenerable sorbents has been investigated as an innovative concept for CO2 capture, and it is considered to be one of the more promising technologies for capturing CO2 from flue gas. The carbonation and regeneration characteristics of K2CO3/Al2O3 sorbent for CO2 capture was investigated with thermogravimetric apparatus (TGA), X-ray diffraction (XRD), scanning electron microscopy analysis (SEM) and N2 adsorption method. Results show that the carbonation characteristics of K2CO3/Al2O3 were different in different reaction conditions (such as temperature, CO2 and H2O concentration), and the regeneration characteristics of those products were different either. K2CO3/Al2O3 showed high CO2 capture capacity and K2CO3 was nearly completely converted to KHCO3 in some case, and the products can completely regenerate. However, K2CO3/Al2O3 shows poor CO2 capture capacity in other case, and the regeneration of products is different from the one before. The differences in carbonation and regeneration characteristics between those K2CO3/Al2O3 sorbents were analyzed from the microscopic view. The by-product of KAl(CO3)2(OH)2 was the reason for decrease in CO2 capture capacity. KHCO3 will be the exclusive product, and the appearance of KAl(CO3)2(OH)2 can be avoided by choosing the proper reaction condition. This investigation can be used as basic data for dry potassium-based sorbents capturing CO2 from flue gas. 24-4

Environmental Benefits of Coal Combustion Products Vinio Floris, Exponent, Inc.; Jim Hicks, CeraTech, Inc., USA

Coal is a relatively abundant, reliable and inexpensive energy source for worldwide power generation. However, it is also one of the main producers of Carbon Dioxide (CO2). Coal combustion has been brought into question regarding other noxious waste products like Mercury, Nitrogen Oxide and Sulphur Dioxide. The US alone produces approximately 1.5 billion tons of CO2 annually from all sources; globally, coal is attributed to one third of all CO2 emissions. Until more economically feasible alternatives are developed for capturing and sequestrating CO2, conventional coal-based power generation is to continue for decades to come. The construction sector can use Coal Combustion Products (CCP) in innovative manners to assist in the decrease of pollutants during a “transition” period. CCP’s can work to mitigate the effects of other CO2 emitting sources. For instance, the use of one unit of fly ash (a by-product of coal burning in power generation and one most common CCP) in the cement-making process could reduce substantial amounts of CO2 emitted by a cement kiln. Worldwide, the production of Portland cement alone accounts for 6 - 8 percent of all human generated CO2 greenhouse gases. Fly ash can be used as a component in the manufacture of cement without posing structural changes to the end product. In fact, durability factors are substantially improved. Fly ash is also a very good substitute for cement when used as a pozzolan in portland cement concrete. Importantly, fly ash can be used in very high quantities with activated fly ash cements. These newly developed activated fly ash products leave virtually no carbon footprint. Updated cementitious binder technology eliminates approximately 1 ton of CO2 emitted into the atmosphere per ton of material produced. These "extreme green cement technology" is engineered specifically for conventional walls and concrete block masonry, new construction and repair projects. The extreme green activated cement and products are comprised of up to 95 percent green sustainable industrial waste stream materials, primarily fly ash. They are manufactured via a simple low energy, powder blending process. The system incorporates block, mortar, grout, structural and parging materials that incorporate high-strength green cement technology. The system produces structures with superior strengths, compared to traditional products made from native raw materials, and in a condensed time frame. Normal setting and hardening products also can be produced. This green cement technology possesses excellent performance characteristics, including high early strengths and 28-day strengths near 10,000 psi.1 Moreover, they

21

can be effectively placed in ambient temperatures ranging from 30 degrees °F to 120 degrees °F. In 2007, a survey of 161 US coal-fired power plants (out of 500 operating coal power plants) showed production of 64 million tons of fly ash. Of this amount, only 12.2 tons (19 percent of the total) were used in concrete or as a concrete product. The survey reported that more than 40 million tons of fly ash is still being disposed of in US landfills annually. Clearly, the use of otherwise waste materials for beneficial use can reduce the amount of CO2 produced. Governments and corporations are beginning to see the benefits of using CCP for mitigating greenhouse emissions. For instance, the State of California through California Bill 32 (AB 32) is seeking reductions in greenhouse gas emissions from the production of cement, primarily carbon dioxide. The California Air Resources Board has already passed regulations requiring annual reporting of greenhouse gases-related emissions data from cement manufacturing plants. California expects a potential 1.1 million tons reduction in CO2 emissions by 2020 from cement manufacturing (with a 9% reduction from 2009 to 2011) and a potential 0.6 to 1.8 million tons reduction in CO2 emissions by 2020 from concrete manufacturing (with a 9 percent to 27 percent replacement of Portland cement with CCP).

SESSION 25

GASIFICATION: UNDERGROUND COAL GASIFICATION – 3

25-1

Coupled Geomechanical Simulations of UCG Cavity Evolution Joseph P. Morris, Thomas A. Buscheck, Yue Hao, Lawrence Livermore National Laboratory, USA

This paper presents recent work from an ongoing project to develop predictive tools for cavity/combustion-zone growth and to gain quantitative understanding of the processes and conditions (both natural and engineered) affecting underground coal gasification (UCG). In this paper we will focus upon the development of coupled geomechanical capabilities for simulating the evolution of the UCG cavity using discrete element methodologies. The Discrete Element Method (DEM) has unique advantages for facilitating the prediction of the mechanical response of fractured rock masses, such as cleated coal seams. In contrast with continuum approaches, the interfaces within the coal can be explicitly included and combinations of both elastic and plastic anisotropic response are simulated directly. Additionally, the DEM facilitates estimation of changes in hydraulic properties by providing estimates of changes in cleat aperture. Simulation of cavity evolution involves a range of coupled processes and the mechanical response of the host coal and adjoining rockmass plays a role in every stage of UCG operations. For example, cavity collapse during the burn has significant effect upon the rate of the burn itself. In the vicinity of the cavity, collapse and fracturing may result in enhanced hydraulic conductivity of the rock matrix in the coal and caprock above the burn chamber. Even far from the cavity, stresses due to subsidence may be sufficient to induce new fractures linking previously isolated aquifers. These mechanical processes are key in understanding the risk of unacceptable subsidence and the potential for groundwater contamination. These mechanical processes are inherently non-linear, involving significant inelastic response, especially in the region closest to the cavity. In addition, the response of the rock mass involves both continuum and discrete mechanical behavior. We have recently commenced coupling the LDEC (Livermore Distinct Element Code) and NUFT (Non-isothermal Unsaturated Flow and Transport) codes to investigate the interaction between combustion, water influx and mechanical response. The modifications to NUFT are described in detail in a companion paper. This paper considers the extension of the LDEC code and the application of the coupled tool to the simulation of cavity growth and collapse. The distinct element technology incorporated into LDEC is ideally suited to simulation of the progressive failure of the cleated coal mass by permitting the simulation of individual planes of weakness. We will discuss the coupling approach and then demonstrate the capability through simulation of several test cases. 25-2

Coupled Thermal-Hydrologic-Chemical Simulations of Underground Coal Gasification

Thomas A. Buscheck, Yue Hao, Elizabeth A. Burton, Lawrence Livermore National Laboratory, USA

This paper presents recent work from an ongoing project at Lawrence Livermore National Laboratory (LLNL) to develop a set of predictive tools for cavity/combustion-zone growth and to gain quantitative understanding of the processes and conditions (both natural and engineered) affecting underground coal gasification (UCG). We discuss the development and application of coupled thermal-hydrologic-chemical simulation capabilities required for predicting UCG cavity growth, as well as for the potential environmental consequences.

Simulation of UCG cavity evolution involves coupled thermal-hydrologic-chemical-mechanical processes in the host coal and adjoining rockmass (cap and bedrock) that can influence UCG operations. In this paper we focus on the thermal-hydrologic-chemical processes, investigating the relationship between coal combustion, heat generation, heat flow, and water influx, and parametrically examine how the thermal and hydrologic properties of the host environment influence those relationships. To achieve this, the NUFT (Non-isothermal Unsaturated Flow and Transport) code has been customized to address the influence of coal combustion on the heating of the host coal and adjoining rock mass. Specifically, NUFT can now represent the relationship between coal combustion, heat generation, and coal consumption (i.e., the conversion of solid coal to the gaseous products). We find that a key property is the heterogeneous distribution of coal-cleat permeability. Other important parameters are coal-seam thickness and the contrast between cap/bedrock thermal-hydrologic properties and those of the coal. This paper describes the customization of the NUFT code and its application in the simulation of UCG processes. We present the simulation of several UCG cases, investigating key parametric dependencies influencing the relationship between coal combustion, heat generation, heat flow, and water influx. The influence of the coupling of mechanical processes (spallation and cavity collapse) with thermal-hydrologic-chemical processes is described in a companion paper (Morris et al. 2009), where the NUFT and LDEC (Livermore Distinct Element Code) codes are coupled to investigate the interaction between coal combustion, water influx, and mechanical response. This work performed under the auspices of the U.S. Department of Energy by Lawrence Livermore National Laboratory under Contract DE-AC52-07NA27344. 25-3

Numerical Modelling of Underground Coal Gasification Process for Estimation of Product Gas Composition

Chetan Ratnakar Chodankar, Bo Feng, A. Y. Klimenko, University of Queensland, AUSTRALIA

A steady state model is developed to estimate the gas production from Underground Coal Gasification (UCG) Process. This model features surface reactions of coal char with gasification medium to produce combustible gaseous product. This model predicts gas composition, temperature and gross calorific value of product gas across the gasification channel. Presented model is tested on different injection rates of gasification medium i.e. steam-oxygen, air and subsequently results were compared with field trial test data, conducted at Centralia, USA. The comparison indicates that present model gives reasonable predictions of the gas compositions at various air/steam injection ratios. 25-4

Surface Versus Underground Coal Methanation Jan Rogut, GIG - Central Mining Institute, POLAND; Marc Steen,

Institute for Energy, Joint Research Centre, European Commission, THE NETHERLANDS

Experimental research on UCG carried out in the frame of HUGE European project has shown that there exists a window of parameters under which the gas produced in situ contains substantial amounts of methane. This has triggered interesting engineering as well as economic questions on the conditions that could be required for massive production of substitute natural gas (SNG) underground. If proved feasible, the technology of direct methanation of unmineable deep coal deposits may play a key role for the energy security of Europe, as alternative clean gaseous fuel source that can be easily distributed through the extensive European natural gas pipeline networks. Moreover, the stable, long time availability of SNG from own coal resources can facilitate the development of a hydrogen economy in Europe as CH4 can easily be converted back to hydrogen using mature methane - steam reforming technologies. The presentation reviews the scientific and engineering backgrounds of various oxidative and reductive pathways of in situ coal methanation concepts, i.e. surface SNG installations. 25-5

Building a Midwest CCS Industry: Where Does UCG Fit? Mike Fowler, Clean Air Task Force, USA

Deployment of carbon capture and storage (CCS) technology at a scale sufficient to reduce climate change impacts of fossil fuel utilization will require far more than isolated demonstration projects: it will require development of a new, integrated, specialized, CCS industry. This industry may develop initially in regional-scale networks, of which the Midwestern United States could be an important early mover. Recent analyses indicate that underground coal gasification (UCG) could be a viable and potentially significant industry in the Midwest of its own accord, and that costs of CCS with UCG are likely to be significantly less than costs of CCS on other coal-based electricity generation technologies. This suggests that UCG with CCS could become an important element of a broader CCS industry in the Midwestern US. UCG projects present unique challenges and opportunities in the context of a developing regional CCS network, however, which are explored in this presentation from Clean Air Task Force.

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SESSION 26

GASIFICATION: FUNDAMENTALS – 3

26-1

Gasifier Model Development Using ANN Technique G. Viswanathan, C. Thirugnanam, S. Veeramani, BHEL, INDIA

In the recent past application of clean coal technology in power generation is being introduced. In order to reduce adverse impact of fossil fuel combustion on environment the Coal gasifier plays an important role while using the fuel as coal in the Integrated Gasification Combined Cycle (IGCC) plants. The gasification process is very complex in nature and involves chemical kinetics and reaction time estimates. Hence it is difficult and cumbersome to model it using fundamental approach. It is felt essential to predict the outputs more accurately, using Artificial Neural Network model, so as to save on frequent operation of the plant for different test runs. Hence a model was developed using Artificial Neural Network (ANN) technique from the experimental data collected from the 6.2 MW Integrated Gasification Combined Cycle Demonstration Project (CCDP) at Trichy. For a given input parameters, behaviour of output parameters were observed during controlled testing of the gasfier. Model results obtained through ANN (computed outputs) and the experimental observations are compared and found to be matching with minor deviations. It can be concluded that a virtual gasifier plant is available as ANN model, which can be used to predict the performance of the gasifier for various combination of inputs, within the trained data range. The Dynamic Link Library (DLL) and the Neuro solution weights obtained for the ANN model was used for the development of application software, which can run independently in any computer for predicting the out put parameters with in the trained range of data. 26-2

Numerical Investigation of Top Fuel Injection Design in a Coal Gasifier Ting Wang, Armin Silaen, University of New Orleans, USA; Heng-Wen Hsu,

Cheng-Hsien Shen, Industrial Technology Research Institute, TAIWAN Computational Fluid Dynamics (CFD) schemes are employed to simulate the effects of potential fuel injection techniques on gasification performance. The objective is to help design the top-loaded fuel injection arrangement for an entrained flow gasifier using coal water slurry as the input feedstock. The major task focuses on investigating the fuel injection scheme of fuel jets varying between 90o - 180o impinge against each other at the centerline of the gasifier. Two specific arrangements are investigated: (a) coaxial dual jets impingement with slurry coal in the center and oxygen in the outer jet and (b) four jets impingement with two single slurry coal jets and two single oxygen jets. When the heterogeneous finite-rate solid-gas reaction scheme is implemented, the particle tracks for both two concentric and four single jets show that the coal particles would hit the wall and could accelerate deterioration of the refractory bricks. The concentric injection case provides better fuel-oxidant mixing than the separate injection case and achieve better heating value. Since the particle collision model can't be implemented with the heterogeneous gasification scheme, the instantaneous gasification model is later employed including the particle collision model, in which the coal (consisting of carbon and volatiles) is injected as gas, and the water is injected as droplets. The result shows that the four-jet case achieves a higher heating value than the two-jet case. It further shows that the instantaneous gasification model gives higher H2 and lower CO in the exit gas with higher heating values and cold coal gasification efficiencies than calculated by the finite-rate solid-gas model. This is attributed to the faster water shift reaction in the instantaneous gasification model than the finite rate model, which is closer to reality. Although both models have their assumptions and limits, the sold-gas finite rate model is more closely mimic the actual process; its results are more trustful. 26-3

Gasification Kinetics: Modeling Tools Development and Validation Boris Eiteneer, Ramanathan Subramanian, Shawn Maghzi, GE Global

Research, USA; Cai Zeng, Xiaofen Guo, Yinhua Long, GE Global Research, GE China Technology Center, CHINA; Lei Chen, Massachusetts Institute of Technology, USA; Ravichandra JS, Ashwin Raman, Jayesh Jain, GE Global Research, GE John Welch Technology Centre, INDIA; Tom Fletcher, Randy

Shurtz, Brigham Young University, USA GE Global Research is conducting an international R&D program on gasification kinetics. The goal of the program is to develop and validate predictive models describing the chemical processes in the gasification and post-gasification zones of practical gasification systems. In this program, comprehensive kinetic modeling approach is adopted to describe the thermochemical processes taking place in the gasifier. Main steps during thermochemical conversion of the fuel in the gasifier include devolatilization, char oxidation, gasification, soot reactions (formation, growth and destruction), homogeneous gas-phase reactions, and interactions between ash,

char, and slag. A distinct detailed kinetic submodel is used to describe each of these steps. The initial individual submodels were selected and adopted from open literature based on detailed analysis. These submodels include: 1) Chemical Percolation Devolatilization (CPD) model for coal devolatilization; 2) Char Burnout Kinetics (CBK) model for char conversion; 3) detailed gas-phase kinetic (GPK) mechanism for gas and tar reactions; 4) method-of-moments model for soot growth and destruction. A detailed mechanism of gasification and combustion of benzene was selected to describe gas and tar formation/conversion processes. The benzene model was updated to include all reactions of gaseous products, including tar, and their conversion to soot precursors. The individual submodels are integrated in a detailed gasification kinetic model that is used as a kinetic tool for analysis and process optimization of gasification systems. The integrated model is developed under Chemical Workbench (CWB) kinetic environment by Kintech in Russia. The detailed kinetic models are reduced as appropriate using special mechanism reduction procedures and form a basis for a new computational fluid dynamics (CFD) model. The resulting CFD tool is used for improving current and future gasification system designs. Several levels of model validation against experimental data are employed in the current program. Each of the individual submodels is optimized and validated based on high-resolution experimental data, typically obtained in bench-scale research facilities under simplified and carefully controlled conditions. Reduced models are constructed, optimized, and validated against full model predictions and experimental data. Optimized reduced submodels are incorporated in the CFD modeling tool. The resulting CFD tool is further validated against bench, pilot, and commercial-scale measurements, including those available in the literature. The current program utilizes a suite of state-of-the-art experimental facilities available at GE Global Research. These facilities include bench-scale gasifier (BSG), high-pressure wire mesh reactor (WMR), high-pressure thermo gravimetric analyzer (TGA), and GE’s unique entrained flow reactor (EFR), capable of reaching high-temperature, high-pressure conditions of industrial gasifiers. The wire mesh reactor is uniquely suited to study fuel devolatilization kinetics. WMR provides highly accurate data on yields of char, tar, and gaseous products that are used as validation targets for CPD model. A novel method of water quantification at very low levels (below 1 mg) developed by GE Global Research enables accurate mass balance closure. The WMR is also used to study the reactivity of the char samples collected in other experimental facilities such as BSG and EFR. A new WMR reactor model was created in CWB environment to correctly decouple kinetic and mass transfer effects taking place during char oxidation and gasification in WMR. The experimental data from the bench scale gasifier are used to develop, test, and optimize the CFD tool. The atmospheric pressure entrained-flow BSG can achieve temperatures up to 1,400ºC and particle residence times up to 5 seconds. At the outlet of the gasifier, the product stream is rapidly quenched by an inert gas. The solid (char, soot, ash, aerosols), liquid (tar), and gaseous products are analyzed separately by on-line and off-line methods. A simplified flow structure of the BSG, approaching that of a plug-flow reactor, allows us to focus on validating the kinetic aspects of the CFD tool based on BSG measurements such as syngas composition, char conversion, char structure and morphology, etc. The more comprehensive validation of the CFD tool will be performed using experimental data from the larger scale EFR. The EFR is equipped with an array of sampling and optical access ports enabling high-fidelity interrogation of the processes taking place in the gasifier and syngas cooling sections. The kinetic data obtained under the current program at high temperatures (up to 1,300-1,500ºC), pressures (40-80 bar), and heating rates (104-105 ºC/sec) enable development and validation of predictive models that can serve as advanced design tools for development of future gasification systems and optimization of existing gasifiers. 26-4

Viscosity Measurements and Empirical Predictions for Coal Slags Josef Matyas, S. Kamakshi Sundaram, Carmen P. Rodriquez, Alejandro

Heredia-Lagner, B. M. Arrigoni, PNNL, USA Slag viscosity in slagging coal gasifier is an important factor affecting the gasification regime and operating cost. Most of the empirical viscosity models of coal slags that are available in the literature are applicable to only limited ranges of temperature and composition. To develop a reliable slag viscosity model, additional data are needed. Slag viscosity was measured under air or reducing atmosphere (calculated pO2~1.2×10-

12 atm at 1400°C) at temperatures in the range of 1150-1550°C on 63 statistically designed slags, including 5 actual coal slag compositions and 4 validation slag compositions. The Arrhenius equation, ln(η) = A+B(x)/T with Arrhenius coefficients A = constant and B expressed as linear function of mass fractions of nine major components was used to fit the viscosity/temperature data. This Arrhenius relationship represents the viscosity–temperature relationship of tested slags reasonably well, R2 = 0.981 (reducing atmosphere) and R2 = 0.974 (air atmosphere). The validation of the model with four randomly selected slags (two from the SciGlass database and two from experimental design) indicated an accurately measured viscosity-temperature data and a fairly good predictive performance of slag viscosity models over designed compositions. The capability of the developed model to predict the viscosity of coal slags under reducing atmosphere was found to be a superior to a number of the most commonly used empirical models in the literature that are based on simplified oxide melts and British or Australian coal ash slags.

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SESSION 27

CARBON MANAGEMENT: POST-COMBUSTION – 2

27-1

Results from the Carbonation-Calcination Reaction (CCR) Process Shwetha Ramkumar, Songgeng Li, William Wang, Siddharth Gumuluru, Zhenchao Sun, Nihar Phalak, Liang-Shih Fan, The Ohio State University;

Robert M. Statnick, ClearSkies Consulting, USA Electrical energy demand is projected to continue to increase, both nationally and internationally. As such, it is predicted coal will continue to play a significant role in electricity generation. Currently, coal is used to generate approximately half of the electricity in the United States; worldwide, coal is used to generate approximately 40% of the electricity demand. Coal combustion has emissions that possess either health or ecological concerns such as sulfur dioxide (SO2) and carbon dioxide (CO2). Currently, several SO2 control technologies are in use, while no control technologies have been installed for post-combustion CO2 capture from a coal-fired power plant. The Ohio State University has developed a post-combustion process that simultaneously removes CO2 and SO2 using a solid, regenerable, calcium-based sorbent. The Carbonation-Calcination Reaction (CCR) process utilizes calcium oxide in a high-temperature reaction with both CO2 and SO2, Reactions (1) and (2). In a kiln, the calcium carbonate formed from Reaction (1) decomposes to regenerate the calcium oxide sorbent while producing a pure, dry stream of CO2 for sequestration, Reaction (3). The thermal stability of calcium sulfate (CaSO4) prevents decomposition of CaSO4 into CaO and SO2 and dilution of the CO2 in the kiln. Due to the high-temperature ranges used and the exothermic reactions involved, the CCR process has a minimal impact on parasitic energy.

REACTION (1) CaO + CO2 → CaCO3 REACTION (2) CaO + SO2 + 0.5 O2 → CaSO4 REACTION (3) CaCO3 → CaO + CO2

Ohio State University has evaluated the CCR process at both the bench-scale using simulated flue gas and actual coal-combustion flue gas at the 20 pound per hour (pph) scale. At the 20 pph scale, several process variables were evaluated, including sorbent type, calcium:carbon mole ratio, reaction residence time, and cyclability of the spent sorbent. Ohio State University has also performed ASPEN simulations of the CCR process. The process parameters of the CCR process, as well as the integration layout, into both new and existing coal-fired power plants are crucial to minimizing the parasitic energy consumption. Under widely varying conditions, results indicate that parasitic energy consumption is competitive, if not superior, to leading post-combustion capture technologies, which are typically, between 25 and 35% including compression. 27-2

Cryogenic CO2 Capture as a Cost-Effective CO2 Capture Process Larry Baxter, Brigham Young University and Sustainable Energy

Technologies; Andrew Baxter, Sustainable Energy Technologies; Stephanie Burt, Brigham Young University, USA

The cryogenic CO2 capture (CCC) process appears to be 30% or more less costly and more efficiency than other major competing processes. The process cools CO2-laden flue gas to desublimation temperatures (-100 to -135 °C), separates solid CO2 that forms from the flue gas from the light gases, uses the cold products to cool incoming gases in a recuperative heat exchanger, compresses the solid/liquid CO2 to final pressures (100-200 atm), and delivers a compressed CO2 stream separated from an atmospheric pressure light-gas stream. The overall energy and economic costs appear to be at least 30% lower than most competing processes that involve air separation units (ASUs), solvents, or similar technologies. In addition, the CCC process enjoys several ancillary benefits, including (a) it is a minimally invasive bolt-on technology, (b) it provides highly efficient removal of most pollutants (Hg, SOx, NO2, HCl, etc.), (c) possible energy storage capacity, and (d) potential water savings. This paper outlines the process details and economic and energy comparisons relative to other well-documented alternatives.

27-3 Atomic-Level Modeling of CO2 Adsorption

and Transport in Nanoporous Materials Jinchen Liu, Rees B. Rankin, J. Karl Johnson,

University of Pittsburgh and DOE-NETL, USA There is a general consensus that new materials are needed to efficiently and cost effectively capture CO2 from fuel or flue gases. Experimental work is critical to progress in developing and testing new materials, but the number of possible candidate materials makes it impractical to use an Edisonian approach to materials discovery. Molecular modeling is a tool that can be used to help guide experiments and screen materials more cost effectively than experiments alone. We present results from both ab initio quantum mechanical calculations and from semi-empirical statistical mechanical models for evaluating the effectiveness of porous sorbent materials for CO2 capture. We have studied adsorption separation using nanoporous materials such as metal organic frameworks and zeolitic imidazolate frameworks. Both pure gas and mixed gas adsorption isotherms are measured. Pure gas adsorption isotherms are compared with experiments where possible. Experimental results for pure gas adsorption are common, but mixed gas adsorption isotherms are extremely difficult to measure. Our calculations therefore complement experimental data by probing conditions that are difficult to measure experimentally. We use equilibrium molecular dynamics to predict diffusion coefficients for pure and mixed gases in nanoporous materials. Measuring pure gas diffusivities is difficult experimentally and there are very few data with which to compare. To the best of our knowledge, there are no experimentally determined mixed gas diffusivities for metal organic frameworks or zeolitic imidazolate frameworks. Our mixture diffusivity calculations are therefore pure predictions. We examine the effects of changing linker groups on both adsorption and diffusion. We discuss the possibility of using molecular modeling to design new materials for CO2 capture. 27-4

Modeling Solid Sorbents for CO2 Capture Bo Zhang, Yuhua Duan, J. Karl Johnson,

University of Pittsburgh and DOE-NETL, USA Current technologies for capturing CO2

include solvent-based systems such as Selexol, Rectisol, and alkanolamine-based materials such as ethanolamine. It is generally accepted that operation or regeneration of these materials is too energy intensive. Hence, there is critical need for new materials that can capture and release CO2 reversibly with acceptable energy costs. Accordingly, solid sorbent materials have been proposed for capture of CO2 through a reversible chemical transformation. There are very many candidate materials for solid sorbents, most of which result in the formation of a carbonate product. We present calculations using first principles density functional theory for the structural, electronic, and thermodynamic properties of transition metal (e.g., Mn, Zn) oxides, hydroxides, and carbonate solids. We present a method for computing the thermodynamic reaction equilibrium properties of CO2 absorption/desorption based on a free energy analysis. We have found that the reaction thermodynamics can be adequately described using only density functional theory total energies of the solids and the statistical mechanical properties of the gases, without resorting to computation of the phonon density of states. We compare our calculations, both with and without phonon contributions, to experimental data where possible. We use density functional theory to examine the thermodynamics of potassium carbonate promoted aluminum oxide, which is considered to be a promising material for low-temperature capture of CO2. The key reaction involved in this process is believed to be 2KHCO3=K2CO3+CO2+H2O. But this material appears to lose capacity after several adsorption/desorption cycles. There is some experimental evidence that KAl(OH)2CO3 plays a kinetically prohibiting role in this process. In this paper, a new theoretical methodology is utilized to study the K2CO3 promoted alumina and also to expand this system to Na2CO3 promoted alumina. This method is based on the minimization of the Gibbs free energy at constant pressure of CO2 and H2O and at constant temperature. Based on only density functional theory energy of solid materials, we propose that KAl(OH)2CO3 is an intermediate phase between KHCO3 and K2CO3 at the low temperatures explored in the process. Our calculations are in good agreement with experimental results. An analogous reaction is predicted from our calculations for the Na2CO3 promoted alumina system, where NaAl(OH)2CO3 is also predicted to be the intermediate phase between NaHCO3 and Na2CO3. 27-5

Superstructure-Based Optimal Design of PSA Cycles for Post-Combustion CO2 Capture

Anshul Agarwal, Lorenz T. Biegler, Carnegie Mellon University; Stephen E. Zitney, DOE-NETL, USA

Recent developments have shown pressure/vacuum swing adsorption (PSA/VSA) to be a promising option to effectively capture CO2 from ue gas streams. In most commercial PSA cycles, the weakly adsorbed component in the mixture is the desired product, and enriching the strongly adsorbed CO2 is not a concern. Thus, it is necessary to develop PSA processes specifically targeted to obtain pure strongly adsorbed component. So far, no systematic methodology has been suggested in the literature to

24

design PSA cycles for high purity CO2 capture. This study addresses this need and presents a systematic optimization-based formulation to synthesize PSA cycles. In particular, a novel PSA superstructure is presented to design optimal PSA cycle configurations and evaluate CO2 capture strategies. The superstructure is rich enough to predict a number of different PSA operating steps. The bed connections in the superstructure are governed by timedependent control variables, which can be varied to realize most PSA operating steps. An optimal sequence of operating steps is achieved through the formulation of an optimal control problem with the partial differential and algebraic equations of the PSA system and the cyclic steady state condition. The superstructure approach is demonstrated for case studies related to post-combustion CO2 capture. In particular, optimal PSA cycles were synthesized which maximize CO2 recovery for a given purity, and minimize overall power consumption. The results show the potential of the superstructure to predict PSA cycles with up to 98% purity and recovery of CO2. Moreover, for recovery of around 85% and purity of over 90%, these cycles can recover CO2 from atmospheric ue gas with a low power consumption of 465 kWh/ton CO2. The approach presented is, therefore, very promising and quite useful for evaluating the suitability of dfferent adsorbents, feedstocks and operating strategies for PSA, and assessing its usefulness for CO2 capture.

SESSION 28

COMBUSTION: CHEMICAL LOOPING – 2

28-1

Copper Oxide as a Carrier for Chemical Looping: A Status Report Kevin Whitty, Edward M. Eyring, JoAnn S. Lighty, Adel F. Sarofim,

The University of Utah, USA Copper oxide was first proposed in 1954 by Lewis and Gilliland as an oxygen carrier in the first description of chemical looping as a means of producing CO2 from the combustion of solid fuels. The advantage of copper oxide for chemical looping was shown by the researchers at Chalmers University to be that, in a fuel reactor run at sufficiently high temperatures (~950°C), the copper oxide will decompose to yield oxygen. Oxygen reacts with coal in an overall exothermic reaction, a distinct advantage over the oxygen carriers for which the oxidation of the fuel is endothermic. The paper will review the developments on the use of copper oxide as an oxygen carrier and provide the results of ongoing research on the reaction kinetics and process formulation for this exciting oxygen carrier. 28-2

Effect of H2S on Chemical Looping Combustion of Coal-Derived Synthesis Gas over Bentonite Supported Metal Oxide Oxygen Carriers

Hanjing Tian, Tom Simonyi, Ranjani Siriwardane, Parsons/ U.S. Department of Energy, National Energy Technology Laboratory, USA

Chemical looping combustion (CLC) is a combustion technology that utilizes oxygen from oxygen carriers such as metal oxides instead of air to combust fuels. The significant advantage of a CLC system is that a concentrated CO2 stream can be obtained after water condensation without requiring any energy for separation of CO2. In addition, NOx production is also greatly reduced. Sulfur is the major impurity in coal synthesis gas. However, only limited studies have been reported in the literature on the effect of sulfur species on reaction performance of metal oxide oxygen carriers. Research work on the effect of H2S on the chemical looping combustion reaction of coal-derived synthesis gas with bentonite supported metal oxides, such as iron oxide, nickel oxide, manganese oxide and copper oxide investigated by thermogravimetric analysis, mass spectrometry and X-ray photoelectron spectroscopy will be presented in this paper. Four reaction steps were observed during the reduction reaction with synthesis gas in the presence of H2S followed by oxidation with air: reduction of metal oxide, sulfidation of reduced metal oxide, sulfur removal and re-oxidation of the metal. The reduction/oxidation capacities of iron oxide and nickel oxide were not affected by the presence of H2S but both manganese oxide and copper oxide showed decrease reduction/oxidation capacities. However, the rates of reduction and oxidation decreased in the presence of H2S for all four metal oxides. 28-3

Performance of Nanocomposite Oxygen Carriers in Chemical Looping Combustion using Sulfur-Laden Coal Gas

Rahul D. Solunke, Goetz Veser, University of Pittsburgh and DOE-NETL, USA

Chemical looping combustion (CLC) is an emerging technology for clean energy-production from fossil and renewable fuels. In CLC, an oxygen carrier (typically a metal) is first oxidized with air. The hot metal oxide is then reduced in contact with a fuel in a second reactor, thus combusting the fuel. Finally, the reduced metal is transferred back to the oxidizer, closing the materials “loop”. In this way, CLC produces sequestration-ready CO2-streams without expensive air separation and hence

without significant energy penalty. Combined with sequestration, CLC thus allows high-efficiency, CO2 emissions-free combustion of fossil fuels, or combustion processes with negative CO2-footprint from biomass-derived fuels. However, CLC suffers from insufficient stability of many metal-based carrier materials at the demanding process conditions of CLC. We previously demonstrated that the embedding of metal nanoparticles into a high-temperature stabilized ceramic matrix can yield highly active and sinter-resistant nanocomposite materials which combine the high reactivity of metals with the high-temperature stability of ceramics. Here, we report on the effect of sulfur contamination in the fuel stream on the performance of different oxygen carriers in CLC. Most of the published work on oxygen carriers to-date has focused on their performance in contaminant-free fuel streams. However, realistic fuel streams contain significant amounts of contaminants, in particular sulfur (mainly in the form of H2S). These contaminants can significant impact the performance of CLC via interaction with oxygen carrier material, affecting both redox kinetics as well as stability of the carriers. Furthermore, metal sulfides often have lower melting points than the corresponding metals or metal oxides, putting an additional constraint on the operating envelope of a CLC process. We studied the effect of H2S contamination on the performance of nanostructured Ni-, Cu-, and Fe-barium hexaaluminate (BHA) carriers in CLC over a range of operating temperatures. Thermodynamic calculations were combined with experimental investigations. We found that in addition to sulfidation of the metal component of the oxygen carrier, sulfidation of the support structure also needs to be considered. For our carriers, sulfidation of the metal component is reversible upon re-oxidation, but the sulfidation of the support is irreversible. The redox kinetics of the carriers are only mildly affected by the significant degree of sulfidation, and the thermal stability of these carriers appears unaffected. Interestingly, we found that the (partial) sulfidation of the support structure results in significant increase in oxygen carrying capacity per carrier weight due to the participation of the support through a sulfite-sulfate cycle. Increases of up to 60% in oxygen carrying capacity were obtained, suggesting that hybrid sulfite-metal oxygen carriers might be an interesting new class of high capacity oxygen carriers for CLC. Preparation and characterization of the carriers before and after exposure to sulfur contaminants, as well as their performance in CLC will be discussed in detail in the presentation. 28-4

Effect of H2S on Chemical Looping Combustion of Coal-Derived Synthesis Gas over NiO Supported on SiO2/ZrO2/TiO2/Sepiolite

Ewelina Ksepko, Marek Sciazko, Institute for Chemical Processing of Coal, POLAND; Ranjani V. Siriwardane, James A. Poston Jr,., DOE-NETL;

Hanjing Tian, Thomas Simonyi, Anthony Zinn, Parsons, USA The paper contains results of collaborative research work on novel combustion technology known as chemical looping combustion (CLC). The objective of paper was to prepare NiO supported on SiO2/ZrO2/TiO2/Sepiolite (IChPW, Poland) oxygen carriers and to evaluate the performance (NETL, US DOE) of these for the CLC process with synthesis gas/air. Thermo gravimetric analysis (TGA) and low pressure (10 psi) bench scale flow reactor tests were conducted to evaluate the performance. Multi cycle tests were conducted in an atmospheric TGA with oxygen carriers utilizing simulated synthesis gas with & without H2S. Effect of H2S impurities on both the stability and the oxygen transport capacity was evaluated. Multi cycle CLC tests were also conducted in the bench scale flow reactor at 800 °C with selected samples. Chemical phase composition was investigated by X-Ray diffraction (XRD) technique. Five Cycle TGA tests at 800 °C indicated that all oxygen carriers had a stable performance at 800 °C, except NiO/SiO2. It was interesting to note that there was that complete reduction/oxidation of the oxygen carrier during the 5-cycle test. The fractional reduction, fractional oxidation and global reaction rates of reactions were calculated from the data. It was found, that support had a significant effect on both fractional reduction/oxidation and the reaction rate. The oxidation reaction was significantly faster than the reduction reaction for all oxygen carriers. The reaction profile was changed by the presence of H2S but there was no effect on the reaction rate due to presence of H2S in syntheses gas. Low pressure bench scale flow reactor data indicated stable reactivity, full consumption of oxygen from oxygen carrier and complete combustion of H2 and CO. XRD data of samples after multi-cycle test showed stable crystalline phases without any formation of sulfides or sulfites/sulfates and complete regeneration of the oxygen carrier after multi-cycle tests. Work supported by the Polish Ministry of Education and Science, Grant № PBZ-MEiN-2/2/2006. Project entitled “Chemistry of perspective processes and coal conversion products”. Work was supported by U.S. Department of Energy, National Energy Technology Laboratories.

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28-5 Multiobjective Optimization Power Generation Systems Involving

Chemical Looping Combustion Juan M. Salazar, Urmila M. Diwekar, Vishwamitra Research Institute: Center for Uncertain Systems Tools for Optimization and Management; DOE-NETL;

Stephen E. Zitney, DOE-NETL, USA Chemical looping combustion has been suggested as a suitable alternative to facilitate the inclusion of CO2 capture technologies in various configurations of power systems. This technology provides inherent CO2 separation by avoiding direct contact of fuel with oxidizing air; instead, exothermic oxidation process takes place with the oxygen from a metal oxide. Recently, simulation studies evaluated the performance and economical aspects of combined cycles fired with natural gas and gasified coal (NGCC and IGCC). Researchers demonstrated that CO2 emissions can be significantly reduced with low cost on efficiency but high cost of energy production. This work presents the application of the CO-compliant stochastic modeling and multi-objective optimization framework for APECS for the analysis of an IGCC system with single-stage gasification and chemical looping combustion. Literature has identified three decision variables that can change the operational characteristics of the process. The decision variables include gasifier temperature controlled by water flow, gasifier pressure, and water gas shift reaction temperature controlled by the steam flow. Multiobjective optimization was carried out based on these three decision variables with three objectives: cold gas efficiency, net power production, and cost of electricity. This framework enables optimizing model complexities in the face of uncertainty and multiple and sometimes conflicting objectives of design. It also provides a decision support tool to address some of the key questions facing designers and planners of advanced process engineering systems.

SESSION 29

COAL SCIENCE: COAL GEOSCIENCE – 1: COAL FIRES

29-1

Overview of Underground Coal Fires Evan J. Granite, DOE-NETL; Ali Rangwala,

Worcester Polytechnic Institute, USA Underground coal fires represent a substantial nuisance in terms of property damage, public safety, greenhouse gas generation, and coal resource destruction. Some of the techniques employed to combat these fires will be illustrated. The magnitude of greenhouse gas generation and coal consumption will be estimated. Future research areas into this important issue such as improved fire fighting, detection, and prevention will be discussed. 29-2

The Tiptop Coal Mine Fire, Kentucky: Preliminary Investigation of the Measurement of Mercury, Carbon Dioxide,

and Carbon Monoxide from Coal-Fire Gas Vents James C. Hower, Kevin R. Henke, University of Kentucky Center for Applied Energy Research; Jennifer M.K. O’Keefe, Morehead State University; Mark A. Engle, U.S. Geological Survey; Glenn B. Stracher, East Georgia College;

Donald R. Blake, University of California-Irvine, USA The Tiptop underground mine fire in the Skyline coalbed of the Middle Pennsylvanian Breathitt Formation was investigated in rural northern Breathitt County, Kentucky, in May 2008 and January 2009, for the purpose of determining the concentrations of CO2, CO, and Hg in the vent and measuring gas-vent temperatures. Concentrations of CO2 peaked at 2.0% and >6.0% (v/v) and CO at 600 ppm and >700 ppm during field analysis in May 2008 and January 2009, respectively. For comparison, these concentrations exceed U.S. Occupational Safety & Health Administration (OSHA) safety exposure limits (0.5% CO2 and 50 ppm CO), although the site is not currently mined. Mercury, in excess of 500 (May) and 2,100 (January) µg/m3 in the field, also exceeded the OSHA eight-hour exposure limit (50 µg/m3). These gases are diluted as they exit and migrate away from a gas vent, but temperature inversions and other meteorological conditions could lead to unhealthy concentrations in small nearby towns. Variation in gas temperatures, up to nearly 300 °C during the January visit to the fire versus <50 °C in May, demonstrate the large temporal variability in fire intensity at the Tiptop mine. These preliminary results suggest that emissions from coal-fires may be important but additional data are required which address the significant variation in composition, flow, and temperature of vent gases. 29-3

Measuring CO2 Emissions from Coal Fires in the U.S. Allan Kolker, Mark Engle, Yomayra Román-Colón, Ricardo Olea, U.S.

Geological Survey; Glenn B. Stracher, East Georgia College; James Hower, University of Kentucky; Anupma Prakash, University of Alaska; Jennifer

O’Keefe, Morehead State University; Lawrence Radke, Airborne Research Consultants, LLC; Ed Heffern, Bureau of Land Management Wyoming

Office; Arnout ter Schure, Electric Power Research Institute, USA Uncontrolled coal fires pose multiple threats to the environment due to the emission of greenhouse gases, mercury, and other toxic or potentially toxic substances. The contribution of coal fires to global atmospheric greenhouse and toxic gas budgets is poorly known, but potentially significant. In an effort to quantify the magnitude of coal-fire emissions, a ground-based approach was developed to calculate fluxes of CO2 from several coal fires in the U.S. This approach combines vent measurements of CO2, CO, CH4, H2S and Hg emissions with a gridded series of CO2 soil flux point measurements. This combination was applied in May, 2009 at three active coal fires in the Powder River Basin, Wyoming: the Welch Ranch fire, the Hotchkiss fire, and the Ankney fire. At the Welch Ranch fire, measurements of 12 vents gave a total vent emission of 6.8 ± 2.4 Mg CO2 d-1. An additional 39 soil flux sampling sites were measured, and the results were interpolated using an inverse distance weighting algorithm. When summed, the interpolated results give a preliminary estimate of 1.0 Mg CO2 d-1 or the CO2 diffuse flux, bringing the total CO2 emitted from the Welch Ranch Fire to just under 8 Mg d-1. Similar calculations are underway for the Hotchkiss fire. For the Ankney Fire, access and safety concerns limited measurement coverage so that only partial fluxes were obtained. Ground-based measurements for the three Powder River Basin Coal Fires are being compared to airborne tropospheric CO2 emission estimates and thermal infrared images of the three fires that are contemporaneous with ground sampling. This combined sampling approach follows a reconnaissance investigation of a burning coal waste pile in the town of Mulga, in northern Alabama near Birmingham. Temperature measurement over the Mulga coal fire show localized hot spots in excess of 250 °C. Diffuse fluxes of CO2 vary by three orders of magnitude in four traverses across the burning coal pile. Within these traverses, CO2 flux shows a moderate, but statistically significant correlation with temperature (r2=0.56; p<0.01) that could potentially be used to estimate CO2 diffuse flux from portions of the fire outside of the traverses, but where soil temperature was determined. 29-4

Extinguishing the Percy Mine Fire Stanley R. Michalski, Phillip E. Glogowski, GAI Consultants, Inc., USA

Mining has occurred in the Uniontown Syncline (coal basin) in Fayette County, Pennsylvania, USA for over one hundred years. Fires periodically occur along the perimeter of the basin in the abandoned workings of the Pittsburgh Coal seam. The Percy Mine Fire is one such fire that occupies the workings of an abandoned coal mine underlying approximately 50 acres on the eastern flank of the Uniontown Syncline. The Pittsburgh Coal was extensively mined in the basin with interconnecting mine workings extending from Uniontown on the south to Connellsville on the north, a distance of 6 miles. Three mine pools, flooding most of the underground workings, are defined within this basin. The coal in the center of the basin can not burn in its current submerged condition. Along the perimeter or outcrop zone, the mine workings rise out of the mine pool and extend to the outcrop where they become susceptible to burning. This zone encompasses more than 74 miles of outcropping coal along the perimeter of the syncline. The Percy Mine Fire, lies within this perimeter and has plagued the surrounding communities of Youngstown and Percy for over 30 years. It has been a threat to the health, safety and welfare of those living near and over the fire and it has lowered the property value of those living in the vicinity of the fire. This paper reports on the history of past mitigation actions and details the methods and results of GAI Consultants, Inc.’s innovative and successful extinguishment plan, utilizing, Low Permeability Cementicious Material® (LPCTM), a coal combustion product, for the first time on an underground coal mine fire. The project was a joint effort headed by Pennsylvania's Bureau of Abandoned Mine Reclamation, GAI Consultants, Inc., Reliant Energy, and Howard Concrete Pumping, Inc.

SESSION 30

COAL-DERIVED PRODUCTS: SUBSTITUTE NATURAL GAS (SNG)

30-1

Production of Methane Rich Fuel Gas from Coal using Steam Hydrogasification

Arun SK Raju, Viresco Energy LLC; Chan S. Park, Joseph M. Norbeck, University of California, Riverside, USA

Natural gas accounts for approximately 20 % of the world energy consumption and is the third largest used fuel after oil and coal. The United States is the second largest producer of natural gas in the world, with an annual production of 546 billion cubic meters (bcm). In addition to the domestic production, the U.S. is also the largest importer of natural gas, at 130 bcm per year. Natural gas prices have steadily increased over the past decade. Synthetic natural gas produced from coal at competitive prices will be an attractive option since this can be accomplished using domestic feedstocks.

26

A new gasification technology has been developed that can generate methane rich product gas from coal and other carbonaceous feedstocks. This technology is based on steam hydrogasification, the conversion of carbonaceous feedstocks into a high energy content product gas using steam and hydrogen as gasifying agents. In this process, the slurry made of the carbonaceous feed (coal) and water, along with the recycled hydrogen are fed to the Steam Hydrogasification Reactor (SHR), operating at approximately 850 ºC and 400 psi. The SHR generates a high methane content product gas that is subjected to warm gas cleanup in order to remove contaminants such as sulfur. The clean product gas from the SHR is then fed into a shift reactor along with the unreacted steam. In the shift reactor, the CO present in the clean product gas reacts with the steam to produce H2. This product gas is then cooled down and H2 is separated for recycle to the SHR as feed. The recycle hydrogen stream eliminates the hydrogen supply problem. The final product gas contains high quantity of methane. Aspen Plus simulation tool has been used to perform material and energy balance calculations for the process using a sub-bituminous coal feedstock. The simulation results indicate that the methane content in the product gas can be varied by controlling the ratio of hydrogen to carbon and water to carbon in the feedstock. Experimental work on the steam hydrogasification of sub-bituminous coal in a batch reactor has also been performed. The carbon conversion values at 700 ºC were approximately around 60 % whereas at 800 ºC, the values were closer to 80 %. The product gas composition in the SHR has been evaluated using the Aspen Plus simulations and the results will be presented. 30-2

Co Production of Substitute Natural Gas and Electricity via Catalytic Coal Gasification

Brian S. Turk, Matthew L. Anderson, Luke J.I. Coleman, Andreas Weber, Raghubir P. Gupta, RTI International, USA

The convenience and clean-burning attributes associated with the use of natural gas has allowed it to become almost indispensible for industrial, commercial, and residential energy and heating needs. The lower carbon intensity of natural gas compared to coal and other hydrocarbon fuels also results in a more favorable carbon footprint. The challenge is that the domestic supply of natural gas is dwindling, which adversely affects its cost and availability. One approach for supplementing domestic resources of natural gas that is receiving considerable attention is the conversion of coal into a methane-rich gaseous product or substitute natural gas (SNG), which meets current natural gas pipeline specifications. The main advantage of this approach is that this SNG product can be added to the extensive network of existing natural gas pipelines increasing supply without any noticeable effect by the end user along with capturing CO2 at a point source for storage. The technical challenge is to develop processes for converting coal into SNG that are thermally efficient, environmentally attractive and economically competitive. With DOE/NETL funding, RTI has been exploring a novel process that converts low ranked coals, like sub-bituminous coal and lignite, into a SNG product meeting pipeline specifications. Several key features of this process are the novel two-stage gasification approach that targets increasing carbon conversion with enhanced selectivity for methane formation and use more effective warm syngas cleaning technologies that actually generate a pure CO2 by-product that is sequestration ready. In this two-stage coal conversion process, coal is initially preprocessed to convert the coal into a mixture of gas phase carbon species, H2 and solid char fines prior to a catalytic reactor, in which, the catalyst promotes the conversion of the gas phase carbon species and H2 into CH4. Because the ash is trapped in the solid char fines and the catalyst on a support, physical contact between the ash and catalyst is impossible eliminating the potential for reaction and deactivation of the catalyst. The product gas mixture from the catalytic reactor is cleaned using the hot gas desulfurization and CO2 capture technologies that have been developed at RTI. The product from the CO2 capture process is a high pressure sequestration ready CO2 byproduct. With a final polishing methanation and gas cleaning process, an SNG product meeting pipeline specifications is produced. During Phase I of this project, RTI has focused on bench-scale testing of the technical feasibility of the different pieces of this coal conversion process. This presentation will describe the results from this bench-scale testing program for evaluating the technical and economic feasibility of the proposed process. 30-3

Steam Hydrogasification of Lignite Coal Yuh Jiun Tan, Chan S. Park, Joseph M. Norbeck,

University of California, Riverside, USA The steam hydrogasification process developed by the University of California Riverside, Bourns College of Engineering-Center for Environmental Research and Technology (CE-CERT) offers potential advantages in processing diverse feedstocks with high moisture content such as lignite which is also known as brown coal. The utilization of wet feedstocks without drying is one of the unique features of the process. The moisture is used as the carrying medium to introduce the carbonaceous feedstock into the steam hydrogasification reactor (SHR) by means of a conventional slurry pump. It also enhances the product gas yield as well as the reactivity compared

to conventional hydrogasification. The product gas from the SHR is used as a feedstock in a steam methane reformer to produce synthesis gas (CO+H2). Steam hydrogasification of various lignite samples collected in the United States and China along with Illinois No. 6 sub-bituminous coal has been conducted in a stirred batch reactor. The Illinois No. 6 coal has been chosen as the baseline feedstock for comparison purposes. The steam hydrogasification reactivity of the lignite samples were studied in a Hydrogen environment at a H2O/Carbon mass ratio of 2. The carbon conversion values ranged from 60 % to 80 % at a temperature of 750 °C. The product gas composition was measured by using a Mass Spectrometer. 30-4

Coal Conversion in a Solid Oxide Fuel Cell Turgut M. Gür, Stanford University and Direct Carbon Technologies, LLC; Michael

Homel, Materials and Systems Research, Inc; Anil V. Virkar, University of Utah, USA This presentation describes direct utilization of coal, and other carbonaceous solid fuels in a modified solid oxide fuel cell (SOFC), where high power densities up to 450 mW/cm2 are achieved with a low-sulfur Alaska coal at 850oC. The fluidized bed direct carbon fuel cell (FB-DCFC) approach introduced here involves a Boudouard gasifier coupled to a SOFC element. An anode-supported tubular SOFC element with yttria stabilized zirconia (YSZ) electrolyte and La-Sr-Mn-O mixed ionically electronically conducting (MIEC) cathode is employed for this purpose. The solid fuel is converted to CO in the minimally fluidized bed dry gasifier, which is fed by the oxidation product CO2. The CO from the fuel bed is electrochemically oxidized at the Ni/YZS cermet anode of the SOFC to generate electricity. The product stream is a CO/CO2 mixture. An oxygen mass balance indicates that all oxygen transported across the YSZ electrolyte ends up in the product stream. This way, the nitrogen does not enter the process stream, so the flue stream potentially be made of pure CO2 ready for capture. The prospect of converting coal into electricity in an efficient manner with capture-ready CO2 as the primary product is an attractive proposition. Moreover, the FB-DCFC approach described here does not consume or use water for gasification, preserving a precious natural resource that is increasingly becoming scarce. Based on proven reserves, coal is by far the most abundant fossil energy resource. It is also the cheapest fossil fuel per unit of stored energy. The US holds about 27% of the world’s coal reserves, and generates nearly 50% of its electricity from coal. Rapidly developing countries like China and India hold vast reserves of coal also, and supply nearly ¾ of their electricity needs from coal fired plants that are added to their inventory at an astonishing rate of almost one power plant per week. Given these realities, it is highly likely that coal will continue to play a major role in our energy portfolio for decades to come. However, most coal-fired power plants in this country and around the world operate at conversion efficiencies in the range of 30-35%, and spew vast quantities of carbon into the atmosphere. The critical question is not how we replace coal, but how do we improve this process and minimize its environmental footprint. The obvious approach is to seek and innovate more efficient technologies that proportionately reduce CO2 emissions and enable CO2 capture less expensive. Certainly, the FB-DCFC approach introduced in this work offers significant gains towards these goals, and in laboratory scale prototype cells has already demonstrated great promise for possible practical development. 30-5

Direct Coal Liquefaction: The Reaction Pathway and the Politics Burtron H. Davis, Robert A. Keogh, Center for Applied Energy Research,

University of Kentucky, USA The interest in direct coal liquefaction has varied from frenzied activity to periods of benign neglect. Discovered and developed in Germany, direct liquefaction produced about 90% of the synthetic fuels utilized in Germany leading up to and during WW II. The German processes utilized high temperature and very high pressures to get the liquid product. The discoveries of vast petroleum reserves in the 1950s led to a loss of interest in coal liquefaction. However, with the rapid price increase and the shortage of petroleum crude in the 1970s there was renewed interest in direct coal liquefaction. In the U.S., at least four processes advanced to the stage of being verified in reasonably large pilot plants. The results generated at these plants will be considered in the light of the reaction mechanism considered below. The direct coal liquefaction pathway has been defined using as lumped products preasphaltenes, asphaltenes and oils plus gases. With these definitions, the thermal and catalytic pathways coincide, suggesting that the initial steps of the conversion are thermal. The catalyst appears to convert some bonds by hydrogenation to a structure that is more susceptible to thermal cracking, allowing for molecular weight reductions. The data for the large pilot plants appear to fit the reaction pathway defined by the conversions in small laboratory reactors. The interest of politicians has followed the perception of petroleum shortages and/or the rapid increase or decrease in the price of crude. To date it has not been possible to make realistic estimates of the shortage or glut of petroleum crude nor the rapid increase or decrease of the price of crude.

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SESSION 31

GASIFICATION: SYNTHESIS GAS CLEANING – 1

31-1

Warm Syngas Cleanup for Chemical Applications using Regenerable CO2 Sorbents

Brian S. Turk, Jason P. Trembly, Jian-Ping Shen, Maruthi Pavani, Pradeepkumar Sharma, Raghubir P. Gupta, RTI International, USA

Exploitation of the large coal reserves available in the U.S. faces strong opposition in carbon constrained world. However, the fact that over 50% of the electricity consumed in the U.S. is generated from coal makes reducing coal use very difficult over a short period of time. Retrofitting existing coal-based power generation plants with CO2 capture technology is technically challenging and expensive, because none of the typical chemical drivers for separation— pressure, temperature or concentration— are available in the post-combustion flue gas stream. Coal gasification produces a syngas from which the carbon dioxide can be extracted before combustion for power or processing to make chemicals. By contrast with the post-combustion flue gas, the syngas produced by gasification is available at high pressures and temperatures and has a high concentration of CO2 results in significantly lower CO2 separation costs. RTI International (RTI) with funding from DOE/NETL has been developing regenerable solid sorbents for CO2 capture from high temperature syngas. One of the objectives of developing a high temperature CO2 capture process is complete the warm syngas cleanup technology platform that RTI has developed which already includes sulfur, ammonia, mercury, arsenic, selenium and chlorine removal. With the complete syngas package, gasification can be used to produce a syngas product that is suitable for power applications both with and without CO2 capture and chemical production without thermal efficiency loss associated with conventional syngas cleaning technologies. However, RTI is also looking at improving the efficiency of the CO2 capture and sequestration process, by generating a pressurized CO2 product. By generating a pressurized CO2 byproduct, the CO2 capture process will significantly reduce the parasitic power for compression and enhance overall energy efficiency. This paper will present sorbent development and testing results for regenerable CO2 sorbents for RTI’s warm syngas cleanup technology portfolio. 31-2

A Compact, Regenerable, Hot Syngas Desulfurizer for Coal-Based Advanced Energy Systems

Rachid B. Slimane, Chun W. Choi, Gas Technology Institute (GTI); Maria Flytzani-Stephanopoulos, Ioannis Valsamakis, Tufts University, USA

Advanced energy systems require new, more demanding syngas processing schemes. Solid oxide fuel cells (SOFCs) in particular place stringent requirement on the selection of a suitable high temperature sorbent since they operate at 650 to 800ºC and require that fuel gases be cleaned to < 1 ppmv total sulfur. GTI, with a long history of sorbent development and state-of-the-art platforms for advancing emerging energy systems, has teamed up with Tufts University to develop a compact, regenerable hot syngas desulfurizer for coal-based advanced energy systems. The desulfurizer is based on the use of fully regenerable sulfur sorbents (single or mixed oxysulfides of the lanthanide group of elements), which are capable of removing any amount of H2S in the fuel gas to sub-ppm levels at temperatures as high as 800°C [M. Flytzani-Stephanopoulos, M. Sakbodin, Z. Wang, Science 312, 1508-1510 (2006)]. The unique characteristic of this class of sorbents is their capability to maintain long-term usefulness by relying on reversible adsorption, rather than bulk sulfur removal by chemical reaction, as the mechanism for desulfurization as well as regeneration of the sulfided sorbent surface for re-use. GTI’s current main focus is on advancing these promising sorbents towards practical implementation as honeycomb monoliths that can be integrated into solid oxide fuel cells for regenerative desulfurization of fuel gas derived from the gasification of Illinois coal. GTI will work closely with Tufts and a commercial sorbent/catalyst vendor (such as Haldor-Topsøe A/S or Süd-Chemie) to manufacture the leading sulfur sorbents in the form of honeycomb monoliths (inert support matrix such as cordierite with the sorbent material coated as a thin layer on the channel walls). The procured materials will be characterized and their desulfurization performance and regenerability demonstrated with a gas mixture simulating an Illinois coal-derived fuel gas. A state-of-the-art Pressurized Fixed-Bed Reactor (PFBR) facility is available for this project. Parametric tests will be performed to evaluate the effects of several key process variables, including temperature (650 to 800°C), space velocity (up to 1,000,000 h-1), H2S content (up to 10,000 ppmv), COS co-adsorption (up to 750 ppmv), reactor pressure (up to 20 bar), and regeneration gas. In parallel, support studies and tests in thermogravimetric analyzers and micro-reactors will be conducted at Tufts that will contribute to the fundamental understanding and further development of these materials. Test results will be used to prepare a preliminary design package for a bench-scale reactor system capable of processing up to 1,500 standard cubic feet per hour (SCFH) of coal-derived fuel gas on a continuous basis. Following successful completion of this phase, GTI intends to demonstrate the compact desulfurizer system with real Illinois coal-derived fuel gas (e.g., slipstream

testing at GTI’s Flex-Fuel Test Facility, a 10 ton per day coal gasification pilot plant). GTI will also continue to collaborate with Tufts and the commercial sorbent manufacturer to fully understand the fundamentals, improve the sorbent surface area, and address/evaluate integration issues of this promising desulfurizer in advanced energy systems such as SOFC applications. Ongoing research efforts will be described in this paper, with a focus on test results and their implications for future directions. 31-3

Multicontaminant Warm Gas Cleanup Girish Srinivas, Steven Gebhard, Will Spalding, TDA Research Inc.; Jason

Vidaurri, Carbon Fiber Technology, LLC, USA The U.S. consumes about one billions tons of coal per year for generating electricity. The main technologies currently being used or developed to generate electricity from coal are traditional combustion and integrated gasification combined-cycle (IGCC). IGCC has the potential to increase the energy efficiency of coal based power plants from approximately 30% to as much as 50%. Raw syngas from the coal gasifier contains carbon monoxide, hydrogen, carbon dioxide, steam, methane, particulates, hydrogen sulfide and small amounts of mercury vapor, and therefore is unsuitable for direct use. In particular, hydrogen sulfide and mercury must be removed from the syngas to minimize sulfur dioxide and Hg emissions from the plant. Current hot gas cleanup technologies that remove H2S by absorption at high temperatures cannot remove Hg. Cold gas cleanup processes such as amine-Claus- SCOT, Rectisol and Selexol work well, but require cooling the syngas, which decreases the energy efficiency of the plant. Warm gas cleanup can remove H2S and Hg at temperatures that are between hot gas and cold gas temperatures, thus avoiding most of their disadvantages. TDA Research Inc (TDA) is developing a warm gas cleanup process where H2S is oxidized with small amounts of air to elemental sulfur and water without hydrogen oxidation. Simultaneously, vapor phase elemental Hg reacts with liquid sulfur in the sulfur condenser to form stable HgS. In Phase II of our DOE SBIR project, TDA has developed a catalyst that will oxidize H2S to sulfur in the presence of hydrogen at temperatures of 230-428°F with no H2 oxidation. To date, we have performed high and low temperature sulfur tolerant water gas shift catalyst tests to determine how to best reduce the CO concentration in the syngas (CO reacts with sulfur vapor to form COS even without a catalyst), as well as performed H2S oxidation catalysts tests at 200 psig and 220°C with 2500 ppm of H2S in the feed. Under these conditions, essentially no SO2 was formed and the H2S conversion was greater than 90%. We have also solved the problem of having both hydrogen and H2S react with the stainless steel walls of the catalyst test apparatus. When both H2 and H2S are present, a quasi-equilibrium is established between Fe, FeS, H2S and H2 on the surfaces of the stainless steel fittings and tubing, which introduces errors in quantifying the concentration of H2S in the gas (and hence introduces errors in accurately measuring conversion and selectivity). The problem is more that of inertness than corrosion. Seeking an inert material that could be used at elevated pressures, we conducted several tests with Hastelloy coupons and found that these alloys are essentially inert under our warm gas catalyst test conditions. We are currently replacing the heated components of the test apparatus with Hastelloy parts to obtain more accurate results. 31-4

Warm Temperature Sorbents for Synthesis Gas Clean-Up Gokhan Alptekin, Ambalavanan Jayaraman, Bob Amalfitano,

TDA Research, Inc., USA Gasification technologies convert coal and other heavy feedstocks into synthesis gas feed streams that can either be used as a fuel for highly efficient power generation cycles or converted into value-added chemicals and transportation fuels. However, coal-derived synthesis gas contains a myriad of contaminants (e.g. sulfur, halides, nitrogen, mercury and arsenic) that may be regulated in power plant emissions and act as poisons for the catalysts used in downstream chemical manufacturing processes. Since these heteroatom and trace metal contaminants can easily poison the Water Gas Shift (WGS) and Fischer-Tropsch (F-T) catalysts, inhibit their activity and change their product selectivity. Due to the complex nature of the coal-derived synthesis gas and the molecular permutations by which these contaminants are present in the gas, it is difficult to formulate catalysts that are resistant to all of these contaminants without significant loss of activity. Therefore, the synthesis gas feed must be treated before it enters the FT and WGS systems to insure that the impurity levels in the incident gas are acceptable. The contaminant control technology must work at elevated temperatures, near or above the operating temperature of the FT and WGS systems (180-300oC range), since the high temperature operation eliminates the need for the expensive heat exchangers (to cool the synthesis gas to the operating temperature of the clean-up system and then to re-heat it back to the operating temperature of the WGS and FT processes) and the gray water treatment problems associated with the large amounts of process condensate. TDA Research, Inc. (TDA) has developed a low-cost, high capacity, sorbent that can remove trace contaminants including sulfur, halides, arsenic and mercury from coal-derived synthesis gas. The sorbent will reduce the concentration of all these contaminants to ppbv levels, providing optimum protection for the Fischer-Tropsch

28

synthesis catalysts used to convert coal derived synthesis gas into liquid fuels. Unlike the commercially available trace metal adsorbents or sulfur polishing sorbents, our sorbent operates at elevated temperatures (500oF). We carried out trace contaminant cleanup of simulated coal-derived syngas with our warm gas cleanup sorbent and our sorbent was able to achieve very high capacity for most of the trace contaminants. The performance results of our warm gas trace contaminant removal sorbent will be presented in the meeting. 31-5

Perovskite Sorbents for Warm-Gas Removal of Sulfur Michael V. Mundschau, David A. Gribble, Sara Rolfe,

Eltron Research & Development Inc., USA Perovskite-based solid sorbents are being developed for use in polishing filters with the goal of reducing concentrations of sulfur in coal-derived IGCC gas streams from low parts per million by volume (ppmv) levels to low parts per billion by volume (ppbv) levels in steam. Sorbents are being designed for use downstream of water-gas shift reactors and upstream of palladium-based hydrogen transport membranes. Membranes for hydrogen separation are envisioned as one means for the ultimate purification of hydrogen while retaining CO2 at coal gasifier pressures for economic sequestration of CO2. However, palladium-based membranes cannot tolerate the full gamut of impurities issuing from coal gasifiers, and concentration of impurities, especially sulfur, need to be reduced to low ppmv levels and preferably ppbv levels to allow long-term operation of membranes. Removal of sulfur from coalderived gas streams to well below ppmv levels also is desired for long-term operation of hydrogen-fueled turbines, for nickel catalysts used in solid-oxide fuel cells (SOFCs) and nickel catalysts used to synthesize substitute natural gas, for cobalt and iron catalysts used in Fischer-Tropsch synthesis, and for operation of platinum catalysts used in proton exchange membrane (PEM) fuel cells. For existing commercial sorbents such as those based upon Cu/ZnO, the lowest achievable concentrations of sulfur under steam are limited by the equilibrium reaction: ZnS + H2O = ZnO + H2S. The equilibrium concentration of H2S released from ZnS is linearly dependent upon the partial pressure of steam and can easily rise to well above 1 ppmv under steam at 200 psi (1.4 MPa). Although ppbv concentrations of sulfur are reached in dry gas streams for Cu/ZnO, condensation of steam is inefficient and uneconomical for many applications of steam-laden coal-derived gas. In addition, zinc-based sorbents release COS under water-gas shift conditions. Similar equilibrium limitations apply to iron-based sulfur sorbents that less tightly bind sulfur relative to zinc. To overcome equilibrium limitations of existing commercial sulfur sorbents in steam, new materials are being designed that incorporate cerium and lanthanum, which chemically bind sulfur much more tightly than zinc and iron or any other elements. However, under desired warm-gas cleaning conditions just above 300°C, simple binary oxides of cerium and lanthanum, such as CeO2, Ce2O3 and La2O3 are too stable to release sufficient oxygen necessary for formation of the required binding sites for sulfur. To allow sufficient release of oxygen at warm-gas clean-up temperatures, cerium and lanthanum are incorporated into oxides with the perovskite crystal structure that are thermodynamically less stable relative to the simple binary oxides. The perovskite-based sorbents are designed to incorporate oxygen-anion vacancies that allow high mobility of surface and lattice oxygen. This aids removal of a fraction of the surface and near-surface lattice oxygen at temperatures just above 300°C to create binding sites for sulfur. Preliminary results show that the kinetics of uptake of H2S of the catalyzed perovskite-based sorbents under laboratory conditions are comparable to that of Cu/ZnO. Mass gain of sulfur in the perovskites indicates formation of bulk sulfides in addition to adsorption of sulfur at surface sites.

SESSION 32

GASIFICATION: FUNDAMENTALS – 4

32-1

The Use of 2,6-Dimethylnaphthalene and 6-(5H)-Phenanthridinone as Surrogates for Studying Soot Formation from Coal Tar

Randy Shurtz, Thomas H. Fletcher, Brigham Young University; Ronald J. Pugmire, Mark S. Solum, University of Utah, USA

Soot produced from coal during gasification plays a significant role in radiative heat transfer inside a gasifier, changing the predicted flame temperature by hundreds of degrees. The radiation from the soot can also increase the wear on the coal injector. Coal tar and soot act as carriers for fuel nitrogen. Additionally, soot may be more difficult to gasify than char and may contribute significantly to the unburned carbon leaving the gasifier. Models have been developed for soot production in light hydrocarbon combustion systems, but soot produced from coal tar is formed by polymerization mechanisms in addition to the commonly-assumed acetylene addition mechanism. The use of many coal tar surrogates in secondary pyrolysis experiments permits the development of more rigorous soot models so that the location, concentration, and composition of the soot can be accurately predicted. In this study 2,6- dimethylnaphthalene and 6-(5H)-phenanthridinone were chosen as surrogates for

coal tar to study the development of the chemical structure of soot during secondary pyrolysis. The model compounds were ground and sieved to 45-75 microns and then injected into a flat-flame burner. The burner settings were adjusted to provide fuel-rich post-flame environments with peak temperatures in the range of 1300-1500 K and heating rates of ~105 K/s. The structures of the compounds formed were determined using 13C-NMR and mass spectrometry. The chemical structures of soot from the model compounds were compared with findings from previous coal-tar surrogates such as biphenyl and pyrene. Soots produced from a Wyodak subbituminous coal and an eastern bituminous coal were also analyzed for comparison. 32-2

The Study on the Charateristics of Coal Fouling Propensity by using Two-Story Deposit Plate under Gasification Condition

Hyung-Taek Kim, Hueon Namkung, Gahee Lee, Ajou University, KOREA Ash ingredient of coal are occasionally deposited into heat transfer area and caused the major downtime during the operation of IGCC power plant. To evaluate the propensity of ash fouling, experimental study was conducted. The main purpose of present investigation is to determine the ash deposition under coal gasification condition by using drop tube furnace (DTF), in which behavior of coal particle in actual gasification condition can be investigated experimentally. Six pulverized coal samples which are in the range of bituminous and sub-bituminous are injected into DTF under gasification condition. The ash particles are deposited onto sample collector by impacting and agglomerating action. Deposit ash samples are collected, weighed, and analyzed to determine the amount and composition of the deposit. Collected samples are further analyzed with X-ray fluorescence (XRF) and found that mineral compositions between two-story probes are different such as top layer has more minerals of Si, Al, Ti. From the results of scanning electron microscopy (SEM) and X-ray diffractometer (XRD), it is also found that grain size of fouling deposit at high temperature is bigger than that at low temperature. It is also found that Mg, Ca and Fe components are generally considered as dominant components governing the ash deposition behavior among alkali and alkaline earth minerals. 32-4

Pyrolysis and Gasification of a Sub-Bituminous Coal at High Heating Rates

Randy Shurtz, Thomas H. Fletcher, Brigham Young University, USA A flat-flame burner system has been developed to pyrolyze and gasify coal at ~105 K/s, temperatures of 1200-1800 K, and total pressures of 2.5-15 atm. The burner is fueled by methane, hydrogen, and air. The flame stoichiometry was adjusted to provide a fuelrich environment for gasification. This system was used to pyrolyze and gasify a sub-bituminous Wyodak coal, ground and sieved to 45-75 microns. The mass distribution of the products between char, light gases, and soot was determined. The physical structure was observed by SEM and the N2 and CO2 internal surface areas were measured. Intrinsic CO2-gasification reactivities were measured at the char formation pressures in a high pressure thermogravimetric analyzer (HPTGA). 32-5

Plant-Wide Dynamic Simulation of an IGCC Plant with CO2 Capture Debangsu Bhattacharyya, Richard Turton, West Virginia University;

Stephen E. Zitney, DOE-NETL, USA To eliminate the harmful effects of greenhouse gases, especially that of CO2, future coalfired power plants need to consider the option for CO2 capture. The loss in efficiency for CO2 capture is less in an Integrated Gasification Combined Cycle (IGCC) plant compared to other conventional coal combustion processes. However, no IGCC plant with CO2 capture currently exists in the world. Therefore, it is important to consider the operability and controllability issues of such a plant before it is commercially built. With this objective in mind, a detailed plant-wide dynamic simulation of an IGCC plant with CO2 capture has been developed. The plant considers a General Electric Energy (GEE)-type downflow radiant-only gasifier followed by a quench section. A two-stage water gas shift (WGS) reaction is considered for conversion of about 96 mol% of CO to CO2. A two-stage acid gas removal (AGR) process based on a physical solvent is simulated for selective capture of H2S and CO2. The clean syngas is sent to a gas turbine (GT) followed by a heat recovery steam generator (HRSG). The steady state results are validated with data from a commercial gasifier. A 5 % ramp increase in the flowrate of coal is introduced to study the system dynamics. To control the conversion of CO at a desired level in the WGS reactors, the steam/CO ratio is manipulated. This strategy is found to be efficient for this operating condition. In the absence of an efficient control strategy in the AGR process, the environmental emissions exceeded the limits by a great extent.

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SESSION 33

CARBON MANAGEMENT: SEQUESTRATION – 1

33-1

Carbon Capture and Storage in Central Appalachia – What Would it Look Like?

Steven M. Carpenter, Marshall Miller & Associates, Inc., USA In an ever increasing “carbon” society; our awareness, management and growth will be measured by our carbon footprint (or output). As power producers fight the battle between demand vs. carbon reduction, one of the essential tools will be capture and storage (e.g. sequestration) of carbon. From business and engineering managers to legislators and end users; understanding Green House Gas (GHG) emissions and strategies will afford open dialogue and better understanding of the implications of carbon management. In the USA, seven US Department of Energy funded regional partnerships and numerous other entities are pursuing technical, full-scale and marketable applications for carbon capture and storage (CCS). These groups have revealed application successes and constructability realities that must be addressed in order for this technology to become marketable and more importantly, used by industry. An overview of the application and implementation of CCS in Central Appalachia will be evaluated and discussed focusing on the legal, regulatory and liability issues that exist. 33-2

Fundamentals of Gas Adsorption in Coalbeds Yangyang Liu, Shela Aboud, Anthony R. Kovscek,

Jennifer Wilcox, Stanford University, USA To mitigate CO2 emissions into atmosphere, as well as to enhance coalbed methane recovery, injecting CO2 into unmineable coalbeds becomes an attractive option for CO2 sequestration. One advantage of storing CO2 in coalbeds is that they are often close in proximity to electricity generation sources. Another advantage is that CO2 injection into coalbeds enhances methane (CH4) recovery from the coalbeds. Coalbed methane represent more than 10% of technically recoverable natural gas in the U.S. Methane strongly adsorbs to coal surfaces but is displaced when CO2 is injected. A major obstacle in CO2 sequestration by coal is insufficient understanding of the molecular-scale processes involving CO2 adsorption on organic matter at pressures and temperatures of interest. The preliminary investigations of fundamentals of gas adsorption onto coal involve the characterization of coal samples by experimental methods and density functional theory (DFT). First, multiple coal samples of different ranks have been characterized by scanning electron microscope (SEM), Fourier transform infrared spectroscopy (FTIR), and X-ray photoelectron spectroscopy (XPS). Preliminary results have been obtained using SEM to gain information regarding the coal structure and the porosity characteristics of bituminous and anthracite coal. Additionally, surface properties and oxygen-containing functional groups have been determined by SEM semi-quantitative elemental analysis and FTIR vibrational spectroscopy analysis. The experimental characterization results aid in creating a set of realistic pore models by taking both structural and chemical heterogeneity into account, while the DFT results will be used to calculate the short- range interactions for a particle-based approach to study of computational simulations of adsorption phenomena. DFT calculations have been performed to investigate the adsorption of CO2 onto simulated coal surfaces. Pore surfaces in coal are modeled by a single perfect graphene layer and defective graphene surface with 3 unique vacancy sites. All of the defective surfaces were proved to exist by others’ experiments. The interactions with different surfaces have been compared, and the preliminary theoretical investigations show that the interaction with a defective graphene surfaces yields stronger CO2-surface interactions compared to those of perfect graphene surface with CO2. 33-3

Direct Observation of CO2 Injection into Coal using Small Angle X-Ray Scattering (SAXS)

A. H. Clemens, CRL Energy Ltd, NEW ZEALAND; Soenke Seifert, Darren R. Locke, Randall E. Winans, Argonne National Laboratory; Joseph M. Calo,

Euan Bain, Brown University, USA Preliminary experiments on a suite of North American and New Zealand coals established that SAXS could be used to observe directly the changes in coal structure brought about by injection of CO2 at pressure. Subsequent experiments have shown that, at least for higher rank coals, the injection process can be interpreted in terms of a simplified two-phase model beginning with shorter term void/pore filling and gas adsorption onto the solid matrix followed by longer term coal swelling. These processes are consistent with an overall decrease in scattering intensity with increasing degree of coal swelling due to the disappearance of the smallest scatterers (voids/pores) accompanied by a shift of the normalized void/pore distribution to larger scatterers.

Consideration of the Porod Invariant – a measure of the variation of the volume fraction of the voids and solid coal matrix with degree of swelling – shows an initial rapid rise followed by a continuous decrease. The rapid increase is consistent with the rapid void/pore filling phase; the decrease is consistent with swelling of the solid matrix primarily via a Class II type diffusion process typically associated with a glassy polymer or gel structure. For lower rank samples the process predominantly involves adsorption onto the surfaces and no swelling or diffusion. 33-4

Results from the Central Appalachian Basin Field Verification Test in Coal Seams

Nino Ripepi, Michael Karmis, Ilija Miskovic, Virginia Tech; Christopher Shea, J. Matthew Conrad, Marshall Miller & Associates, Inc., USA

The Central Appalachian Coal Seam Group of the Southeast Regional Carbon Sequestration Partnership (SECARB) has completed the injection of 1,000 tons of carbon dioxide as part of a field validation test at their Russell County, VA site. Initial results of the test that began in January 2008 are promising with higher than anticipated injection rates. The research team, comprised of the Virginia Center for Coal and Energy Research (VCCER) at Virginia Tech and Marshall Miller & Associates, Inc. (MM&A), has concluded that coal seams in the area and over the expanded Central Appalachian region have significant carbon sequestration and enhanced coalbed methane recovery potential, particularly in Buchanan, Dickenson and Wise Counties, Virginia and Fayette, McDowell, Raleigh and Wyoming Counties, West Virginia. A mature coalbed methane well in Russell County, donated by CNX Gas Corporation, was converted to an injection well and used for the test with two off-set wells drilled and instrumented for monitoring purposes. This test injected a total of 1,000 tons of carbon dioxide into multiple coal seams in tests of two geologic formations, the shallower Lee Formation and the deeper Pocahontas Formation. This presentation will describe the results from the injection test and highlight monitoring activities at the site, which include: soil flux monitoring, tracer monitoring, soil gas composition, surface and subsurface water analysis, and monitor well pressure and gas composition. 33-5

Evaluation of CO2 Storage Capacity in Unexploited Coal Deposits: Application to an Unexploited Area of Provence Coal Basin in France

Zbigniew Pokryszka, Stéphane Lafortune, Candice Lagny, Christophe Didier, Delphine Charriere, French National Institute for Industrial Environment and

Risks (INERIS); Didier Bonijoly, BRGM, FRANCE Carbon dioxide storage in unexploited coal deposits constitutes one of geological storage options. Because coal is an heterogeneous and microporous sedimentary rock with a great specific surface (usually from 100 to 400 m2/g), coal seams are seen as possible underground reservoirs to store anthropogenic carbon dioxide. In nature, coal seams contain originally gases such as methane or carbon dioxide. Gas compounds can be held in seams as (1) an adsorbed phase on the surface of the coal, (2) an absorbed phase within the mineralogical structure of the coal, (3) a free gas phase in the fractures or the pores and (4) a dissolved phase in the formation water. Injected in coal seams, anthropogenic carbon dioxide could then be stored in each of these four phases. Due to the high values of the specific surface of coal, trapping as an adsorbed phase appears to be the most important way of carbon dioxide storage in coal seams. Thus the Carbon Sequestration Leadership Forum (CSFL) has proposed a specific formula to evaluate the carbon dioxide storage capacity of coal seams without considering the capacity related to the absorbed, free and dissolved phases. In this study, INERIS will propose improvements of this formula. This paper will focus on the evaluation of the theoretical carbon dioxide storage capacity of an unexploited area in the Provence coal basin (South of France). As a first step, this evaluation has only been performed by considering under critical conditions (no supercritical fluids). The methodology which was used in this study takes into account gas held in the adsorbed phase and the free phase in the pores of the coal. Indeed, in some conditions of porosity and gas pressure, the free gas phase could represent up to 10% of the gas volume held in coal seams. The mineral fraction of the coal (ash) is considered to be inert to carbon dioxide. The adsorption capacity is determined from Langmuir theory on the basis of experimental isotherms. The evaluation takes also into account several other characteristics of the coal deposits such as: temperature, humidity, ash content, initial gas content and composition, etc. Similarly, several configurations are possible, depending on whether the coal bed originally contains gas or not (most often CH4 and/or CO2), and whether this gas is recovered prior to storage or not (as it could the case for methane for example). The first application done for an unexploited area of coal deposit of about 100 km2 made it possible to estimate the theoretical capacity of carbon dioxide storage, only in the two principal coal seams located between 500 and 1500 meters of depth. This capacity was evaluated at more than 60 Mt of CO2 (for under critical conditions). This value is compatible with the quantity of carbon dioxide which could be produced during about twenty years by the Gardanne coal-fired power plant, located near the studied storage area.

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33-6

Alberta’s Carbon Management Strategy: An Integrated Aproach to Carbon Capture and Storage and Technology

Development and Demonstration Duke du Plessis, Eddy Isaacs, Alberta Energy Research Institute, CANADA

Alberta has vast energy resources in the form of oil, coal and natural gas. With 174 billion barrels of recoverable reserves, Alberta’s oil sands rank second in the world after Saudi Arabia. Currently over 1 million barrels per day oil sands crude are produced in Alberta, most of which is exported via pipelines to the United States markets. Coal reserves total over 34 billion tonnes consisting primarily of sub-bituminous coal. Current coal production is over 37 million tonnes per year, most of which is used for thermal power generation. Alberta’s oil sands and coal industries are energy intensive and account for over 50% of Alberta’s total carbon emissions and about 15% of Canada’s total emissions. Although Alberta’s contribute less than 0.2% of the world’s carbon emissions, long term sustainable development of these large resources requires on-going technical innovation. As the technology arm of the Alberta Government, the Alberta Energy Research Institute (AERI) has since 2002 been working in partnership with industry to evaluate, develop and demonstrate new and improved technologies for converting our coal and oil sands into cleaner energy products, and in January 2008 the Government of Alberta released its new Climate Change Strategy. The goal of the Strategy is to ensure that the province remains at the forefront of achieving significant reductions in greenhouse gas emissions. The Strategy takes action on three fronts: implementing carbon capture and storage (CCS); greening energy production; and conserving and using energy more efficiently. CCS technology involves capturing CO2 emissions from large industrial sources and transporting them by pipeline to sites where they are injected into deep rock formations for permanent storage. Alberta has unique attributes that favour successful CCS operations including close proximity of large emitters to both deep saline aquifers with large sequestration capacity and oil reservoirs amenable to CO2 enhanced oil recovery. CCS projects are expensive, and innovative processes have higher technical and financial risks. Given these risk, the Government of Alberta established a $2 billion Carbon Capture and Storage Fund (CCSF) in July, 2008 to support demonstration projects that undertake to advance the broader adoption of CCS technologies in Alberta. The ultimate goal of the CCSF is to encourage the development of three to five large scale integrated CCS facilities that will capture and permanently store up to 5 million tonnes per year of CO2 by 2015, for a period of at least 10 years. This initiative is an important first step in the broader adoption of CCS in the province and aims to create the momentum for private sector investments for CCS. In reaching this goal, greenhouse emissions at facilities such as coal-fired electricity plants, oil sands extraction sites, upgraders, and other large scale industrial facilities will be reduced. Given the strategic importance of oil sands operations and the perception that oil sands derived crude oil is “dirtier” than other crudes, AERI undertook a robust life cycle analysis (LCA) comparison of oil sands versus conventional crudes processed in the US. This recently completed study was carried out under the direction of a publically vetted steering team from government, academia and industry. The presentation summarizes the LCA results, describes Alberta’s CCS Strategy and the status of the CCS projects (coal and oil sands based), and gives an overview of the technologies being developed in the AERI-Industry program.

SESSION 34

COMBUSTION: MERCURY

34-1

Particle-Loaded Membranes as Mercury Capture System Edgar B. Klunder, Evan J. Granite, Richard A. Hargis, DOE-NETL, USA

Commercial particle-loaded membranes have been tested as a way to remove mercury from flue gas. Greater than 90% mercury capture was demonstrated from a flue gas slip stream out of NETL’s 500-lb/h pulverized coal-fired combustion unit. Mercury inlet concentration was 35 µg/dscm (micrograms per dry standard cubic meter), with 86% being in the form of elemental mercury. The sorbent medium was a commercial 3M Empore® carbon disk that is normally used for water filtration. Tiny sorbent particles, embedded in an expanded membrane of support fibers, presented sufficiently large surface area for efficient mercury capture from a contaminated gas. Such particle-loaded membranes can be incorporated into or even replace conventional filter bags in bag houses, and thus separate the removal of fly ash from the Hg capture step. Such a combination not only reduces the capital cost assignable to mercury capture but also allows continued use of low-carbon fly ash as a concrete amendment. Depending on the composition of the flue gas, the particles may also act as catalysts for oxidizing elemental mercury. In such instances, bag houses outfitted with these special fabric filters may be located upstream of conventional wet scrubber systems that capture oxidized mercury.

Further work entails optimization of the sorbent/catalyst and the membrane material. The concept can also be extended to the removal of mercury from synthesis gas when the sorbent and supporting fabric material are compatible with the syngas composition and temperature. 34-2

Method to Improve Measurement of Mercury in Coal Combustion Flue Gas

Keiichiro Kai, Seiji Ikemoto, Yasuyoshi Kato, Hirohumi Kikkawa, Yoshinori Nagai, Babcock-Hitachi K.K., JAPAN

This paper indicates the incorrectness of mercury (Hg) measurement results by wet-chemistry methods, such as Ontario-Hydro (OH) Method or EPA method 29, in which a certain amount of Hg slips the sampling train without being captured at H2SO4-KMnO4 impinger set as well as KCl impinger set. Laboratory-scale tests were performed to reveal the cause of the measurement error. The results indicated that Hg mists, which could not be captured in both KCl solution and H2SO4-KMnO4 solution, were formed in the sampling probe before KCl impinger set. Carrying a certain amount of oxidized Hg with submicron sulfuric acid mists produced in the sampling train could cause Hg mists. In order to avoid the measurement error in OH method, the following methods are effective. (a) Adding a filter unit before H2O2-HNO3 impinger set, or (b) Setting a condenser tube unit before KCl impinger set. 34-3

Effect of Polarities of Pulsed Corona Discharge on Oxidation of Gaseous Elemental Mercury

Youngchul Byun, Moohyun Cho, Won Namkung, Pohang University of Science and Technology; Kyoung Bo Ko, Hynix Semiconductor Inc; Dong

Nam Shin, Dong Jun Koh, Research Institute of Industrial Science & Technology, KOREA

The effect of polarities of pulsed corona discharge (PCD) was investigated on the oxidation of gaseous elemental mercury (Hg0). The N2 gases containing 50 µg/Nm3 of Hg0 were introduced into the PCD reactor, where the flow rate and the temperature were set to 2 L min-1 and 150 °C, respectively. Although the oxidation of Hg0 by the positive PCD was higher than that by the negative one at the same applied voltage, there is no difference between the polarities at the same input energy density (J L-1). These results imply that the oxidation of Hg0 in the PCD process is decided by the input energy density regardless of the polarities. 34-4

Homogeneous and Heterogeneous Mercury Reaction Chemistry in Coal Combustion Flue Gases

Sang-Sup Lee, Erdem Sasmaz, Bihter Padak, Jennifer Wilcox, Stanford University, USA

Mercury in coal is vaporized as a gaseous elemental form of mercury through coal combustion processes. The elemental mercury can be oxidized by subsequent reactions with other gaseous components (homogeneous) and solid materials (heterogeneous) in coal-fired flue gases. While the oxidized mercury in coal-fired flue gases is readily controlled by the interaction with fly ash and co-benefit of an existing sulfur dioxide control system in coal-fired utility, elemental mercury is hardly controlled without the application of a specific control method for mercury. Therefore, it is important to understand homogeneous and heterogeneous mercury reaction mechanisms to predict the levels of mercury emissions from coal-fired power plants and determine the best applicable control technologies. Homogeneous mercury reactions were explored in our tubular reactor. Mercury and chlorine were introduced into a laminar flow premixed methane and air flame in the tubular reactor. The speciation of the resultant oxidized mercury was conducted by a direct measurement using a mass spectrometer specially designed for mercury measurements in our laboratory. Heterogeneous mercury reaction mechanisms will be investigated using inorganic alloy and activated carbon-based sorbent. Our Density Functional Theory calculations demonstrated that the inorganic materials such as palladium (Pd) and gold (Au) can be applicable for mercury capture at elevated temperatures, and a slight addition of Au to Pd can increase the binding energy with mercury. In addition, increases in the amounts of lactone and carbonyl groups on the activated carbon surfaces were found to increase the binding energy of elemental mercury. Experimental studies will also be conducted using a bench-scale packed-bed system and an entrained-flow system to further understand heterogeneous mercury reaction mechanisms. The inorganic alloy and activated carbon-based sorbent will be tested in these systems, and the spent materials will be characterized by Auger Electron Spectroscopy (AES) and X-ray Photoelectron Spectroscopy (XPS). In addition, entrained-flow tests will be conducted with different operating conditions such as residence time, gas temperature, gas velocity, and flue gas composition to develop heterogeneous reaction kinetics and mechanisms.

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34-6 Powdered Biocarbon as a Mercury Removal Technology

in Utility Flue Gas Applications Hugh McLaughlin, Alterna Energy Inc., CANADA

Powdered Activated Carbon (PAC) is a proven technology for the removal of mercury from utility flue gas streams. Depending on the properties of the coal being combusted and particular mercury speciation present in the flue gases, either unmodified or impregnated PAC can be used to remove mercury to regulated levels. Typical commercial PACs that have demonstrated success in these applications are the Norit Darco FGD, FGL and HG family of PACs and competitive products from Calgon Carbon Company. The approaching implementation of widespread mercury removal requirements has produced a specter of shortages in the traditional mercury removal PAC products. Furthermore, additional market forces, including the current import tariff on Chinese activated carbon products, have led to a pronounced increase in the cost of all activated carbon products. As such, there is a heightened interest in alternative products that could be utilized as replacements for traditional powdered activated carbons in mercury removal applications. One such alternative product is powdered biocarbon, made by carbonizing forestry residues. Studies have shown that some biocarbons, but not all, have “native adsorption capacity”, achieved at the end of the carbonization processing and without a formal activation step, which approaches 65% of commercial mercury removal PACs. Since biocarbons are produced directly from biomass in a single thermal conversion step and at higher yields than traditional activated carbon products, the unit cost of adsorption capacity is significantly lower for powdered biocarbons. The talk will present an overview of the analytical methods available for characterizing the adsorption capacities of activated carbon materials. The comparison of the properties of biocarbons, including native adsorption capacity and other relevant characteristics, will be made with the Norit Darco flue gas PACs. Mercury removal testing by powdered biocarbons is currently underway and the results of those tests, to the extent the results are conclusive and available, will be presented.

SESSION 35

COAL SCIENCE: COAL CHEMISTRY – 2

35-3

Thermal Evolution Characteristics of Coal Macerals Formed in Different Reductivity Environment by IN-SITU XRD

Ke-Chang Xie, Wen-Ying Li, Haizhou Chang, Jie Feng, Taiyuan University of Technology, CHINA

Considering the coal stacking structure, thermal evolution characteristics of coal macerals are studied by in situ XRD technique. The results are as follows: 1) The entire pyrolysis process of coal macerals in the light of the aggregation structure is supposed to include four stages from room temperature to 900ºC. In the first stage (a), the stacking structures are destructed and its order degree is to be reduced. In the second stage (b), the orientation elongation level (La) of aromatic system is enhanced. In the third stage (c), La of aromatic system is damaged. In the fourth stage (d), the large condensed ring of aromatic system is to be formed and its order degree is to elevate obviously. 2) By analyzing the evolution characteristics of d002, Lc and La, it could be found that the four stages for the vitrinite of coal formed in the stronger reductivity environment are presented but are not for the corresponding inertinite; and that stage a and b for the vitrinite with the weaker reductivity are hard to be differentiated while stage c and d are strongly presented and for the corresponding inertinite, the evolution characteristics of Lc are similar to the vitrinite. 3) The results obtained from in situ XRD could really reflect the evolution characteristics of stacking structure of coal macerals in pyrolysis and are different from the results by using the method of off-line XRD. 35-6

Simulation Aided Evaluation of Performance of FGX Separator on Turkish Lignites

Nuray Yalcin, Mustafa Ozdingis, General Directorate of Turkish Coal; Levent Ergun, Oczan Gulsoy, E. Caner Orhan, Hacettepe University, TURKEY

The increasing demand towards the use of dry and hence more environment-friendly coal cleaning technologies together with the struggle of decreasing operating costs of coal washing operations forces the coal producers to investigate the use of alternative equipments. FGX Separator developed in China in the last decade is now being used at hundreds of plants and is challenging in both purposes. This study aims to put forward the applicability of FGX Separator on Turkish lignites discussing the benefits and main drawbacks. The simulations carried out show that the separator fails to provide a clean coal for household purposes. Besides, although fulfilling its deshaling duties, it causes the loss of significant amount of coal to the tailings. However, in Husamlar coal, the

use of FGX Separator is sufficient to produce the power plant coal with 40% ash without the need for further processing.

SESSION 36

COAL-DERIVED PRODUCTS: HYDROGEN PRODUCTION – 1

36-1

Concomitant Production of High Purity Hydrogen and Sequestration Ready Carbon Dioxide from Coal

Tomasz Wiltowski, Kanchan Mondal, Southern Illinois University, USA A novel process on the production of a high purity stream of hydrogen from gasification products with concomitant generation of sequestration-ready carbon dioxide stream is presented. The central theme of the process lies in the sequential use of a) an oxygen transfer compound (OTC) to oxidize carbon monoxide present in syngas and b) capture of CO2 using an appropriate carbon dioxide removal material (CDRM) leading to the production of high purity hydrogen stream. Subsequently the reduced OTC which also contains carbon is oxidized (and thus regenerated) in the presence of air/oxygen/steam and the heat liberated via the exothermic reaction is utilized to regenerate CDRM. Iron oxide has been identified as a suitable OTC and calcium oxide as the most suitable CDRM. In the hydrogen enrichment pass, all of the carbon monoxide is converted to carbon dioxide (via water gas shift reaction, oxidation by OTC, and Boudouard reaction) and carbon (by Boudouard reaction). Thus, the products of this system would result into three separate streams of a) high purity hydrogen for use in fuel cells; b) sequestration ready CO2; and c) high temperature (pressure) oxygen depleted air for use in gas turbines. Due to its water gas shift activity and the ability to transfer oxygen to CO, hematite was chosen as the OTC. CaO was selected as the CDRM. Even at 50 % efficiency, CaO can capture 393 g CO2/kg of CaO. Simultaneous coal gasification and hydrogen enrichment experiments were conducted in the pressurized fluidized bed reactor at one and 250 psi. The following are the reactions expected to take place in the reactor. The heats of reaction are calculated for 800 °C. C + H2O → CO + H2 (Steam Reforming of Coal) +135.74 kJ/mol [1] CO + H2O → CO2 + H2 (Water Gas Shift Reaction) -33.07 kJ/mol [3] CO + Fe2O3 → 2 FeO + CO2 (CO oxidation) -4.75 kJ/mol [5] CaO + CO2 → CaCO3 (CaO Carbonation) -168.69 kJ/mol [6] The influence of temperature and steam partial pressures on the gasification and hydrogen enrichment processes was evaluated. Experiments were also conducted to evaluate the effect of solids composition (iron oxide, calcium oxide and coal) on the product gases. Both the gaseous yield and hydrogen purity was observed to increase due to the use of these solid oxides. Simple gasification produced a gas with a maximum purity less than 40 %. However, greater than 60 % pure hydrogen was obtained in most cases. The conditions were optimized to obtain nearly 90 % pure hydrogen in the exiting stream. In addition, the gaseous yield was observed to increase two fold as a result of the use of the reactive solids in the bed. The major contaminant was methane which appeared increase linearly with temperature. 36-2

Utilization of High Temperature CO2 Chemisorbents in Sorption Enhanced Reaction Concepts for Production of Fuel Cell Grade H2 from

Fossil Fuel Feedstocks Michael G. Beaver, Hugo Caram, Shivaji Sircar, Lehigh University, USA

Much attention has been focused on the role that fuel cells will play in the advent of hydrogen economy. The hydrogen fuel for these units requires very a high purity (99.99+ %) H2 stream and may only contain very small amounts (<20 ppm) of CO. One proposed method of high purity H2 production involves the gasification of coal into syngas, trace impurity (S, Hg, Cl) removal from the syngas, the shifting of the syngas in high and low temperature WGS reactors, followed by a multi-column, multi-step PSA unit for purification of the H2 product. Another conventional method of fuel cell grade H2 production involves Steam Methane Reforming (SMR) of natural gas (NG). This process requires multiple units, including a high temperature (~900 °C) catalytic SMR reactor, high (400 °C) and low (200 °C) temperature catalytic Water Gas Shift (WGS) reactors, and a multi-column, multi-step Pressure Swing Adsorption (PSA) unit for H2 purification. Both of these processes require multiple process units, with some operating at extreme temperatures (SMR reactor), and are energy intensive. The PSA unit operates at near ambient temperatures, and any water present must be removed prior to PSA. Also, 10-25% of the H2 product is consumed as back purge in a conventional PSA unit. The Sorption Enhanced Reaction (SER) concept integrates several of the process steps. In SER applied to the syngas produced by the gasification of coal, the multi-stage WGS and H2 purification steps can be condensed into a single unit operation to directly produce a stream of fuel cell grade H2 at feed gas pressure, and can also produce a stream of pure CO2 at high pressure, suitable for sequestration. SER can also be applied to SMR by combining the SMR reactor, WGS reactors, and H2 purification unit into a single unit. These concepts use a fixed bed sorber-reactor packed with an

32

admixture of reaction catalyst (SMR or WGS) and a selective CO2 chemisorbent. The feed gas (NG or syngas) is passed through the reactor and the by-product CO2 is removed from the reaction zone by the chemisorbent. This directly results in the production of a pure H2 (dry basis) at feed gas pressure. The chemisorbent is periodically regenerated by using the principals of pressure or thermal swing adsorption, and this CO2 can be recovered at high pressure and is suitable for sequestration. The removal of the by-product CO2 from the reaction zone circumvents the thermodynamic limitations of both SMR and WGS, allowing the reaction to near completion by Le Chatlier’s principle. The forward rate of reaction is also enhanced. In order for SER to be successful, a highly CO2 selective sorbent that operates at high temperatures (200-600 °C) must be developed. The sorbent must also display fast sorption/desorption kinetics, have low heats of CO2 sorption to facilitate the desorption, and also must be thermally stable at the temperatures of interest. Our group has extensively characterized two highly selective CO2 chemisorbent materials over the last few years: K2CO3 promoted hydrotalcite and Na2O promoted Alumina. CO2 sorption isotherms, heats, kinetics, and stability have been measured in our laboratories, and a mathematical model has been developed to describe these processes. The SER concept for High Purity H2 production has been experimentally demonstrated for both SMR and WGS reactions using different CO2 chemisorbents. The mathematical model has been used to simulate the performance of SER for SMR and WGS. Comparisons have been made to compare the experimental & simulated performances of different sorbents in both Sorption Enhanced SMR and WGS reactions, and are presented here. 36-3

Coal Gasification Experimental Plant for a CO2-Free Hydrogen Production

Alberto Pettinau, Carlo Amorino, Francesca Ferrara, Sotacarbo S.p.A., ITALY

The possibility to have a large scale hydrogen production from coal through zero emissions power generation plants is being more and more interesting for its implications from the economic and environmental points of view. However, the application of these technologies is subject to the high capital and operative costs. This need a great scientific and technical effort in order to optimize the processes and the equipments, thus reducing the hydrogen production cost. In this field, Sotacarbo has build up a pilot platform for a combined production of hydrogen and electrical energy from coal. The platform includes two different units: a 5 MWth demonstrative plant (with a fuel capacity of 700 kg/h of coal) and a 200 kWth pilot plant (feed with 35 kg/h of coal). While the main goal of the demonstrative plant is the optimization of the gasification process, the pilot plant has been designed to develop and optimize the syngas treatment line for hydrogen production and power generation, with CO2 separation. This paper reports a description of the overall experimental equipment, with particular reference to the pilot plant (which includes a fixed-bed up-draft gasifier, a syngas depulveration system, a cold and hot gas desulphurization processes, an integrated CO-shift and CO2 absorption system, a PSA section for hydrogen purification and a syngas-feed internal combustion engine for power generation). A critical analysis of the main results obtained in the first experimental campaign in the pilot plant has been presented, together with a global hydrogen and carbon balance. Moreover, the results of a preliminary test carried out in order to evaluate the possibility to operate coal gasification with mixtures of oxygen and carbon dioxide as oxidant agent has been reported. These results allowed to obtain useful indications to improve the plant performances and to optimize each syngas treatment and hydrogen production process. 36-4

Absorption of CO2 in CO2-philic Oligomers Matthew Miller, De-Li Chen, Hong-Bin Xie, Robert M. Enick, J. Karl

Johnson, University of Pittsburgh, USA Coal gasification plants employ the water-gas shift reaction to produce a high pressure mixture of CO2 and H2. It is desirable to separate this mixture into two high pressure streams, such as high pressure CO2 for sequestration and high pressure hydrogen for energy, however most separation techniques are capable of yielding only one high pressure product. For example, commercial absorption technologies are designed to selectively absorb one compound (e.g. CO2) at high pressure, and then release it at low pressure during regeneration, thereby yielding a high pressure stream of (non-absorbed) H2 and a low pressure stream of CO2. In particular, the SelexolTM process uses a polydisperse mixture of poly(ethylene glycol) di-methylethers, PEGDME, as a solvent for the absorption of CO2. The first objective of our research is to compare the CO2 solvent strength of PEGDME with polymers that are known to be very “CO2-philic”, including poly(propylene glycol) di-methyl ether (PPGDME), poly(di-methyl siloxane) (PDMS), and perfluoropolyether (PFPE). Pressure-composition phase behavior diagrams are presented for the pseudo-binary systems of CO2 with PEGDME Mw 250, PPGDME Mw 230, Krytox® PFPE GPL 100 Mw ~1000, or PDMS Mw 237, each at 25 °C. Henry’s law constants were also calculated for each pseudo-binary system in the high polymer concentration region. It appears that PPGDME may be the

best CO2 solvent, although the performance of PPGDME, PEGDME and PDMS are quite comparable when compared on a wt% of CO2 absorbed basis. Our second objective was to determine whether the solubility of CO2 in these solvents could be accurately predicted with COSMOtherm thermodynamic software. Remarkably good predictions were obtained after the vapor pressure of CO2 was fitted; no other parameters were adjusted. Therefore COSMOtherm appears to be a very useful tool for the design of new CO2 solvents. 36-5

Syngas Chemial Looping: Road to Sub-Pilot Scale Demonstrations Deepak Sridhar, Fanxing Li, Andrew Tong, Rae Kim, Liang Zeng, Fei Wang,

Liang –Shih Fan, The Ohio State University, USA Syngas Chemical Looping (SCL) is a promising clean coal conversion scheme that produces high-purity Hydrogen while separating CO2. This process utilizes an iron-based metal oxide composite particle, also referred to as the Oxygen Carrier (OC), for transporting the oxygen from steam/air to the fuel for combustion. This indirect combustion scheme eliminates the energy intensive product separation steps. The SCL unit comprises of 3 main reactors namely, the reducer, the oxidizer and the combustor. In the reducer, the OC provides the oxygen for fuel combustion, resulting in a concentrated CO2 stream ready for sequestration. Then, the reduced OC is moved to the oxidizer where it is partially regenerated with steam. H2 is simultaneously produced in this step. The regeneration of OC is completed in the combustor where heat is also produced. The reducer and oxidizer are countercurrent moving bed reactors while the combustor is an entrained bed reactor. Experiments on multiple scales and process simulations have been performed to validate the feasibility of the individual reactors and the process respectively. Successful results spurred the construction of the Sub-Pilot scale unit to demonstrate the continuous operation of the SCL process. This paper reviews on the pathway for the development of the SCL process with the focus on the preliminary results obtained in the Sub-Pilot scale SCL unit.

SESSION 37

GASIFICATION: SYNTHESIS GAS CLEANING – 2

37-1

Solid Regenerable Sorbents for H2S Removal from Syngas at a Warm Temperature

Jeom-In Baek, Tae Hyoung Eom, Joong Beom Lee, Won Sik Jeon, Chong Kul Ryu, Korea Electric Power Research Institute, KOREA

Warm syngas clean-up has the benefit enhancing the thermal efficiency of IGCC system compared with wet scrubbing operated at low temperatures. Solid sorbent is used in warm syngas clean-up to remove H2S in the synthesis gas. Korea Electric Power Research Institute (KEPRI) has been developing solid regenerable sorbents for H2S removal. In this work, the physical properties and H2S sorption capacities of newly developed solid regenerable H2S sorbent formed by spray drying method were investigated to evaluate their suitability for the fluidized-bed reactors. The mechanical strengths of some sorbents measured by ASTM D 5757-95 were better than commercial fluidized catalytic cracking (FCC) catalyst. Even though some sorbents did not have spherical shape, other physical properties were suitable for fluidized-bed process applications. The H2S sorption capacity and reactivity of the sorbents was examined with thermogravimetric analyzer (TGA) simulating the desulfurization reactor and regeneration reactor by switching the synthesis gas containing H2S (CO2 13%, H2 30%, CO 41%, H2O 15% and H2S 1%) and air at the system pressure of 20 bar and the temperature of 500 °C for desulfurization and 650 °C for regeneration. 37-2

Computational Methods for Evaluating Potential Warm Synthesis Gas Cleanup Technologies

David Couling, Kshitij Prakash, Anubhav Jain, Seyed-Abdolreza Seyed-Reihani, Chris Fischer, Ujjal Das, Gerbrand Ceder, William Green,

Massachusetts Institute of Technology, USA With the abundance of the world’s coal supply and the ever-growing need to produce electricity more efficiently, Integrated Gasification Combined Cycle (IGCC) coal power plants are showing increasing potential for electricity generation. IGCC plants can dramatically increase the overall power generation efficiency compared to a traditional coal-fired power plant; however, a significant obstacle to the large-scale implementation of IGCC is the development of optimal techniques for pollution reduction. One suggested technique is to take several of the cleanup processes, currently performed at low temperature, and perform them at higher temperatures using solid adsorbents. Unfortunately, no commercial processes exist for several of the required high-temperature separations, and in many cases the materials necessary to perform such high-temperature separations have not been identified. Historically, this type of problem has been addressed by synthesizing a large number of potential materials and screening them experimentally. However, not only is this

33

process time-intensive, it can also leave a large amount of uncertainty about the optimal conditions for the screening experiments and about the energy benefits that would result from any promising technology. Here we present a different approach, where a combination of numerical integration software and ASPEN Plus process simulations are used to determine the process conditions and sorbent properties which would optimize any potential sorbent. These process simulations also provide insight into the potential energy benefits that may arise from a given sorbent technology by providing a direct comparison between the novel process and the traditional low-temperature processes. In addition to the process simulations, energy calculations using quantum chemistry methods are used to screen a large number of potential sorbents. The use of these techniques can significantly reduce the number of sorbents that need to be synthesized and tested empirically. Applications to the removal of mercury and carbon dioxide from IGCC streams are presented as illustrations of this new approach. 37-3

Bechtel Pressure Swing Claus Sulfur Recovery Technology Tomas C. Maramba, Robert Geosits, Charles Kimtantas,

Bechtel Oil & Gas, USA The removal and recovery of the sulfur compounds from a syngas stream is normally a two-step process: an amine or physical solvent sulfur removal step followed by a Claus-type process to convert the sulfur species to elemental sulfur. This normally requires cooling the syngas to ambient temperature or lower before treating. In addition the sulfur removal step will usually remove some of the carbon dioxide and generate a medium pressure carbon dioxide stream and/or the carbon dioxide may be with the hydrogen sulfide as a low pressure gas stream for feeding to a Claus sulfur recovery unit. This paper will present a new, single-step sulfur removal and recovery technology that operates at full gasification pressure and at medium temperatures. The technology will reduce plant capital cost and improve operating efficiency. The advantages of removing the sulfur separately from the syngas and carbon dioxide are two fold: 1. The process reacts and removes the hydrogen sulfide leaving the gasification syngas at pressure and with all of the carbon dioxide. This enhances the mass for the turbine combustion in an integrated gas combustion cycle power generation system and thereby increases the power recovery. 2. If removal of most of the carbon dioxide is desirable, then a simple physical solvent with flash regeneration can be used since the sulfur was removed upstream and the solvent does not need to be regenerated severely to meet sulfur specifications. Bench scale testing has been completed to prove out the basic chemistry and reaction kinetics. Overall sulfur recoveries have been determined and various catalysts evaluated. As a result of this work a patent application was submitted and a U.S. Patent, No. 7,374,742, was issued. The basic process chemistry, the process flow scheme and how the unit operates will be discussed. Supporting research and test work will be reviewed. Options for combining this sulfur recovery technology with CO2 recovery will also be discussed. 37-4

Development of Novel Multifunctional Selective Catalytic Reduction Systems for IGCC Plants

Anatoly Sobolevskiy, Siemens Energy, Inc.; Joe Rossin, Guild Associates, Inc., USA

The development of Advanced Combustion Turbine Technology for IGCC plants requires a post-combustion treatment of the exhaust gases in order to reduce NOx emissions to very low (<2.5 ppm ) levels. The exhaust gas composition for IGCC plant is significantly different from combined cycle plants that use natural gas as fuel. The high water vapor and sulfur content makes the clean up of the post-combustion gases using selective catalytic reduction system very challenging. Contaminates that are present in the IGCC plant fuel as a result of coal gasification also affect the efficiency of the SCR system with respect to NOx emissions. Low NOx emissions levels at IGCC plants require an increase of SCR removal efficiency up to 90+ % with very limited ammonia slip. The novel SCR systems were developed to overcome the influence of the above negative factors on SCR performance. The aim of this work was to develop and design a new multifunctional selective catalytic reduction systems by using hydrogen or ammonia as reductants that were capable of reducing emissions of NOx, CO, and VOC to ultra low levels (<2 ppm) in the single SCR bed without ammonia emissions (novel H2-SCR) or allowing a negligible ammonia slip (novel NH3-SCR). The novel SCR systems are able to carry out the whole complex of NOx reactions and support oxidizing reactions to achieve ultra low levels of NOx, CO and VOC emissions. The newly designed SCR systems have been extensively evaluated in the test rig by using flue gases from natural gas, coal and fuel oil combustion, and simulated IGCC gas turbine exhaust with sulfur content up to 50 ppm and water concentrations up to 25 vol.%. It was found that the novel SCR systems were capable of reaching of NOx removal efficiency 90+% by using H2-SCR (no ammonia slip) and reducing NOx, CO, and VOC emissions to the levels below 2ppm (emissions reduction efficiency 90-95%) with ammonia slip at the level of 0.5-1 ppm in the wide range of operating temperatures and gas space velocities. The long lasting durability runs of the novel SCR systems including testing at the pilot scale level (2000-2500 hours)

demonstrated very stable catalyst performance within target values of emissions reduction.

SESSION 38

GASIFICATION: ADVANCED TECHNOLOGIES – 1

38-1

Enabling Clean Energy Production from Coal: ITM Oxygen Development Update

Lori A. Vratsanos, Phillip A. Armstrong, Richard P. Underwood, VanEric E. Stein, E.P. (Ted) Foster, Air Products and Chemicals, Inc., USA

Air Products and Chemicals along with partners and through partnership with the U.S. Department of Energy has made substantial progress in developing a novel air separation technology. Unlike conventional cryogenic processes, this method uses high temperature ceramic membranes to produce high purity oxygen. The membranes selectively transport oxygen ions with high flux and infinite theoretical selectivity. An energy-rich non-permeate stream is produced that can be used to produce power and steam. Operation of the process at high temperature allows good integration into both advanced power generation processes as well as traditional energy intensive industrial processes which require oxygen. Good synergy with CO2 capture applications is expected. ITM Oxygen technology has entered Phase III of a multiphase development effort. During Phases I and II, the ITM Oxygen team established the feasibility of the ceramic membrane approach and designed and built commercial-scale membrane modules. The team has successfully demonstrated expected performance of commercial-scale modules in a prototype facility that produces up to 5 tons- per-day of oxygen. In Phase III, a membrane separator will be integrated with a compressor/expander set to co-produce power and up to 150 tons-per-day (TPD) of oxygen in the 2010 timeframe. Data from the 150-TPD plant test will provide the design basis for a much larger plant that could supply up to 2500 TPD scale. This paper will present an overview and update of the ITM Oxygen development effort, including testing of commercial-scale ceramic modules, developing integration schemes with gas turbines and energy-intensive industrial processes, and process economic analyses. A commercialization timeline will be discussed. 38-2

Oxygen Purity Control in the Air Separation Unit of an IGCC Power Generation System during Rapid Production Fluctuation

Priyadarshi Mahapatra, B. Wayne Bequette, Rensselaer Polytechnic Institute, USA

An Air Separation Unit (ASU) plays a vital role in future oxygen-blown combustion/gasification-based power plant. In comparison to “cold box” plants solely producing ultra-high purity oxygen and nitrogen mainly in liquid form, air separation plants specifically designed for IGCC vary largely due to different specifications and operating conditions. The operating pressures of both the columns are kept high to nullify significant pressure losses due to air-integration of this unit with the gas turbine. Furthermore, usage of additional feed-flow control valves is also avoided. Therefore, in addition to design complexity due to decreased separation efficiency at higher pressure, the column pressure and temperature dynamics (shorter time-scale), and composition profiles (longer time-scale), float in tune with rapid pressure fluctuation from the gas-turbine-combustor section, leading to erratic mass flowfluctuations in the high pressure column of the ASU. These disturbances quickly propagate to the low-pressure column through tight energy integration between the reboiler-condensor as well as the LP column liquid reflux stream which has a deteriorating effect on the oxygen-product purity, especially during sudden decrease of pressure. Fast restoration of refrigeration to avoid rapid boilup due to the flashing of oxygen-rich vapors during these events requires a tight and efficient control structure design. It must also be emphasized that current floating pressure arrangements poses a significant control design difficultly in terms of fixed temperature control, and alternate control schemes using either composition control loops or differential tray temperature loops must be devised. In this study, a fully pressure-driven dynamic model has been developed using Aspen Plus/Aspen Dynamics software. Rigorous study involving many possible steady state design configuration within a single flow-sheet using optimization and sensitivity tools is presented. A rigorous heat-exchanger design has been incorporated into the model to study carefully the effect of thermal lags and wrong-way (inverse response) temperature effects due to feed-effluent heat exchange. Moreover, additional refrigeration effects by changing the pre-feed temperature to the HP-column during transient states is studied and the approach is found to provide system stability and significant robustness in oxygen purity control. In the current study, direct oxygen and nitrogen purity control is attained by measuring compositions directly. The prospect of controlling the unit, especially during vast pressure variations, solely using temperature measurements is highlighted using a differential tray-temperature approach. Further, a model predictive control strategy that handles rate-of-change constraints imposed by

34

the process design of the air separation unit has been studied and compared with performance using decentralized classical PID schemes Finally we close with a discussion of future work on the simulation and control of an entire IGCC power plant. 38-3

Efficient and Reliable Coal Feeding System for Entrained Flow Gasification

Thomas Metz, S. Henker, S. Stoye, F. Hannemann, R. Rüsseler, Siemens Fuel Gasification GmbH & Co., GERMANY

The type of fuel feeding system is of substantial importance for entrained flow gasification of coal and other feedstock. Currently there are two options commercially available: Slurry feeding and dry feeding (pneumatic dense flow). The dry feeding system enables higher cold gas efficiency and carbon conversion. It also permits higher fuel flexibility with the possibility to gasify low rank coals. However, certain design parameters must be met to ensure proper operation at high availability. Since coal is a natural product which varies in composition, a good design needs to take experimental data into account, along with simulation results and empirical data. For that purpose Siemens operates a coal feeding test rig with a capacity of up to 300 t/d under commercial scale conditions. This plant is currently used to test different coals, coal specific instrumentation and to validate simulation models. The article presents results of the test program regarding lock hopper cycles, coal mass flow monitoring and testing of alternative feedstock like biomass. Together with lab scale tests and results gained from gasification testing in the adjacent test plant this provides a solid basis for proper design and reliable operation of dry coal feeding systems. 38-4

PWR Compact Gasification Development Status Kenneth Sprouse, Steven P. Fusselman, Timothy Saunders,

Pratt & Whitney Rocketdyne; John W. Fulton, Mike Raterman, ExxonMobil Research and Engineering Co., USA

Development activities on the Pratt & Whitney Rocketdyne (PWR) High Pressure (1,000 psia) Compact Gasification System are presented. They include: (a) facility preparation for testing an 18 tons/day pilot plant gasifier at the Gasification Technologies Institute (GTI -- Des Plaines, IL), (b) design activities on a 400 to 600 tons/day dry solids linear extrusion pump at the University of North Dakota's Energy & Environmental Research Center (EERC Grand Forks, ND), and (c) biomass development activities for inclusion of this renewable as a candidate feedstock. 38-5

CFD Modeling for Moving Bed Reducer in Syngas Chemical Looping Process

Liang Zeng, Fanxing Li, Zhao Yu, Deepak Sridhar, Ray Kim, Andrew Tong, Fei Wang, Liang-Shih Fan, The Ohio State University, USA

The syngas chemical looping (SCL) process efficiently coproduces hydrogen and electricity from coal derived syngas while capturing CO2. The reducer reactor in the SCL process converts syngas with the oxygen carrier particles. Therefore, the reducer performance is of vital importance to the overall process efficiency. Thermodynamic analysis indicates that a countercurrent moving bed design enhances the gas and solids conversions in the reducer. Although thermodynamic calculation can predict the reducer conversions at equilibrium conditions, a comprehensive CFD model that takes into account the complex gas and solid flow behavior and reaction kinetics and thermodynamics is needed in order to accurately simulate the reducer performance. In the present work, a CFD model for the moving bed reducer is developed using FLUENT. A two-dimensional cylindrical moving bed reactor is constructed with comprehensive geometrical and operational parameters. A shrinking core submodel is adopted for reaction kinetics with the physical and chemical property data retrieved from an external database. The continuity equation for each species and the governing equations for continuity, momentum, and energy for the solid and gas phases are established. Therefore, the comprehensive CFD model takes into account the hydrodynamics, heat transfer, reaction kinetics and mass transfer behavior in the reducer. Important reducer performance data such as the gases and solids conversions, the temperature and gas and solid compositions, and the flow pattern inside the reactors are obtained using the CFD model.

SESSION 39

CARBON MANAGEMENT: SEQUESTRATION – 2

39-1

U.S. Geological Survey Probabilistic Assessment Methodology for the Evaluation of Carbon Dioxide Storage

Sean T. Brennan, R.C. Burruss, M.D. Merrill, P.A. Freeman, L.F. Ruppert, M.F. Becker, U.S. Geological Survey, USA

The U.S. Geological Survey (USGS) has developed a probabilistic assessment methodology for evaluation of the technically accessible resource potential for storage of CO2 in subsurface geologic formations of the United States. This methodology for assessing CO2 storage is based on USGS assessment methodology of oil and gas resources, which has been created and refined over the last 30 years. In the case of CO2 storage, the resource that is evaluated is the technically accessible pore space in the subsurface in the depth range of 3,000 to 13,000 ft, within a geologically defined storage assessment unit consisting of a storage formation and an enclosing seal formation. The storage capacity assessment methodology is primarily a volumetric calculation of pore space coupled with an estimate of ‘storage efficiency’, the percentage of pore space that would be occupied by free-phase CO2. Storage assessment units are divided into portions that are physical traps (PTs), which in most cases are producing or depleted oil and gas reservoirs, and the surrounding saline formation (SF) that constitutes the remainder of the storage formation. The distribution of the size of potential storage resource is determined separately for the PT and SF settings by Monte Carlo simulation methods. To estimate the aggregate storage resource distribution of PTs, a second Monte Carlo simulation step is used to sample the distributions of the size and number of PTs. Aspects of the USGS capacity assessment methodology which make it distinct from other proposed methods include utilization of various distribution functions of the available data as input values. The data available for PTs allow for several types of storage capacity values to be determined, such as: (1) the amount of CO2 stored via enhanced oil recovery (EOR); (2) the amount of CO2 that can be stored relative to the net volume of fluid produced from the trap; and (3) the volumetric estimation of available pore space using distribution of the areal extents, thicknesses, and porosities of known traps and storage efficiency values. The ultimate goal of the storage capacity assessment methodology is to determine the total trap volume beyond the petroleum-bearing volume, i.e. the “fill-to-spill” storage capacity. The SF methodology is a volumetric estimation that uses Monte Carlo simulations to sample distributions based on the uncertainties of the average values for thickness, porosity, and storage efficiency. The storage distributions assessed in both PTs and the SF are reported as unconditional and conditional capacity. The unconditional capacity estimates, in contrast to the conditional estimates, take into account the probability of successful storage for individual PTs or the entire SF, as defined by the likelihood that the CO2 stored will be greater than a prescribed minimum. Therefore, the unconditional storage values represent estimates with the greatest degree of geologic certainty based on current knowledge and available data. 39-2

Hydrodynamics and CO2 Injection in Saline Aquifers – Can Aquifer Flow Alone Immobilize the CO2?

Randall G. Larkin, R. G. Larkin Consulting, USA Deep saline aquifers under consideration for commercial scale CO2 geologic sequestration (GS) are regional in scale with no conventional stratigraphic or structural traps. The fate of supercritical CO2 injected in saline aquifers depends on aquifer hydrodynamics and phase trapping. This paper examines the question of whether basinward flow of brine alone can counteract updip CO2 movement after injection ends, and render the gas immobile. Ignoring near wellbore pressure gradients, the important post injection flow mechanisms are viscous flow of brine (imposed by compaction and gravity) and buoyant flow of CO2 (imposed by the density contrast between injected CO2 and the formation brine). Examples are given of deep basin aquifer dynamics and regional brine flow rates as they relate to GS. Brine flow and buoyant flow may be in the same direction (immature compacting basin) or the opposite direction (mature basin). The mature basin scenario is optimum for GS, as long-term updip CO2 movement will be reduced by brine flow. Analytic expressions, based on multiphase fractional flow theory, are used with certain simplifying assumptions to estimate the rate of buoyant movement after CO2 injection ends. Key inputs such as permeability, porosity, dip, and density contrast were varied to assess their relative influence. Of these, permeability and dip were the most important. In most cases, brine flow rates should be less than buoyant flow rates. Therefore, in a mature basin, brine flow alone will usually be insufficient to counteract buoyancy, and phase trapping is needed to ultimately immobilize the CO2. Buoyant flow rates can be significant, and saline aquifer/seal pairs extending for tens of miles may be needed for GS.

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39-3 CO2 Sequestration: Temperature and Gas Compositional Effects on the

Kinetics of Mineralogical Reactions Prashanth Mandalaparty, Milind Deo, Joseph Moore,

University of Utah, USA It may be possible to lower costs of Carbon Capture and Sequestration by keeping constituents such as sulfur dioxide (SO2) in the flue gas stream. The reactive behavior of pure CO2 and CO2 + SO2 mixtures within a geologically realistic environment was examined. The experimental apparatus consisted of a series of four high-pressure reactors operated at different conditions and with different feed gas compositions to observe changes in both the rock and water compositions. The rock consisted of equal proportions of quartz, calcite, andesine, dolomite, chlorite and magnesite (constituents in arkose or dirty sand stone). The brine was prepared from laboratory grade sodium chloride and by varying the amount of magnesium concentration in the brine. Several long term batch experiments with pure CO2 were carried out at different temperatures. Each mineral in the mixture showed evidence of participating in the geo-chemical reactions. Layers of calcite were seen growing on the surface of the arkose. Analcime deposits were omnipresent, either occurring as large connected aggregates or as deposits on the surfaces of other minerals (Quartz). Ankerite and calcite depositions were observed as amorphous masses intergrown with the feed. The CO2 + SO2 mixture experiments showed growth of euhedral anhydrite crystals and pronounced dissolution patterns over the examined surfaces. The growth of these new phases would lead to significant changes in the petrophysical properties of the rock. The trends in ionic concentration changes in the aqueous phase complemented the changes in the rock chemistry. The rates of these reactions were computed by measuring the changes in the compositions of the initial and the final samples. The rates of these reactions were computed by computing the changes in the compositions of the initial and the final rock samples (both individual and mixture) provided by the XRD analyses and were observed to be lower than expected. 39-4

Update on Carbon Capture & Storage Project at AEP’s Mountaineer Plant, New Haven, WV

Daniel Duellman, American Electric Power, USA Provide an update on the 100,000 ton per year, post combustion CO2 capture project installed at the AEP Mountaineer Plant. AEP and Alstom have installed a 20 MW slip stream CO2 capture and deep saline aquifer storage system at the AEP Mountaineer Power plant in New Haven West Virginia. The capture system uses the Alstom Chilled Ammonia Capture system. This installation is a first of a kind scale up for this technology. The captured CO2 will be pressurized and injected into two different deep saline aquifers below this plant site. The powerpoint presentation will discuss the status of this project, and some of the challenges of the “first of a kind” installation. 39-5

First-order Estimates for CO2 Leakage through Geological Seals Considered for CO2 Sequestration in Saline Reservoir

Craig Griffith, Yee Soong, Sheila Hedges, DOE-NETL; Gregory Lowry, David Dzombak, USA

The U.S. Department of Energy (DOE) currently has several field and large-scale candidate demonstration sites for saline reservoir sequestration of CO2. The DOE demonstration projects have a programmatic goal of achieving 99% storage permanence of injected CO2 over 100 and 1,000 years. To determine allowable limits for CO2 leakage in saline reservoirs, physical and mineral characteristics with structural features of several geological seals used at DOE demonstration sites were examined to identify common reactive minerals, structural and hydraulic properties relevant to assessing their ability to prevent leakage. Common seal characteristics were used to develop conceptual models for idealized CO2 leakage scenarios and to perform numerical simulations based on 1D vertical Advection-Dispersion-Reaction (ADR) models in a stochastic framework. These evaluations are intended to provide first-order estimates for the expected ranges of CO2 leakage and to identify critical parameters and leakage processes common to geological seals considered for saline CO2 sequestration.

SESSION 40

COMBUSTION: OXY-COMBUSTION – 3

40-1

Investigation of the Effect of Inherent Water Content on the Combustion Characteristics of Victorian Brown Coal in Air

and under Oxy-Fuel Conditions Eleanor Binner, Lian Zhang, Sankar Bhattacharya,

Monash University, AUSTRALIA This paper details in-situ investigations into the effect of inherent moisture content (10 – 30 wt%) on the combustion characteristics of a Victorian brown coal in a Drop Tube Furnace (DTF). The effect of the following parameters was examined: particle size, furnace temperature and combustion atmosphere (air versus 27% oxygen (O2) and 73% carbon dioxide (CO2)). A high speed camera and a two-colour pyrometer were used for in-situ diagnostics. The particle temperature was found to be around 80°C lower in the combustion of wet coal (~30 wt% water) versus dry coal (~10 wt% water) for most of the conditions. And increase in coal water content caused an ignition delay and prolonged combustion. Devolatilisation followed by volatile combustion was observed in all cases. At higher temperatures, coal/char combusted simultaneously with the volatiles. Dry coal was found to be less sensitive than wet coal to changes in furnace temperature and particle size. Particle temperatures were matched in both the wet and dry case when air was replaced by 27% O2 in CO2. However, oxy-fuel combustion of wet coal resulted in a barely visible unstable flame. 40-2

Flameless, Pressurized Oxyfuel Combustion: The Advantaged Process for Carbon Capture from Coal Based Power Production

Leo Salinas, Salinas Consulting, USA; Massimo Malavasi, ITEA Spa; Giancarlo Benelli, ENEL Spa, ITALY

Combustion of coal with oxygen is a technology that has been under investigation for decades. But Oxy-Combustion in a Flameless, Pressurized environment is a very recent, yet promising and fast growing player in the “Near Zero” emission coal-fired power technologies arena. The technology has under development for 3 years at the pilot plant scale (5MWth), with a 50 MWth demonstration unit under erection in Italy projected on-stream in 2010. This technology provided a quantum leap in integral emissions (air-born, liquid, solid emission) reduction, with high yield, low capital per kWh, and with simplified operations. The flameless condition of the combustor achieves six-nines conversion and quantitative melting and coalescence of both heavy and fly ashes. By achieving this level of performance in the combustor, clean hot pressurized fumes exit the reactor, simplifying the back end cleanup. The slag produced is fully vitrified and inert. Pressurized carbon dioxide is produced for carbon capture. Flameless Pressurized Oxy-combustion has been discovered and patented by ITEA Spa, Italian company of the Sofinter Group. The exploitation of this technology for coal fired Power production is conducted in co-operation with ENEL, European utility coleader. Process characteristics, performances, and potential future improvements are represented. 40-3

CFD Modeling of Char Conversion in Oxygen Enhanced Combustion Adrian Goanta, Valentin Becher, Jan-Peter Bohn, Stephan Gleis, Hartmut

Spliethoff, Technische Universität München, GERMANY Oxy-fuel combustion is a process where fuel is burned in a mixture of oxygen and recycled flue gas. The flue gas recirculation is applied to limit the flame temperatures, otherwise too high when burning only with pure oxygen, to levels comparable to conventional combustion. In this way the atmospheric nitrogen is eliminated from the process leading to a flue gas consisting mainly of carbon dioxide and water vapor. Further on, this stream is treated to obtain a high CO2 concentration by condensing the water. This renders the oxyfuel process as a suitable candidate for the Carbon Capture and Storage technology. For realizing an oxy-fuel based CCS process, understanding the fundamental characteristics of fossil fuel combustion under these conditions plays a key role. CFD modeling is a powerful tool which can be regarded as an aid in designing new facilities or retrofitting the existing ones. However, modeling of coal combustion under oxy-fuel conditions is not straightforward. Adjustments of the constituting submodels which form the combustion model are necessary in order to account for the possible changes in particle reactivity and the surrounding gas composition, and properties which influence the heat and mass transfer mechanisms. All these factors reflect on the predictability of particle burnout. This paper presents, in a comparative manner, two existing submodels for predicting pulverized coal combustion under oxygen enhanced conditions. The performance of the submodels is tested against experimental data from literature in terms of particle

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burnout as a function of residence time. To correct the reactivity at low oxygen levels, gasification reactions of the char particle are included. In addition the oxygen diffusivity towards the particle external surface is adjusted accordingly. 40-4

Partitioning of Basic Elements in Fine Ash from Oxy-Coal Combustion Dunxi Yu, Will Morris, Jost O.L. Wendt, University of Utah, USA

Fouling and slagging are currently unquantified problems in the application of oxy-coal combustion to existing power plants for CO2 capture and storage. Basic elements (i.e. Na, K, Ca, Mg and Fe) play important roles in such processes. The present work aimed to explore the partitioning characteristics of the basic elements and their implications on fouling and slagging under oxy-coal combustion conditions with once-through CO2. To further understand the effects of once-through CO2, air combustion tests were also carried out. All experiments were performed on a newly-completed 100 kW oxy-coal furnace. Ash particles were first extracted from the flue gas into an isokinetic sampling probe and quenched immediately with a stream of nitrogen. The quenched sample was then directed to a Berner Low Pressure Impactor, where it was collected and size-segregated into eleven size fractions from >15.7 µm down to about 0.03 µm. The size-classified ash fractions were mainly subjected to average composition analysis under a high-resolution scanning electron microscope (SEM) coupled with an energy dispersive x-ray spectrometer (EDS). The size distributions of the basic elements were carefully studied. Particles >0.5 µm were also examined individually with the SEM and EDS in a manual way. The association of the basic elements with silicates was characterized. Such information was used to provide insights into ash slagging tendencies under oxy-coal combustion conditions. Preliminary results showed that the change of air-firing to oxy-firing conditions affected the partitioning behavior of the basic elements. The enrichment of most basic elements in fine ash particles was favored by oxy-firing conditions and high flame temperatures. Ash deposition might be more severe under oxy-coal combustion conditions compared to air combustion conditions. Future work will explore the effects of recycled CO2, where fine particle concentrations and SO2 concentrations are likely to be much higher. 40-5

Pelletization of Cao-Based Sorbents for CO2 Capture Edward J. Anthony, Vasilije Manovic, R. Hughes, R. Symonds, D. Lu,

CanmetENERGY, Natural Resources Canada, CANADA The use of pelletization technology has been explored for CO2 capture using Ca looping cycles. The initial work suggests that, whereas binders like Na2CO3, and Na and Ca bentonites do make potentially strong pellets, this benefit is compromised by the loss of CO2 capture activity that results from the presence of elevated levels of Na and/or Si in the binder, even over tens of cycles. This suggests that, if sorbents need to perform for a hundred cycles of more, these materials must be avoided. The use of water sprays to bind pellets is also problematic given that the pellets often lack mechanical strength, and/or tend to be destroyed in the curing process. Experimental work at CanmetEnergy suggests that these problems appear to be resolvable by using Ca aluminate cements at about 10% addition level, which give pellets that are strong and show high activity over up to 50-60 cycles. Moreover, such binders are relatively cheap, and our results support the hypothesis that the goal of producing a sorbent capable of achieving avoided CO2 costs of less than $20/tonne may be achievable using such binders.

SESSION 41

COAL SCIENCE: COAL GEOSCIENCE – 2

41-1

Relations between Petrographic and Geochemical Indices of HC Potential in Coals and Source Rocks

Louis Loung-Yie Tsai, National Central University; Hsien-Tsung Lee, National Central University and Nan Kai Institute of Technology; Li-Chung

Sun, Nan Kai Institute of Technology, TAIWAN In order to evaluate the relations between petrographic and geochemical indices of coals and source rocks while assessing their HC potential, more than one thousand samples corresponding to kerogen type II/III were analyzed to detect their Hydrogen Index (HI), Quality Index (QI), and Bitumen Index (BI). In addition, cross-plots of HI, QI and BI vs. vitrinite reflectance (%Ro) and Tmax (°C) were depicted. The constructed HI, QI and BI bands were broad at low maturities and gradually narrowed down with increasing thermal maturity. The decline in BI means that the start of the oil expulsion window occurs within the vitrinite reflectance range of 0.75-1.05 % or Tmax 440-455 °C. Furthermore, the petroleum potential can be divided into four different parts based on the cross-plot of HI vs. %Ro, in which the highest petroleum potential area is located with Ro = 0.6-1.0%, and HI>100. The exponential equation of regression can thus be achieved. The organic materials studied also exhibit two ranges

of oil expulsion window: Ro = 0.75-1.95% or Tmax = 440-525°C, and Ro = 1.05-1.25% or Tmax = 455-465°C, respectively. Finally, the start of the oil expulsion window occurs within Ro range of 0.75-1.05% or Tmax range of 440-455°C, and the total oil window extends to Ro = 1.25-1.95% or Tmax = 465-525°C. HC potential is completely exhausted at Ro = 2.0-2.2% or Tmax = 510-520°C. 41-2

Distribution and Mode of Occurrence of Mercury and Sulfur in Illinois Coal

Liliana Lefticariu, Rajesh Singh, Mohammad Wahidur Rahman, Southern Illinois University, USA

Coal is a heterogeneous mixture of organic and inorganic constituents that results from the alteration of original plant materials during coalification through geologic time. Inorganic constituents in coal, including sulfur (S), mercury (Hg), selenium (Se), and arsenic (As), have a significant effect on almost every aspect of coal utilization, as well as major impacts on the environment. Geochemical studies of Hg, S, As, and other toxic elements in coal have intensified in recent years, due to a growing awareness of the potential effects of these elements on the environment. Detailed knowledge on distribution, abundance, speciation, and modes of occurrence of trace elements is essential to understanding and predicting the transformations taking place during the coal fuel-cycle. Illinois Basin contains some of the most important coal resources in the United States. However, high concentrations of sulfur and other chemical elements result in important environmental and technological problems associated with the use of Illinois coals. The present study was undertaken to evaluate the geochemical controls on Hg and S occurrence and speciation in the Illinois coal. In this study we used a novel sequential extraction procedure, which involved an iterative selective leaching protocol on coal samples. This method is specific to complex systems containing many organic and inorganic phases and consequently is a more accurate representation of trace element distribution in coal and coal products. Coal samples were collected from mines located in three counties in Southern Illinois. We sampled the following coal members of the Illinois coal basin: Herrin No. 6 and Springfield No. 5 of Carbondale Formation and Murphysboro and Mt. Rorah of Spoon Formation. Preliminary data suggest that the distribution of sulfur and mercury is highly variable within the coal sample. Our preliminary results show that the low-sulfur coals are generally poor in Hg. In high-sulfur coal samples, a significant portion of sulfur is concentrated in sulfide minerals (e.g., pyrite, chalcopyrite). These sulfide minerals could have precipitated from hydrothermal solutions. High-sulfur coals usually contain higher amounts of Hg, which is typically associated with pyrite. In these coals, routine techniques of sulfur removal may also reduce other trace element content. 41-3

Partitioning of Iron in Organic and Mineral Phases: Sequential Extractions of Lignite and Bituminous Coal

Amy Wolfe, Daniel Bain, Brian Stewart, Rosemary Capo, University of Pittsburgh, USA

Pyrite (FeS2), the most common sulfide mineral in Earth’s surface environments, is a strong indicator of reducing conditions in aqueous environments (Descostes et al., 2004). The abundance of pyrite in nature and the important role of pyrite formation in geochemical cycles has spurred numerous experimental investigations addressing formation mechanisms at low temperatures ( < 100°C) and over a broad range of solution chemistries (Rickard and Luther, 2007 and references therein). The principal steps in sedimentary pyrite formation require the consumption of iron compounds to varying degrees through reaction with microbially-formed hydrogen sulfide (Luther 1991). The results presented here are part of an investigation of pyrite formation in organic-rich sediments, including coal. There are several working hypotheses for pyrite formation: a) iron is deposited diagenetically and pyrite formation is biologically driven; b) pyrite is being dissolved and residual iron is adsorbing to the surface; or c) pyrite is formed epigenetically, as iron attached to the coal surface reacts with sulfur compounds via percolating surface water or interactions with groundwater. The interaction of iron with both mineral and organic matter makes characterization of iron partitioning difficult, and thus it is poorly understood in modern and ancient organic-rich sediments. We have developed a sequential extraction allowing detailed information on the speciation of iron in coal. Five sediment iron fractions are characterized (1) surficially bonded Fe; (2) organically bound Fe (Feorg); (3) carbonate-associated Fe, including siderite and ankerite; (4) reducible oxides, including ferrihydrite, lepidocrocite, goethite; (4) silicate Fe; and (5) pyrite Fe. Iron fractions were determined using a combination of pressurized fluid extraction, using EDTA and NMP, as well as leaching on a suite of cannel, lignite, and coal samples collected from different coal regions within the United States. Preliminary data from a sample of bituminous coal collected from the Clarion Coal seam (Turkey City, PA) suggests that 90% of iron within the coal is bound to the coal surface. Additional samples are being processed and trends will be assessed between samples and coal quality groups. Ultimately, iron distribution within the coal seam has important implications for inferring formation and dissolution conditions. Understanding iron partitioning may

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assist in optimizing coal processing and combustion while minimizing environmental impacts.

SESSION 42

COAL-DERIVED PRODUCTS: HYDROGEN PRODUCTION – 2

42-1

Development of Cermet Membranes for Hydrogen Separation from Coal Gasification Stream

U. (Balu) Balachandran, T. H. Lee, C. Y. Park, Y. Lu, S. E. Dorris, Argonne National Laboratory, USA

Hydrogen, the fuel of choice for both electric power and transportation sectors, can be produced from fossil and renewable resources by various technologies. Because it is produced in gas streams with numerous components, purification is a critical step in its production. Argonne National Laboratory is developing dense cermet (i.e., ceramic-metal composite) hydrogen transport membranes (HTMs) for separating hydrogen from coal gasification streams. Hydrogen separation with Argonne's HTMs yields high purity hydrogen, thereby eliminating the need for post-separation purification steps. HTMs were prepared by standard ceramic fabrication techniques, and their hydrogen permeation rate, or flux, was measured in the range of 400-900°C. A cermet membrane (thickness ≈18 µm) on a porous support structure gave a maximum hydrogen flux of ≈52 cm3(STP)/min-cm2 at 900°C in tests using 100% H2 at ambient pressure as the feed gas. Because good chemical stability is critical for HTMs, due to the corrosive nature of product streams from coal gasification, we evaluated the effect of various contaminants on the chemical stability of cermet membranes. Hydrogen sulfide (H2S), a particularly corrosive contaminant, impedes hydrogen permeation through cermet membranes by reacting with them to form palladium sulfide (Pd4S). To evaluate the chemical stability of membranes, the Pd/Pd4S phase boundary was determined in the temperature range ≈450-750°C in tests using various feed gases that contained 10-73% H2 and ≈8-400 ppm H2S. We assessed the effect of syngas components on the Pd/Pd4S phase boundary by locating the phase boundary in feed gas that contained CH4, CO2, and CO in addition to 400 ppm H2S. When cermet membranes were tested in a gas mixture with high concentrations of CH4, CO, and CO2 for ≈700 h, performance did not degrade. The present status of membrane development at Argonne and the challenges involved in bringing this technology to fruition will be presented in this talk. Work supported by the U.S. Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory’s Hydrogen and Syngas Technology Program, under Contract DEAC02- 06CH11357. 42-2

Hydrogen Transport through Palladium-Based Separation Membranes in the Presence of Hydrogen Sulfide

Casey P. O’Brien, James B. Miller, Andrew J. Gellman, DOE-NETL and Carnegie Mellon University; Bret H. Howard,

Bryan D. Morreale, DOE-NETL, USA Dense Pd and Pd-alloy membranes have received significant attention for their ability to separate hydrogen from mixed gas streams, such as those produced by gasification of coal. However, exposure to H2S, a common contaminant in gasification process streams, can cause membrane performance to deteriorate. In the absence of H2S, hydrogen fluxes through Pd and Pd47Cu53 foils at 350 °C are similar. In the presence of 1000 ppm H2S, hydrogen fluxes through both foils are substantially reduced, but with significantly different decay patterns. Six hours after the start of H2S exposure, Pd is still permeable to H2, but with flux decreasing slowly over time. Analysis of the Pd foil by x-ray photoelectron spectroscopic (XPS) depth profiling and x-ray diffraction (XRD) reveals that sulfur penetrates far into the Pd foil, at least 200 nm, and that Pd reacts with H2S to form a specific palladium sulfide corrosion product, Pd4S. These observations are consistent with slow growth of a low-permeability, but still catalytically active, sulfide corrosion layer on the Pd surface. In contrast, the H2 flux through the Pd47Cu53 foil is undetectable within only five minutes of the start of H2S exposure. XPS depth profiling of the Pd47Cu53 foil reveals that sulfur does not penetrate far into the foil’s surface, only about 1-2 nm. Rapid formation of a mixed PdCuS terminal layer, which is either inactive for H2 dissociation or impermeable to H-atoms, is responsible for the deactivation of the alloy membrane in H2S at 350 °C. 42-3

Co-Production of Pure Hydrogen and Electricity from Coal Syngas via the Steam-Iron Process using Promoted Iron-Based Catalysts

Jason P. Trembly, Brian S. Turk, Raghubir P. Gupta, RTI International, USA RTI with funding from the U.S. Department of Energy has successfully developed a novel iron-based catalyst for using the iron redox cycle to produce high purity high pressure hydrogen from syngas. This novel iron-based catalyst was based on nanostructured crystalline phases which allowed significantly higher hydrogen

production at significantly lower temperatures compared to the state-of-art iron-based redox systems. A preliminary techno-economic analysis of RTI’s steam-iron process using this catalyst for co-production of hydrogen and power in an IGCC plant showed cost benefits over a commercial pressure swing adsorption process for hydrogen production. RTI is continuing the development of this steam-iron process technology focusing on scaling up production of the novel iron-based catalyst and design and fabrication of a circulating dual fluidized bed reactor system. Using bench-scale results, RTI has initiated scale up efforts to produce catalyst batches of up to 100 lbs with commercial equipment. In parallel, a 50kWTh circulating fluidized-bed reactor system capable of operating at 550 °C and 300 psig is being designed and fabricated to provide a suitable system for process development under commercially suitable operating conditions. With this reactor system, the key technical challenges relating to operating conditions, reactor design, catalyst deactivation, and catalyst mechanical stability, which are necessary for a cost competitive commercial process, will be addressed. The reactor system will also be used to evaluate integration strategies and to develop a design package for a pilot-plant unit for slipstream testing of syngas from a commercial gasifier. 42-4

Calcium Looping Process for Clean Fossil Fuel Conversion Shwetha Ramkumar, L. S. Fan, The Ohio State University, USA

The rising energy demand coupled with the depleting global oil reserves and the environmental degradation due to emissions has led to extensive research in the field of clean energy production. The total energy use, globally, has been predicted to increase from 421 quadrillion BTU in 2003 to 722 quadrillion BTU in 2030 (EIA, 2006). On the other front, the energy related CO2 emission has increased at an annual average percentage of 1.3 % in the past decade and is projected by the EIA to increase at the same rate till 2030. Hence, the implementation of energy generation technologies as well as production of “Green” fuels which will reduce the dependence on oil and natural gas, limit the emissions of CO2, sulfur and other pollutants and be economically feasible are the need of the hour. The Calcium Looping Process (CLP) is one of the clean coal technologies being developed for the production of hydrogen (H2), electricity and liquid fuels and is based on the syngas obtained from coal gasification. It integrates the water gas shift (WGS) reaction with in-situ carbon dioxide (CO2), sulfur and halide removal at high temperatures in a single reactor while eliminating the need for a WGS catalyst and reducing the overall foot print of the hydrogen production process. The CLP comprises of two reactors; the carbonation reactor where the thermodynamic constraint of the WGS reaction is overcome by the incessant removal of the CO2 product and high-purity H2 is produced with contaminant removal and the calciner where the calcium sorbent is regenerated and a sequestration-ready CO2 stream is produced. The purity of H2 is increased by a large extent when the carbonation reaction is integrated with the WGS reaction. The steam addition for the WGS reaction is also reduced to stoichiometric quantities which aids in reducing the parasitic energy consumption of the process. In addition, the extent of sulfur and halide removal by the calcium oxide (CaO) sorbent is also enhanced by operating at lower steam partial pressures. Experiments conducted in a bench scale facility have revealed that high purity H2 of 99.7% purity with less that 1 ppm sulfur impurity is produced by the CLP. Process evaluation using ASPEN Plus® software suggests that the overall efficiency of a coal to high purity hydrogen (99.999%) process with CLP is 64% (HHV) and is significantly higher than the state-of-the-art process which is 57% (HHV). 42-5

Poisoning and Corrosion of Pd-Alloy Hydrogen Separation Membranes by H2S

Bret H. Howard, Bryan Morreale, DOE-NETL, USA Gasification technologies are generally recognized as a viable near-term approach for addressing national fuel security and economic sustainability concerns, while simultaneously addressing the control of greenhouse gas emissions. The gasification process can utilize a variety of carbon-based feed stocks such as coal and biomass to produce a highly-flexible synthesis gas and, when combined with water-gas shift (WGS), can be effectively used to maximize hydrogen production. The hydrogen can be used for a variety of energy applications, including power generation via H2 turbine combustion, power generation via fuel cell technologies and liquid fuels through several synthesis routes. Additionally, the integration of the water-gas shift reaction with simultaneous hydrogen separation (a WGS membrane reactor) can be used to enhance CO-conversion beyond that attainable in conventional reactors decreasing the necessity for multiple reactors, added catalysts, and large quantities of steam, while producing a highly concentrated, high pressure stream of carbon dioxide ready for co-sequestration. Dense metal membranes are a promising technology for the separation of hydrogen from these other product gases due to their high permeability and high selectivity for hydrogen. However, impurities typically contained in coal and biomass derived synthesis gas (compounds containing S, N, C, alkalis, heavy metals, etc.) can have adverse effects on metal-based separation membranes including corrosion and catalytic poisoning. Sulfur compounds, particularly hydrogen sulfide which can be present at concentrations as high as ~2% in a raw shifted coal-derived syngas stream

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down to low part-per-million levels following gas clean-up processes are probably the most detrimental to metal membrane technologies. H2S is well known to severely impact the performance of dense metal membranes. These effects include catalytic poisoning and corrosion which can result in severe performance degradation and mechanical failure. Therefore, developing a thorough understanding of the effects of syngas constituents, especially H2S, on metal membrane-based hydrogen separation membranes is imperative to facilitate the acceptance and deployment of membranes in gasification technologies. NETL’s Office of Research and Development is currently utilizing experimental and computational techniques to evaluate and develop potential sulfur tolerant membrane materials. A variety of binary and ternary Pd-based alloys (Pd combined with Cu, Ag, Au, Pt, etc.) are being studied for application in the severe conditions and environments associated with the gasification process. The performance of these various Pd-based alloy membranes were evaluated in the absence and presence of 1000 ppm H2S in H2 at conditions consistent with syngas processing. The observed hydrogen flux trends on exposure to 1000 ppm H2S in H2 were correlated with results obtained from post test XRD and SEM/EDS characterization. A range of performance degradation trends were observed under exposure to H2S ranging from nearly no detectable effect to severe poisoning and corrosion. Results indicate that temperature, composition, H2S concentration and crystalline phase all play a role in the observed membrane degradation mechanism and its corresponding influence on performance. Under the conditions of this study, the decrease in the hydrogen flux for Pd appears to be governed by the formation of a rapidly growing, poorly permeable Pd4S scale while the effect of H2S on the Pd alloys is much more complicated.

SESSION 43

GASIFICATION: CO-GASIFICATION AND LOW-RANK COAL – 1

43-1

Economics of Wyoming Coal Gasification William C. Schaffers, David Bell, University of Wyoming, USA

A complete transition away from fossil fuels for energy and chemical feed stocks is likely to take decades, if not centuries. It is also becoming apparent that the future use of fossil fuels will require some form of carbon management. These two factors together present a unique opportunity for Wyoming’s vast sub-bituminous coal reserves along with its oil and gas fields. Carbon dioxide produced by oxygen blown coal gasification processes has a much higher partial pressure than that produced by conventional coal fired plants, making capture and compression much more efficient. Compressed CO2 can then be shipped and sequestered in available oil and gas fields providing the added economic benefit of enhanced oil and gas recovery. Ultimately, these studies seek to evaluate the relative economics of Wyoming coal gasification for power production (IGCC) as well as for production of liquid fuels and chemical feed stocks. Initially, mine-mouth coal-to-liquids and IGCC plants with the same coal feed rates were compared to determine relative economics. Coal-to-liquids cases with and without CO2 sequestration were also compared. Results showed the possible effects of carbon capture and sequestration requirements on synthetic coal based fuels and electricity produced from Wyoming PRB coal. It is also desired to compare these Wyoming based plants with similar Midwest based facilities (Illinois, for example). The objective here is an economic comparison of Wyoming’s cheaper, but lower grade, sub-bituminous coals with more expensive, higher grade, bituminous coals when used for coal-to-liquids or electricity production. Eventually, these processes will be simulated comparing different gasification reactors in the hopes of determining optimal configurations for Wyoming’s coal. These models could be further refined as more detailed information on the gasification kinetics of PRB coal is developed. The ultimate goal of these studies is the continued use of Wyoming’s vast coal reserves in the most efficient and environmentally friendly means for the benefit of Wyoming and the Nation. 43-2

Gasification Characteristics of Western Canadian Feedstocks: An Overview of Current Projects and Results

Duke du Plessis, Malcolm McDonald, Alberta Energy Research Institute, CANADA

Western Canada has an abundance of coal, and oil sands residues in the form of petroleum coke (petcoke), that are potential feedstocks for gasification operations. Over 95% of Canada’s coal resources occur in western Canada, and most of these consist of sub-bituminous deposits in Alberta and lignite in Saskatchewan; the majority of the coal currently mined is used for power generation. Oil sands operations in Alberta currently produce between five (5) and ten (10) million tonnes per year of petcoke, most of which currently is being stockpiled. These feedstocks have physical and chemical properties that effect gasification performance and overall gasifier facility costs. Early work by Canadian Clean Power Coalition evaluated different western Canadian coals in IGGC plants with CO2 capture using dry and slurry feed gasifier types. In 2005/06, this led to the initiation of a Front End Engineering Design

(FEED) study of a 270 MW IGCC plant with CO2 capture using sub-bituminous coal from Genesee, Alberta. A Sherritt-AERI project tested different western Canadian coals as well as oil sands petroleum coke and coal-petcoke blends in the Siemens Gasification pilot plant in Freiberg, Germany. The results were subsequently modeled and analyzed against a reference bituminous coal (Illinois #6). The presentation gives an overview of the AERI-Sherritt work and discusses the CCPC’s current research program aimed at gaining further insights into the gasification characteristics of western Canadian feedstocks. 43-3

Lignite Gasification Testing at the Power Systems Development Facility John Northington, Johnny Dorminey, Roxann Leonard, Ruth Ann Yongue,

Southern Company Services, USA Lignite coal can contribute significantly to clean coal energy production because of its abundance, accessibility, and low cost relative to other ranks of coal. Identifying processes that can economically utilize lignite coals can be challenging, however, due to other characteristics of lignite such as its low heating value, high ash, and high moisture contents. Integrated Gasification Combined Cycle (IGCC) may be the most promising method of lignite utilization for energy production. Lignite gasification employing Transport Integrated Gasifier (TRIG™) technology is a commercially viable option. TRIG™ technology, developed at the Power Systems Development Facility (PSDF), is a dry-feed, non-slagging, circulating fluidized bed gasifier making it well suited for lignite operation. The Power Systems Development Facility (PSDF) is a state-of-the-art test center sponsored by the U.S. Department of Energy (DOE) and dedicated to the advancement of clean coal technology. Located in Wilsonville, Alabama, the PSDF is a highly flexible facility where researchers can economically evaluate innovative power system components on a semi-commercial scale, focusing on ways to reduce capital cost, enhance equipment reliability, and increase efficiency while meeting strict environmental standards. Development and testing of lignite coal at the PSDF including utilization of waste heat for lignite drying, highly efficient ash removal systems, and optimum operating conditions are the keys to commercial deployment of lignite gasification and the subject of this report. 43-4

Upgrading of Low Rank Coal for Enhancing its Gasification Reactivity Kouichi Miura, Ryuichi Ashida, Mitsunori Makino, Atsushi Nishida,

Kyoto University, JAPAN Enhancement of gasification reactivity of coal chars is very effective in increasing coal gasification efficiency. Gasification reactivity of coal chars is believed to be controlled mainly by catalytic effect of inherent minerals. Then addition of catalyst has been performed to further increase the gasification reactivity of coal char. A more cost-effective method, however, has been desired to enhance the gasification rate. We have recently proposed an upgrading method of low rank coal which consists of treatment of coal in non-polar solvent, such as 1-methylnaphthalene, at temperatures below 350°C. The products obtained from the treatment are solvent-soluble fraction (extract) and insoluble fraction which we call “upgraded coal”. The gasification reactivity of the upgraded coal char was much larger than that of the raw coal for all the three coals tested. The CO2 gasification rate at 900°C of the upgraded coal char prepared from an Australian brown coal, Loy Yang coal, was surprisingly larger than the rates of any other coal chars reported in the literature. Furthermore, demineralized upgraded coal char still had higher gasification reactivity than demineralized raw coal char, suggesting that the enhancement of the gasification reactivity was not due to the catalytic effect. Thus, it was found that the proposed upgrading method of low rank coal can be one of the ways of enhancing the gasification reactivity of coal char without using catalyst. 43-5

Gasification of Lignites to Produce Liquid Fuel, Hydrogen, and Power Joshua Stanislowski, University of North Dakota, Energy & Environmental Research Center, USA

The Energy & Environmental Research Center (EERC) has completed the gasification of lignites program, with the second half of the program featuring hydrogen production from coal and lignite testing in a transport reactor and entrained-flow gasifier. The program was sponsored by the U.S. Department of Energy through the EERC’s National Center for Hydrogen Technology and a consortium of lignite users. Tests conducted at the EERC demonstrated that a pure stream of hydrogen could be produced from a Texas lignite in a transport gasifier while maintaining the temperature of the syngas above 400°F (204°C). Warm-gas-cleaning techniques were employed that reduced sulfur levels to below 0.1 ppm, and a hydrogen separation membrane was used to produce the pure stream of hydrogen. This technique has potential economic advantages over conventional temperature swing adsorption and pressure swing adsorption because the need to heat or cool the syngas has been eliminated. Testing of several lignites also occurred in a bench-scale entrained-flow gasifier. This paper

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describes the warm-gas hydrogen production technique in detail and provides the results of the entrained-flow gasifier tests.

SESSION 44

GASIFICATION: ADVANCED TECHNOLOGIES – 2

44-1

1 Ton/day Class Dry Feeding Coal Gasification Facility Hai-Kyung Seo, Jae-Hwa Chung, Seong-Bok Lee, Jun-Hwa Chi, Dal-Hong

Ahn, Korea Electric Power Research Institute (KEPRI); Ji-Sun Ju, Seok-Woo Chung, Institute for Advanced Engineering (IAE), SOUTH KOREA

In Korea, the development of a Korean type coal-gasification system has been progressing since December of 2006 as an eight year project in parallel with the construction of a 300MW class IGCC demonstration plant, funded by the Korean government and several domestic power companies. Under this development project, KEPRI will develop a 20 ton/day class Korean type coal-gasification system, and we are currently designing a dry feeding type gasifier and a clean-up system. Prior to this pilot plant, a 1 ton/day class gasification system will be used for pre-testing of several coal types. This paper introduces the configuration and design of this 1 ton/day class system, presenting the gas/coal ratio, oxygen/coal ratio, cold gas efficiency, and others. The existing combustion furnace for residual oil was retrofitted as a coal gasifier and a vertical and down-flow type burner was manufactured. Ash removal is carried out with a water quencher under the gasifier and a scrubber following the quencher, and the sulfur is removed by adsorption in an activated carbon tower. The gas produced from the gasifier is burned at the flare stack. The vertical burner of the gasifier will be replaced with a 4-tangential and up-flow burner in the 20 ton/day pilot class. Therefore, several types of burners, including vertical, tangential, and up-flow types, will be applied for the 1 ton/day class. The operation results from the 1 ton/day class will be utilized in the development of the 20 ton/day system. 44-2

Mild Airblown Gasification Integrated Combined Cycle (MaGIC) for Retrofitting Existing Coalplants

Alex Wormser, Wormser Energy Solutions, Inc., USA The paper describes the continued development of the IGCC known as MaGIC (for “Mild Airblown Integrated Gasification Combined Cycle.) The technology’s main application is to retrofit existing steamplants by converting them into IGCCs in order to increase their generating capacity while also eliminating their carbon dioxide emissions. The power from the new system, including the carbon capture, is expected to cost less than the power from a new pulverized coal plant without it. The potential effect of this on the fight against global warming is discussed in a separate paper at this conference. The design retains key elements of the design described two years ago at this conference, including the preservation of volatiles to minimize the syngas flowrate, and the use of mild gasification to burn the char fines rather than gasifying them. Combustion is six orders of magnitude faster than gasification at the temperatures of airblown gasifiers, which reduces the reactor size needed to consume them by as much as two thirds. The main changes since then: a carbon capture system has been conceptualized that removes virtually all of the CO2, as well as a new process for burning the char fines. The carbon capture system remains to be demonstrated. 44-3

Study of Hybrid Fluidized Bed Gasifier for Industrial Applications Drew Spradling, Touchstone Research Laboratory, USA

An indirectly-heated, atmospheric fluidized-bed hybrid gasifier concept is being investigated for applications in the small industrial gasification market. The results of an ongoing feasibility study jointly funded by The State of Ohio’s Coal Development Office and DOE/NETL will be presented. This project builds on the successful demonstration of an AFBC for the supply of hot water to a commercial greenhouse facility in Ohio, which has been in successful operation for 5 years. Utilizing the current AFBC technology and combining it with an indirectly-heated atmospheric fluidized bed gasifier (AFBG) yields a hybrid gasifier concept ideally suited for the smaller-scale industrial gasification market segment. The study is currently assessing the preliminary designs and estimated capital costs for a 10 MMBtu/hr. input demonstration-scale plant, as well as a 20MWe commercial-scale facility. This type of hybrid gasification concept uses two physically separate fluidized bed reactors. The gasification reactor converts the coal and/or biomass feedstock into a medium Btu syngas containing a high percentage of methane, and residual char. The combustion reactor burns the residual char received from the gasification reactor, along with some coal, and provides heat for the gasifier. A carrier, composed of sand, limestone, and ash, circulates between both of the reactors and indirectly applies the heat from the combustor to the gasifier coal feed. The combustor heats the sand, which is then fed to the gasification reactor, quickly turning the particles into gas

before returning into the combustor to be reheated. The gasification reactions are driven by injected steam and a portion of hot recycled syngas, thereby limiting the amount of introduced nitrogen and increasing methane content, ensuring a higher heating value of the final syngas. Some of the challenges associated with smaller-scale industrial gasification technologies, including economies of scale, syngas cleaning, and carbon emission handling will be discussed. While the 10 MMBtu/hr. demonstration unit being planned will not be competitive with natural gas, it is anticipated that larger commercial scale units approaching the 20 MWe size will be able to economically compete with natural gas in the future, as increased demand for the fuel in electricity and transportation causes prices to rise. The feasibility study will determine the actual cost of building the first demonstration unit rated at 10 MMBtu/hr. coal input, and conceptual engineering designs for the AFBC and AFBG will be presented, along with the preliminary site engineering and environmental permit determinations. Projections of capital and O&M costs of a larger commercial-scale unit will also be presented. A major outcome of the project is the illustration of a commercialization path for this coal gasification technology where industrial users are seeking less expensive fuels than natural gas for process heating. By incorporation of smaller-scale, distributed gasification plants to produce medium-Btu syngas, many industrial customers could realize lower energy costs, while using abundant locally-sourced coal and coal/biomass mixtures.

SESSION 45

SUSTAINABILITY AND ENVIRONMENT: GENERAL – 1

45-1

Assessment of Non-Traditional Sources of Water in the Illinois Basin for Use in Coal-Based Power Plants

Seyed A. Dastgheib, David Ruhter, Chad Knutson, University of Illinois at Urbana-Champaign, USA

Thermoelectric power generation accounts for about 39% of the total freshwater withdrawals (345 billion gallons per day (BGD)), the second largest after irrigation, and about 3% of total water consumption (100 BGD) in the U.S. In Illinois, about 82% of the estimated 14 BGD of freshwater withdrawals in 2000 were used in the thermoelectric power sector. The amount of thermoelectric freshwater consumption in Illinois is estimated as one-third of the state total 1 BGD consumption. The U.S. Department of Energy/National Energy Technology Laboratory (DOE/NETL) predicts that for an expected 22% increase in the U.S. thermoelectric capacity by 2030, water consumption increases by 30-50%, and water withdrawal changes within a range of -20% to 7%. In addition, CO2 capture from power generation plants will increase raw water consumption by 95% in subcritical pulverized coal boilers and 37% in Integrated Gasification Combined Cycles. It is likely that the coal-based power generation industry will face restrictions for water because of the limited resource availability and the increasing demand for water in the domestic, agricultural, and industrial sectors. Produced water from coal-bed methane (CBM) recovery, CO2 enhanced oil recovery (CO2-EOR), and active/abandoned coal mines are potential sources to supplement/replace freshwater needs of the power generation plants. Produced water generally contains a high concentration of total dissolved solids and other pollutants which must be reduced to an acceptable level, depending on the application, prior to its use in power plant. The U.S. DOE/NETL has selected the University of Illinois at Urbana-Champaign to evaluate the feasibility of using selected types of non-traditional sources of water in the Illinois Basin by coal-based power generation industry. The project is aimed at characterizing the geographic distribution, quantity, and quality of produced water from CO2-EOR operation, CBM recovery, and active and abandoned underground coal mines; estimating cooling/process water demand for coal-based power plants; identifying suitable technologies and costs for treating the produced water to different quality levels; and optimizing the cost of a pipeline distribution network for transporting the produced water. This presentation will provide a general review of the project and summarize geographic distribution and estimated quantities of produced water from potential future CO2-EOR and CBM operations in the Illinois Basin. 45-2

Minimization of Water Consumption under Uncertainty for PC Process Juan M. Salazar, Urmila M. Diwekar, Vishwamitra Research Institute: Center for Uncertain Systems Tools for Optimization and Management; DOE-NETL;

Stephen E. Zitney, DOE-NETL, USA Coal-fired power plants are large water consumers second only to agricultural irrigation. Water restrictions become more influential when water-expensive carbon sequestration technologies are added to the process. Therefore, national efforts to study the reduction of water withdrawal and consumption in existing and future plants have been intensified. Water consumption in thermoelectric generation is strongly associated to evaporation losses and makeup streams on cooling and contaminant

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removal systems. Thus, minimization of water consumption requires optimal operating conditions and parameters, while fulfilling the environmental constraints. Several uncertainties affect the operation of the plants and this work studies those associated to weather. Air conditions (temperature and humidity) were included as uncertain factors for pulverized coal (PC) power plants. The study comprises three main steps: Characterization of uncertainty, sensitivity analysis and optimization. Probability distributions were obtained from available atmospheric and electric generation data. The distributions characterize air conditions and electricity demand variability as uncertain factors. A stochastic simulation capability in the Aspen Plus process simulator was employed to perform sensitivity analysis and to determine the decision variables for the final step. Optimization under uncertainty for these large-scale complex processes with black-box models cannot be solved with conventional stochastic programming algorithms because of the large computational expense. Employment of the novel better optimization of nonlinear uncertain systems (BONUS) algorithm, also implemented as an Aspen Plus capability, dramatically decreased the computational requirements of the stochastic optimization. Operating conditions including reactor temperatures and pressures; reactant ratios and conditions; and steam flowrates and conditions were calculated to obtain the minimum water consumption under the above mentioned uncertainties. Reductions of up to 12% in water consumption were calculated when process variables were set to optimal values. 45-3

Performance and Cost of Wet and Dry Cooling Systems for Coal-based Power Plants

Haibo Zhai, Michael Berkenpas, Edward S. Rubin, Carnegie Mellon University, USA

Water use is becoming an important issue at thermoelectric power plants where significant quantities of water are required for the purpose of cooling. The significant influence of the Clean Water Act, Section 316(b) regulation is to promote the wide use of cooling towers in most new power plants. The pressure on water resource availability and conservation also may lead to increasing employment of dry cooling systems in thermoelectric power plants. The principal objective of this study is to systematically evaluate the performance and cost of wet and dry cooling systems in pulverized coal (PC) power plants. The system-level analysis for individual cooling technologies explores the effects of key parameters and factors and quantifies the performance and cost of different cooling systems in subcritical and supercritical PC plants. For a wet cooling tower, water has to be provided to make up losses due mainly to evaporation and blowdown. Our results show that the average makeup water for the wet cooling system is 568 gallons per MWh for subcritical PC plants and 511 gallons per MWh for supercritical PC plants. The total plant cost of the wet cooling system is $69 per net kW on average for the PC plants. When air-cooled condensers (ACCs) are used as the dry cooling system, the steam turbine generally incurs a high backpressure, which reduces the steam cycle thermal efficiency and increases the initial temperature differences (ITD) between inlet cooling air and exhaust steam. The size and capital cost of a dry cooling system vary significantly by a factor of three to four over a wide range of ITD. In spite of the advantage in reducing water usage, the dry cooling system has a much larger capital cost than the wet cooling system. The capital cost ratio for ACCs versus a wet cooling tower averages 2.9 for the subcritical case and 3.2 for the supercritical case based on typical design assumptions. Nevertheless, sensitivity analysis shows that the cost ratio maybe as high as factor of six or more and is strongly dependent on the ITD. The capital cost and cost ratio of dry versus wet cooling systems depend strongly on specific site and system characteristics. 45-4

Survey of Potential Uses for Carbon Dioxide Captured from Coal-Burning Power Plants

Evan J. Granite, Bryan Morreale, Nathan T. Weiland, Henry W. Pennline, David R. Luebke, Todd H. Gardner, Lindsay M. Bombalski,

George A. Richards, DOE-NETL, USA Approximately 52% of the electricity in the United States is generated through the combustion of coal. One billion tons of coal is burned annually for electricity production, resulting in three billion tons of carbon dioxide. Carbon dioxide is a potent greenhouse gas that can contribute to global warming. The United States Department of Energy is sponsoring research on the separation and sequestration of carbon dioxide from coal-derived flue gas. A major issue is determining good uses for the massive quantities of carbon dioxide that could potentially be separated from flue gas. Some of the current uses of carbon dioxide that will be examined include fire suppression, food preservation, refrigeration and cooling, beverage carbonation, inert gas needs such as for welding, enhanced oil and coal bed methane recovery, supercritical cleaning, biomass production, and polymer-plastic manufacture. Future research areas for carbon dioxide utilization such as fuel production, pharmaceutical chemicals, coal gasification, oxy-combustion of coal, and passivation of alkaline wastes will also be discussed. Literature Cited

1. Edwards, J.H. Potential sources of CO2 and the options for its large-scale utilization now and in the future, Catalysis Today, 23, 59-66, 1995.

2. White, C.M.; Strazisar, B.R.; Granite, E.J.; Hoffman, J.S.; Pennline, H.W. Separation and Capture of CO2 from large Stationary Sources and Sequestration in Geological Formations – Coalbeds and Deep Saline Aquifers, Journal of the Air & Waste Management Association, 53, 645-715, 2003. 45-5

Sustainability and the Environment Frank Kranik, Lauryn Burkhalter, Ecology & Environment Inc., USA

Sustainability must include a system that integrates local concerns into the decision making process and include involvement of all key stakeholders to balance social, environmental, and economic project needs. This poster provides an example of a successful energy project planning process utilizing sustainable development guidelines.

SESSION 46

COMBUSTION – 2

46-1

Performance Improvement of 235 MWe and 260 MWe Circulating Fluidized Bed Boilers

Wojciech Nowak, Czestochowa University of Technology; Roman Walkowiak, Tomasz Ozimowski, Janusz Jablonski, J. Wyszynski, PGE

Elektrownia “Turow” S.A., POLAND PGE Turow Power Plant S.A. is a large (2106 MWe) commercial thermal electric power plant located in the south-western part of Poland, at the border of three states: Poland, the Czech Republic and Germany. It has been producing electric energy uninterruptedly for 45 years. In the years 1995-2004 it underwent modernization, whereby 6 power units were replaced. Their pulverized combustion (PC) boilers were substituted with circulating fluidized bed (CFB) boilers. The article discusses the reasons behind the choice of this combustion technology, the course of modernization, the basic design characteristics of CFB boilers, the currently achieved performance indices and finally performance improvements (presentation in Power Point). The assessment of the operation of two types of CFB boilers – the CFB type with an external cyclone and the CFB compact type is provided. The article provides a summary of nearly 10 years of operation of these boilers. Also, the problem of choosing a new technology for the planned construction of a new unit is addressed. With its power of almost 1500 MWe installed on power units with CFB boilers, PGE Turow Power Plant S.A. is currently the world's largest electric power plant of this type. 46-2

Characterising the Combustion Behaviour of Particles of European Ash with Different Shape Aspect Ratios and Moisture Contents

Mark Flower, Jon Gibbins, Imperial College London, UNITED KINGDOM The UK has committed itself to drastically reducing carbon dioxide emissions by 2020. To help meet this target biomass is regularly being co-fired with coal in many of the UK’s PF power stations. To study biomass combustion particles of European ash, chosen as a representative woody fuel, have been burnt in air within a wire mesh apparatus. Prior to experimentation each particle’s mass, moisture content and shape aspect ratio were measured. Characteristic combustion times of measured drying time, devolatilisation ending time and particle burn out time were then determined for each particle. The devolatilisation ending times and particle burn out times were found to increase with increasing dry mass and shape aspect ratio whilst the measured drying time was found to be independent of dry shape aspect ratio. Moisture was found to delay measured drying time and devolatilisation ending time, having a more significant effect as the particle mass and shape aspect ratio increased. The moisture did not affect the particle burn out times. 46-3

Impact of Coal Properties on Combustion Characteristics in a Pulverized Coal Furnace

Byoung-Hwa Lee, Ryang-Gyoon Kim, Ju-Hun Song, Young-June Chang, Chung-Hwan Jeon, Pusan National University, SOUTH KOREA

Coal is an important energy resource to meet the future demand of electricity because its reserve is more abundant than those of other fossil fuel. At the present time, bituminous coal has been largely used in the thermal power stations Korea because of its high heating value and high ignitability. However, since the demand for coal is considered to be getting more and more worldwide, it is desired that low-rank coals with high moisture and high volatile matter content because of low price and abundant reserve in the worldwide, such as sub-bituminous coal and lignite coal can be utilized. It is, therefore, of great importance to sufficiently clarify the effects of moisture and

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volatile matter content in the coal on the pulverized coal combustion characteristics. This study is to investigate the effect of the moisture, volatile matter and size in the coal on the pulverized coal combustion characteristics by means of a three-dimensional numerical simulation method. The results show that combustion temperature in the boiler utilizing sub-bituminous coal is entirely getting lower as the moisture content in a coal increase, because of heat loss driven from latent heat of vaporization and reduction of heating value from moisture. When sub-bituminous coal is utilized in order to get equivalent output power in the boiler which was designed for bituminous coal, more amount of coal should be injected in boiler with increasing air. At that time, the temperature in the boiler tends to lower as expected, because of cooling effect for air. So, to get the equivalent power for sub-bituminous, the more amount of coal must be injected. The more volatile matter content in a coal is, the more combustion occurs quickly and rapidly near burner. Therefore, as the temperature near region of burner becomes high, the burner is expected to be damaged. Also, mean temperature at the elevation burner located is higher than those of other elevation, because of characteristics of volatile matter. On the other hand, temperature in the part of super-heater where is rear region of boiler is lower, for the combustion time of particle is very short. In order to keep temperature like bituminous coal condition at the super-heater part where generate the steam, this paper presents that particle size is needed to be larger than that of the bituminous coal condition. As the particle size increases, the temperature rear region of boiler show tendency to return back to conditions where temperature is similar to bituminous coal condition, for combustion burning time of coal can be keep longer. This implies that in order to apply sub-bituminous coal into the boiler designed for bituminous coal, enlarging pulverized coal particle size could be an alternative to maintain appropriate temperature in the rear region of the boiler. 46-4

Highly Stable Bimetallic Nanocatalysts for Combustion Applications Anmin Cao, University of Pittsburgh; Goetz Veser,

University of Pittsburgh and DOE-NETL, USA Bimetallic nanoparticles are of great interest both from a scientific and a technological perspective. The existence of a second metal can introduce new chemical and physical properties and, in particular, lead to significantly improved catalytic properties compared to monometallic catalysts. As a result, investigations on the catalysis of bimetallic nanoparticles are currently increasing dramatically. However, a major issue with nanoparticle-based catalysts is the lack of thermal stability of these materials. In order to overcome this hurdle and making nanostructured catalysts viable for technical application, we previously developed a straightforward one-pot synthesis route for Pt-Barium Hexaaluminate (Pt-BHA) nanocomposite catalysts. These catalysts exhibits excellent high-temperature stability based on the thermal stability of the nanostructured BHA support. However, since the stability of the Pt is inherited from the ceramic support, the minimum stable nanoparticle size is ~10-15 nm in the temperature range above ~550 °C. Here, we present an extension of these studies in which we alloy the Pt nanoparticles with a second metal in order to enhance their intrinsic thermal stability towards higher temperatures. A series of PtM-BHA, where M = Fe, Cu, Ru, Rh, and Pd, were synthesized in a straightforward extension of oue previous one-pot synthesis route, and were tested for their activity and stability in methane combustion. For PtRh-BHA nanocomposites, in particular, we find exceptional stability of the bimetallic nanoparticles. The nanoparticles are homogeneously dispersed throughout the BHA support, and show a narrow size distribution around 4 nm. Most importantly, they can sustain extended high- temperature calcination at temperatures up to ~850 ºC without significant changes in their particle size distribution. Interestingly, this stability is a sensitive function of the Pt:Rh ratio. The PtRh catalysts are furthermore highly active combustion catalysts with ignition temperatures for methane combustion (1% CH4 in air) as low as 450 ºC and complete conversion at 580 ºC. As expected from the high-temperature calcination stability, the catalyst is stable in successive ignition-extinction cycles, in contrast to commercial Pt/Al2O3 and our previously synthesize monometallic Pt-BHA catalysts which show lower activity and different degrees of deactivation over several cycles. Synthesis and sintering behavior of the PtM-BHA catalysts as function of Pt:M ratio, and results from the methance combustion studies will be discussed in detail in the presentation. 46-5

Use of CFD Modeling to Design the Nose of a Pulverized Coal-Fired Boiler

Zumao Chen, Joseph T. Buckler, Scott A. Dudek, The Babcock & Wilcox Company, USA

In a pulverized coal-fired boiler, uniformity of the gas temperature profile at the furnace exit is vital for uniform heat transfer to the water tubes in order to avoid local overheating of the tubes, since local overheating often leads to tube failure. In addition, a non-uniform gas temperature profile in the upper furnace may also lead to slag buildup on the convection pass tube surfaces. The boiler nose plays a crucial role in achieving a uniform gas temperature profile at the furnace exit by promoting mixing of the flue gas entering the convection pass. The boiler nose also shields the tube banks in the upper furnace from the strong radiation of the burner region. An additional benefit

of adequate flue gas mixing at the boiler nose is a lower CO concentration at the stack. In this paper, computational fluid dynamics (CFD) modeling is used to design the nose of an opposed wall-fired radiant boiler. The combustion performance of the boiler with a new nose design is compared to that with the existing shorter nose. The effect of the extension of the existing nose on changes in the gas flow field and the gas temperature distribution in the upper furnace is discussed. The objective is to optimize the flow distribution before entering the convection pass and to enhance flue gas mixing for reduction of CO concentration at the furnace exit.

SESSION 47

COAL SCIENCE: COAL GEOSCIENCE – 3

This SESSION was canceled.

SESSION 48

COAL-DERIVED PRODUCTS: SYNGAS UTILIZATION (GAS TURBINES, FUEL CELLS)

48-1

DOE’s SECA Program: 2009 Progress & Plans Wayne A. Surdoval, DOE-NETL, USA

Developing technology to ensure that the use of coal is an economic energy source while maintaining America’s ever tightening environmental and climate requirements is of crucial U.S. national importance for solving today’s energy security concerns. The U.S. Department of Energy’s (DOE) is sponsoring the research and development (R&D) of solid oxide fuel cells (SOFCs) under the Solid State Energy Conversion Alliance (SECA). SECA is leading the way to low-cost, environmentally-friendly, fuel-flexible SOFCs and coal-based SOFC power generation systems for stationary markets. SECA is managed by the DOE’s National Energy Technology Laboratory (NETL) Program Office, in partnership with private industry, educational institutions and national laboratories. SECA has three major focus areas: Cost Reduction, Coal-Based Systems, and Core Technology R&D. The SECA Cost Reduction goal is to reduce the manufactured cost of SOFC power systems to $700 per kilowatt (2007 basis) by 2010. Concurrently, Coal-Based Systems is pursuing the scaling, aggregation and integration of the technology for use in large Integrated Gasification Fuel Cell (IGFC) systems for central power generation applications in order to efficiently and cleanly utilize the nation’s large coal reserves. The performance of IGFC systems will be consistent with Fossil Energy’s Advanced Power Systems goals, including over 45 percent efficiency (coal higher heating value HHV to electricity) with 90 percent carbon capture. Megawatt (MW)-class proof-of-concept systems will be demonstrated no later than 2012 and 2015. By 2017, the MW demos will have sufficient operating experience and integration of fuel cell and heat recovery (turbines) to warrant sponsoring a Clean Coal Power Initiative resulting in a 250-500 MW IGFC system by 2020. In support of these goals, SECA Industry Teams are establishing the requisite manufacturing base, and the SECA Core Technology Program is providing vital R&D to further improve on the substantial progress made through the SECA program. The first series of SOFC system prototypes fielded by the SECA Industry Teams surpassed SECA’s intermediate-targets for efficiency, reliability and production cost. Furthermore, NETL analyses show that an IGFC system with a pressurized SOFC and catalytic gasification with recycle permits a high net efficiency approaching 60 percent HHV with carbon capture of 99 percent. Separate fuel and air streams to the SOFC substantially reduce the amount of water required to condense, recycle and reuse process water, and without a steam cycle, there is virtually no external water requirement. The high efficiency maintains an economic cost of electricity (COE) due to less fuel per megawatt hour and a smaller plant. Meeting SECA goals result in the lowest COE coal option with environmental regulation compliance that effectively eliminates the carbon footprint and has near-zero water requirements. This technology makes substantial strides in permitting clean economic energy production from coal in any state in the U.S. 48-2

Concept Evaluations for an Efficient Coal-Fueled Solid Oxide Fuel Cell Power System Equipped for CO2 Separation

Arun K.S. Iyengar, Eugene E. Smeltzer, Daniel Danila, Wayne L. Lundberg, Siemens Energy, Inc., USA

Concept development and evaluations are underway at Siemens for a baseline electric power generating system fueled with coal syngas, operating with high electric efficiency, and equipped for CO2 separation. Basic design objectives are that the system must include a solid oxide fuel cell module basis, its net electric power capacity and efficiency must exceed 100 MWe and 50% (net AC/coal HHV), at least 90% of

42

the carbon exiting the gasifier in the syngas stream must be captured in CO2 form, and the design must meet specified equipment cost objectives. In addition to updating system performance and cost estimates from the completed initial phase of project work, studies have continued during the past year to evaluate the potential performance effects of applying advanced coal gasification, syngas cleanup, and fuel cell module design features. The reference baseline power system cycle concept is described, current baseline system performance and cost estimates are discussed, and results of selected advanced-system studies are reviewed. All work reported was done under U.S. Department of Energy contract no. DE-FC26-05NT42613. 48-3

Examination of the Performance of a Coal Based Gas Turbine Fuel Cell Hybrid Power Generation System with Pre-Combustion Carbon Capture

and Staged Compression and Expansion John Van Osdol, Edward Parsons, DOE-NETL, USA

In recent years there has been significant interest in different carbon capturing technologies that might be applied to fossil fuel power generation plants. These technologies are intended to reduce the amount of CO2 that would normally be emitted into the atmosphere. In terms of system efficiency and operating costs carbon capture technology is expensive. The additional equipment that would be used to capture these emissions often requires an auxiliary heat source and they add to the complexity of the system. There has also been significant interest in coal based gas turbine solid oxide fuel cell hybrid power plants. A gas turbine fuel cell hybrid power plant can have a greater efficiency than a conventional gas turbine power plant because the heat that is normally unused in a standalone fuel cell is recovered in the hybrid system, and used to drive the turbine. It is thought that the increased system efficiency of the hybrid system might compensate for the increased expense of performing carbon capture. In order to provide some analytical insight on how to best use the heat that is generated from a solid oxide fuel cell (SOFC) in a coal fired power system we examine several different configurations. In each system we assume that a 200 MW SOFC is driven by a coal derived syngas. Each system uses an isolated anode stream and assumes that carbon capture has been performed upstream of the fuel cell thus providing a hydrogen rich syngas to the SOFC. This differs from hybrid systems which have been previously posed where an isolated anode stream was used as a means to isolate and capture CO2 after the syngas has passed through the fuel cell and a post combustion process that is fed with pure oxygen producing an exhaust stream of water and CO2. The configurations in this study are different in that the anode and cathode streams remain isolated so that the expansion leg of the heat engine cycle may be staged. By staging both the compression and expansion processes of the hybrid system we show that there is increased availability of useable heat over single staged systems. Maximizing this availability would give the hybrid system more energy to drive other auxiliary processes that are necessary for coal fired systems. These auxiliary operations could include fuel reforming or shift reactions, pre heating of coal for the gasification system, reheating the syngas after cooling for cleaning, or even heating steam in a bottoming cycle. 48-4

Progress in Coal-Based Solid Oxide Fuel Cell Power Plant Development Hossein Ghezel-Ayagh, Richard Way, Peng Huang, Jim Walzak, Stephen

Jolly, Dilip Patel, Mike Lukas, Carl Willman, Keith E. Davis, FuelCell Energy, Inc; David Stauffer, Vladimir Vaysman, WorleyParsons Group Inc.;

Michael Pastula, Randy Petri, Versa Power Systems, USA; Eric Tang, Versa Power Systems, CANADA

Integrated Gasification Fuel Cell (IGFC) plants, incorporating solid oxide fuel cells (SOFCs), are expected to achieve an overall operating efficiency of greater than 50 percent—15 percentage points higher than today’s average U.S.-based coal-fired power plant—while separating at least 90 percent of the carbon dioxide emissions for capture and environmentally secure storage. Among the key features of the IGFCs are: near-zero emissions of SOx and NOx, low water consumption, and reduced effects on climate change, as compared to IGCCs. The SOFC systems are also anticipated to be cost-competitive with other power generation technologies. FuelCell Energy, Inc (FCE) has been involved in a multiphase program for development of very efficient coal-to-electricity IGFC plants. The project is being carried out through a cooperative agreement with the U.S. Department of Energy’s Solid Energy Conversion Alliance (SECA) program. Some of the key research and development activities include: cell and stack size scale-up, SOFC performance optimization, increased stack manufacturing capacity development, and MW-class conceptual design. FCE utilizes the SOFC technology of its partner, Versa Power Systems (VPS), in the development of IGFC power plants. The baseline centralized IGFC system design is being developed in collaboration with WorleyParsons Group, Inc. FCE has successfully completed Phase I of the project. Two VPS fuel cell stacks achieved 5,000 hours of service in February, 2009. The milestone marks a step toward the ultimate SECA objective of providing low-cost SOFC technology for coal-based power plants and other power generation applications. The FCE/Versa Power fuel cell stacks not only surpassed SECA's requirement of 5,000 hours of service, they also

exhibited an overall degradation of only 1.7 percent and 2.6 percent per 1,000 hours—much less than SECA's 2008 (interim) target of 4.0 percent per 1,000 hours. Phase II of the program is currently underway, focusing on optimization of cell and stack performance and modularization of the stack building block units into a MW-size module. The Phase II goals include a demonstration test of a ≥ 25 kW stack tower, running for 5,000 hours with a degradation of less than 2.0 percent per 1,000 hours, and costs of $400 per kilowatt (in 2002 dollars) or less for the system power block. Concurrently, the conceptual design of a 1 MW Module Demonstration Unit will be completed, utilizing the optimized cell stacks in a 1 MW module. Upon successful completion of Phase II and selection by DOE to continue, Phase III of the project will focus on the design and fabrication of a 1 MW Module Demonstration Unit. While the 1 MW SOFC demonstration test is in progress, a 5 MW Proof-of-Concept power plant will be designed, built, and tested using syngas as the fuel for the power plant. Combined with existing carbon dioxide separation technologies, the power plant is expected to achieve ultra high efficiencies while emitting near-zero levels of emissions of SOx, NOx, and greenhouse gases to the environment. 48-5

Liquid Tin Anode Fuel Cell for Direct Coal Conversion Thomas Tao, Jeff Bentley, CellTech Power, USA

The Liquid Tin Anode (LTA) Fuel Cell can operate on gaseous, liquid and solid fuels containing hydrogen, carbon or hydrocarbon compounds. The LTA is the enabling technology for ElectroChemical Looping (ECL). ECL is a new concept for direct conversion of coal to power which is described in other papers. ECL combines multiple processes, reducing inefficiency and lowering capital cost compared to other advanced baseload technologies. The current version of the LTA, called Gen 3.1 was developed specifically to generate electricity from liquid hydrocarbon fuel. It has been shown to operate directly on military logistics fuel (JP-8) for over 100 hours with peak efficiency greater than 50%. The LTA has also demonstrated the ability to operate in the presence of sulfur and under sooting conditions. The LTA can also generate power directly from solid fuels. The power production in the LTA comes from the conversion of liquid tin to tin oxide: Sn(l) + 2 O2- = SnO2 (s) + 4 e [1] A solid fuel such as carbon can be used to reduce tin oxide back to tin via one of the following pathways. SnO2(s) + 2 C = 2 CO(g) + Sn [2] SnO2(s) + C = 2 CO2(g) + Sn [3] SnO2(s) + CO(g) = CO2(g) + Sn [4] CO2(g) + C = 2 CO(g) [5] Equations [2] and [3] describe direct oxidation of carbon, which has been demonstrated by CellTech Power. The Generation 3.1 cell incorporates a porous ceramic which provides containment of the tin anode and allows only gaseous products to interact with the tin. In this case, Eqs [4] and [5] describe the oxidation process. The LTA also makes power from hydrogen. The LTA can also be used for power production from hydrogen, with water as the product. This paper will describe CellTech’s work on small scale LTA cells operating directly on diesel and military logistics fuel. These small cells have also been operated on carbon, coal, biomass and other carbonaceous feedstock. This presentation will discuss the technical progress in small scale Liquid Tin Anode Fuel configurations. This work is supported by military organizations including the Office of Naval Research, the Army Research Laboratory and DARPA. Laboratory results of scale model testing of LTA cells will be presented including data on LTA operation on JP-8 and coal. Recent testing on JP-8 has demonstrated power density of 170 mW/cm2, which is close to the target performance for early markets. Further work on LTA cells and components to improve power density and longevity will be discussed. Coal can incorporate a number of elements which are potentially harmful to the fuel cell. Laboratory testing of tin/coal reactions has demonstrated that the tin coal reactor will act as a purifier, rejecting nearly all contaminants before they can reach the fuel cell. Details of laboratory testing of LTA cells spiked with key contaminates will be presented. Commercialization progress for small scale cells provides a foundation for moving to larger cells capable of integration into utility scale applications. Several conceptual approaches to cell scale-up have been developed. These approaches will be discussed and the key risk items being addressed in LTA commercialization efforts will be discussed.

43

SESSION 49

GASIFICATION: CO-GASIFICATION AND LOW-RANK COAL – 2

49-1

Co-Gasification of Biomass and Lignite in the Indirect Gasifier Milena B.J. Vreugdenhil, A. van der Drift, C.M. van der Meijden, Energy Research

Centre of the Netherlands, THE NETHERLANDS The Energy research Centre of the Netherlands (ECN) is developing an indirect biomass gasifier. This so called MILENA gasifier produces a nitrogen free and methane rich producer gas, which subsequently can be utilized in gas engines, gas turbines or even be further upgraded into Substitute Natural Gas (SNG). The MILENA gasifier is mostly operated on woody biomass in order to produce SNG. Since the MILENA is a fuel flexible gasifier, tests were done to see the influence of lignite on the overall process. Reasons for testing lignite are the abundance of lignite around the globe and the relatively low price of lignite. The results from the tests were rather promising, for up to 55 wt-% of lignite could be mixed with biomass and still be gasified. The gas composition changed quite drastically when introducing lignite. The hydrogen yield increased whereas CO decreased. Lignite also had a positive effect on the reduction of heavy tar compounds. These compounds are related to the fouling characteristics, which are a general gasification problem. The results in the paper deal with the effect of lignite on the producer gas composition, a brief overview of the sulphur species will be presented, the effect of lignite on the formation of tar is given and an overview of future plans is presented. These future plans comprise amongst others, the construction of a 50 MWth SNG production plant. In this plant the ECN gasification and tar removal technology will be coupled with more conventional methanation catalysts to produce SNG. In this process roughly 40% of the carbon in the biomass ends up in a pure CO2 stream, which can be sequestrated making the whole process 70% CO2 negative (beyond CO2 neutral). When partly replacing biomass with much cheaper lignite, the process may remain CO2-neutral, while being economically more viable! 49-2

Low Temperature Gasification of Biomass using Ni-Loaded Brown Coal Takayuki Takarada, Kayoko Morishita, Gunma University; Liuyun Li,

Xianbin Xiao, Gunma Industry Support Organization, JAPAN The low temperature pyrolysis and steam gasification of biomass using Ni-loaded brown coal char as a catalyst for tar cracking and reforming were investigated in a two-stage quartz fixed bed reactor and a Internally Circulating Fluidized-bed Gasifier (1kg/h) at the temperature range of 450 - 650 °C. A typical livestock waste, swine compost, and wood chip were used as biomass samples. Loy Yang brown coal from Australia was used as a catalyst support. The nickel-loaded coal sample was prepared by impregnation method. Ni loading was about 9wt%. A commercial nickel catalyst (Ni/Al2O3, 0.5~1.0 mm, Ni loading 20±2 wt %) and silica sand (0.5~1.0 mm) were used as reference materials. When swine compost was gasified at 650 °C using silica sand, the gas yield was quite low, that is, 12mmol/g-sample and much tarry materials (about 30wt%) were produced. On the other hand, when Ni-loaded brown coal char was used in the gasification of swine, the gas yield enormously increased by 3.1 times compared with that obtained using silica sand and almost no tarry material was produced. It is noteworthy that almost all the nitrogen-containing products (NH3, HCN, N-containing liquids) were converted to N2 in the case of Ni-loaded brown coal. Large catalytic effectiveness for tar cracking and reforming was recognized above 500 °C. A part of Ni-loaded brown coal char was gasified during the gasification of biomass. The experiments in the fluidized bed demonstrate that ICFG can operate well by using nickel catalysts and the combination of the high performance catalyst with the fluidized bed reactor provide a suitable system for hydrogen, high calorific fuel gas and syngas productions from biomass. 49-3

Thermochemical Conversion of Coal-Biomass Feed Mixtures Nicholas C. Means, Paul Zandhuis, DOE-NETL; NETL Site Support

Contractor, Parsons; Goetz Veser, University of Pittsburgh and DOE-NETL; Dirk Link, Bryan D. Morreale, DOE-NETL, USA

The United States Department of Energy’s National Energy Technology Laboratory (NETL) is working to develop technologies that allow for the efficient conversion and utilization of domestically abundant resources in an effort to mitigate environmental issues, improve national security and develop greater fuel independence. Coal, an abundant natural resource, can be utilized by thermochemical processes to produce electricity, hydrogen, liquid fuels or other chemicals. Co-gasification of coal and non-food oriented biomass can prolong national fossil energy resources while reducing many environmental issues. Gasification can often be considered a two-stage process at low heating rates and a single stage process (simultaneous pyrolysis and gasification reactions) at high heating rates. Pyrolysis, a devolatilization reaction involving the

breakdown of the macromolecular structure of carbonaceous fuel material and the release of volatile gases (CO, CO2, H2, CH4, H2O, etc.) and liquid products, first occurs during heat-up. After devolatilization is complete, the residual solid (char) is free to react by gasification reactions to produce syngas components. In order to further understand gasification phenomena, both reactions will be investigated at various feed compositions and reactor conditions. The focus of this paper is on the first and most complex pyrolysis reaction. An experimental study on co-pyrolysis of Illinois#6 coal and switch grass was done in a semi-batch reactor at conditions consistent with an entrained gasifier. Co-pyrolysis experiments were performed in an effort to gain an understanding of the effect of coal-biomass co-fed products on reaction kinetics and gaseous, liquid and solid product distributions. Coal and biomass were fed to the reactor with varying feed ratios (100%, 85%, 70%, 50% and 0% coal, balance biomass). Primary gaseous products (CO, CO2, CH4, H2 and H2O) were monitored and analyzed online using quadrupole mass spectrometry and infrared gas analysis of CO and CO2. Trace gaseous products were collected as a batch and analyzed using gas chromatography/mass spectrometry. Tar/liquid product analysis was done using gas chromatography/mass spectrometry and residual solid analysis was done with inductively coupled plasma optical emission spectroscopy. Initial results indicate that the addition of small quantities of biomass to coal can improve gaseous product yield and decrease product sulfur species. 49-4

Product Characterization for Entrained Flow Coal/Biomass Co-Gasification

Boris Eiteneer, Ramanathan Subramanian, Shawn Maghzi, David Wark, John Arnason, GE Global Research, USA

GE Global Research (GEGR) is conducting an R&D program sponsored by the U.S. Department of Energy’s National Energy Technology Laboratory (DOE/NETL) under contract DE-NT0006305 on co-gasification of coal/biomass mixtures. Substantial experience and knowledge had been developed worldwide on gasification of either coal or biomass. However, reliable data on effects of blending various biomass fuels with coal during gasification process and resulting syngas composition are lacking. The primary project goal is to perform a complete characterization of the gas, liquid, and solid products that result from the co-gasification of various coal/biomass mixtures with focus on biomass concentrations between 30 wt.% and 50 wt.% (dry coal and dry biomass basis). The outcome of this project will provide guidance on the appropriate gas clean-up systems and optimization of operating parameters for development of future gasification systems. Under this project, GEGR performs a comprehensive characterization of the coal/biomass co-gasification products using a bench-scale gasifier (BSG) and a pilot-scale entrained flow reactor (EFR). Experiments are performed on mixtures of the three major types of coal (bituminous, sub-bituminous, and lignite) with three types of biomass (corn stover, wood, and grass). Biomass feedstocks include wood sawdust as a representative wood biomass and switchgrass as a representative herbaceous biomass. Wood sawdust and milled switchgrass are well suited for experimental testing in the small-scale entrained flow gasification facilities. The first part of the project focuses on using the BSG to map the composition of the gaseous, liquid, and solid products, define their concentration ranges as functions of coal/biomass mixture composition and operating conditions, and optimize product analysis methods and procedures. The atmospheric pressure entrained-flow BSG can achieve temperatures up to 1,400ºC and particle residence times up to 5 seconds. At the outlet of the gasifier, the product stream is rapidly quenched by an inert gas. The solid (char, soot, ash, aerosols), liquid (tar), and gaseous products are analyzed separately by on-line and off-line methods. Morphology of solid char and ash samples is characterized using a scanning electron microscope (SEM). Inductively coupled plasma-atomic emission spectroscopy (ICP-AES) and inductively coupled plasma-mass spectrometry (ICP-MS) with appropriate sample digestion methods are applied to determine the minor and trace metal concentrations in the fuel samples and gasification products. GE’s unique state-of-the-art EFR experimental test facility will be used in the second part of the project to perform a focused set of experiments based upon the initial results obtained from the BSG. The EFR will provide the bulk of high-fidelity quantitative data under temperature, pressure, heating rate, and residence time conditions closely matching those of commercial oxygen-blown entrained flow gasifiers. The EFR is comprised of a gasifier section with residence time of up to 5 seconds, a syngas cooling section with residence time of up to 40 seconds, and a test section equipped with an array of access ports and analytical equipment. The EFR will operate at temperatures up to 1,600ºC and pressures up to 65 bar. The syngas cooling section of the EFR will be configured to replicate the temperature profile and residence time of a commercial radiant syngas cooler. Accurate matching of syngas time-temperature history during cooling ensures that complex species interactions including homogeneous and heterogeneous processes such as particle nucleation, coagulation, surface condensation, and gas-phase reactions will be properly reproduced and will lead to representative syngas composition at the syngas cooler outlet. While the main gasification products for both fuel types comprise H2, CO, CO2, and H2O, albeit in varying concentrations, the makeup of minor components of the syngas can change dramatically depending on chemical compositions of both coal and biomass as well as process conditions. In particular, the higher alkali metal content of biomass, relative to coal, poses a serious operational problem since these metals are

44

contained largely in water-soluble forms and can easily vaporize at the high temperatures encountered in commercial EF gasifiers. The condensation of volatile metals can form sticky deposits on heat exchangers and downstream gas clean-up equipment. The gas-phase alkali species formed in gasification process are predominantly chlorides and hydroxides, whereas the condensed phase metal species consist mainly of silicates. The critical control variables that affect the formation of the gas-phase alkali species include the concentrations of sulfur, silicon, and particularly chlorine, and gasification conditions such as pressure, temperature and the oxygen/fuel ratio. In addition to posing operational difficulties, nitrogen, sulfur, alkali and chlorine species (including H2S, COS, NH3, HCN, chlorides, and particulates) act as severe poisons to commercial FT catalysts. The experimental work is leveraging other ongoing GE R&D efforts such as biomass gasification and dry feeding systems projects. Experimental data obtained under this project will be compared with predictions of the advanced gasification model that is currently being developed by GE under internally funded Gasification Fundamentals program. Comparison with fundamentals-based model will allow extending the applicability of the project’s findings and provide guidance on the appropriate clean-up system(s) and operating parameters to coal and biomass combinations beyond those evaluated under this project.

SESSION 50

GASIFICATION: ADVANCED TECHNOLOGIES – 3

50-1

NETL Advances IGCC Technology with CO2 Capture by Working to Establish Dynamic Simulation Research and Training Center

Graham T. Provost, Herman P. Stone, Michael McClintock, Fossil Consulting Services, Inc.; Stephen E. Zitney, Eric Liese, DOE-NETL; Richard Turton, Debangsu Bhattacharyya, West Virginia University; Merrill Quintrell, Jose

Marasigan, EPRI; Michael R. Erbes, Enginomix, LLC, USA In this paper, we highlight the Department of Energy’s (DOE) National Energy Technology Laboratory (NETL) project to develop a generic, full-scope, real-time dynamic plant simulator for a commercial-scale, coal-fired, integrated gasification combined cycle (IGCC) plant with CO2 capture. The IGCC simulator will be deployed at NETL’s Dynamic Simulator Research & Training Center co-located at NETL and the National Research Center for Coal & Energy (NRCCE) at West Virginia University (WVU). The Simulator, under development by Invensys Process Systems (IPS), will combine a process/gasification simulator with a power/combinedcycle simulator together in a single dynamic simulation framework for use in engineering research studies and training applications. The Simulator, scheduled to be launched in midyear 2010, will have the following capabilities: • High-fidelity, dynamic model of gasification-side (gasification and gas cleaning with CO2 capture) and power-block-side (combined cycle) for a generic IGCC plant fueled by coal and/or petroleum coke. • Ability to enhance and modify the plant model to facilitate studies of changes in plant configuration, equipment, and control strategies to support future R&D efforts. • Highly flexible configuration that allows concurrent training on separate gasification and combined cycle simulators, or up to two IGCC simulation sessions at the same time. • Training capabilities including startup, shutdown, load following and shedding, response to fuel and ambient condition variations, control strategy analysis (turbine vs. gasifier lead, etc.), representative malfunctions/trips, alarms, scenarios, trending, snapshots, data historian, etc. To support the acquisition of the Simulator, a detailed functional specification was developed including process descriptions and control strategies for all major sections of the plant. These descriptions now serve as the basis for building the Simulator. In this paper, we describe the engineering, design, and testing process that the Simulator will undergo in order to ensure that maximum fidelity is built into the dynamic IGCC simulator. Future applications and training programs associated with gasification, combined cycle, and IGCC simulations are discussed, including plant operation and control demonstrations, as well as education and training delivery. 50-2

GTI’s Syngas Sampling and Monitoring Systems for Performance Assessment and Environmental Characterization of Gasification

and Downstream Processes Tanya S. Tickel, Rachid B. Slimane, Chun W. Choi, Osman Akpolat, Bruce

G. Bryan, Gas Technology Institute (GTI), USA To support the development and commercialization of gasification technologies and provide a cost-effective platform for evaluating emerging syngas end-use applications, GTI has designed, constructed, and commissioned a state-of-the-art pilot-scale gasification facility, the Henry R. Linden Flex-Fuel Test Facility (FFTF). Built with support from the natural gas industry and the State of Illinois, the FFTF was successfully commissioned in early 2004 and has since been used in the performance

of several projects. To respond to the renewed enthusiasm for gasification technologies in recent years, the FFTF has been vastly expanded. The various programs have ranged from purely gasification projects, to evaluate the gasification characteristics of selected coal and biomass feedstocks, to very involved projects, which in addition to the U-GAS® fluidized-bed coal gasifier (or RENUGAS® gasifier for biomass), include various downstream syngas processing units (e.g., filter-reactors, tar reformers, sorbent vessels, sulfur scavengers, gas-liquid contactor for acid gas treatment, scrubbers, etc.) to clean and condition the product syngas for specific end-use applications. A necessary step in all these projects is the ability to monitor the gas composition from the time it leaves the gasifier until flaring. Other important analyses are also conducted on product/by-product solid and liquid samples for mass balance considerations as well as for environmental characterization. To address these needs, GTI has developed and implemented elaborate analytical approaches to equip its pilot plants with innovative sampling and monitoring systems. These state-of-the-art systems consist of “in-situ” gas sample extraction and conditioning probes, suitably conditioned (coated, internally-heated, and insulated) transport lines, and a suite of analytical instruments, which together have enabled comprehensive, real-time process performance assessment. Both the design of the sampling system’s configuration and the selection of suitable analyzers are made to meet the project’s scope and objectives in a cost-effective manner. These systems are flexible, making it possible to efficiently introduce the necessary changes or upgrades to best meet the needs of new testing programs. Significant successes have been made with these systems, including convincing demonstration of the capability of the filter-reactor concept (which exploits particulate control devices as chemical reactors for multi-pollutant control at hot/warm temperatures) to remove sulfur (H2S and COS) and halides (HCl) down to parts-per-billion (ppbv) levels. Another notable application is the complete characterization of biomass-derived syngas, including speciation of tars and other contaminants, and performance assessment of a proprietary tar reformer in reforming tars and methane in a biomass-to-liquids technology validation program. In this paper, these systems are described, the rationale for their design is explained, and some non-proprietary examples of test results are provided to illustrate the type and usefulness of the information developed. Along with the wide range of unique test equipment available in GTI’s pilot facilities, these innovative analytical systems add significant value for conducting research on gasification enabling technologies (e.g., advanced IGCC-based power generation, coal-to-hydrogen, coal-to-SNG (substitute natural gas), coal-to-liquids via Fischer-Tropsch synthesis, biomass-to-hydrogen, -SNG, -liquids, CO2 capture research, etc.) that have shown promise in laboratory- and bench-scale testing and need evaluation at the next scale. 50-3

Tunable Diode Laser Absorption Temperature Measurements in a Fluidized-Bed Gasifier

Jay B. Jeffries, Andrew Fahrland, Wanki Min, Ronald K. Hanson, Stanford University; Daniel Sweeney, David Wagner, Kevin J. Whitty, University of

Utah; Robert C. Steele, Electric Power Research Institute, USA Tunable diode laser (TDL) absorption has proven highly effective for time-resolved in situ sensing of gaseous flows, and as a result such sensors are utilized increasingly in the development and control of advanced energy conversion technologies, where TDL sensors provide concentration of selected species as well as gas properties such as temperature and/or velocity. Coal gasification presents two challenges to laser absorption sensing. First, the particulate loading in the reactor or even the exhaust stream from a reactor is high, which strongly attenuates the transmitted laser light intensity by scattering. Second, modern gasifier designs anticipate pressures as high as 80 atm, and the absorption transitions in gases are broadened by collisions complicating the interpretation of direct absorption strategies often used for atmospheric pressure flows. Recent advances in diode laser technology have provided highpower diode lasers that can sustain large scattering losses and still provide a gas-phase absorption signal. Here we have developed a normalized wavelength-modulation strategy for absorption measurements with non-absorption losses. This wavelength modulation strategy has proven quite robust for measurements at elevated pressures; successful measurements of gas temperature have been performed using TDL sensing of water vapor at pressures above 30 atm. Here we report TDL absorption measurements of gas temperature in a pressurized, pilot-scale, bubbling fluidized-bed gasifier using absorption transitions of water vapor in the near-infrared, which can be accessed by robust telecommunications diode lasers. Measurements were made in the reactor freeboard during the gasification of black liquor where the char particulate attenuated the transmitted beam intensity by more than 90%. Measurements were also made in the splash zone above the bed (without black liquor fuel), where the motion of the bed particulate produces rapid time-varying transmission. Successful temperature measurements in the presence of the large intensity attenuation by particulate scattering provide proof-of-concept for the use of TDL absorption as a time-resolved temperature (and gas composition) diagnostic for application to coal gasification. These results include the first known TDL absorption measurements in an operating gasifier. Development of TDL-based monitoring of harsh environments is a continuing goal, with particular focus on in situ measurement of temperature and gas composition in high-pressure entrained-flow coal gasifiers.

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50-4 Decentralized vs. Centralized Control of IGCC Power Cycles

Priyadarshi Mahapatra, B. Wayne Bequette, Rensselaer Polytechnic Institute, USA

Integrated coal gasification and combined cycle (IGCC) power plants pose a classic example for complex, large scaled, nonlinear, highly interacting, multirate system. One might not find a better problem to test rigorousness and robustness of a controller design/algorithm which could simultaneously address all of these plant characteristics in a manner which ensures highest efficiency and safe plant operation in the face of multiple disturbances and rapid variation of demand and supply. An approach one takes in these scenarios can vary from simplistic single level fully-decentralized mode, which although simple to design and significantly intuitive and adherent to any operator, is far from the best possible operating route; to a complex multilayer control architecture, where a centralized supervisory layer keeps track of the overall economics, logistics and performance of the plant while providing best possible or “optimized” setpoint signals to the lower level of controller hierarchy, which in turn are designed to meet the setpoints in the “best” possible way. An IGCC plant is an assimilation of similar operating units or subsections which share characteristics such as tight energy integration, similar process objectives or time scales. These subsections closely interact among themselves through material and energy flows which in turn provide natural hierarchy for high level control structure design. The focus of this paper is to investigate, through rigorous dynamic process modeling in Aspen Plus/Dynamics, a comparison of controller design performance among a fully-centralized model predictive controller (MPC) for the Air Separation-Gas Turbine/Combustor-Gasifier power loop; a semi-centralized design where each sub-section is controlled by centralized MPC passing setpoint information among each other; and a fully decentralized IMC based PID controller design where each control loop remains oblivious to others presence. It is apparent and has been shown that the process variables operating at different time-scales pose significant problems when operating in simple PID-based control schemes. Whereas this might seem intuitive for a complex integrating process, a sub-section operating at much faster rate as compared to others, such as the gas-turbine/combustor, does not provide much performance improvement when switching to more complex centralized design thus deteriorating the overall performance of IGCC power cycle. Finally, we close with a discussion of future work on implementation of multiple time-scale and multiple model predictive control (MMPC) to study controllability of entire IGCC power plant.

SESSION 51

SUSTAINABILITY AND ENVIRONMENT: GENERAL – 2

51-1

Projections for Ultimate World Coal Production from Production Histories

David Rutledge, Caltech, USA How should we go about making a projection for ultimate world coal production? Ultimate production here means total production, past and future. Such a projection, if credible, would be important for climate change policy, because the time scale for the climate response from burning coal is much longer than the time for burning it. In addition, the time scale for coal production is important for considering the development of alternative power sources. Historically, coal reserves were meant as estimates of ultimate production. This is different from oil reserves, where much oil was undiscovered, and for this reason, not included in reserves. Reserve numbers for coal may be available quite early in the production cycle. For example, in Great Britain, a detailed reserves study was done by a Royal Commission in 1871. However, now that 150 years have passed, and British coal production is 16 times less than peak production, we can see that the reserves were too high. Britain has produced only 18% of the coal that the Commission thought was minable. It turns out that by fitting a logistic curve to the cumulative production history, an accurate projection for the ultimate (28 Gt, production in this paper is given in metric tons) becomes available by 1904, and it has never been more than 10% off since. There is a similar pattern for three other mature coal regions where exhaustion has reached 99%: Pennsylvania anthracite (5 Gt), France and Belgium (7 Gt), and Japan and South Korea (4 Gt). In each case, reserves are available early in the production cycle, but they were too high, and a curve fit to the production history gives better accuracy. In addition, logistic and cumulative normal curve fits are used to make projections for ultimate coal production for ten active regions: Western US, Eastern US, Europe, China, South Asia, Canada, Latin America, Russia, Australia, and Africa. In eight of the ten, I am able to fit either a logistic or a cumulative normal to make a projection for the ultimate. The projected ultimates are Western US 46Gt, Eastern US 83 Gt, Europe 127 Gt, China 117 Gt, Canada 4 Gt, Russia 83 Gt, Australia 52 Gt, and Africa 23 Gt. For South Asia and Latin America, the curve fits fail, because cumulative production has been growing by 5% per year in both. For these two, I use reserves to estimate the ultimates (South Asia 78 Gt, Latin America 19 Gt), recognizing that the reserves are likely to be high, but hoping that this would compensate for an under-estimate elsewhere, such as a North

Slope coal field that do not currently have rail access. The total for the 14 regions gives a projection for the world ultimate, 676 Gt. The historical range for the projection since 1994 is 662 to 693 Gt. The projection is 60% of the current World Energy Council reserves plus cumulative production (1,130 Gt). 51-2

Co-Firing Biocarbon Energy Pellets with Coal: Engineered Properties for Supply Chain and Combustion Compatibility

Hugh McLaughlin, Alterna Energy Inc., CANADA The limitations when co-firing wood pellets in conventional coal combustion infrastructure are dictated by the chemical and physical characteristics of the biomass product and flexibility of the original combustion train. As such, unless the original design fuel was lignite, the range of co-firing with wood is generally less than 15% of the energy duty. Biocarbon Energy Pellets are biomass-based fuel that has been engineered for compatibility with installed coal combustion trains. The starting lignocellulosic biomass is thermally carbonized to fuel biocarbon, which is basically a charcoal that is manufactured to higher volatile and yield than biocarbons intended for soil application, metal refining or adsorption applications. The carbonization conditions are flexible enough to fine-tune the biocarbon combustion properties to the intended combustion outlet with respect to combustion reactivity and rate of heat release. The actual physical properties of the biocarbon are typically different from the original coal fuel properties due to the higher porosity and internal surface area of biocarbons. After carbonization, the biocarbon is further processed for the supply chain requirements and can, again, be tailored to the specifics of the intended destination for the biocarbon product. The starting biocarbon is low density and very friable. It is subsequently processed to achieve higher density to improve transportation economics and formed into a variety of shapes, including pellets, briquettes and larger extruded cross-sections and lengths. The water-repellency and crush properties can be adjusted to meet specific supply chain conditions, including extended unprotected storage. Conceptually, Biocarbon Energy Pellets are like Biodiesel, where the starting fuel, raw biomass or vegetable oil, has been modified to create compatibility with the existing fuel-consuming infrastructure. There are economic advantages to be realized in the higher energy density, which lowers the transportation burden per unit of fuel delivered. The major advantage of converting the starting biomass into biocarbon is the ability to consume the fuel in existing coal combustion trains with little or no modification to the existing installed equipment. The paper will review the overall carbonization and densification technologies, then focus on the range of physical and chemical properties available for Biocarbon Energy Pellets and other shapes of densified biocarbon. 51-3

A Synergistic Analysis of Coal Based IGCC and Corn Based Ethanol Production

Donald J. Chmielewski, Illinois Institute of Technology, USA The objective of this work is to identify potential synergies between a dry-mill corn fed (EtOH) plant and a coal based Integrated Gasification Combined Cycle (IGCC) power plant. The general conclusion is that heat integration opportunities do exist between EtOH production and IGCC, and indicate that further investigation of the topic is warranted. Specific results indicate that in a best case scenario all of the heat load due to EtOH distillation, evaporator and drum dryer could be met by unutilized heat from the IGCC, and would result in significant economic and carbon emission benefits. In the worst case scenario, it is concluded that only a significant portion of drum dryer load could be met, which would still yield significant economic and moderate carbon emission reduction benefits. 51-5

Biogenic RDF: A New Emerging Renewable Fuel Source from MSW Kevin Furnary, LEEP Holdings, LLC; Tom Balkum, Balkrete, Inc; Bill

Ellison, Ellison Consultants, USA An assessment is offered of a BIOGENIC (rdf) Refuse Derived Fuel to be delivered to power generators for co firing with Fossil Fuels or to WtE power generating facilities, and convert the recovered Non-biogenic plastics into Balkrete Engineered Aggregate, a LEED Compliant hardened concrete component of the building trades, sequestering this carbon component in perpetuity. The BIOGENIC rdf, is produced using best-in-class technology. High torque, low speed primary shredders will deliver mixed Municipal Solid Waste (MSW) reduced to 4-6” size to trommel screens, thus removing glass and moisture, then to magnetic and eddy current metal separators, and finally to LEEP Separating Towers to fractionate out the above non-biogenic high-carbon plastic component. The resultant Biogenic MSW Fraction, a renewable fuel, is then delivered to the benefit of combustion boilers assisting, where appropriate, in meeting applicable Renewable Portfolio Standards (RPS). A 1500 ton per day Urban Municipal Solid Waste Plan will create approximately 450-900 tons of Biogenic Renewable fuel to be further processed to be compatible with Pulverized coal boilers and Circulating fluid bed boilers and, as needed, to be injected

46

via LEEP Methods to the combustion process. The Balkrete process will sequester an additional 100-200 tons of fractionated non-biogenic, high-carbon plastic as an Engineered Aggregate. For every ton of Plastic so converted, 3 tons of CO2 emissions are avoided: in this example, 300-600 tons daily.

SESSION 52

COMBUSTION: FLUE GAS CLEAN UP

52-1

Regenerable Copper-Based Sorbents for Simultaneous Removal of SOx and NOx from Flue Gas

Javad Abbasian, Illinois Institute of Technology; Vasudeo Gavaskar, Gas Technology Institute, USA

Simultaneous removal of SO2 and NOx from flue gases can be accomplished at elevated temperature using a regenerative fluid-bed process based on the utilization of dry regenerable copper-based sorbents. Regenerable processes offer advantages over the once-through processes, which include elimination of large quantities of waste materials and conversion of captured sulfur to salable products. However, highly reactive and attrition resistant sorbents are needed to make these processes economically more attractive than a combined traditional FGD and SCR processes. This paper discusses the results obtained in a fluidized-bed for removal of SO2 and reduction of NOx using highly reactive and attrition resistant regenerable copper-based sorbents (i.e., ICCI-10g) prepared by a modified sol-gel technique. The results obtained in this study indicate that the sorbent has eight times higher attrition resistance and two times higher capacity compared to the sorbents prepared by conventional methods and capable of removing close to 100 percent of SOx and NOx from a simulated flue gas. The results of the long-term durability tests indicate a small decrease in its sulfur capacity over the initial 15 cycles, which appeared to stabilize after about 15-25 cycles. However, the catalytic activity of the sorbent is not affected by the cyclic operation. The sorbent is capable of 100% NOx removal at NH3/NOx ratios at or above 1:1. Furthermore, the ammonia slip was determined to be about 6 ppmv with fresh sorbent, which gradually decreased in the cyclic process. No ammonia slip was detected after the 15th cycle. 52-3

Hydrogen Chloride Removal from Flue Gas using Novel High Reactivity Calcium Oxide

Zhenchao Sun, Fu-Chen Yu, Shwetha Ramkumar, Songgeng Li, William Wang, Liang–Shih Fan, The Ohio State University, USA

Hydrogen chloride is present in the flue gas from pulverized-coal combustion power plant at relatively low concentrations depending on the types of coal. Due to its toxic and corrosive nature, a gas clean-up process, either wet scrubbing or dry removal, has to be used to remove hydrogen chloride before emission. Major problems of existing processes include high energy penalty and low sorbent reactivity. Therefore, a lot of attention is put on the development of novel sorbent, which has higher reactivity, better high-temperature stability, and higher utilization. This novel high-reactivity calcium oxide, obtained from calcination of specially tailored Precipitated Calcium Carbonate (PCC), is investigated for its potential application in hydrogen chloride removal from flue gas. Compared to commercial lime or limestone sorbents, this studied PCC-CaO has higher surface area and larger porosity, which lead to better reactivity and more effective hydrogen chloride capture. Kinetics study shows that the chloridation reaction is the fastest around 550°C. Higher hydrogen chloride partial pressure as well as smaller sorbent particle size increases chloridation reaction rate. In addition, multi-cyclic Carbonation-Calcination Reaction (CCR) has less de-activating effect on PCC-CaO than on other studied CaO-based sorbents. Based on its outstanding properties, this novel sorbent demonstrates great potential and promise in the future hydrogen chloride removal process. 52-5

Comparing Flue Gas Cleanup Options via Dynamic Simulation Nick Elder, TRAX Engineering, USA

As legislation regulating power plant emissions becomes increasingly stringent, plants find it necessary to continue to add flue gas cleaning equipment to comply with these mandates. Different pieces of equipment are used to remove the various pollutants, and with so many viable options from which to choose, determining the most appropriate and economic solution can be difficult. Dynamic simulation is a convenient and well-proven method of comparing the merits of different proposed configurations. An accurate dynamic model allows direct comparison of alternative pieces of equipment. The choice of scrubber technology alone leads to many options including wet, dry, fluid bed, and bubbling reactor types. In addition, to accommodate the added flow resistance of the new environmental equipment, a plant typically requires modification to existing fans, or addition of new fans. This creates further design

choices, such as single or multiple fan configurations, booster fans or increased capacity induced draft (ID) fans, axial or centrifugal fans, and inlet guide vane (IGV) or variable frequency drive (VFD) control. Clearly, the number of possible configurations can become quite extensive. This paper discusses considerations that arise when constructing a dynamic model, validation of a model against plant data, and then the use of the model to evaluate various alternate equipment configurations. A case study is then used to illustrate this procedure.

SESSION 53

COAL SCIENCE: COAL GEOSCIENCE – 4

This SESSION was canceled.

SESSION 54

COAL-DERIVED PRODUCTS: COAL CO-CONVERSION WITH OTHER FEEDSTOCKS

54-1

Coal and Biomass to Gasoline: A Baseline Analysis of a Methanol-to-Gasoline (Mtg) System

Thomas J. Tarka, John G. Wimer, DOE-NETL, USA Concerns over energy supply security and oil price volatility has prompted a renewed interest in the production of transportation fuels from domestic resources. The fuels vary, as do their feedstocks, with consideration being given to everything from hydrogen to cellulosic ethanol and natural gas-based liquids. Numerous studies are currently underway evaluating the economics, scale, and energy conversion efficiency of producing these fuels. Furthermore, the growing awareness of global climate change has intensified the need for any fuel under consideration to have life-cycle greenhouse gas (GHG) emissions which either match or are reduced when compared to conventional petroleum fuels. One potential pathway is the production of gasoline from coal and biomass, via the Methanol-To-Gasoline synthesis process. This pathway enables the use of a renewable, low-carbon feedstock with an existing technology for liquid fuels production. This process has been operated at commercial-scales for over 10 years and produces a product which can be used in today’s fueling infrastructure. The National Energy Technology Laboratory (NETL) initiated a study in 2008 to better explore the potential for the production of gasoline through this process, with the goal of understanding plant performance, as well as the trade-offs between product selling price, GHG footprint, and scale achievable. Three different scenarios were examined, including the use of coal versus a mixture of coal and biomass, and the integration of Carbon Capture and Storage (CCS). This paper details the findings of this extensive study and serves to establish the baseline performance data of such a system. 54-2

Determination of the Effect of Coal/Biomass-Derived Syngas Contaminants on the Performance of Fischer-Tropsch

and Water-Gas-Shift Catalysts Jason P. Trembly, Matt E. Cooper, Brian S. Turk,

Raghubir P. Gupta, RTI International, USA Gasification of biomass/coal mixtures offers distinct advantages over gasification of either coal or biomass. For coal, the main benefit comes from the reduction in carbon emissions derived from using biomass/coal mixtures with as little as 30 % biomass. Using a biomass/coal mixture with about 30% biomass and CO2 capture and sequestration, CO2 emissions for transportation fuel production with Fischer Tropsch (FT) synthesis are about 25% of current emissions from production from crude oil. By comparison, using just coal for transportation fuel production with FT synthesis results in slightly more CO2 emissions than current production from crude oil with full CO2 capture and sequestration and about 80% more CO2 emissions with no CO2 capture and sequestration. By contrast, gasification of biomass/coal mixtures offers the potential to exploit economies of scale that are not possible with just biomass. Because different gasification technologies are used to derive syngas from biomass and coal and coal and biomass have different concentrations and types of contaminants, syngas generated from biomass/coal mixtures will have a unique contaminant composition. Syngas cleanup for gasification of biomass/coal mixtures will need to address the unique contaminant composition to support downstream processing and equipment. RTI is working with DOE to establish syngas cleanup specifications for utilization of gasification of biomass/coal mixtures for the production of transportation fuels using FT synthesis. To establish these specifications, RTI is testing commercial formulations

47

of water gas shift catalysts (high temperature, low temperature and sour) and FT catalysts (cobalt and iron) with different contaminants that would be expected in a syngas generated from biomass/coal mixtures. This testing program is being used to investigate the effect of single components and synergistic effects resulting from multiple contaminants. Prior to beginning this test program, RTI used thermodynamic equilibrium data to investigate the effects of single and multi-contaminant mixtures on the catalysts. The results from this testing were used to help select suitable parametric testing to accelerate identification of acceptable contaminant concentrations and associated long term effects on catalysts performance. These results will lead to identification of the most cost effective syngas cleanup technologies and processes. This presentation will detail the ongoing theoretical and experimental assessments to establish acceptable syngas contaminant specifications for water-gas-shift and FT catalysts for syngas derived from biomass/coal mixtures. 54-3

Investigation of the Impact of the Contaminants Produced by Co-Gasification of Coal and Biomass on the Commercial Fischer-Tropsch

and Water-Gas-Shift Catalysts Gokhan Alptekin, Ambalavanan Jayaraman, Bob Amalfitano,

TDA Research, Inc., USA In the co-gasification of coal and biomass, it is anticipated that ash, sulfur species, trace toxic metals, halides, and nitrogen species will be present. But the concentrations of these contaminants will be much lower in the synthesis gas generated by co-gasification compared to coal alone. The poisoning effects of heteroatoms (e.g., sulfur, nitrogen and oxygen) as well as halides and trace metals, are well-documented for the Water Gas Shift (WGS) and Fischer Tropsch (F-T) catalysts. Nevertheless, the impact of these contaminants must be re-evaluated at the reduced concentrations predicted for the CBTL application. In addition, the biomass feedstock will introduce a different spectrum of contaminants, including the vapors of alkali metals (such as sodium and potassium compounds) and their respective salts (e.g., KCl and NaCl), ammonia and phosphorous that could render the WGS and FT catalysts inactive. TDA Research, Inc with Department of Energy (DOE) funding is carrying out an investigation of the effects of coal and biomass contaminants on the performance (activity and selectivity) and life of the Water Gas Shift (WGS) and Fischer Tropsch (F-T) catalysts. In this study, we have first used thermodynamic modeling tools to identify contaminants that are most likely to react with the active phase and promoters used in the WGS and F-T catalysts. We then carried out screening experiments utilizing generic and commercial catalysts to measure changes in activity and selectivity due to exposure to contaminant species under representative conditions. In this paper, we will present the preliminary results from the catalyst development and contaminant evaluations done at TDA. 54-4

Coal and other Feedstock to Power, Liquids, and Gas Plant with Co-Products

Wm. Mark Hart, R&D Colorado School of Mines, USA The object of this paper is to provide some background on blended coal feedstock’s with wood products into the gasifier. Various feedstock mixtures will be discussed and examined as they transition through the gasifier from input to output. The characteristics of the syngas will be reviewed as they relate primarily to CO and H2. The presentation will include how the syngas can be cleaned to meet latest emission standards and future emission standards and subsequently a description of power, liquids, and gas will follow. Co-products will also be reviewed and discussed. It is contemplated that a real research and development project will be the center of this presentation. 54-5

Study on Coliquefaction of Cornstalk and Chinese Lignite Deping Xu, Xiangkun Guo, Fan Zhang, Fan Yang, Jin Liu, Zhihong Wang,

Yonggang Wang, China University of Mining and Technology, CHINA Coals are the foremost fossil energy resource, and liquid products obtained from coal conversion are the potential substitute of petrochemicals, in the future. Cornstalk (CS) is considered to be one of the most important renewable energy resource. The utilization of coals and CS, synthetically and cleanly, is increasing to be an emergent and exigent issue from the viewpoint of environmental protection and energy security. In this contribution, the coliquefaction processes of CS and Chinese lignite, Shengli Coal (SLC), were investigated to seek identified solutions to utilize coal and agricultural waste, effectively and cleanly. The coliquefying processes of CS and SLC were conducted varying temperature, initial hydrogen pressure and material formula ratio, in Tetralin. The result, conclusively, show that the CS seems to enhance the direct liquefaction of SLC. The maximum oil yield of can be obtained under 6MPa initial hydrogen pressure, and the oil yields can be considered to be stabilized in the pressure range of 6MPa to 9MPa. The oil yield of the co-liquefaction reach the maximum of 62.5% at the CS/SLC ratio of 2:8, the gas yield increases from 12.7% to 20.7% while the CS/SLC ratio changes from 1:9 to 5:5.

POSTER SESSION 1

COMBUSTION

P1-1

Simulation Analysis of Multi-Fuel Hybrid Cycles Marcin Liszka, Janusz Kotowicz, Lukasz Bartela,

Silesian University of Technology, POLAND The presented study deals with thermodynamic simulation of power units consisted of supercritical steam cycle (SC), pulverized-fuel boiler, gas turbine (GT) and heat recovery system using GT waste flue gas as heat source in steam cycle. Three variants of the integration of gas-fired and coal-fired plants have been proposed and analyzed. They are different in the arrangement of heat recovery system. First of them is based on preheating of steam cycle condensate and boiler feed water by flue gas leaving GT unit. Second option deals with an application of supercritical heat recovery steam generator which is placed in parallel to coal-fired steam boiler. The third analyzed case is a structural combination of two previous variants. Simultaneous application of natural gas and bituminous coal in the integrated power unit can be profitable in case of unstable fuel prices. Moreover, the GT load can be dynamically changed to match the power system requirement which gives additional profits to plant operators on the peak-load operation. On the other hand in case of base-load GT operation the crucial parameter is efficiency of gaseous fuel utilization. Taking into account that natural gas can be converted into electricity as a sole fuel in conventional gas turbine combined cycles by efficiency close to 60% (LHV based), its alternative utilization in analyzed gas&coal cycles should be carefully examined. Thermodynamic evaluation has been thus based on several assessment factors including overall efficiency of electricity generation and incremental efficiency of gaseous fuel utilization defined as ratio of total power increase because of GT use to chemical energy of gaseous fuel. All analyzed systems have been modeled on GateCycle software. The basis of steam cycle structure is the same for all cases. Parameters of live/reheated steam are: 600/620°C and 28.5/5.1 MPa. It has been assumed that the basic steam cycle is coupled with once-through coal-fired steam boiler. Such a basic plant arrangement is then modified towards integration with GT unit by different way in each analyzed variant. The optimal ratio of GT-to-SC power have been determined for each variant. Obtained simulation results show clearly that gas&coal hybrid cycles are thermodynamically attractive. The efficiency of gaseous fuel utilization (LHV based) varies from 54 to 59% depending on variant of integration while the overall efficiency of natural gas and coal use are in the range from 50 to 52%. It should be noted that above values have been obtained for moderate level of GT technology which means that there is some potential for improvement of presented efficiencies. P1-2

Application of Color Measurements for Estimation of Composition of Ash Formed by Fluidized-Bed Combustion

Dagmar Juchelkova, Helena Raclavska, Konstantnin Raclavsky, VSB-Technical University of Ostrava, CZECH REPUBLIC

The relationships between colour parameters and composition of combustion products (bottom ash and fly ash) were studied. Combustion tests were performed at the fluidized-bed boiler, Trinec, the Czech Republic. The measured colour parameters according to CIE L*a*b* standard have significant relationships with mineral phases (magnetite, anhydrite, lime, amorphous phase) and with chemical components (MnO2, TiO2 and minor elements) of fly ash. P1-3

Pyrolyses of the Various Types of Fuels Dagmar Juchelkova, Helena Raclavska, Konstantnin Raclavsky, Vaclav Roubicek, VSB-Technical University of Ostrava, CZECH REPUBLIC

The project concerns on the Technologies for pyrolyses processes and quality of fuels. We concern us also on the optimization of technology and the influencing of system and output parameters. According to the experiences of long term test form the small units was redesigned. The new unit allows making tests close to the real conditions. Some interesting information will be present. P1-4

The LEEP High Gas Velocity FGD Tail End Scrubber for Gasification and Combustion Processes

Kevin P. Furnary, LEEP Holdings, LLC; Bill Ellison, Ellison Consultants, USA

LEEP flue gas treatment technology originates from commercially successful, patented, American and overseas design engineering expertise. The LEEP proprietary scrubber uses a high gas velocity chemical reactor that creates a

48

large surface area for the fullest reaction between flue gas and multiple chemical scrubbing media. Inflow of the circulating scrubbing media and its resultant kinetic energy occur stepwise along the course of a circular reaction vessel at several sequential contact stations. Each station consists of a ring of nozzles that brings about intense mixing and interaction, greatly augmented by pronounced fluid feed shearing. To further optimize the process in high–sulfur service, the final contact station optionally uses a chemically reducing scrubbing medium affording effective application of newly field-proven, oxidation-reduction chemical process operation that achieves simultaneous SO2, NOx, and Hgo removal. The principle advantages of the LEEP Scrubbing System result from a unique combination of chemical process and mechanical engineering design features that allow for: • Sub-atmospheric operation due to mechanical engineering design that is free of

booster fan use • Operation of a commercial state-of-the art, in advanced horizontal-gas-flow,

scrubber mist eliminator of European origin • Zero-effluent, calcium-based scrubbing, which yields sulfite-solid output for

intermixed (post-combination) combined with the pre-collected dry fly ash catch for landfill disposal

P1-6

A Comparison between Ignition Behaviours of 7 Different UK and World-Traded Coals in Air, and in a Mixture of Oxygen and Carbon

Dioxide Gases Representative of Oxy-Combution Conditions Mark Flower, Jon Gibbins, Niall McGlashan, Imperial College London,

UNITED KINGDOM; Chi Man, NIOSH, USA A 20 L ignition test chamber has been used to test suspensions of 7 UK and world traded coals in air and O2/CO2 mixtures typical of oxy-combustion conditions. The coals varied in rank from sub-bituminous to bituminous and were tested in varying concentrations from the ignition limit to 400 g/m3. Following each successful test the combustion residue was collected, weighed and analysed within a thermogravimetric analyser, allowing Q factors to be estimated. The ignition limit varied slightly in air, but was mostly around the 200 g/m3 level. With the exception of Coal C, which was much harder to ignite, it correlated roughly with coal rank. The ignition limit changed significantly with O2 concentration when in mixed O2/CO2 gases. Only a few high volatile coals ignited in 21% O2/CO2 v/v, and then only with a 2500 J, rather than a 1000 J, igniter. An increase in O2/CO2 levels to 30 or 35% gave ignition patterns similar to those carried out in air with a further increase to 40% having little additional effect. In addition the minimum ignition concentration decreased with increase in O2. Heterogeneous combustion or gasification of the coal by CO2 appears to be confirmed by comparing weight loss results for air and O2/CO2 mixtures respectively for an equivalent peak pressure rise. P1-7

Deposit and Slag Emittances Richard Reid, Joseph Hoskisson, Larry Baxter,

Brigham Young University, USA Original experimental data summarizing spectral and total emittances of ash deposits and slags from coal, biomass, and coal-biomass blends presented and discussed in this paper exhibit trends in temperature and wavenumber or wavelength consistent with theory and observed boiler performance. Bituminous coal deposits exhibit higher emittances over nearly the entire spectral range than do subbituminous coals or deposits. All deposits exhibit total emittances that decrease with increasing temperature, mainly because of shifts in the radiation intensity with temperature. Slags exhibit less temperature variation than deposits. These radiative transport properties relate directly to boiler performance, operation, and design. P1-8

Numerical Simulation of Two Phase Flow and Combustion in the Preignition Chamber of a Pulverized-Coal Furnace

Dabao Xu, Hao Cao, Lili Yan, Beijing Research Institute of Coal Chemistry, CHINA

The average thermal efficiency of small and medium-sized coal-fired industrial furnace is low in China. It is urgent to solve the issue of technology improvement for these furnaces. In order to understand the performance of a new-style furnace, the commercial software FLUENT was used to simulate the preignition chamber’s two phase flow and combustion in three-dimension. The simulation of chemical reaction and heat transfer employed the non-premixed combustion model and the P-1 radiation model respectively. The gas phase transportation is simulated by the standard κ-ε turbulence model while particle phase uses the stochastic model. The distribution of the temperature in the chamber is in agreement with the measured values. The results provided useful references to improve the structure and operation condition of the furnace.

P1-11 Development of Ash Modification to Cementitious Material and

Desulfurization Technology by Calcium Fine Particles Injection into Pulverized Coal Fired Boilers

Akira Ohnaka, Tatsumi Tano, Takahiko Terada, Ube Industries, Ltd.; Ryunosuke Itokazu, Masato Tamura, IHI Corporation, JAPAN

As a part of basic study on ash modification to convert fly ash into cementitious material and also in-furnace desulfurization technology in pulverized coal fired boiler, trial firing based on a bench scale experiments with injection of calcium fine particles that can be collected from cement manufacturing process were performed. It was found from the DTF experiments that the decarboxylation occurred at temperature above 740°C and the crystal structure was changed within the range between 1200 and 1300°C. Thus the effective temperature of in-furnace desulfurization is between 740°C and 1200-1300°C, and that of clinkering reaction is in range of 1200-1300°C or more. Bench scale test programme achieved the following positive results. 1) Desulfurization rate reaches 20% with the calcium fine particles injection into the furnace temperature within the range of 1200°C or less and Ca/S ratio 2 or more, and is higher than 40% with the blow-in point temperature 1150°C or less and Ca/S ratio 3, 2) Under the ash property improvement condition, free-CaO is reduced from 50% to 10-15% and balance component is increased from 9% to 50-65%, which indicates the acceleration of clinkering reaction. P1-12

Update on the Thief Process for Mercury Removal from Flue Gas Evan J. Granite, Henry W. Pennline, Mark C. Freeman, William J. O’Dowd,

Richard A. Hargis, DOE-NETL; Scott Renninger, Brian S. Higgins, Eric Fischer, John Meier, Nalco Mobotec, USA

The Thief Process is a cost-effective variation to activated carbon injection (ACI) for removal of mercury from coal-fired utility flue gas. Partially combusted coal from the furnace of a pulverized coal power generation plant is extracted by a lance and then re-injected into the ductwork downstream of the air preheater. The Thief Process can be very helpful to industry, especially with recent projections indicating future shortages of activated carbon for the coal-burning utilities. Recent results on a 500-lb/hr pilot-scale combustion facility show similar removals of mercury for both the Thief Process and ACI. The tests conducted to date at laboratory, bench, and pilot-scales demonstrate that the Thief sorbents exhibit capacities for mercury from flue gas streams that are comparable to those exhibited by commercially available activated carbons. The Thief sorbents are significantly cheaper than commercially-available activated carbons; exhibit excellent capacities for mercury; and the overall process holds great potential for reducing the cost of mercury removal from flue gas. The Thief Process was licensed to Nalco Mobotec in May of 2005. Production results from a commercial facility will be discussed. P1-13

Update on GP-254 Process for Photochemical Removal of Mercury from Flue Gas

Evan J. Granite, Henry W. Pennline, DOE-NETL, USA A promising technology has been developed to capture and remove elemental mercury from flue gas. The GP-254 Process introduces ultraviolet light at a wavelength of 254-nm into the flue gas, resulting in the conversion of elemental mercury to a more readily captured oxidized form. The process has the potential to serve as a low cost mercury oxidation technology that will facilitate the removal of elemental mercury in a downstream scrubber, wet electrostatic precipitator, or baghouse. Over 90% removal of mercury has been obtained from 25-100 scfm streams of simulated subbituminous flue gases in large bench-scale tests. There have been recent projections indicating potential shortages of activated carbon for the coal-burning power plants. The injection of powdered activated carbon into the ductwork upstream of the particulate collection device can sometimes render the fly ash as a unsalable for the concrete market. Sulfur trioxide has been recently shown to poison activated carbons for the removal of mercury from flue gas. The short in-flight residence times and often poor mixing within the ductwork make it difficult for activated carbon injection to achieve 90% removal of mercury. With many states requiring 90% removal of mercury from coal-derived flue gas, and sulfur trioxide being a difficult poison for activated carbon sorbents, the GP-254 Process can serve as a stand-alone, or as a polishing step, to guarantee this high level of removal. Parasitic power is the major operating cost associated with the process. The parasitic power requirement is estimated to be less than 0.35%. This level of parasitic power leads to very favorable cost estimates for mercury removal. In addition, further reductions in the parasitic power requirements are likely with larger-scale and optimized lamp designs. The technology is available for license for the coal-burning power plants; medical, municipal, hazardous and weapons incinerators; waste-to-energy plants; and the chlor-alkali industry.

49

P1-14 The Impact of Moisture on the Energetics for an Amine-Based Sorbent

Used for Carbon Dioxide Capture Henry W. Pennline, James S. Hoffman, McMahan L. Gray, Daniel J. Fauth,

DOE-NETL; Kevin P. Resnik, Deborah Hreha, Parsons, USA One potential technique to mitigate carbon dioxide (CO2) emissions from fossil fuel-fired power generation point sources is carbon sequestration, where the capture of carbon dioxide from a gas stream is followed by the permanent storage of it. For those power generators that burn coal to produce a flue gas that contains about 10-15% CO2,

the use of regenerable sorbents as a means to capture the CO2 is a viable technology. Conceptually, for a solids transport-type system, the sorbent absorbs CO2 in one vessel and then the sorbent is regenerated in another vessel at higher temperature. The overall heat of regeneration or heat duty is an important parameter since it has implications with respect to the energetics of the process. Heat of reaction of CO2 with the sorbent, sensible heating of the sorbent from absorption to regeneration temperature, and several other factors impact the heat duty. Additionally, if moisture that is present in the flue gas is adsorbed and desorbed during the respective absorption and regeneration steps, then this heat effect must also be considered in the overall energetics. Experimentation has been conducted with a particular amine enriched solid sorbent with the purpose of not only characterizing the carbon dioxide removal capabilities but also determining the impact of moisture adsorption onto the solid. Calorimetry was used to measure the heat of adsorption for the moisture; a laboratory-scale packed bed reactor system equipped with a mass spectrometer was used to determine moisture loadings for the sorbent and substrate by itself. By quantifying the resulting information, the moisture impact on the heat duty and overall energetics was identified. Implications of this information on the design of a sorbent-based CO2 capture facility are discussed. P1-15

Proof-of-Concept Testing with an Electrochemical Cell for Carbon Dioxide Separation from Flue Gas

Henry W. Pennline, Evan J. Granite, David R. Luebke, DOE-NETL; John R. Kitchin, James Landon, Ethan Demeter, Carnegie Mellon University, USA

A significant amount of carbon dioxide (CO2) in the U.S. is emitted from power generation point sources that use coal. Carbon dioxide can be separated from flue gas streams produced by pulverized coal combustion by using high temperature molten carbonate electrochemical cells, as has been shown in the past. Difficulties due to the elevated operational temperature and due to the presence of trace contaminants, i.e., sulfur dioxide and nitric oxides, in the flue gas can deleteriously impact the operation of the electrochemical cell. If a lower temperature cell could be devised that would utilize the benefits of commercially-available, upstream desulfurization and denitrification in the power plant, then this CO2 separation technique can approach more viability as a technique to capture carbon dioxide from flue gas. In addition, although the electrochemical cell is extremely selective towards CO2 separation, the separated CO2 will include O2. However, this gas mixture may be an excellent feed for an oxy-fired combustor. Recent work has led to the assembly and successful operation of a low temperature electrochemical cell. In the proof-of-concept testing with this cell, an anion exchange membrane was sandwiched between gas diffusion electrodes consisting of nickel-based electrocatalyst on carbon paper. When a potential was applied across the cell and a mixture of oxygen and carbon dioxide was flowed over the wetted electrolyte on the cathode side, a stream of CO2 to O2 was produced on the anode side, suggesting that bicarbonate ions are the CO2 carriers in the membrane. Since a mixture of CO2 and O2 is produced, the possibility exists to use this stream in oxy-firing of additional fuel eventually resulting in an effluent rich in carbon dioxide that can be sequestered.

POSTER SESSION 2

GASIFICATION

P2-1

Millimeter-Wave Sensor Development for Coal Gasification J. S. McCloy, J. V. Crum, S. K. Sundaram,

Pacific Northwest National Laboratory, USA Sensor technology for in-situ monitoring in slagging coal gasifiers has been identified as a key enabling technology need for process optimization. The use of conventional thermocouples for measurements of slags is limited by durability and accuracy. Infrared pyrometers do not allow for measurements through the dirty environments inside gasifiers and they require emissivity calibration to report the correct temperatures. PNNL is operating a state-of-the-art dual channel millimeter-wave passive radiometer with active interferometric capabilities from a narrowband local oscillator. The heterodyne receiver system allows for radiometric measurements of sample temperature and emissivity simultaneously up to at least 1600 ˚C in harsh

environments. Interferometric capabilities through the mixed “video” channels at 137 GHz allow measurement of volume expansion/level change and viscosity. Demonstration of these capabilities for measuring temperature and simulated coal slag infiltration into a refractory brick sample will be presented. Simulated Pittsburgh#8 slag infiltration into Serv95 refractory sample at 1450˚C in air atmosphere was studied. The results showed the promise of the MMW system for extracting valuable quantitative process parameters from operating slagging gasifiers. P2-2

Experimental and Model Results of Diesel Fuel Gasification in a Pilot Scale Gasifier

Randy Pummill, Kevin Whitty, University of Utah, USA Liquid diesel fuel (approx. C12H23) was gasified with pure oxygen in a pilot scale entrained-flow gasifier. During the gasification, several parameters were varied so the effect that each parameter has on the process performance could be determined. These parameters were the internal pressure of the reactor (from atmospheric up to 85 psig) and the ratio of oxygen to fuel in the feed. The diesel feed rate was kept constant for these experiments. The synthesis gas produced from the gasification process was analyzed using a gas chromatograph. In particular, concentrations of O2, CH4, CO, CO2, and H2 in the dry gas were recorded and the results were tabulated for each variable. In this paper, these experimental results were compared to theoretical predictions obtained from an equilibrium simulation program developed by the authors. This simulation program accepts the atomic composition and heating value of the feedstock and uses a Gibbs free energy minimization technique to predict the products of the as well as the reactor temperature. The program also takes the reactor pressure into account. P2-4

The Potential Role of Nuclear Heat in Balancing and Greening the UCG Processes

Marc Steen, Michael Fuetterer, Institute for Energy, Joint Research Centre, European Commission, THE NETHERLANDS; Jan Rogut,

GIG - Central Mining Institute, POLAND The presentation evaluates the potential of using heat produced in current nuclear reactors and in HTRs, to upgrade the composition, purity and heating value from Underground Coal Gasification products. The use of UCG gases to reduce iron oxides and subsequently produce hydrogen under pressure in the low temperature iron-steam reaction is taken as example. The work highlights the economic and environmental synergy that can be achieved by the integration of coal, hydrogen and nuclear energy technologies. P2-5

Hydrodynamics Testing of a Solid Circulating Fluidized Process for Desulfurization in a Pressurized Condition

Young Cheol Park, Sung-Ho Jo, Ho-Jung Ryu, Chang-Keun Yi, Korea Institute of Energy Research; Jeom-In Baek, Korea Electric

Power Research Institute, KOREA The high temperature desulfurization technique is one of the elemental technologies of syngas purification having both higher thermal efficiency and lower emissions compared with conventional wet cleanup processes. The high temperature desulfurization is a novel method to remove H2S efficiently in syngas with regenerable sorbent at high temperature and high pressure condition which are preferable to gasification condition. In this study, we developed solid circulating fluidized process composed of a riser type desulfurizer, a fluidized-bed type regenerator, and a loopseal. We first investigated the effects of operating variables on solid circulation rate, gas leakage between two reactors and then, pressures in a circulation loop at high pressure condition were measured in a cold mode with dry regenerable sorbents. The voidage and mixture densities of gas-solid at various sections were analyzed from differential pressures data. P2-6

Computational Approaches for Geomechanical Evaluation of UCG Activities

Oleg Vorobiev, Yuliya Kanarska, Joseph P. Morris, S. Julio Friedmann, LLNL, USA

The mechanical response of the coal and host rock mass plays a role in every stage of UCG operations. For example, cavity collapse during the burn has significant effect upon the rate of the burn itself. In the vicinity of the cavity, collapse and fracturing may result in enhanced hydraulic conductivity of the rock matrix above the burn chamber. Even far from the cavity, stresses due to subsidence may be sufficient to induce new fractures linking previously isolated aquifers. Understanding these mechanical processes is important to evaluate the effectiveness of the operation as well as the risks associated with ground subsidence and groundwater contamination. These mechanical processes are inherently non-linear, involving significant inelastic

50

response, especially in the region closest to the cavity. In addition, the response of the rock mass involves both continuum and discrete mechanical behavior. To better understand these effects, we have applied a suite of highly non-linear computational tools in both two and three dimensions to a series of UCG scenarios. Our calculations include combinations of continuum and discrete mechanical responses by employing both explicit finite element and discrete element codes, such as GEODYN-L and LDEC, used to model stress evolution around the UCG cavities and the cavity collapse, and an implicit parallel code LMC used to model fluid flows around the pile of rubble created during the cavity collapse on the floor of the cavity. We will discuss the features of our geo-material modeling framework including our treatment for rock failure. This work performed under the auspices of the U.S. Department of Energy by Lawrence Livermore National Laboratory under Contract DE-AC52-07NA27344. P2-7

Experimental Tests on a High-Temperature H2S Removal Bench Scale System Caterina Frau, Francesca Ferrara, Alberto Pettinau, Alessandro Orsini, Carlo Amorino,

Mario Porcu, Sotacarbo S.p.A., ITALY Hydrogen sulphide is the most abundant sulphur compound in coal syngas and involves the need to introduce removal systems in order to meet the emission regulations and to preserve the equipment from corrosion. Gasification of a high sulphur coal, in particular for hydrogen production, requires the use of highly efficient desulphurisation systems. Moreover, depending on the plant configuration, the use of a hot gas desulphurization system (instead of a conventional cold gas desulphurisation process) could allow to increase the overall efficiency of a power generation plant. Regenerable metal oxides sorbents are the best candidates for hydrogen sulphide removal from hot coal syngas. Sotacarbo is currently engaged in a research project regarding the development and optimization of coal-to-hydrogen technologies for distributed power generation. In this field, a series of experimental tests has been planned to characterize different commercial zinc oxide based sorbents to be used in the hot gas desulphurisation system included in the Sotacarbo coal-to-hydrogen pilot plant. This paper shows the main results of the preliminary experimental tests carried out in a bench scale fixed bed reactor in the Sotacarbo Laboratories. The behaviour of commercial sorbents based on zinc oxide has been investigated as high temperature desulphurising agents from non-reducing gaseous streams containing 1.5% (in volume) of H2S diluted in N2. In particular, the effects of space velocity and temperature on the sulphidation reaction have been analysed.

POSTER SESSION 3

SUSTAINABILITY AND ENVIRONMENT

P3-1

The Coal Production in South Brazil and the Pyrite Challenge Michael Peterson, Josilaine T. Joaquim, Júlia Pavanelo, Luciana Correa Heck,

Universidade do Extremo Sul Catarinense; Adilson Oliveira da Silva, Fórmula Indústria Química do Brasil, BRAZIL

Economic activity in the southern region of Brazil had as a slapper the coal mining. Santa Catarina´sCoal has a low quality, with a large presence of ash and sulfur. This last component (the sulfur) is present as pyrite (FeS2), which is responsible for the major environmental degradation in the region by the formation of acid mines drainage (AMD). Finding economically viable applications for this ore is a major challenge for mining companies. This work sought to develop a technological implementation for pyrite with thermal oxidation for the formation of hematite in a specific oven roasting in controlled atmosphere (O2 and SO2). The development was done joinnig the Universidade do Extremo Sul Catarinense and the Criciúma Coal Company. The results have shown possible to produce an inorganil pigment for ceramic coating using hematite formed from pyrite thermal oxidation. P3-2

Integration and Industrial Development of Innovative Technologies for High-Sulfur Coal Clean Utilization in Yanzhou Mining Area

Guan Beifeng, Chen Guifeng, Wu Lixin, China Coal Research Institute, CHINA

Yanzhou Mining Area is very abundant in high-sulfur coal resource which accounts for nearly 50% of its remained economic coal reserves. The exploitation and utilization of high-sulfur coal on the basis of traditional using ways which can lead to serious environment pollution will be restricted strictly by Chinese industrial and environment policies. In order to make a full use of this so called inferior resource to realize the sustainable development, Yankuang Group has explored and demonstrated series innovative crucial technologies of high-sulfur coal clean utilization which have been integrated systematically. Up to now, advanced poly-generation system of high-sulfur

coal clean utilization has been formed and commercial industrial base of high-sulfur coal clean utilization on a million tons scale has been established in Yankuang Group. During the course of high-sulfur coal clean utilization, many advanced technologies of energy saving and emission reduction domestic and abroad have been adopted comprehensively, meanwhile, novel treatment and reuse process of chemical wastewater has been used. Therefore, the maximum of energy efficiency and nearly zero emission of typical pollutants have been realized, which embodies the idea of recycle economy and clean production. P3-3

The Mechanism of Active Pulsing Air Classification and its Application in Discarded Catalyst Recycling

Jingfeng He, Yaqun He, Weiran Zuo, Chenlong Duan, Baofeng Wen, China University of Mining and Technology, CHINA

The discarded catalyst of oil refining industry contains cavernous body with precious metal components and sintered magnetic beads. It is important to separate the two constituents for purifying the precious metal components. Dry separation of the discarded catalyst could effectively prevent materials from being modified by wet separation and is beneficial to the following purifying of the precious metal components. To this end, the experimental active pulsing air classifier was developed, the structure of the active pulsing air classifier was introduced, the mechanism of the active pulsing air classification was analyzed by the method of Computational Fluid Dynamics and the dynamic model in pulsing flow field of the particles with different densities and/or diameters, but similar aerodynamic characteristics was established. An experiment was conducted with the discarded catalyst of which light constituents density is 0.7~0.8g/cm3, heavy constituents density is 1.3~1.4 g/cm3, and particle size is -5+1mm by the use of the active pulsing air classifier. The results indicated that the separation efficiency was over 94.50% when the frequency of the active pulsing air was 7/3Hz and the airflow velocity was 2.50-6.00 m/s. The highest separation efficiency of 97.63% was achieved with airflow velocity of 3.33 m/s. The effective separation by density under the condition of dilute phase of the wide size range, non-homogeneous and multi-component materials could be realized by the active pulsing air classifier which has a board application prospect in the field of solid waste recycling.

POSTER SESSION 4

CARBON MANAGEMENT

P4-1

Prediction of CO2 Solubility in Oligomers De-Li Chen, Hong-Bin Xie, J. Karl Johnson, University of Pittsburgh and

DOE-NETL, USA We have used a combination of ab initio quantum mechanics and semi-empirical statistical mechanics to predict the solubility of CO2 in different oligomers. The goal of this work is to identify the important features that control solubility of CO2 in oligomers in order to design better materials for CO2 capture. Turbomole and COSMOtherm packages were employed to perform ab initio calculations and statistical thermodynamic calculations, respectively. We have modeled the vapor liquid equilibrium of CO2 and several CO2-philic oligomers, including polyethylene glycol dimethylether (PEGDME), poly(propyleneglycol) dimethylether (PPGDME), poly(dimethylsiloxane) (PDMS), and perfluoropolyether (PFPE). We find that the PEGDME has the highest solubility of CO2. Our theoretical data for the four oligomers are in good agreement with experiments, as shown for PFPE in Figure 1.

0 20 40 60 80 1000

200

400

600

800

1000

Pres

sure

(psi

)

PFPE (wt%)

Experiments Calculations (n=5)

Figure 1. Solubility of CO2 in PFPE having about 5 repeat units, as measured experimentally (circles) along with predictions for a KRYTOX 5-mer as computed from COSMOtherm (line).

51

P4-2 Post-Combustion CO2 Capture Utilizing Polymeric- and Silica-Based

Supported Poly(ethylenimine) Sorbents: The Effects of Flue Gas Constituents

Daniel J. Fauth, McMahan L. Gray, James S. Hoffman, Murphy J. Keller III, Henry W. Pennline, DOE-NETL; Kevin P. Resnik, RDS-Parsons, USA

Capture and sequestration of CO2 emissions from coal-fired generation plants and other stationary sources is considered a vital alternative for greenhouse gas mitigation. Research efforts underway at the Department of Energy’s National Energy Technology Laboratory are aimed at developing CO2 capture technologies to complement advanced, highly-efficient fossil fuel conversion processes as well as the existing fleet of power generators. One pivotal research effort at NETL has focused on developing solid, regenerable highly efficient CO2 sorbent materials prepared by impregnation of high surface, high pore volume polymeric or silica-based supports poly(ethylenimine) (PEI). The rationale for investigating dry, regenerable sorbent-based CO2 capture processes lies in their potential of being more energy-efficient as compared to traditional liquid amine scrubbing processes. Project goals include design, formulation, and testing of a series of CO2 sorbents utilized to selectively capture and thermally release carbon dioxide. In this work, high, reversible CO2 sorption uptake values (>10% of sorbent weight) were obtained for samples contacted in simulated flue gas streams (10% CO2, nitrogen balance) under dry and humidified conditions (up to 10% H2O, absolute humidity) at 60oC in bench-scale, fixed-bed flow systems and thermogravimetric instruments. Performance of silica- and polymeric-based supported poly (ethylenimine) sorbents was influenced largely by molecular configuration of PEI coupled with pore size of support. Additional experiments were conducted for assessing the thermal stability of supported PEI sorbents in pure CO2, N2, and oxidative environments, along with evaluating temperature swing desorption (and thermally assisted pressure swing desorption) as potential routes for successfully regenerating solid PEI-based sorbents over many multiple cycles. Furthermore, the effects of flue gas constituents including O2, NO, NO2, and SO2 on sorbent performance were evaluated. CO2 adsorption capacities for polymeric- and silica-based supported PEI sorbents were determined over multiple adsorption/desorption/thermal regeneration cycles at 60oC. Polymeric-based supported PEI samples suffered moderate to severe degradation upon exposure to a simulated 10% CO2 flue gas stream containing 3.5% oxygen at elevated temperatures. Thermocouples positioned within the sorbent bed registered temperatures in excess of 130oC during the initial adsorption stage of the experiment. Visual inspection of the sample after testing displayed “dark” discoloration. Post-test, infra-red analysis (DRIFT) revealed formation of Schiff bases possibly due to reaction between “exposed” PMMA carbonyl groups and reactive primary amino groups of PEI. Schiff bases produced in the condensation reaction present a characteristic absorption band near 1660 cm-1, assigned to C=N stretching vibrations. In contrast, testing of silica-based supported PEI samples in a 10% CO2, 3.5% O2, N2 balance stream afforded stable, reliable performance over adsorption/desorption/thermal regeneration cycles at 60oC with enhanced CO2 sorption capacity. Accelerated exposures of trace contaminants (NO, NO2, SO2) typically found in flue gas were performed. Adsorption of nitrogen oxide (NO) was less significant (5% NO2 removal efficiency) in relation to CO2 adsorption during multi-cycle testing at high NO concentrations (750 ppmv). Multi-cycle testing of samples with streams containing 650 ppmv NO2 revealed incremental loss in sorbent performance. Studies of the SO2-induced (1000 ppmv) degradation of polymeric- and silica-based PEI samples resulted in progressive degrees of sorbent discoloration upon repeated exposure. Such observations advise the need for upstream removal of these trace contaminants prior to CO2 capture. P4-3

A Mechanistic Study on the Reaction of MEA with CO2 in Aqueous Solution

Hong-bin Xie, J. Karl Johnson, University of Pittsburgh and DOE-NETL, USA

The monoethanolamine (MEA) + CO2 reaction has been considered as the rate-determining factor for the adsorption of CO2 by MEA in aqueous solution. This is a well-established technology for removal of CO2 from gas mixtures to reduce greenhouse gas emissions and has been used on a commercial scale for more than 75 years. Unfortunately, there still exists a controversy about the reaction mechanism as computed from theoretical studies. In this paper, detailed theoretical investigations at the B3LYP/6-311++G(d,p) level have been performed for the reaction of MEA+CO2, covering three different reaction channels suggested by previous experimental studies. In contrast to previous studies, we have included implicit solvent effects in both the geometry optimizations and frequency calculations for this reaction. A two-step reaction channel that proceeds via a zwitterion intermediate to form the carbamate is found to be most favorable. However, the reaction channels predicted by previous theoretical studies are kinetically much less competitive. In addition, all reaction channels considered in this paper must proceed through zwitterion intermediates and therefore it is a vital intermediate in the process of reaction. Calculations with MP2 and B3LYP methods combined with various base sets affirm that the zwitterion geometry is a true minimum (has no imaginary frequencies). Furthermore, NBO charge analysis confirms the zwitterionic character of the complex. We have included

explicit water molecules in addition to an implicit solvent model in order to identify explicit solvent effects on the reaction. We find that inclusion of explicit water lowers the reaction barriers. P4-4

CO2 Capture Capacity of CaO in a Small Pilot of Carbonation/Calcination Cycles

Chin- Ming Huang, Chen-Ching Wang, Wan- Hsia Liu, Heng- Wen Hsu, ITRI, TAIWAN

CaO used as sorbent in the removal of CO2 is an effective technique due to its high capacity, high activity and low cost. In this study, a bench-scale CO2 capture system consisted of carbonation column and calcination oven, with fluidized and moving bed structure respectively, were established. Highly capacity sorbents were obtained when the CaO were activation by steam for 2h. In the process, CaO was obtained when the CaCO3 calcinated in the temperature range 800-900oC and the CO2 was further captured by carbonation at 600-700oC. According to the result, a highly efficiency, about 96.6% in 16.1% CO2 concentration system, can be arrived when the carbonation temperature controlled at 650 °C. In addition, the SEM micrographs for the sorbents were also analyzed. And the surface area, properties and pore structural were also characterized by Brunauer-Emett-Teller (BET) analysis in this work. P4-5

Recent Development and Scale-Up of a Fluidized-Bed Process Capturing CO2 in a Coal-Fired Flue Gas using Dry Regenerable Sorbents

Young Cheol Park, Sung-Ho Jo, Seung-Yong Lee, Chang-Keun Yi, Korea Institute of Energy Research; Chong Kul Ryu, Korea Electric

Power Research Institute, KOREA We used a dry sorbent CO2 capture fluidized-bed process which was capable of capturing 0.5 ton CO2/day (100 Nm3/hr of flue gas treatment). We investigated the sorbent performance in continuous operation mode with solid circulation between a fast fluidized-bed type carbonation reactor and a bubbling fluidized-bed type regeneration reactor. We used a slip stream of a real flue gas from coal-fired circulating fluidized-bed power facility in Korea Institute of Energy Research in order to check possibility of deactivation of dry sorbent by contaminants such as SOx and NOx. The maximum CO2 removal reached above 90% and the average CO2 removal was about 83% for more than 50 hours with the presence of several contaminants. It was shown that the contaminants in the flue gas had no adverse effect on the sorbent performance. Based on the field test results, a pilot-scale unit capable of capturing 10 ton CO2/day (2,000 Nm3/hr of flue gas treatment) has been designed. To make the design correct, we first measured overall heat transfer coefficient for cooling using cooling water in the carbonation reactor and for heating using steam in the regeneration reactor. Then the dimensions of both reactors have been decided by considering gas and solid residence time as well as heat transfer area. The pilot-scale unit consists of a fast fluidized-bed type carbonation reactor and a bubbling fluidized-bed type regenerator just like a bench-scale unit of capturing 0.5 ton CO2/day. The pilot-scale unit will be constructed at Hadong coal-fired power plants in Korea Southern Power Co., Ltd. P4-7

Evaluating the Reaction Barrier of Amine Based Sorbents through Experimental Plug Flow Reactor Measurements

W. Richard Alesi, John R. Kitchin, Carnegie Mellon University and DOE-NETL; McMahan Gray, DOE-NETL, USA

Green house gas emissions, notably carbon dioxide (CO2), have steadily increased over the last century in part, due to rising energy demands. Increases in human population and the influence of technology on everyday life will likely result in subsequent increases in energy demand in the future. Therefore, we must determine a means in the next coming decades to reduce these continued emissions and any harmful side effects which may result upon the environment. Tertiary amidine based sorbents and other sorbents with amine moeties are ideal for capturing CO2 at low temperature in large part due to their high basicity which allows the amine to chemically interact with acid gases. In order to maximize the capture capacity of amine based sorbents, one must first understand the effect basicity, molecular structure, and substituent modifiers have on tuning the interaction between CO2 and the amine. Changes in any of these properties will result in a change in either the thermodynamic barriers of CO2 interaction or the energies associated with activation of the complex. Gas phase adsorption / desorption experiments provide an ideal framework to understand these properties in contrast to the more complex liquid and membrane systems where mass transfer affects the measured extrinsic properties of the sorbent. In the course of this work, we conduct various gas adsorption experiments of solid amine-based sorbents in a tubular plug flow reactor. This technique consists of an adsorption step, usually conducted at low temperature in the presence of CO2 and a subsequent regeneration step at elevated temperatures under an inert feed stream, to induce the desorption of CO2 from the amine. Characterization of molar gas compositions from a mass spectrometer is conducted under a wide range of operating conditions including simulated flue gas conditions (12% CO2) as well as gas

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compositions ranging from pure CO2 to inert gas feed streams, and temperature swings between ambient up to 125°C. These changes in operating conditions affect the driving forces of CO2 adsorption and desorption in the system, allowing us to obtain a better understanding of the thermodynamic properties of the amine complex. We conduct wet impregnation and surface functionalization of amines onto silica surfaces including various functionalities of MTHP, a tertiary amidine, in order to determine the effects that basicity, molecular structure, and substituent effects play on the gas phase interaction of CO2 and the support. Through evaluation of our plug flow reactor experiments in addition to thermogravimetric analysis, we derive experimental reaction barriers for desorption in the amine systems. Density Functional Theory (DFT) is used in conjunction with these experimental techniques to better elucidate the mechanism and thermodynamic properties of the system. Density functional calculations are performed at zero Kelvin to obtain the electronic ground state energies and the electronic structural effects that result from application of various sterically hindered and electron withdrawing and donating groups in close proximity to the interacting nitrogen of the amine. We use an atomistic thermodynamic framework to relate these measurements to our experiments conducted at ambient conditions and one atmosphere in order to obtain a better understanding of the changes in the thermodynamic and kinetic properties that control the adsorption and desorption of CO2 on the amine sorbent. In this work we conduct experimental tubular plug flow reactor measurements to characterize the interaction of CO2 with various supported amines in the gas phase. We then derive experimental reaction barriers to compare with computationally calculated electronic energies and begin to develop a methodology of how modification of the structural properties of the amine can tune the basicity and result in changes of the effect that thermodynamic driving forces have on CO2 capture. P4-8

Carbon Dioxide Absorption Behaviors of Calcium and Silica Compounds Choong-Gon Lee, Hanbat National University; Chong-Kul Ryu, Korea

Electric Power Research Institute, KOREA: Minghua Wang, Northeastern University, CHINA

It is essential to develop a promising CO2 sorbent for the CO2 emission reduction. Herein, CaSiO3, Ca2SiO4, Ca3SiO5, Ca3Si2O7 were synthesized by a solid reaction of CaCO3 and SiO2, characterized via XRD and TGA. The results showed that reaction of CO2 sorption and desorption were reversible at higher temperature. The optimal operation temperature was around 800°C where the Ca3SiO5 showed 55.08 wt% increases in the flow of 15% CO2 in N2. The calcium and silica compounds exhibited gradual decreasing cycle properties. In case of Ca3SiO5, CO2 sorption efficiency dropped from 55.08 wt% to 18.65 wt% after 17 times of sorption-desorption cycles at around 800oC. Following SEM analysis suggested that the specimens were melted at the temperature so that the CO2 absorption was obstructed by the reduced surface area. P4-9

Perovskite Catalyst Design for Electrocehmical Oxygen Separation James Landon, Carnegie Mellon University and DOE-NETL; John Kitchin,

Carnegie Mellon University, USA Oxy-fuel coal combustion is a method of power generation currently being employed as a means to capture carbon dioxide. Air is first separated into its primary components of oxygen and nitrogen using cryogenic distillation. This method is energy intensive, so alternatives to cryogenic distillation are being examined. The purpose of this research is to investigate the use of an electrochemical membrane to carry out air separation. Some of the benefits of electrochemical separations include high selectivity, operation at room temperature and pressure, and theoretically low energy requirements. Oxygen present in the air is electrochemically reduced at an electrode to hydroxide ions. These hydroxide ions are transported across a selective anion exchange membrane under the presence of an electric field to a second electrode where the reverse reaction occurs, and oxygen gas is evolved. The kinetics of both oxygen reduction and oxygen evolution reactions are quite slow. This research focuses on increasing the reaction kinetics of the oxygen evolution reaction. Current catalysts for oxygen evolution are typically made of nickel. While nickel can catalyze this reaction, high energy is necessary to accomplish this. Perovskite catalysts have been shown to be active for oxygen evolution in alkaline solutions and may provide a robust structure by which to create a more active catalyst. To make this improvement, a rational catalyst design approach using a volcano plot is being utilized. This volcano plot shows catalyst activity for oxygen evolution versus a characteristic metal-hydroxide (M-OH) bond strength. Catalysts located on the left side of this plot have a weak M-OH bond strength, making the rate limiting step of the reaction the adsorption of the reactant. Similarly, catalysts located on the right side of the plot have a strong M-OH bond strength changing the rate limiting step to desorption. Perovskites have been synthesized in our lab using an evaporation-induced self-assembly technique yielding surface areas from 5-20 m2/g. Perovskite formation was confirmed using x-ray diffraction (XRD). The activity of these catalysts has been characterized using cyclic voltammetry (CV) and chronoamperometry (CA) techniques. Oxygen evolution current densities of 0.2 A/m2 have been achieved at an

overpotential of 0.857 V for a La0.7Sr0.3CoO3 catalysts. La0.7Sr0.3BO3 B=[Ni, Fe, Mn] catalysts have also been examined for oxygen evolution capability. Active La0.7Sr0.3BO3 B=[Ni, Co] catalysts have been incorporated as anodes into a electrochemical separation cell. A 3M KOH or 3M K2CO3 electrolyte was used in conjunction with a standard Pt/C oxygen reduction cathode. Oxygen and carbon dioxide were successfully captured from an air feed stream. A current density of 2 mA/cm2 was achieved with a La0.7Sr0.3CNiO3 anode at a cell potential of 1.2 V. P4-10

Comparative Thermodynamic Evaluation of Oxygen Carriers for Chemical Looping Combustion using Steam and CO2 as Oxidizing Gases

Michelle Najera, Rahul D. Solunke, Goetz Veser, University of Pittsburgh and DOE-NETL; Selasi Blavo, University of Pittsburgh, USA

Chemical looping combustion (CLC) is an emerging technology for clean energy production and CO2 mitigation from fossil and renewable fuel sources. In this process, an oxygen carrier – typically a metal – is oxidized in the presence of air. The hot metal oxide is then reduced via contacting with a fuel in a second reactor. Finally, the reduced metal is transferred back to the first reactor, closing the materials. CLC can hence be considered an oxy-fuel combustion process which allows for flameless, NOx-free combustion without, however, requiring air separation, and results in sequestration-ready CO2 streams without a significant energy penalty. Going beyond the combustion process, CLC can be modified by replacing air with steam or even CO2 as oxidizing agent. The overall reaction scheme, i.e. addition of the oxidizing and reducing reactions in the two reactors, would hence yield a steam reforming and dry reforming process, respectively, as illustrated below for steam as oxidant: Fuel reactor: CH4 + 4 MO = CO2 + 2 H2O + 4 M Oxidizer: 4 M + 4 H2O = 4 MO + 4 H2 Sum reaction: CH4 + 2 H2O = CO2 + 4 H2 In the present work, a detailed thermodynamic study of a range of metals and metal sulfides as potential oxygen carriers is conducted in order to identify potential materials for a modified CLC process using steam or CO2 as oxidizers. The calculations are based on the commercial software package FACTSAGE™, and span a wide range of temperatures (400 – 1200°C) and pressures (1 – 50 bar). Our results indicate that both process variants are thermodynamically feasible based on several different oxygen carrier materials. Beyond thermodynamic feasibility, the overall energy balance and the energy split between the oxidizer and the fuel reactor are also discussed for different fuels. P4-11

Characterization of Solid CO2 Sorbent and WGS Catalyst for SEWGS Process

Joong Beom Lee, Tae Hyoung Eom, Jeom-In Baek, Won Sik Jeon, Ji-Woong Kim, Chong Kul Ryu, Korea Electric Power Research Institute, KOREA

Sorption enhanced water gas shift (SEWGS) process technology is one of the emerging technologies as a cost-effective and energy efficient technology for CO2 capture from syngas. The process simultaneously carries out the water gas shift (WGS) reaction and removal of CO2 in a single unit. Five hydrotalcite-based dry regenerable CO2 sorbent and four CuO-based water gas shift catalyst were prepared by spray-drying techniques. Their physical properties and reactivities were tested to evaluate their applicability to a fluidized-bed SEWGS process for pre-combustion CO2 capture. Hydrotalcite-based sorbents satisfied most of the physical requirements for commercial fluidized bed reactor process along with reasonable chemical reactivity. All sorbent had a spherical shape, an average size of 112–125 µm, and a size distribution of 45–250 µm, a bulk density of 0.63–0.83 g/mL. The attrition Index (AI) of all the sorbent was below 15% compared to about 20% for commercial fluidized catalytic cracking (FCC) catalysts. CO2 sorption capacity of PC-1 was approximately 7.0 wt% at 200°C and 21 bar with synthesis gas conditions. Spray dried CuO-based WGS catalyst showed relatively good physical properties. Most of catalyst had a semi- spherical shape, an average size of 132–150 um, and a size distribution of 53–250 µm, a bulk density of 0.76–0.91 g/mL. Attrition Index (AI) of PC-4 was about 7%, which is suitable for fluidized SEWGS process. P4-12

Seismic Evaluation of the Fruitland Formation with Implications on Leakage Potential of Injected CO2

Tom Wilson, West Virginia University; Art Wells, DOE-NETL; George Koperna, Advanced Resources International, USA

Subsurface characterization activities undertaken in collaboration with the Southwest Regional Carbon Sequestration Partnership on their San Juan Basin pilot test include acquisition of geophysical logs, time lapse VSP and analysis of 3D seismic data from the site. The project is funded by the U.S. Department of Energy and is managed by the National Energy Technology Laboratory.CO2 injection began in late July of 2008 and appears it will continue at least into early August of 2009. Total CO2 injection volume to date (mid July, 2009) is approximately 300 MMcf. Subsurface

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characterization activities are critical to the evaluation of reservoir integrity and the potential that leakage of injected CO2 might occur. Work discussed in this presentation focuses primarily on the analysis of 3D seismic from the area. 3D seismic interpretation reveals that the Late Cretaceous Fruitland Formation forms a well defined seismic sequence bounded by high amplitude reflection events at its top and base. The pattern of internal reflection events is parallel and conformable near the top and base of the sequence. The 3D seismic view of the Fruitland Formation shows considerable detail not inferred from well log correlations in the area. The pattern of internal reflection events is marked by significant internal discontinuity. Fruitland coal reflection events reveal the presence of local fold-like structures with wavelengths of 1 km to 3.5 km accompanied by relief of 6 feet to 60 feet. The origin of these structures is uncertain. Some of the structures observed in the Fruitland are present in overlying Paleocene and Late Cretaceous intervals. Post-stack processing of the 3D seismic is undertaken to enhance subtle discontinuity in the data that might be indicative of small faults or fracture zones that could jeopardize reservoir integrity. 3D seismic from the area is processed using edge enhancement, event similarity and spectral decomposition algorithms. Additional seismic attributes are also evaluated for evidence of faults or fracture zones. The analysis raises questions concerning local variations in Fruitland coal depositional systems, the influence of differential compaction within the Fruitland coal section, and local structure of possible tectonic origin. The vertical extension of larger wavelength structures into shallower strata suggests that local deformation of the area continued through the Paleocene and may include minor deformation of Eocene strata exposed at the surface in the areas surrounding the pilot site. Extensive tracer monitoring at the surface for evidence of CO2 escape ensures that escape very small amounts of CO2, should that occur, will be detected. P4-13

Geophysical Characterization of the Marshall County West Virginia Pilot Sequestration Site

Tom Wilson, Richard Bajura, Doug Patchen, West Virginia University; Richard A. Winschel, Ravi S. Srivastava, Roy Scandrol, CONSOL Energy

Inc.; Art Wells, DOE-NETL, USA A pilot test is being conducted in Marshall County, West Virginia, to evaluate enhanced coalbed methane (CBM) recovery and simultaneous carbon dioxide (CO2) sequestration in an unminable coal seam in the Northern Appalachian Basin. Researchers from CONSOL Energy Inc., West Virginia University and the National Energy Technology Laboratory (NETL) are collaborating in this effort. The project is funded by the U.S. Department of Energy and is managed by the National Energy Technology Laboratory. It is planned to inject up to 20,000 short tons of carbon dioxide at a pressure of up to 700 psig and at a rate of about 27 short tons per day into an “unminable” region of the Upper Freeport coal seam located at depths of 1200 to 1800 feet, depending on surface topography. Horizontal coalbed methane wells were drilled in a modified five-spot pattern over a 200-acre area into the Upper Freeport seam and separately into the overlying Pittsburgh coal seam, and these wells have been producing CBM since 2004. The center wells will be converted to CO2 injection wells. It is anticipated that CO2 injection will commence in the summer of 2009. A Class II underground injection control permit was obtained from the West Virginia Department of Environmental Protection Office of Oil and Gas. The impacts of CO2 injection into the center wells on the production and composition of the coalbed methane produced in the peripheral and overlying wells will be monitored. Injection will cease when either 20,000 short tons have been injected or the coalbed methane from the peripheral or overlying wells becomes contaminated with CO2. The pilot test incorporates numerous site characterization and monitoring activities including 1) monitoring of the gas and water produced from numerous active coalbed methane wells and from numerous abandoned deep gas wells in the area of review, and from two observation wells drilled for this project, 2) ground water monitoring, 3) stream water monitoring, 4) soil gas monitoring, 5) perfluorocarbon tracer testing, 6) tiltmeter observations and 7) seismic observations. Monitoring will continue for two years after injection ceases. Subsurface characterization of the site employs well-log-derived structure and isopach maps, integration of structure inferred from the horizontal well paths, and partial 2D and 3D seismic coverage. Density and sonic logs from one well help establish an approximate tie between the seismic response and subsurface stratigraphic intervals. Data from Schlumberger’s sonic scanner tool combined with density provide mechanical properties of overburden intervals. 3D swath data collected by Steve McCrossin, Precision Geophysical, were processed using pre-stack time and depth migrations (Vaso Leci, Vemek Ventura Energy). The bandwidth of the data is about 75 Hz (25-100Hz) with a peak frequency of approximately 50 to 60 Hz. The interval velocity in the Pittsburgh coal is approximately 6700 fps; in the Upper Freeport it is about 8900 fps, which limits resolution to 30 to 40 feet thick intervals, respectively. The Pittsburgh coal is between 6 and 7 feet thick in the area, whereas the Upper Freeport varies between 2 to 6 feet across the site. Local disruptions in reflection discontinuity are common in intervals bounding the Upper Freeport. Major penetrative faults and folds have not been observed at the site. Edge detection and event similarity analysis of the 3D seismic volume reveals local structural heterogeneity. The acquisition footprint is suppressed using a short crossline smoother. Tuning cubes generated along horizon-guided intervals help evaluate seismic properties of

depositional environments bounding the Pittsburgh and Upper Freeport coals at the site. P4-14

Experimental Study of Multiphase Fluid Transport in the Cleat and Matrix System of Coals: Implication for CO2-ECBM

Fengshuang Han, Chinese Academy of Sciences and RWTH Aachen University; Bernhard M. Krooss, RWTH Aachen University, GERMANY; Jianli Yang, Zhenyu Liu, Institute of Coal Chemistry, Chinese Academy of

Sciences, CHINA; Niels van Wageningen, Andreas Busch, Shell International Exploration and Production B.V., THE NETHERLANDS

CO2 geological sequestration in deep and unminable coal seams is considered an option to reduce the release of CO2 into the atmosphere since it has the potential to enhance the production of coalbed methane (ECBM), partially offsetting the cost of sequestration. The feasibility assessment, modeling and operation of CO2-ECBM processes require fundamental information on fluid conductivities of the dual pore structure of coal seams: interconnected cleat system and inter-cleat (porous matrix) system. Darcy flow of fluid in the face and butt cleats is considered to play the primary role in CBM/ECBM production. However, the gas exchange behavior between coal matrix volumes and the cleat system constitutes another important process that is still poorly understood. The coal matrix is considered relatively “impermeable” compared to the cleats. So it could become the rate-limiting step for CBM/ECBM recovery and CO2 storage in unminable coal seams in particular when coal seams have relatively high permeability due to well developed cleat systems. Therefore the operation and numerical simulation of CO2-ECBM necessitates the acquisition of further knowledge on gas and water exchange and transport process on the coal matrix scale. In order to elucidate the mechanisms of CBM/ECBM-related fluid transfer between coal matrix and cleat system, a comparative study of the conductivity characteristics of the cleat system and the coal matrix was performed. Therefore, cylindrical coal plugs (28.5 mm in diameter, ~20 mm in length) with and without visual cleats (coal matrix samples) were selected and used in flow-through tests in a triaxial flow cell. Single-phase and two-phase (gas breakthrough tests on water-saturated samples) fluid flow experiments with water, argon and helium were conducted on the selected cleat and matrix coal plugs, respectively. In a first set of measurements the permeability of “as received” samples were determined with argon gas under varying stress conditions. Then the coal plugs were saturated with water and steady-state single-phase water permeability was measured. The fully water-saturated samples were then subjected to pressure gradients of argon and helium to study two-phase flow (gas breakthrough tests) under controlled effective stress conditions. The permeability of the “matrix” samples was two orders of magnitude lower than that of the coal samples with visible cleats for the same fluid. Both, the permeability of the coal matrix samples and cleat samples was found to be strongly fluid-dependent: the permeability coefficient to argon measured on the dry coal was one order of magnitude higher than that measured with water at the same stress conditions. The effective permeability coeffcients (after gas breakthrough) to He and Ar gas were one order of magnitude lower than water permeability. Furthermore, He and Ar gas breakthrough tests on water-saturated samples revealed that the studied coal sample was water-wet in the gas/water/coal system, and capillary effects may play a significant role in fluid transport in coals. P4-15

Characterization of Dry Regenerable Sorbents for CO2 Capture from Syngas

Jeom-In Baek, Tae Hyoung Eom, Joong Beom Lee, Won Sik Jeon, Ji-Woong Kim, Chong Kul Ryu, Korea Electric Power Research Institute, KOREA

Dry regenerable sorbents with 40 wt% MgO for CO2 capture from syngas stream in warm temperatures were prepared by spray drying method. Physical properties of the sorbents calcined at different temperatures were characterized in terms of shape, particle size, packing density, and attrition resistance etc. to evaluate their suitability for use in the fluidized-bed CO2 capture process. The shape of the sorbents taken by scanning electron microscopy (SEM) was mainly sphere. Average particle size, particle size distribution and bulk density were appropriate for fluidization. The attrition indices (AI) of some sorbents measured by ASTM D 5757-95 were below 20 %, which were better than commercial fluidized catalytic cracking (FCC) catalyst. The reactivity of the sorbents was measured with thermogravimetric analyzer (TGA) with simulated syngas (CO2 36%, H2 48%, CO 6% and H2O 10%) at the system pressure of 20 bar and the temperature of 200 and 400°C for absorption and regeneration, respectively. The measured CO2 sorption capacity of the sorbents was 5-7 wt% which is much lower than theoretical sorption capacity of 32.8 wt%. Sorbent development work will be continued to improve the CO2 sorption capacity to near the theoretical value.

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P4-16 Integration of CO2 Capture Technology in Coal-Fired

Power Generation Facilities Brian Drover, Stephan Broek, Hatch, CANADA; Paul Casson, Hatch, AUSTRALIA

This work examines the integration issues involved with installing a CO2 capture plant at coal-fired power generation facilities. For optimal performance of an amine CO2 capture solvent, strict impurity levels in the incoming flue gas must be maintained by the flue gas cleaning scheme. Conventional gas cleaning technologies and available design upgrades required to meet these conditions are discussed. Hatch’s experience in the engineering, procurement, construction and ramp-up of the world’s first BASF PuraTreat™ F CO2 Recovery Plant, as part of the BHP-Billiton Yabulu Nickel Refinery Extension Project, is utilized to describe other issues encountered during start-up of a CO2 Capture plant.

POSTER SESSION 5

COAL-DERIVED PRODUCTS

P5-1

Characterization of Zeolites from Polish Fly Ashes Aleksandra Ściubidło, Wojciech Nowak, Izabela Majchrzak-Kucęba,

Czestochowa University of Technology, POLAND Synthesis zeolites from Fly Ash is one of the methods of fly ash utilization. The fly ashes from both on-going production may be utilized as well as those already disposed onto landfills. Since the combustion of coal is the main method of energy generation in Poland we are compelled to search for better and more efficient solutions that would enable the utilization of power industry wastes. Due to its chemical composition -featuring high contents of SiO2 and Al2O3 - fly ash has become a attractive raw material for the synthesis of zeolites. The article describes two methods for synthesis zeolites (Na-X)from fly ash; traditional hydrothermal conversion and fusion. The first method basis on stirring ash in a sodium hydroxide solution, and the second method involves the sintering of fly ash with sodium hydroxide. 14 different fly ashes were used for both synthesis processes. The fly ashes from both PC and CFB combustion of hard coal and lignite as well as from biomass cofiring were used. For the determination of chemical and physical zeolites’ properties the techniques of XRD, IR and N2 adsorption we used. This work was carried out with support from the Project supported by a grant from Iceland, Liechtenstein and Norway through the EEA Financial Mechanism and the Norwegian Financial Mechanism (E031/T02/2008/02/85). P5-4

Studies on the Properties of Mesoporous Materials Derived from Polish Fly Ashes

Izabela Majchrzak-Kucęba, Wojciech Nowak, Aleksandra Ściubidło, Czestochowa University of Technology, POLAND

The synthesis of mesoporous molecular sieves from fly ashes is an undoubtedly new and interesting direction of use of the values of fly ash, and specifically its chemical composition (Si, Al), for obtaining high-quality porous materials offering wide possibilities of utilization. An attempt was made in the present work to obtain the MCM- 41 mesoporous materials from 10 different fly ashes originating from Polish Power Stations. Fly ashes were chemically analyzed and used to prepare mesoporous materials -MCM-41. The preparation procedure of the MCM-41 mesoporous materials from fly ash comprised two stages: the extraction of Si from the fly ash and the proper synthesis of MCM-41 on the basis of the obtained silicon extract. The synthesis was carried out by the hydrothermal method using the supernatants of coal fly ashes (fused fly ash solutions) and cationic cetyltrimethylammonium bromide (CTAB) surfactants as the structure-directing agents. The fly ash-based MCM-41 mesoporous materials were characterized by powder X-ray diffraction (XRD) and TGA. On the basis of all examinations of the obtained products it can be stated that the fused fly ash filtrate containing Si and Al can be used for production of gel necessary for the synthesis of mesoporous materials, but, at the same time, the Si content and the Si/Al ratio in the starting filtrate must be at the appropriate level. Highsilicon ashes (with a high Si content) are favourable for the synthesis. P5-5

Fischer-Tropsch Refining Issues David A. Bell, Sara Harkins, University of Wyoming, USA

Fischer-Tropsch fluids refineries were simulated using Aspen Plus software. The goal was to make products that meet conventional petroleum specifications. Three refineries were simulated. The first produces diesel and gasoline, with fuel gas as a byproduct. The second produces jet fuel instead of diesel. The third was designed to produce lubricant base stocks as its primary products.

The feedstock for each of these simulations was a waxy Fischer Tropsch fluid produced by a cobalt catalyst. This fluid consists entirely of straight chain molecules that are primarily normal alkanes, but also include alkenes and alcohols. It is well-known that this type of feedstock can be used to make high cetane diesel, but the straight chain nature of the feedstock can cause problems meeting other product specifications. Diesel and jet fuel tend to have poor low temperature properties, and gasoline produced from Fischer-Tropsch fluids tends to have low octane numbers. These properties can be improved by isomerizing the feed to produce isoalkanes (branched chain alkanes). For the diesel and jet fuel cases, a hydrocracker was used to reduce the molecular weight of the Fischer-Tropsch wax, and to partially isomerize the feed. Experimental data by Leckel has shown that an increase in hydrocracking severity decreases diesel yield and improves diesel low temperature properties. We found little quantitative data that relates diesel and jet fuel low temperature data to molecular composition, so it is difficult to predict the level of hydrocracking severity required to meet low temperature specifications. Because of this, there is considerable uncertainty in predicting the yield of diesel, naphtha, and fuel gas from the hydrocracker. To boost octane number, we explored the use of naphtha isomerization and alkylation (production of isooctane). Process conditions that meet octane specifications excessively hydrocracked the feed, so boiling point specifications were not met. Fischer-Tropsch wax appears to be an excellent feedstock for lubricant base oil production. These base oils are worth substantially more than liquid fuels. There are commercial catalysts available for this purpose, but little information about these catalysts is available in the open literature. This work shows that additional research is needed. Better correlations are needed to predict low temperature performance based on jet fuel and diesel composition. Better information is needed regarding catalysts with high isomerization/hydrocracking selectivity. P5-6

Secondary Phases of P-Impurity in Sofc Anode Operating on Coal Syngas: Theoretical and Experimental Investigation

Fatma Nihan Cayan, Mingjia Zhi, Suryanarayana Raju Pakalapati, Nianqiang Wu, Ismail Celik, West Virginia University, USA

The main advantages of Solid Oxide Fuel Cells (SOFCs) when compared with other traditional power generation techniques include high efficiency, low emissions and fuel flexibility. These features render the SOFCs one of the most viable candidate for future power plants. SOFCs can be operated directly on a wide variety of fuels including natural gas, hydrocarbon gases and coal derived synthesis gas (coal syngas). Direct utilization of coal syngas in SOFCs is an especially attractive prospect given the vast quantities of coal reserves in the world. Combination of a coal gasifier with a SOFC will provide clean, efficient and cost effective use of coal. However, coal syngas contains various impurities whose affect on the performance and durability of Ni-YSZ (Nickel -Yttria stabilized zirconia) based anode of the SOFC is not yet well understood. In the present study experimental characterization of SOFC anode and thermodynamic equilibrium calculations are performed to ascertain the stable forms of P impurity under the SOFC operating conditions. The experimental techniques include SEM and XPS analysis of the anode samples before and after the exposure to PH3 containing syngas. Equilibrium calculations take into account all possible compounds of the syngas components including PH3 and the anode materials both in gaseous and condensed phases. The results from experimental characterization and those from equilibrium calculations are compared to corroborate the individual findings and arrive at a conclusion regarding which compounds of Ni and P are prevalent in SOFC anodes under operating conditions. Finally predictions are made with another commonly found impurity, As, in coal syngas. P5-7

Electrochemical Looping using the Liquid Tin Anode Fuel Cell for Direct Coal Conversion

Jeff Bentley, Thomas Tao, CellTech Power, USA Coal plays a vital role in the power economies of major countries but efficient generation options are limited, particularly for applications where carbon capture and sequestration is desired. Improved generation efficiency can increase economic viability and environmental responsiveness of coal power generation. ElectroChemical Looping (ECL) is a new concept for direct conversion of coal to power using the liquid tin anode (LTA) fuel cell. ECL combines multiple processes, eliminating inefficient process steps and lowering capital cost compared to other advanced baseload technologies. The electrochemical aspect refers to the efficient production of power without combustion while the looping concept refers to the shuttling or “looping” of oxygen by the liquid tin anode. The liquid tin “loops” between the fuel cell and the tin reactor, shuttling all of the oxygen used to convert the coal. The net effect is that power is produced directly and efficiently from coal or biomass without burning and with inherent separation/rejection of nitrogen. The enabling technology is the LTA, is described in more detail in other papers. This paper describes the ECL process, underlying systems analyses and the commercialization strategy. The ECL concept is being developed by CellTech Power with support from DOE-NETL and EPRI. The enabling technology for ECL is the Liquid Tin Anode Fuel cell

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which is already under commercial development for small power applications. Detailed ECL flow sheets have been developed and analyzed. In the most promising system configuration for coal power production at utility scale the fuel oxidation step is carried out in a separate tin-coal reactor. Coal is introduced to the reactor which converts tin oxide to tin. Ash and most contaminants will be separated by gravity and skimmed off the reactor. At the LTA fuel cell, power is produced when tin is converted to tin oxide. NOx formation is not expected because nitrogen does not participate in the reactions. Sulfur emissions can be cleaned up using conventional technology. CO2 emissions and ash production are lower than other alternatives because less coal is used per kwh produced. CO2 can be captured in a pure stream from the ECL system using conventional technologies. Independent analyses have predicted high ECL efficiency (61% on coal) and low capital cost in configurations which also capture CO2 for sequestration. A plan for further ECL development includes work on key risk items, demonstration of a bench scale system and scale up of the enabling technology components. One key risk item is degradation of the LTA by coal contaminants. The results of several types of bench level contamination testing will be presented including test evaluation using coal introduced into actual scale LTA hardware. Other risk items that will be addressed in upcoming programs include continued refinement of ECL architecture and improvement of LTA durability. ECL is an early-stage concept with significant promise but many steps to full scale commercialization for utility power generation. CellTech has developed a commercialization path which incorporates early revenue from markets such as portable power and distributed generation with less demanding cost and durability goals compared with utility applications. These early markets, will provide near-term reliability improvement for the LTA while reducing the time and risk associated with development of baseload applications. P5-8

Effect of Preparing Condition on Apparent Viscosity of Coal Oil Slurry at Different Temperature and Atmospheric Pressure

Yonggang Wang, Xiangkun Guo, Chu’an Xiong, Shan Zhong, Wei Chen, Deping Xu, China University of Mining and Technology -Beijing, CHINA

Coal oil slurry, or coal solvent paste, one of emblematical solid liquid two phase flow, is a crucial important constituent of the feedstock for direct coal liquefaction, and its viscous property plays prominent technical rule for manageable and pumpable mixture preparation. The effects of preparation conditions, such as solvent, coal particle size, and concentration of coal particle on apparent viscosity of Chinese lignite (from Erdos, Inner Mongolia of China) oil slurry were investigated at temperature range from 303K to 623K and ambient pressure. Experimental investigations revealed that the pastes are non-Newtonian fluid. The viscosity of suspension possesses negative correlation with coal particle size distribution (CPSD). However, the apparent viscosity of suspending system presents complicated change at range of 353K to 623K. It decreases at range of 303K to 353~433K, and keeps, approximatively, constant at the range of 353~433K to 573K, and then, increases at range of 573K to 623K for different slurries. Notwithstanding the diversity, the viscosity of the mixtures can be predicted with a series of 6th-order polynomial models in terms of temperature. P5-12

Ab-Initio Studies of Palladium –Niobium Alloys for Hydrogen Separation Ekin Ozdogan, Shela Aboud, Jennifer Wilcox, Stanford University, USA

Coal, having the most abundant reserves of any fossil fuel by approximately 847 billion tonnes of proven reserves worldwide, provides at least 27% of the world’s total energy consumption. Moreover, its lower price compared to oil and natural gas, makes coal an economical source to be used for power generation. Gasification of coal used in power generation allows for the application of membranes by giving highly concentrated 40-55% vol. CO2 streams compared to the 15% vol. CO2 flue gas produced by typical pulverized coal combustion processes. The use of membranes not only reduces the carbon emissions by separating CO2 but also produces the clean energy carrier hydrogen. As a membrane material, palladium has been the main focus by many researchers since it has a high selective permeability and catalytic activity to H2. However, a high affinity of Pd to interact with sulfur species causes sulfur poisoning of the membrane even in ppm concentrations of sulfur and makes this option technically and economically unfavorable. It is possible to overcome these barriers and increase the functionality of the membranes by alloying Pd by other metals. Nb is a good candidate for this reason since it has the highest hydrogen permeability among any other 5A metals. Unfortunately, hydrogen embrittlement is an important drawback in the pure Nb systems. In this study, Pd-Nb alloys were investigated to understand the mechanisms involved in surface site stabilities, reactivity, and subsurface hydrogen diffusion. Binding energies of hydrogen and sulfur species in alloys of Pd and Nb were calculated by using the Vienna ab initio Simulation software package employing density functional theory. Surface and bulk properties of materials composed of transition metals were obtained through a density of states analysis and the reactivity was predicted using the “d-band center shift” model of Hammer and NØrskov. Moreover the binding mechanisms associated with hydrogen and sulfur were understood by calculating the local density of states (LDOS) of the s- p- and d-orbital states of the individual atoms.

P5-13

Synthesis of High Surface Area Materials for Solid Oxide Fuel Cells Robin Chao, John Kitchin, Paul Salvador, Carnegie Mellon University;

Christopher Matranga, DOE-NETL, USA The efficiency of the solid oxide fuel cell is limited by the cathode polarizations, and thus it is essential to understand the factors that influence the oxygen reduction reaction at the surface of cathode material to identify strategies for improving SOFC performance. Many tools are useful for surface chemical measurements, such as IR spectroscopy, but these techniques require very high specific surface area of the sample to obtain measurable signals. Conventional synthesis methods to produce perovskites, which are commonly used in the solid oxide fuel cell cathode, produce limited specific surface area materials (4m2/g ~ 30m2/g). Therefore, as the first step, a new synthesis path needs to be developed for obtaining high surface area materials for characterization. The approach in this work adopts evaporated-induced self-assembly (EISA) as the synthesis route, in which a mesoporous soft template formed with surfactants is backfilled with metal precursors. Upon calcination, the surfactants are decomposed and oxide forms with mesoporosity that provides high surface area. The main parameter tested in this work is the precursor/surfactant mixing ratio. In order to study the effects of the precursor/surfactant ratio, 5 mmol, 10 mmol, 20 mmol, and 40 mmol of metal precursors are mixed with fixed amount of surfactants in water and ethanol, and aged at room temperature with a relative humidity of 60%. Two commonly used organic templating agents have been used, including non-ionic tri-block polymer Pluronics 123 and anionic surfactant centrimonium bromide (CTAB), to test the effect of varying precursor/surfactant ratio in different surfactant systems. Upon evaporation, micellization takes place, and the soft template forms inside of the aging solution which determines the surface area of the produced powders. The solution then is calcined and ground in a mortar and pestle to be characterized. The produced lanthanum manganese oxide powders are characterized by X-ray diffraction (XRD) and BET analysis to examine their structure and specific surface area. With control of the synthesis condition parameters and choice of surfactants, pure phase perovskites with specific surface area higher than conventional methods are produced (40m2/g~50m2/g). The data indicates that as the precursor/surfactant ratio increases, the surface area as well increases from 4m2/g to 50m2/g, which shows a strong relation between surface area and the precursor/surfactant ratio. Results also suggest that the powders produced with CTAB have higher surface area than the ones produced with P123. The different outcome is much related to the mesophases formed during aging. The produced oxide powders were also subjected to temperature programmed desorption (TPD), and thermogravimetric analysis (TGA). A preliminary study with TGA shows that a weight loss occurred at 650°C in air, and it is partially reversible as temperature decreases to lower temperatures. It is suspected that the weight loss is due to loss of lattice oxygen. Further investigations of the surface reaction are in process. P5-15

Below the Petroleum Baseline using Coal: A Response to Section 526 Guido B. DeHoratiis, Mark Ackiewicz, U.S. Department of Energy; Ed

Schmetz, Leonardo Technologies, Inc., USA The major issue confronting domestic production of alternative transportation fuels today and in the future is balancing the ability to economically compete with liquid fuels produced from petroleum while addressing global climate change. The requirements of Section 526 of the Energy Independence and Security Act of 2007 (Section 526) set a standard that the lifecycle greenhouse gas (GHG) emissions of alternative or synthetic fuel be no more than its petroleum-derived equivalent. The concept of co-feeding coal and biomass mixtures to produce liquid fuels while capturing carbon dioxide (CO2) from the process will utilize coal in a way that is below the CO2 footprint specified in Section 526. Section 526 was proposed to ensure that federal agencies are not spending taxpayer dollars on new fuel sources that could exacerbate global warming and was in response to efforts by the U.S. Air Force to develop coal-to-liquid (CTL) fuels. The specific impact of Section 526 is prohibiting U.S. Federal agencies from entering into any contract for the procurement of an alternative or synthetic fuel, including fuel produced from non-conventional petroleum sources, unless the contract specifies that the lifecycle greenhouse gas emissions associated with such fuel are less than or equal to emissions from conventional petroleum sources. The requirement would ensure that any products from a coal-derived liquids facility sold to a government agency would include some form of carbon management. The reaction to Section 526 has been largely to find ways to ensure compliance to the standard. However, there remains little guidance on what alternative and synthetic fuels should be included. Terms like the petroleum baseline must be defined and the methodology to estimate the lifecycle GHG emissions must still be developed along with the certification and verification processes. There has been some resistance to Section 526, but none of the bills repealing Section 526 made it past their respective second readings in the House and the Senate. However, Section 121 of a draft of the Waxman/Markey climate bill would impose a federal low carbon fuel standard (LCFS)

56

similar to Section 526, but would expand the scope of the LCFS to all nationwide fuel markets. As with any technology attempting to meet the standards of Section 526, CBTL technology must address the technical, economic, environmental and social challenges associated with future deployment. DOE’s recent research awards will provide valuable experimental data that can be used to refine methods of implementing the feeding coal/biomass mixtures across a higher pressure gradient, detailed characterization of the products from gasifying coal/biomass mixtures, and optimization of the Fischer-Tropsch (FT) and Water-Gas-Shift (WGS) processes for coal/biomass mixtures. This research will better define the process strategies that can be made to reduce technical risks and the environmental footprint. The co-feeding of coal and biomass or co-siting of biomass and coal gasification technology with joint down-stream processing could produce quality liquid transportation fuels alone or in combination with electricity, and other co-products such as hydrogen and/or chemicals. Section 526 is an energy security and economic driver to further decrease the level of petroleum imports while also reducing the environmental impact of liquid fuels. Domestic production of fuels from coal and biomass enable the use of coal while maintaining an acceptable carbon footprint. P5-17

Effect of Potassium and Copper Additive on Iron-Ruthenium Composite Catalyst for Fischer-Tropsch Synthesis

Qingjie Tang, Xiangkun Guo, Yonggang Wang, Fan Shao, Liu Bo, Caihong Wang, China University of Mining and Technology -Beijing, CHINA

A series of Fe-Ru composite catalysts were prepared by sedimentation and immersion, the effects of potassium and copper on the performance of Fe-Ru composite catalyst for Fischer-Tropsch synthesis were investigated in a slurry bed reactor at 260℃, 2MPa, CO/H2＝1:1, and the effect of potassium and copper on reduction behavior of Fe-Ru composite catalyst were study by temperature programmed reduction (TPR). The results show that Fe-Ru composite catalyst possesses excellent performance for Fischer-Tropsch synthesis, the activity and selectivity of Fe-Ru composite catalyst can be improved by potassium and copper, and the addition of copper to the Fe-Ru composite catalytic system results in redounding to reduction of Fe-Ru composite catalyst. P5-18

Upgrading of Coal Liquids by Adsorptive Denitrogenation over Carbon-Based Adsorbent

Xiaoliang Ma, Na Li, Masoud Almarr, Chunshan Song, Pennsylvania State University, USA

Coal will become one of the major sources for transportation fuels again in near future. The coal liquids from direct coal liquefaction and pyrolysis contain up to more than 1 wt % of nitrogen. Thus, denitrogenation is one of the major tasks in upgrading of the coal liquids. The current commercial hydrotreating technologies that were developed for hydrodesulfurization of petroleum distillates may be not suitable for the upgrading of the coal liquids from direct coal liquefaction and pyrolysis, because the hydrodenitrogenation of such coal liquids needs to be operated at much severe conditions with much high hydrogen consumption. It is necessary to develop a new method that allows the denitrogenation of the coal liquid at more energy efficient, economical and environmentally friendly conditions. The adsorptive denitrogenation (ADN) is an alternative and promising method for upgrading of the coal liquids, as the ADN process can be conducted at ambient condition without using expensive hydrogen. The present paper reports our current approach to ADN of a model coal liquid and a real coal liquid by using the carbon-based adsorbents. The results indicate that some carbon-based material with surface modification is a promising adsorbent for upgrading of the coal liquids. P5-20

Mesophase Oriented Growth of a Copolymer-Modified Coal Tar Pitch Ming-Lin Jin, Ai-Hua Huang, Shanghai Institute of Technology; Xiao-Long

Zhou, Cheng-Lie Li, East China University of Science and Technology, CHINA

Coal tar pitch was modified by a special copolymer to meet the feedstock requirement for carbon material production. The mesophase oriented growth behaviors in early stages of the thermal treatment to pure and copolymer-improved pitches were comparatively studied by solvent analysis and polarized-light micrograph observation. It was demonstrated that the formation and coalescence of the mesophase spherules were accelerated and the flow anisotropy optical structures were clearly exhibited in the specimens soaked up to 24 and 30 hours, when a blend of the pitch with 1-3% copolymer was used as the feedstock. The function of copolymer addition was also discussed.

P5-23 SNG Production Process Based on Hybrid Gasification Shimin (Benjamin) Deng, Rory Hynes, Hatch, CANADA

A new SNG (synthetic natural gas) production process has been developed. It has advantages in performance, cost and operability. The performance of the new process is analyzed and compared with two existing processes – one process based on hydrogasification and one conventional SNG production process. Based on process modeling, exergy analysis is carried out to identify the specific loss of each sub-process. The thermodynamic features of the new process are investigated to show the trend of the parameters of the hybrid gasifier and the whole process. A concept of critical conversion rate is identified and defined. Key parameters of the hybrid gasifier and thermal performance of the system are examined and presented. Besides thermal performance, other issues related to operation and cost are discussed.

POSTER SESSION 6

COAL SCIENCE

P6-8

Hydropholized Limestone by Different Methods as an Antiexplosive Powder

Bronislaw Buczek, Elzbieta Vogt, AGH, University of Science and Technology, POLAND

Two kinds of stone powder are produced (regular and water-proof) which are used for sprinkling and for constructing dust barriers. A regular limestone powder is most commonly used for these purposes. Its major defect is its tendency to lose volatility, because of agglomeration under humid conditions, often reaching 100 % water saturation in mine atmospheres. Using the waterproof powder may eliminate it. Two different methods (hydrophobization from vapour phase and solutions) and various modifiers (stearic acid or silicones solution) have been used in order to manufacture hydrophobized limestone powder. Some of obtained in this way material may be used as an anti-explosive agent in the mining industry. Its properties have been analyzed according to Polish Standard. All obtained products are characterized not only by the typical properties for water-resistant materials but also by the properties suitable for fine materials. Obtained samples were analyzed with the use of the research methods originally applied in the powder technique due to the powder state of the material. Moreover the adhesive force and shear test was measured. Data from shear tests are mainly an important basis for design of reliable bulk solids handling equipment. In this work, these results tried to use as an index of hydrophobization level. The authors compare obtained results and determined which analytical methods applied in this work are the best for purposes of such materials characterization. Obtained results increase the present state of knowledge in the subject area of fine materials modification. P6-12

Study on Multi-Form Coal Impact Breakage using SHI’s Breakage Model

Weiran Zuo, Yaqun He, Jingfeng He, Nianxin Zhou, Baofeng Wen, China University of Mining and Technology, CHINA; Frank Shi,

University of Queensland, AUSTRALIA The Shi’s breakage model was introduced to describe the relationship of breakage index, t10, to the particle size and impact energy. To validate the application of this model in coal impact breakage, three types of impact breakage tests including drop weight test, rotary breakage test and bed breakage were conducted, which represent single particle binary side impact breakage, single particle single side impact breakage and particle batch impact breakage respectively. The results show that Shi’s breakage model fits the coal impact breakage well with the average R2 of above 0.95. For single particle, one side impact was found to be more efficient than binary side impact. For batch breakage, the sample with higher ash content was more liable to be broken due to ash grinding aid effect. The maximum t10 of coal impact breakage was subject to the breakage pattern in a large degree. In this paper, the mean maximum t10 of above three kinds of tests are 67.6%, 76.1% and, 43.7% respectively.