Abstract Booklet 2006 - Swanson School of Engineering - University ...

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these materials is likely to lead to the discovery of new and improved materials for hydrogen storage that meets the challenging specifications set by the US DOE. In the traditional rare earth intermetallic compounds, hydrogen is stored in the interstitial sites of a crystal. The heat of formation of the hydrides is typically about -15 kJ/H, the plateau pressures can be fine-tuned by modifying the alloy compositions, the kinetics of hydrogen absorption-desorption are fast ( ~200 sec.) and the volumetric hydrogen capacity is reasonably high. However, the gravimetric hydrogen storage capacity is only about 1.5 wt%, far short of DOE goals. Metallic magnesium chemically reacts with hydrogen to form stable MgH 2 with a heat of formation of ~-37 kJ/H. The theoretical gravimetric capacity is as high as 7 wt%. However, the kinetics of decomposition even in microcrystalline samples is extremely slow (several thousand seconds at ~300°C). Our recent research work has shown that (1) kinetics of decomposition of the hydride increases when the material is reduced to the nanocrystalline size through mechanical milling technique and (2) Addition of small amounts (~2 wt%) of, for example, nanocrystalline iron modifies the plateau pressure significantly. More recently, we have begun synthesis, characterization and hydrogen adsorption studies of Microporous Metal Organic Frameworks (MMOFs). These materials are composed of various metals, including selected group-1 and group-2 light elements and transition metals and sp 2 -carbon based ligands, which form the internal surfaces of the pores. We have synthesized several MMOF materials with a number of metals and organic ligands, and studied their hydrogen adsorption properties at room temperature as well as at low temperatures (78 K). For instance, we found that the hydrogen storage capacity is about 3 w% and 2.25 w% at 78 K and decreases to about 0.29 w% and 0.5 w% at room temperature for [Co 3 (bpdc) 3 bpy] 4DMF H 2 O (bpdc = biphenyldicarboxylate) and Cu 3 BTC (BTC = Benzene-1,3,5-tricarboxylate), respectively, at hydrogen pressures of ~30 atm. The hydrogen uptake appears to be related, in part, to the pore size and pore structure. Thermal stability, pore structure and hydrogen storage characteristics of these and other related MMOF materials will be presented. We have performed atomistically-detailed modeling of H 2 adsorption in various MMOF materials and have compared these theoretical predictions with experimental data. We have computed both the adsorption isotherms and isosteric heats of adsorption at different temperatures. In general we find qualitative agreement between simulations and experiments. The simulations indicate that the most attractive sites for adsorption are near the corners of the frameworks, close to where oxygens are bound to the metal atoms. Calculations indicate that substantially higher heats of adsorption are needed to effectively store hydrogen at room temperature. Supported by: US DOE Grants: DE-FC26-05NT42446 and DE-FG02-04ER83886 12-1 SESSION 12 GLOBAL CLIMATE CHANGE: GEOLOGIC CARBON SEQUESTRATION – 2 The Use of Water Injection for CO 2 Sequestration in Coalbeds Miguel Tovar, Shahab Mohaghegh, West Virginia University, USA Carbon capture and storage in geologic formations has been proposed as a global warming mitigation strategy that can contribute to stabilize the atmospheric concentration of carbon dioxide, the anthropogenic gas with the largest greenhouse effect. Particularly in the US, the storage of CO 2 in unmineable coalbeds is an attractive prospect due to the large amount of coal reserves and the possibility of enhanced coalbed methane recovery. This study introduces a new strategy for the prevention of post-sequestration CO 2 seepage to the surface from the CBM (CoalBed Methane) formations that is named the “Nature’s Sequestration Technique”. The idea is to retain the adsorbed CO 2 in the coalbed formation by having formation water filling the cleat system. Coalbed formations have the capacity to retain methane adsorbed on its surface through the geologic time under an appropriated pressure condition. This pressure condition is mainly established by water contained in the fracture network (the cleat system). We can take advantage of this natural occurrence in order to restore the system’s original conditions by filling the cleat system with water and having CO 2 adsorbed on the matrix instead of methane. Using a commercial numerical simulator and data representative of the Appalachian basin region; we investigate whether or not the presence of water on the cleats helps to sequester CO 2 in a coalbed for a long period of time without significant seepage. Several scenarios were considered for this study, with variations of depth, flow mechanism and nature of potential fracture that would work as a conduit for the seepage of CO 2 to the surface. Results show that water filling the coal cleat system decreases significantly the amount of CO 2 seeped to the formations above the target formation. 12-2 Numerical Modeling of CO 2 Sequestration in Unmineable Coal Seams Guoxiang Liu, Andrei Smirnov, West Virginia University, USA Numerical modeling of CO 2 sequestration in deep unmineable coal seams can be used for long term predictions of storage capacity of these reservoirs, as well as enables one to analyze possible CO 2 escape routes. In addition to this, the computations can provide estimates on the possibility of residual methane recovery in CO 2 sequestration operations. The process of CO 2 transport in a coal seam can be influenced by many factors, such as bounding layers permeabilities, porosities, fracture densities, etc. In this study a series of computer simulations was conducted with a purpose of predicting CO 2 transport in a multi-layer environment of typical unmineable coal seams. The parameters of three typical coal basins were considered as examples: San- Juan, Appalachian, and Powder River basins. In the majority of cases it was presumed that the upward migration was limited by the lowest permeability layers. An opensource OpenFOAM CFD solver (openfoam.org) was used in this study to analyze CO 2 transport in coal seams. Darcy’s diffusion term was added into the solver, and mass injection was modeled within the framework of compressible flow. To facilitate the analysis of more complex layer formations in reservoirs a voxel-based geometric design system was adapted and interfaced with the OpenFOAM and TOUGH2 simulators. The study can provide long term projections for the CO 2 sequestration operations in known coal seams. 12-3 Determination of Coalbed Methane Potential and Gas Adsorption Capacity in Western Kentucky Coals Sarah Mardon, Kathy G. Takacs, James C. Hower, Cortland F.Eble, University of Kentucky, USA Maria Mastalerz, Indiana University, USA The Illinois Basin has not been developed for Coalbed Methane (CBM) production. It is imperative to determine both gas content and other parameters for the Kentucky portion of the Illinois Basin if exploration is to progress and production is to occur in this area. This research is part of a larger project being conducted by the Kentucky Geological Survey to evaluate the CBM production of Pennsylvanian-age western Kentucky coals in Ohio, Webster, and Union counties using methane adsorption isotherms, direct gas desorption measurements, and chemical analyses of coal and gas. This research will investigate relationships between CBM potential and petrographic, surface area, pore size, and gas adsorption isotherm analyses of the coals. Maceral and reflectance analyses are being conducted at the Center for Applied Energy Research. At the Indiana Geological Survey, the surface area and pore size of the coals will be analyzed using a Micrometrics ASAP 2020, and the CO 2 isotherm analyses will be conducted using a volumetric adsorption apparatus in a water temperature bath. The aforementioned analyses will be used to determine site specific correlations for the Kentucky part of the Illinois Basin. The data collected will be compared with previous work in the Illinois Basin and will be correlated with data and structural features in the basin. Gas composition and carbon and hydrogen isotopic data suggest mostly thermogenic origin of coalbed gas in coals from Webster and Union Counties, Kentucky, in contrast to the dominantly biogenic character of coalbed gas in Ohio County, Kentucky. 12-4 Effects of Structural Rearrangements on Sorption Capacity of Coals Vyacheslav Romanov, Yee Soong, Robert Warzinski, Ronald Lynn, DOE/NETL, USA Recently, the problems in practical application of experimental data and modeling to the sequestration of carbon dioxide in coal seams and the concurrent enhanced coalbed methane (ECBM) recovery have underscored the need for new approaches that take into account the ability of coal for structural rearrangements. Areas of interest include plasticization of coal due to CO 2 dissolution, the effect of coal swelling on estimation of the capacity of a coal-seam to adsorb CO 2 (adsorption isotherm), and the stability of the CO 2 saturated phase once formed, especially with respect to how it might be affected by changes in the post-sequestration environment (environmental effects). Coals are organic macromolecular systems well known to imbibe organic liquids and carbon dioxide. CO 2 dissolves in coals and swells them. The problems become more prominent in the region of supercritical CO 2 . We investigated the effects of moisture content and pressure cycling history on temporal changes in the coal sorptive capacity for a set of Argonne premium coals. The samples were tested as received, dried at 80°C for 36 hours, and moisture equilibrated at 96-97% RH and 30°C for 48 hours. The powders were compared to core samples. Additionally, plasticization of coal powders was studied by high pressure dilatometer. 12-5 Sorption of Gases by Argonne Premium Coals at Supercritical Pressures Richard Sakurovs, Stuart Day, Steve Weir, Greg Duffy, CSIRO Energy Technology, AUSTRALIA Modelling the sorption properties of coals for carbon dioxide under supercritical conditions is necessary for accurate prediction of the sequestering ability of coals in seams. We present recent data for sorption curves for three dry Argonne Premium coals using a gravimetric system, and apply a recently developed model to the fitting of the excess sorption by these coals of carbon dioxide, methane and nitrogen at two different temperatures at pressures up to 15MPa. The model is unique in that it uses gas density rather than pressure as the main variable. It is a modified Dubinin- Radushkevich (DR) equation, using adsorbed phase density rather than saturation pressure as the upper limit. The fit of this model is generally around 1% of the sorption capacity. The sorption capacity of the coal is found to decrease with increasing temperature, which disagrees with expectations from simple models of coal sorption that predict a sorption capacity that is independent of temperature. This means that sorption capacity should not be considered a direct measure of the surface area of coal. 10
13-1 SESSION 13 GASIFICATION TECHNOLOGIES: APPLICATIONS AND ECONOMICS – 3 GE and Bechtel’s IGCC Reference Plant Update Rich Rapagnani, GE Energy, USA For background, GE Energy purchased ChevronTexaco's gasification technology business in June of 2004, and soon thereafter formed an IGCC alliance with Bechtel Corporation to jointly develop and commercialize an IGCC reference plant. Rated nominally at 630 MW, this IGCC Reference Plant provides customers a commercially competitive, cleaner coal alternative for coal to power. Moreover, the GE and Bechtel IGCC Alliance provides this IGCC product on a turnkey basis, including commercial guarantees, thus offering the total package customers need for successful commercialization of their project. This presentation provides to the conference attendees an update on the GE and Bechtel IGCC Reference Plant design status, a look at the fuel flexibility benefits inherent in such a plant design, a preview of the expanded fuel envelope capabilities under development by GE and a discussion of the business aspects supporting development of IGCC projects. 13-2 Beluga Coal Gasification Feasibility Study Phase 1 Ronald Schoff, Robert Chaney, RDS-Parsons Corporation, USA The Beluga Coal Gasification study aims to determine the economic feasibility of siting a coal-based gasification plant in the Cook Inlet region of Alaska for the co-production of electric power and marketable by-products. The plant products may include synthesis gas, Fischer-Tropsch (F-T) liquids, fertilizers such as ammonia and urea, alcohols, hydrogen, nitrogen and carbon dioxide, that would be manufactured for local use or for sale in domestic and foreign markets. The project was divided into two phases. In Phase 1, the Agrium fertilizer plant in Nikiski serves as the case study site and customer for product gases (including hydrogen, nitrogen and carbon dioxide), steam and power from the coal gasification facility. In Phase 2, an assessment of alternative locations and plant designs based on local and export markets for the suite of potential products will take place. The Phase 1 case study results, reported here, will feed into the Phase 2 central Alaska regional study. The project may be broken into four major subject areas, described below: Gasification Plant Design: The coal gasification plant investigated in this study is designed to provide the Kenai Nitrogen Operations (KNO) plant with the following suite of required products: • 282 million standard cubic feet per day (MMSCFD) of hydrogen at 400 psig and of suitable quality for ammonia production. • Stoichiometric quantity of nitrogen (approximately 100 MMSCFD) at 400 psig and 99.99% purity. • 1,500,000 lb/hr steam at 1500 psig and a minimum temperature of 825°F. • 300,000 lb/hr steam at 600 psig and 625°F. • 2,500 tpd CO 2 suitable for urea production (25 psig) • Electric power to satisfy the auxiliary power requirements for the gasification plant and the KNO facility, to make the entire facility electric power independent. Two cases were considered: Case 1: Process the syngas from the gasification plant to supply required hydrogen and nitrogen to the KNO ammonia synthesis loop compressor and produce sufficient steam and power for the KNO needs. Capital Cost was $1.64 billion. Case 2: Process the syngas from the gasification plant to supply required hydrogen and nitrogen to the KNO ammonia synthesis loop compressor, but do not produce power from a gas turbine. Rather, independently produce the required steam and power for the KNO facility with a CFB coal-fired boiler. Capital Cost was $1.87 billion. Financial Analysis - The Power Systems Financial Model Version 5.0 (now the standard used by NETL for IGCC systems analysis) was used to perform the financial analysis. Factors in the analysis included: coal and limestone supply and cost, by-product markets, and impact on local natural gas and electric power markets. Project return on equity investment (ROI) and a discounted cash flow analysis were key results. Identification of key model sensitivities also occurred. Case 1 possesses superior financial potential relative to Case 2. For Case 1, the ROI was 11.1% with a Payback Year of 2023, assuming start-up in 2011. For Case 2, the ROI was 6.0% with a Payback Year of 2031. While both cases produce enough raw materials necessary for ammonia and urea production at the Agrium facility, Case 2 is more expensive, produces less export power, and requires slightly more coal feed in order to do so. Sensitivity analysis was performed on all model inputs in both cases. The items found to have the greatest impact on the financial results are the plant EPC cost, system availability, ammonia/urea prices, and coal price. Environmental Issues The analysis of the design basis indicates that a proposed IGCC facility at the Agrium Kenai Plant is feasible in terms of current environmental permitting and compliance requirements imposed by federal, state and local regulations. Carbon Capture/Use - The potential for use of CO 2 for enhanced oil recovery in regional oil fields was a major consideration. It was determined that CO 2 floods could economically produce up to 300 million barrels of oil in Cook Inlet fields with oil prices at $35 to $40/bbl and CO 2 price at from $0.50 to $1.20/mcf. The production potential is equal to that achieved locally over the last 25 years by conventional methods. 13-3 2006 Cost and Performance Estimates of Fossil Energy Power Plants Jared P. Ciferno, RDS-Parsons Corporation, USA Julianne Klara, NETL, USA In 1999, the Department of Energy s National Energy Technology Center (NETL) sponsored a report entitled Market-Based Advanced Coal Power Systems in response to a newly deregulated power industry. The study, conducted by Parsons Corporation, compared the performance and economics of power systems that were advanced, yet market-ready within a 5 year time frame that included Pulverized Coal Boiler (PC), Natural Gas Combined Cycle (NGCC), Integrated Gasification Combined Cycle (IGCC) and 2nd Generation Pressurized Fluidized Bed Combustion (PFBC) power plants. In the 7 years since this report was published, natural gas prices have more than doubled while proposed emissions regulations such as EPA s Clean Air Interstate Rule (CAIR) and the Proposed Power Plant Mercury Rule, have forced the potential inclusion of control devices and operational strategies to lower future power plant emissions. Furthermore, concern over the potential effect of CO 2 emissions from fossil fuel power plants on the global climate is a key issue for the future of power generation worldwide. With energy demand projected to rise by over 60% through 2030, limiting CO 2 emissions from power plants is becoming ever more pressing. Finally, technological advances such as the anticipated introduction of a synthesis gas fired gas turbine and expected improvements in the operation of gasifiers will affect the overall plant performance. As a result of changing economic, regulatory and technological issues, the 1999 study has become outdated. The effort that is currently underway is the 2006 Market-Based Advanced Coal Power Systems study, expanded to include three competitive gasifier technologies, with and without CO 2 capture. Economic issues, including the rapid increase in natural gas prices and the shift in the industry back to coal-based plants, are considered here. Pollution control technology advances, brought about by anticipated regulation, result in cleaner plants. Advances in gas turbine, gasifier and other balance of plant equipment are taken into account. Cost and performance results of the study effort will be discussed in this paper and at the conference presentation. 13-4 Advanced Clean Coal Technologies for Capture Minish Shah, Praxair, Inc., USA In the absence of any regulations on CO 2 emissions in the US, the focus is on building new power plants that are CO 2 capture ready. This paper compares and contrasts two advanced clean coal technologies for CO 2 capture: Integrated Gasification Combined Cycle and Oxy- Coal Fired Boiler. The gasification has been widely promoted and the oxy-fuel combustion is also gaining support as a viable alternative for CO 2 capture. Both of these technologies are touted for their potential to capture CO 2 at low cost. There are significant differences in the commercial readiness and the CO 2 capture readiness. These issues will be highlighted and the cost and performance with CO 2 capture will be presented for both the technologies. All the individual components of IGCC plant with CO 2 capture have been demonstrated in large scale operation in different applications. The main obstacles to commercialization of IGCC are uncertainties related to costs and reliability. Adding CO 2 capture capability to IGCC will impact the performance of all the major sub-units (gasification, combined cycle and ASU). Therefore, to make IGCC CO 2 capture ready, significant preplanning will be required. The oxy-fuel technology allows utilities to build power plants based on air-fired PC boiler, technology they are most familiar with and one which requires lower initial investment compared to IGCC. And for CO 2 capture, two new sub-systems (an air separation unit and a CO 2 clean-up unit) can be installed only when needed further minimizing up-front investment. However, there has been no large-scale demonstration of some of the subcomponents of this technology. Although in theory, the oxy-coal fired boiler can be operated to mimic the air-coal fired boiler, testing at smaller scale will be necessary to understand flame and heat transfer characteristics and materials compatibility due to different chemical environment within the boiler. The learnings from such testing will also be needed to establish whether any design changes are required for the CO 2 -capture ready plant. The CO 2 clean-up will also require further development to address issues related to impurities such as SO x and NO x . 13-5 Power Systems Development Facility Update on Six Trig Studies Luke H. Rogers, Southern Company Services, USA George S. Booras, Electrical Power Research Institute, USA Ronald W. Breault, National Energy Technology Center, USA Nicola Salazar, Kellogg Brown and Root, Inc., USA The pursuit of more cost-effective and reliable coal technologies with superior environmental performance continues to drive the development of the Transport Gasifier at the Power Systems Development Facility (PSDF). This paper presents the results of six updated system and economic studies of Transport Integrated Gasification (TrIG) plants. Southern Company and Kellogg Brown and Root (KBR), in conjunction with the U.S. Department of Energy (DOE) and other partners, are developing the TrIG process at the PSDF for commercial application in the power industry. The PSDF is an engineering scale demonstration of the KBR Transport Gasifier along with a high-temperature, high-pressure 11
Page 1 and 2: TABLE OF CONTENTS Oral Sessions Pag
Page 3 and 4: 1-1 SESSION 1 GASIFICATION TECHNOLO
Page 5 and 6: The U.S. pioneered development of s
Page 7 and 8: 5-5 Enhanced Hydrogen Production wi
Page 9 and 10: derived synthesis gases employing i
Page 11: Several physical adsorbents, partic
Page 15 and 16: promising Clean Coal technologies u
Page 17 and 18: high selectivity (theoretically pro
Page 19 and 20: 19-3 Development of Highly Efficien
Page 21 and 22: The Aim of the project is the impro
Page 23 and 24: 24-3 Development of Fluidizable Lit
Page 25 and 26: the classical Lurgi-gasifcation pro
Page 27 and 28: 28-5 A Kinetic Approach to Catalyti
Page 29 and 30: turbine cycles. The models provide
Page 31 and 32: up to 290 psia and temperatures up
Page 33 and 34: 35-2 Development of Iron-Based Pero
Page 35 and 36: features of the BGL 1000 technology
Page 37 and 38: Heat-exchangers, particle filters,
Page 39 and 40: 41-4 Using Fly Ash-Based Foundry Co
Page 41 and 42: ocks using elemental ratios. Data f
Page 43 and 44: 600-900°C. Changes in the amount o
Page 45 and 46: ATL process has three stages, namel
Page 47 and 48: commercial-scale gasifier was shutd
Page 49 and 50: 52-5 Pilot-Scale Demonstration of U
Page 51 and 52: POSTER SESSION 1 COMBUSTION TECHNOL
Page 53 and 54: experimental data available in lite
Page 55 and 56: activation. It was concluded that C

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