Showing papers on "Integrated gasification combined cycle published in 2004"

An integrated modeling framework for carbon management technologies

Abstract: CO{sub 2} capture and storage (CCS) is gaining widespread interest as a potential method to control greenhouse gas emissions from fossil fuel sources, especially electric power plants. Commercial applications of CO{sub 2} separation and capture technologies are found in a number of industrial process operations worldwide. Many of these capture technologies also are applicable to fossil fuel power plants, although applications to large-scale power generation remain to be demonstrated. This report describes the development of a generalized modeling framework to assess alternative CO{sub 2} capture and storage options in the context of multi-pollutant control requirements for fossil fuel power plants. The focus of the report is on post-combustion CO{sub 2} capture using amine-based absorption systems at pulverized coal-fired plants, which are the most prevalent technology used for power generation today. The modeling framework builds on the previously developed Integrated Environmental Control Model (IECM). The expanded version with carbon sequestration is designated as IECM-cs. The expanded modeling capability also includes natural gas combined cycle (NGCC) power plants and integrated coal gasification combined cycle (IGCC) systems as well as pulverized coal (PC) plants. This report presents details of the performance and cost models developed for an amine-based CO{sub 2} capture system, representing the baseline of current commercial technology. The key uncertainties and variability in process design, performance and cost parameters which influence the overall cost of carbon mitigation also are characterized. The new performance and cost models for CO{sub 2} capture systems have been integrated into the IECM-cs, along with models to estimate CO{sub 2} transport and storage costs. The CO{sub 2} control system also interacts with other emission control technologies such as flue gas desulfurization (FGD) systems for SO{sub 2} control. The integrated model is applied to study the feasibility and cost of carbon capture and sequestration at both new and existing PC plants as well as new NGCC plants. The cost of CO{sub 2} avoidance using amine-based CO{sub 2} capture technology is found to be sensitive to assumptions about the reference plant design and operation, as well as assumptions about the CO{sub 2} capture system design. The case studies also reveal multi-pollutant interactions and potential tradeoffs in the capture of CO{sub 2}, SO{sub 2}, NO{sub 2} and NH{sub 3}. The potential for targeted R&D to reduce the cost of CO{sub 2} capture also is explored using the IECM-cs in conjunction with expert elicitations regarding potential improvements in key performance and cost parameters of amine-based systems. The results indicate that the performance of amine-based CO{sub 2} capture systems can be improved significantly, and the cost of CO{sub 2} capture reduced substantially over the next decade or two, via innovations such as new or improved sorbents with lower regeneration heat requirements, and improvements in power plant heat integration to reduce the (currently large) energy penalty of CO{sub 2} capture. Future work will explore in more detail a broader set of advanced technology options to lower the costs of CO{sub 2} capture and storage. Volume 2 of this report presents a detailed User's Manual for the IECM-cs computer model as a companion to the technical documentation in Volume 1.

Greenhouse gas emissions from coal gasification power generation systems

Abstract: Life cycle assessments (LCA) of coal gasification-based electricity generation technologies for emissions of greenhouse gases (GHG), principally CO2, are computed. Two approaches for computing LCAs are compared for construction and operation of integrated coal gasification combined cycle (IGCC) plants: a traditional process-based approach, and one based on economic input-output analysis named Economic Input-Output Life Cycle Assessment (EIO-LCA). It is shown that EIO-LCA provides a more complete accounting for emissions incurred during construction resulting in larger estimates of emissions. For plant construction process-based LCA computes emissions that approximate a subset of emissions computed via the EIO-LCA method. For plant operation, however, only emissions due to mining and consumption of coal at the plant are significant, and both methods of analysis give essentially equivalent results. For conventional coal-based power generators, and even for those that would capture 90% of carbon emissions, GHG emissions during a typical operating life of 30-50 years dominate the life cycle. Literature values for life cycle emissions of GHGs for a number of renewable technologies are compared to emissions from IGCC systems with and without carbon capture and from natural gas combined cycle (NGCC) without capture. Lowest life cycle emissions are achieved with dammed hydro power and wind farms. IGCC with 90% CO2 capture exhibits lower life cycle GHG emissions than NGCC and solar photovoltaic systems.

Recovery of CO2 with MEA and K2CO3 absorption in the IGCC system

Abstract: Recovery of CO2 with monoethanolamine (MEA) and hot potassium carbonate (K2CO3) absorption processes in an integrated gasification combined cycle (IGCC) power plant was studied for the purpose of development of greenhouse gas control technology. Based on energy and exergy analysis of the two systems, improvement options were provided to further reduce energy penalty for the CO2 separation in the IGCC system. In the improvement options, the energy consumption for CO2 separation is reduced by about 32%. As a result, the thermal efficiency of IGCC system is increased by 2.15 percentage-point for the IGCC system with MEA absorption, and by 1.56 percentage-point for the IGCC system with K2CO3 absorption. Copyright (C) 2004 John Wiley Sons, Ltd.

Carbon dioxide absorption and fixation method for flue gas

Abstract: The present invention provides a low-cost carbon dioxide fixation method that allows effective usage of a large amount of generated coal ashes, and effective fixation of carbon dioxide included in flue gas generated from coal, refuse, or waste product, as well as improvement in the applicability of coal ashes to various applications and effective usage of by-product carbonate. Carbon dioxide is absorbed and fixated by subjecting the flue gas to gas-liquid contact with coal ash water slurry or coal ash eluate so as to make the carbon dioxide in the flue gas react and be absorbed thereinto, thereby fixating the carbon dioxide as carbonate. This method can be favorably used for disposal of flue gas from a boiler at a coal thermal power plant.

Coupling of Biomass Steam Gasification and an SOFC-Gas Turbine Hybrid System for Highly Efficient Electricity Generation

Abstract: An energetic model of an internal reforming solid oxide fuel cell (IRSOFC) is developed. It is integrated in a process coupling fluidized bed steam gasification of biomass and an IRSOFC-gas turbine hybrid cycle. Process simulation is performed using the software package IPSEpro. The model of the gasification and gas conditioning section is based on data from the 8 MW (fuel power) plant in Guessing/Austria, while the fuel cell is modeled based on recent literature data. Heat utilization for power generation is considered covering both hybrid cycle exhaust and heat from the gasification process. Electric efficiencies up to 43% are expected for combined heat and power application even at small plant capacities in the range of 8 MW fuel power.Copyright © 2004 by ASME

Gasification and Combustion of Brown Coal

Abstract: Publisher Summary This chapter deals with coal gasification, which refers to the reactions of coal with air, oxygen, steam, carbon dioxide, hydrogen or a mixture of these gases to yield a gaseous product These products can be used either as a source of energy or as a raw material for the synthesis of chemicals, liquid fuels or other gaseous fuels The gasification converts solid coal into gaseous products Since coal combustion is defined as the reactions of coal with air or oxygen, it can be regarded as a special case of coal gasification When as-received Victorian brown coal is heated up under gasification conditions, it first undergoes dewatering and pyrolysis Unlike bituminous coals and many other low rank coals, Victorian brown coals have large contents of moisture (60 - 65 %) The dewatering process is therefore particularly important from a practical point of view In the pyrolysis step (sometimes referred to as devolatilisation), inorganic and hydrocarbon gases as well as tarry vapors evolve as volatile matters to leave a solid residue as char Subsequently, a relatively slow reaction of the devolatilised char with a gasifying agent takes place predominantly

Hot gas granular moving bed filters for advanced power systems

Abstract: In advanced coal-fire cycles it is important to remove the fine particles from high temperature and high pressure gas streams, to satisfy gas turbine fuel quality requirements. J Smid, S S Hsiau, C Y Peng and H T Lee assess granular moving bed hot gas particulate clean-up systems for advanced IGCC and PFBC, under development in the USA.

Evaluation of Gas Turbine and Gasifier-based Power Generation System

Abstract: As a technology in early commercial phase, research work is needed to provide evaluation of the effects of alternative designs and technology advances and provide guidelines for development direction of Integrated Gasification Combined Cycle (IGCC) technology in future. The objective of this study is to evaluate the potential pay-offs as well as risks of technological infeasibility for IGCC systems and to provide insight regarding desired strategies for the future development of advanced IGCC systems. Texaco gasifier process is widely used in power generation. A process simulation model for a base Texaco gasifier-based IGCC system, including performance (e.g., efficiency), emissions, and cost, was implemented in the ASPEN Plus. To find out the implications of the effects of coal compositions on IGCC plant, Illinois No.6, Pittsburgh No.8, and West Kentucky coal are selected for comparison. The effects of the most advanced Frame 7H and the current widely used Frame 7F gas turbine combined cycles on IGCC system were evaluated. The IGCC system based on 7H gas turbine (IGCC-7H) has higher efficiency, lower CO2 emission, and lower cost of electricity than the 7FA based system (IGCC-7FA). A simplified spreadsheet model is developed to estimate performance of gas turbine combined cycle. This study implicated the ability to do desktop simulations to support policy analysis. Uncertainty analysis is implemented to evaluate risks associated with IGCC systems, i.e., there is about 80% probability that the uncertain results of the efficiency of IGCC-7FA are lower than the deterministic result. The IGCC-7H system is superior to IGCC-7FA despite the uncertainty of inputs. Gasifier carbon conversion and project uncertainty are identified as the key uncertain inputs. The effects of different integration methods of air separation unit (ASU) and gas turbine are evaluated. The results indicate that the integrated IGCC design has higher efficiency and lower cost than nonintegrated design. Recommendations are provided based on the simulation and evaluation work, and main conclusions. More standard IGCC systems should be developed to provide a consistent basis for benchmarking, verification, and comparison.

Underground Coal Gasification for Power Generation: High Efficiency and CO2-Emissions

Abstract: Underground Coal Gasification (UCG) is a gasification process carried out in non-mined coal seams using injection and production wells drilled from the surface, enabling the coal to be converted into product gas. The UCG process practiced by Ergo Exergy is called Exergy UCG or e UCG. e UCG was applied in the Chinchilla UCG-IGCC Project in Australia. The IGCC project in Chinchilla, Australia has been under development since July 1999. The project involves construction of the underground gasifier and demonstration of UCG technology, and installation of the power island. Since December 1999 the plant has been making gas continuously, and its maximum capacity is 80,000 Nm3 /h. Approximately 32,000 tonnes of coal have been gasified, and 100% availability of gas production has been demonstrated over 30 months of operation. The UCG operation in Chinchilla is the largest and the longest to date in the Western world. The e UCG facility at Chinchilla has used air injection, and produced a low BTU gas of about 5.0 MJ/m3 at a pressure of 10 barg (145 psig) and temperature of 300° C (570° F). It included 9 process wells that have been producing gas manufactured from a 10 m thick coal seam at the depth of about 140 m. The process displayed high efficiency and consistency in providing gas of stable quality and quantity. The results of operations in Chinchilla to date have demonstrated that e UCG can consistently provide gas of stable quantity and quality for IGCC power projects at very low cost enabling the UCG-IGCC plant to compete with coal-fired power stations. This has been done in full compliance with rigorous environmental regulations. A wide range of gas turbines can be used for UCG-IGCC applications. The turbines using UCG gas will demonstrate an increase in output by up to 25% compared to natural gas. The power block efficiency reaches 55%, while the overall efficiency of the UCG-IGCC process can reach 43%. A UCG-IGCC power plant will generate electricity at a much lower cost than existing or proposed fossil fuel power plants. CO2 emissions of the plant can be reduced to a level 55% less than those of a supercritical coal-fired plant and 25% less than the emissions of NG CC.Copyright © 2004 by ASME

Co-Gasification of Coal and Biomass in an IGCC Power Plant: Gasifier Modeling

Abstract: Co-gasification of coal and biomass in an existing coal-fired IGCC power plant is proposed as an efficient, flexible and environmentally friendly way to increase the biomass contribution to electricity generation. A model of an entrained flow gasifier is described and validated with nearly 3,000 actual steady-state operational data points (4,800 hours). The model is then used to study co-gasification of coal, petroleum coke and up to 10 percent of several types of biomass. As a result, the influence of fuel variations on gasifier performance and modifications in operation that should be made in co-gasification are obtained. A conclusion of our study is that co-gasification is possible provided that operation is properly adapted. A validated model can be very useful for predicting operating points for new fuel mixtures.

Gas turbine power augmentation method

Abstract: A power augmentation method for a gas turbine (1) in which water is injected into one or more stages (22, 24, 26, 28) of an auxiliary compressor (2) to produce a vapor containing gas stream (20). The vapor containing gas stream (20) is at least in part introduced into combustors (16) of the gas turbine (1) for power augmentation. Part of the vapor containing compressed gas stream (20) can be introduced into a reactor (84) to generate a hydrogen containing synthesis gas (90) to support lower flame temperatures occurring within the combustors (16) of the gas turbine (1) due to the introduction of the vapor containing gas stream (20). In such manner, NOx emissions of the gas turbine (1) can be reduced. Furthermore, the power augmentation method can be conducted in conjunction with an integrated gasification combined cycle (124).

System Study of Rich Catalytic/Lean burn (RCL) Catalytic Combustion for Natural Gas and Coal-Derived Syngas Combustion Turbines

Abstract: Rich Catalytic/Lean burn (RCL{reg_sign}) technology has been successfully developed to provide improvement in Dry Low Emission gas turbine technology for coal derived syngas and natural gas delivering near zero NOx emissions, improved efficiency, extending component lifetime and the ability to have fuel flexibility. The present report shows substantial net cost saving using RCL{reg_sign} technology as compared to other technologies both for new and retrofit applications, thus eliminating the need for Selective Catalytic Reduction (SCR) in combined or simple cycle for Integrated Gasification Combined Cycle (IGCC) and natural gas fired combustion turbines.

Carbon Dioxide Capture and Transportation Options in the Illinois Basin

Abstract: This report describes carbon dioxide (CO{sub 2}) capture options from large stationary emission sources in the Illinois Basin, primarily focusing on coal-fired utility power plants The CO{sub 2} emissions data were collected for utility power plants and industrial facilities over most of Illinois, southwestern Indiana, and western Kentucky Coal-fired power plants are by far the largest CO{sub 2} emission sources in the Illinois Basin The data revealed that sources within the Illinois Basin emit about 276 million tonnes of CO2 annually from 122 utility power plants and industrial facilities Industrial facilities include 48 emission sources and contribute about 10% of total emissions A process analysis study was conducted to review the suitability of various CO{sub 2} capture technologies for large stationary sources The advantages and disadvantages of each class of technology were investigated Based on these analyses, a suitable CO{sub 2} capture technology was assigned to each type of emission source in the Illinois Basin Techno-economic studies were then conducted to evaluate the energy and economic performances of three coal-based power generation plants with CO{sub 2} capture facilities The three plants considered were (1) pulverized coal (PC) + post combustion chemical absorption (monoethanolamine, or MEA), (2) integrated gasification combined cycle (IGCC) + pre-combustion physical absorption (Selexol), and (3) oxygen-enriched coal combustion plants A conventional PC power plant without CO2 capture was also investigated as a baseline plant for comparison Gross capacities of 266, 533, and 1,054 MW were investigated at each power plant The economic study considered the burning of both Illinois No 6 coal and Powder River Basin (PRB) coal The cost estimation included the cost for compressing the CO{sub 2} stream to pipeline pressure A process simulation software, CHEMCAD, was employed to perform steady-state simulations of power generation systems and CO{sub 2} capture processes Financial models were developed to estimate the capital cost, operations and maintenance cost, cost of electricity, and CO{sub 2} avoidance cost Results showed that, depending on the plant size and the type of coal burned, CO{sub 2} avoidance cost is between $47/t to $67/t for a PC +MEA plant, between $2203/t to $3205/t for an oxygen combustion plant, and between $1358/t to $$2678/t for an IGCC + Selexol plant A sensitivity analysis was conducted to evaluate the impact on the CO2 avoidance cost of the heat of absorption of solvent in an MEA plant and energy consumption of the ASU in an oxy-coal combustion plant An economic analysis of CO{sub 2} capture from an ethanol plant was also conducted The cost of CO{sub 2} capture from an ethanol plant with a production capacity of 100 million gallons/year was estimated to be about $$1392/t

Biomass Gasification Combined Cycle Thermodynamic Optimisation Using Integrated Drying

Abstract: The conversion of solid fuels such as biomass into a combustible gas provides the opportunity to enhance the efficiency of biomass based power systems. It allows solid fuels to be used in high efficiency power generation processes such as Integrated Gasification Combined Cycle (IGCC). Using woody biomass with high water content without drying has negative effects on the overall efficiency of the process. The option of using dryer biomass is limited by the higher fuel costs. Drying with low temperature heat is the link between the usage of wet low price fuel and optimum process conditions. In this paper, the possibilities of integrating fuel drying into a pressurized IGCC process and the effects on the efficiencies are discussed. For this purpose, an equation oriented process simulation environment with a modular structure is used. Different dryer types are integrated into this tool. Several solutions for the implementation of a drying into an IGCC process are investigated using steam and exhaust gas as heat sources. The obtained results are analyzed by the means of an exergetic analysis. Finally an optimum concept with a high electrical efficiency was obtained which will also meet the environmental regulations. Integrating drying into a biomass based IGGC concept can be an essential step for the economic operation of a plant.Copyright © 2004 by ASME

Long-term Perspectives for Carbon Capture in Power Plants: Scenarios for the 21st Century

Abstract: The report analyzes the role of fossil-fired power plants equipped with carbon capture systems in long-term scenarios of the global energy system representing technological change as an endogenous process. Within this framework the impacts of a technology policy is illustrated that requires over time an increasing fraction of fossil-fired power generation to incorporate carbon capture technologies. In particular, we examine the potential costs and the contribution that such a policy could offer in reducing energy-related carbon dioxide emissions and highlight some of the technologies that may play a role in doing so. The analysis is carried out with the global energysystems optimization MESSAGE model (Messner and Strubegger 1995) considering endogenous technology learning for fossil power plants and the corresponding carbon capture technologies, such that they experience cost reductions as a function of accumulated capacity installations. The report describes two baseline scenarios: (1) including learning for fossil power plants and (2) the other with no learning. In addition, the analysis examines three cases that are based on a technology policy that enforces an increasing share of fossil fuel power plants with carbon capture, distinguishing between future worlds assuming: (1) no learning for fossil systems, (2) learning just for the carbon capture component, and (3) full learning for the reference plants as well as for the carbon capture systems. The analysis shows that the introduction of a policy for carbon capture and storage would lead to considerable reductions in carbon emissions in the electricity sector and major changes in the power generation mix. Technologies are chosen, that provide the most cost-effective combination between electricity generation and carbon capture, fostering the penetration of advanced fossil technologies. In particular, coal gasification systems such as, IGCC power plants and high temperature fuel cells, and in addition gas-fired combined cycle power plants appear as the most attractive fossil-fired electricity generation options.

The Prospects for Integrating Fast Pyrolysis into Biomass Power Systems

Abstract: Pyrolysis has progressed significantly in the processing of herbaceous materials as well as woody plants. In fast pyrolysis, the widely used fluid bed reactor is a relatively simple design with favourable heat transfer characteristics. Recent advancements in char removal and bio-oil collection increase the effective use of pyrolysis oils as fuel in advanced power cycles. Due to the shortcomings of integrated gasification/combined cycles (IGCC), we are developing an alternative to IGCC for biomass power: the integrated (fast) pyrolysis/combined cycle (IPCC). Solid biomass is converted into liquid bio-oil. This bio-oil is a mixture of oxygenated organic compounds and water that can fuel a gas turbine topping cycle. Resulting waste heat provides thermal energy to a steam turbine bottoming cycle. Advantages of the biomass-fueled IPCC system include: combined cycle efficiency exceeding 33.6% efficiency for a system as small as 7.6 MW; absence of high-pressure thermal reactors; decoupling of fuel processing and power generation; and opportunities for recovering value-added products from the bio-oil. In addition, this technology co-utilizes biomass with natural gas in the pyrolysis cycle and diesel fuel in the turbine cycle. This article reviews the state of fast pyrolysis technology, describes the operation of the proposed IPCC power system, and estimates the capital and operating costs of the system operating on agricultural residues.

Application status and development tendency of coal entrained-bed gasification

Abstract: Coal entrained-bed gasification,the key technology of clean utilization of coal,meets the challenge of energy safety and sustainable development in China.The application status of coal entrained-bed gasification technologies was described briefly.The major affecting factors of the coal water slurry gasification,such as feed injector,refractory and quench ring,were analyzed.The advantages and disadvantages of the dry pulverized coal gasification were pointed out.The development tendency of coal entrained-bed gasification technologies was also introduced.A lot of experience has been accumulated in the coal water slurry gasification,while the feasibility and operability of the dry pulverized coal gasification will be examined in the chemical industry.Based on the analysis of development status and industrial operational aspect of the coal gasification in China,the development strategy was brought forward.

An Overview of Advanced Power generation Technologies Using Brown Coal

Abstract: Publisher Summary This chapter describes the process of power generations technologies using brown coal. A number of advanced technologies have been or are being developed to improve thermal efficiency, to reduce NOx, SOx and CO2 emissions and to reduce the cost of electricity. These include the circulating fluidized bed combustion (CFBC), pressurized fluidized bed combustion (PFBC), integrated gasification combined cycle (IGCC), and integrated gasification fuel cell (IGFC) technologies. There are specific issues to consider in the utilization of high-moisture low-rank coals for power generation and, in particular, the need to incorporate a coal drying process. Other properties of low-rank coals such as coal reactivity, alkalinity of the ash and the difficulty of handling raw coal also impact the design of the system components. The chapter describes the analyses of various advanced power generation technologies using brown coal. The efficiencies determined here are based on the first law of thermodynamics. This is essentially an accounting of energies entering and exiting the system. Efficiencies are evaluated as ratios of energy quantities and are often used to assess the performance of a system and to compare various systems.

Preliminary assessment of electricity costs for existing pulverized fuel plant retrofitted with an advanced supercritical boiler and turbine and solvent CO2 capture

Abstract: Preliminary economic analyses for baseload electricity generation with carbon capture and storage (CCS) in a recent UK Department of Trade and Industry (DTI) study are extended to include existing pulverized fuel (PF) plant retrofitted with an advanced supercritical boiler and turbine and with solvent scrubbing. Predicted generation costs are in the region of 3.2–3.5 p/kWh. This appears to be comparable with recent IEA predictions for electricity costs from new IGCC plant. Ways in which CCS plant, and solvent scrubbing plant in particular, can provide the flexibility required to complement a high proportion of renewable generation are also discussed.

Processing of residual oil by residual oil supercritical extraction integrated with gasification combined cycle

Abstract: Residual oil supercritical extraction (ROSE) 10 and integrated gasification combined-cycle (IGCC) power systems 70, 114 are cooperatively integrated. High-level heat from the IGCC is used via a heat transfer fluid 84 for high level process heating requirements in the ROSE unit. This can eliminate the fired heater normally required in the ROSE unit, and reduces the size of the gasifier 62 waste heat boiler 72 and/or the high-pressure steam coil 134 and steam turbine generator 144 in the IGCC.

Improved refractories for slagging gasifiers in IGCC power systems

Abstract: Most gasifiers are operated for refining, chemical production, and power generation. They are also considered a possible future source of H2 for future power systems under consideration. A gasifier fulfills these roles by acting as a containment vessel to react carbon-containing raw materials with oxygen and water using fluidized-bed, moving-bed, or entrained-flow systems to produce CO and H2, along with other gaseous by-products including CO2, CH4, SOx, HS, and/or NOx. The gasification process provides the opportunity to produce energy more efficiently and with less environmental impact than more conventional combustion processes. Because of these advantages, gasification is viewed as one of the key processes in the U.S. Department of Energy?s vision of an advanced power system for the 21st Century. However, issues with both the reliability and the economics of gasifier operation will have to be resolved before gasification will be widely adopted by the power industry. Central to both enhanced reliability and economics is the development of materials with longer service lives in gasifier systems that can provide extended periods of continuous, trouble-free gasifier operation. The focus of the Advanced Refractories for Gasification project at the Albany Research Center (ARC) is to develop improved refractory liner materials capable of withstanding the harsh, high-temperature environment created by the gasification reaction. Current generation refractory liners in slagging gasifiers are typically replaced every 3 to 18 months at costs ranging up to $1,000,000 or more, depending upon the size of the gasification vessel. Compounding materials and installation costs are the lost-opportunity costs for the time that the gasifier is off-line for refractory repair/exchange. The goal of this project is to develop new refractory materials or to extend the service life of refractory liner materials currently used to at least 3 years. Post-mortem analyses of refractory brick removed from slagging commercial gasifiers and of laboratory produced refractory materials has indicated that slag corrosion and structural spalling are the primary causes of refractory failure. Historically, refractory materials with chrome oxide content as high as 90 pct have been found necessary to achieve the best refractory service life. To meet project goals, an improved high chrome oxide refractory material containing phosphate additions was developed at ARC, produced commercially, and is undergoing gasifier plant trials. Early laboratory tests on the high chrome oxide material suggested that phosphate additions could double the service life of currently available high chromium oxide refractories, translating into a potential savings of millions of dollars in annual gasifier operating costs, as well a significant increase in gasifier on-line availability. The ARC is also researching the potential of no-chrome/low-chrome oxide refractory materials for use in gasifiers. Some of the driving forces for no-chrome/low-chrome oxide refractories include the high cost and manufacturing difficulties of chrome oxide refractories and the fact that they have not met the performance requirements of commercial gasifiers. Development of no/low chrome oxide refractories is taking place through an examination of historical research, through the evaluation of thermodynamics, and through the evaluation of phase diagram information. This work has been followed by cup tests in the laboratory to evaluate slag/refractory interactions. Preliminary results of plant trials and the results of ARC efforts to develop no-chrome/low chrome refractory materials will be presented.