Integrated Gasification Combined Cycle Systems Research Articles

Sorbents for Mercury Capture from Fuel Gas with Application to Gasification Systems

In regard to gasification for power generation, the removal of mercury by sorbents at elevated temperatures preserves the higher thermal efficiency of the integrated gasification combined cycle system. Unfortunately, most sorbents display poor capacity for elemental mercury at elevated temperatures. Previous experience with sorbents in flue gas has allowed for judicious selection of potential high-temperature candidate sorbents. The capacities of many sorbents for elemental mercury from nitrogen, as well as from four different simulated fuel gases at temperatures of 204−371 °C, have been determined. The simulated fuel gas compositions contain varying concentrations of carbon monoxide, hydrogen, carbon dioxide, moisture, and hydrogen sulfide. Promising high-temperature sorbent candidates have been identified. Palladium sorbents seem to be the most promising for high-temperature capture of mercury and other trace elements from fuel gases. A collaborative research and development agreement has been initiated between the Department of Energy's National Energy Technology Laboratory (NETL) and Johnson Matthey for optimization of the sorbents for trace element capture from high-temperature fuel gas. Future directions for mercury sorbent development for fuel gas application will be discussed.

Improved System Integration for Integrated Gasification Combined Cycle (IGCC) Systems

Integrated gasification combined cycle (IGCC) systems are a promising technology for power generation. They include an air separation unit (ASU), a gasification system, and a gas turbine combined cycle power block, and feature competitive efficiency and lower emissions compared to conventional power generation technology. IGCC systems are not yet in widespread commercial use and opportunities remain to improve system feasibility via improved process integration. A process simulation model was developed for IGCC systems with alternative types of ASU and gas turbine integration. The model is applied to evaluate integration schemes involving nitrogen injection, air extraction, and combinations of both, as well as different ASU pressure levels. The optimal nitrogen injection only case in combination with an elevated pressure ASU had the highest efficiency and power output and approximately the lowest emissions per unit output of all cases considered, and thus is a recommended design option. The optimal combination of air extraction coupled with nitrogen injection had slightly worse efficiency, power output, and emissions than the optimal nitrogen injection only case. Air extraction alone typically produced lower efficiency, lower power output, and higher emissions than all other cases. The recommended nitrogen injection only case is estimated to provide annualized cost savings compared to a nonintegrated design. Process simulation modeling is shown to be a useful tool for evaluation and screening of technology options.

Optimization under Variability and Uncertainty: A Case Study for NOxEmissions Control for a Gasification System

Methods for optimization of process technologies considering the distinction between variability and uncertainty are developed and applied to case studies of NOx control for Integrated Gasification Combined Cycle systems. Existing methods of stochastic optimization (SO) and stochastic programming (SP) are demonstrated. A comparison of SO and SP results provides the value of collecting additional information to reduce uncertainty. For example, an expected annual benefit of 240,000 dollars is estimated if uncertainty can be reduced before a final design is chosen. SO and SP are typically applied to uncertainty. However, when applied to variability, the benefit of dynamic process control is obtained. For example, an annual savings of 1 million dollars could be achieved if the system is adjusted to changes in process conditions. When variability and uncertainty are treated distinctively, a coupled stochastic optimization and programming method and a two-dimensional stochastic programming method are demonstrated via a case study. For the case study, the mean annual benefit of dynamic process control is estimated to be 700,000 dollars, with a 95% confidence range of 500,000 dollars to 940,000 dollars. These methods are expected to be of greatest utility for problems involving a large commitment of resources, for which small differences in designs can produce large cost savings.

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

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.

A novel IGCC system with steam injected H 2/O 2 cycle and CO 2 recovery

In this paper, we have proposed a novel integrated gasification combined cycle (IGCC) system with steam injected H 2/O 2 cycle and CO 2 recovery. A new evaluation criterion for comprehensive performance of the IGCC system has also been presented. The thermodynamic characteristics, environmental and comprehensive performance of the new system have been investigated based on comparison of different IGCC systems with O 2/CO 2 cycle. The promising results show the new system has less energy penalty for separating and recovering CO 2, an efficiency decrease of less than 1 percentage point. The ratio of CO 2 penalty price to fuel price is an important factor influencing the comprehensive performance of this system. The performance of the IGCC with O 2/CO 2 cycle and syngas separation is better than that with the simple semi-closed O 2/CO 2 cycle. The above research achievements will provide valuable information for further study on IGCC systems with low CO 2 emission.

Cleaner energy production with integrated gasification combined cycle systems and use of metal oxide sorbents for H2S cleanup from coal gas

Cleaner energy production with integrated gasification combined cycle systems and use of metal oxide sorbents for H2S cleanup from coal gas

Cleaner energy production with integrated gasification combined cycle systems and use of metal oxide sorbents for H2S cleanup from coal gas

World primary energy demand increases with increases in population and economic development. Within the last 25 years, total energy consumption has almost doubled. In order to meet this demand, research into new sources of energy as well as improving the efficiency of energy production technologies is being carried out. In both cases, the production of clean energy is very important because of environmental concerns and regulations. Integrated gasification combined cycle (IGCC) technology seems to be one of the most promising technologies for production of energy by using fossil fuels, especially coal. Hot gas desulfurization is a crucial issue in the development of the IGCC system. This paper reviews the importance of clean energy production, the IGCC technology and focuses on the development of several metal oxide-based sorbents used for desulfurization of the hot coal gas in the IGCC system.

00/02084 Staged catalytic ammonia decomposition in integrated gasification combined cycle systems

00/02084 Staged catalytic ammonia decomposition in integrated gasification combined cycle systems

00/00464 Low-grade coal improves the burnability of cement raw meal

This project emphasizes CO2-capture technologies combined with integrated gasification combined-cycle (IGCC) power systems, CO2 transportation, and options for the long-term sequestration of CO2. The intent is to quantify the CO2 budget, or an “equivalent CO2” budget, associated with each of the individual energy-cycle steps, in addition to process design capital and operating costs. The base case is a 458-MW (gross generation) IGCC system that uses an oxygen-blown Kellogg-Rust-Westinghouse (KRW) agglomerating fluidized-bed gasifier, bituminous coal feed, and low-pressure glycol sulfur removal, followed by Claus/SCOT treatment, to produce a saleable product. Mining, feed preparation, and conversion result in a net electric power production for the entire energy cycle of 411 MW, with a CO2 release rate of 0.801 kg/kWhe. For comparison, in two cases, the gasifier output was taken through water-gas shift and then to low-pressure glycol H2S recovery, followed by either low-pressure glycol or membrane CO2 recovery and then by a combustion turbine being fed a high-hydrogen-content fuel. Two additional cases employed chilled methanol for H2S recovery and a fuel cell as the topping cycle, with no shift stages. From the IGCC plant, a 500-km pipeline takes the CO2 to geological sequestering. For the optimal CO2 recovery case, the net electric power production was reduced by 37.6 MW from the base case, with a CO2 release rate of 0.277 kg/kWhe (when makeup power was considered). In a comparison of air-blown and oxygen-blown CO2-release base cases, the cost of electricity for the air-blown IGCC was 56.86 mills/kWh, while the cost for oxygen-blown IGCC was 58.29 mills/kWh. For the optimal cases employing glycol CO2 recovery, there was no clear advantage; the cost for air-blown IGCC was 95.48 mills/kWh, and the cost for the oxygen-blown IGCC was slightly lower, at 94.55 mills/kWh.

High-Pressure Reaction Kinetics of Hydrogen Sulfide and Uncalcined Limestone Powder

High-pressure and high-temperature in-gasifier removal of H2S using CaCO3 sorbent powder is studied in a differential-bed flow-through reactor at pressures of up to 2 MPa and temperatures of up to 900 °C. The CaCO3 sulfidation kinetic data are obtained under conditions closely simulating the pressurized fluidized bed gasifier conditions of an integrated gasification combined cycle system. The effects of total pressure, H2S partial pressure (2−5 kPa), reaction temperature, CO2 and H2 partial pressures, particle size (16−200 μm), and CaCO3 surface area on the extent of H2S removal and solid conversion are determined. The gasifier pressure is found to have a negative effect on the sulfidation reaction. The sulfidation reaction is first order with respect to H2S partial pressure. The conversion data of the sulfidation reaction are analyzed using the grain model, with the overall reaction rate being controlled by chemical reaction at the interface and by diffusion through the product layer. At higher conversions, the reaction is found to be product layer diffusion controlled with an apparent activation energy of about 48.7 kcal/mol. The high-pressure sulfidation kinetic data obtained in this study would be useful in understanding and optimizing the in-gasifier H2S capture using CaCO3 sorbents.

99/01990 Temperature measuring device inside coal gasifier: Yoshida, K. et al. Jpn. Kokai Tokkyo Koho JP 10 237,466 [98 237,466], (Cl. C10J3/48), 8 Sep 1998, Appl. 97/45,504, 28 Feb 1997, 6 pp. (In Japanese)

This project emphasizes CO2-capture technologies combined with integrated gasification combined-cycle (IGCC) power systems, CO2 transportation, and options for the long-term sequestration of CO2. The intent is to quantify the CO2 budget, or an “equivalent CO2” budget, associated with each of the individual energy-cycle steps, in addition to process design capital and operating costs. The base case is a 458-MW (gross generation) IGCC system that uses an oxygen-blown Kellogg-Rust-Westinghouse (KRW) agglomerating fluidized-bed gasifier, bituminous coal feed, and low-pressure glycol sulfur removal, followed by Claus/SCOT treatment, to produce a saleable product. Mining, feed preparation, and conversion result in a net electric power production for the entire energy cycle of 411 MW, with a CO2 release rate of 0.801 kg/kWhe. For comparison, in two cases, the gasifier output was taken through water-gas shift and then to low-pressure glycol H2S recovery, followed by either low-pressure glycol or membrane CO2 recovery and then by a combustion turbine being fed a high-hydrogen-content fuel. Two additional cases employed chilled methanol for H2S recovery and a fuel cell as the topping cycle, with no shift stages. From the IGCC plant, a 500-km pipeline takes the CO2 to geological sequestering. For the optimal CO2 recovery case, the net electric power production was reduced by 37.6 MW from the base case, with a CO2 release rate of 0.277 kg/kWhe (when makeup power was considered). In a comparison of air-blown and oxygen-blown CO2-release base cases, the cost of electricity for the air-blown IGCC was 56.86 mills/kWh, while the cost for oxygen-blown IGCC was 58.29 mills/kWh. For the optimal cases employing glycol CO2 recovery, there was no clear advantage; the cost for air-blown IGCC was 95.48 mills/kWh, and the cost for the oxygen-blown IGCC was slightly lower, at 94.55 mills/kWh.

Hot gas clean-up bioflow ceramic filter experience

Future energy production will be handled by advanced technologies that are more efficient and more environmentally friendly and less in capital cost. An integrated gasification combined cycle (IGCC) power plant is among the most promising technologies to meet the above goals. The use of biofuels, a renewable form of energy, in IGCC systems is an excellent option to reduce the CO 2 emission. In 1992, Sydkraft AB of Sweden and Foster Wheeler Energia Oy of Finland formed a joint venture company, Bioflow Ltd, to develop the biomass-based IGCC system with the gasification part provided by pressurized circulating fluidized bed technology. The new IGCC system is expected to have higher efficiency (44–50%) and the gaseous emissions would be lowered by 20–50% of the current levels. A Bioflow IGCC demonstration plant has already been built in Varnamo, Sweden and it is now in operation. In this plant, the first in the world, the integration of a pressurized gasifier with a gas turbine will take place utilizing low heating value fuel from biomass gasification. The cogen plant produces 6 MW e electricity and 9 MW th district heat. The plant has, among other critical components, a ceramic barrier filter for hot gas particulate clean up. This paper describes the hot gas ceramic filter operation at about 400°C under pressure. Over 2000 hr of operation has been logged. The performance of the filter has been satisfactory.

Study on Commercialization of High Efficiency IGCC System.

The Integrated Gasification Combined Cycle (IGCC) is regarded as a prospective winner of thermal power system in the next decade. Ishikawajima Harima Heavy Industries Co., Ltd. (IHI) has been developing gasification technology and dry gas desulfurization technology. These are key technologies for IGCC commercialization. IHI has constructed Texaco Type coal gasification test facility and has been carrying out various tests since 1987. Also at the Japanese national IGCC development project. IH I has been in charge of a dry gas desulfurization pilot plant development for 200 coal tons/day gasification plant. This worldly largest desulfurization unit has performed successfully and concluded in February 1996. With these test results, IHI has continued to improve IGCC system through yarious feasibility studies with Toshiba who designed the combined cycle. We also carried out parameter survey that focused on the influence of fuel properties. These results made clear some useful features for IGCC development.

Energy studies of different cogeneration systems for black liquor gasification

The prior goal for a pulp and paper mill is to achieve a chemical recovery system with high availability and good reliability. It is also important that the heat recovery system produces sufficient process heat for the heat-demanding processes in the mill. Black liquor gasification promises to be a future alternative or a complement to the conventional Tomlinson recovery boilers in the pulp industry. Black liquor gasification should offer several advantages from both a chemical recovery and an energy point of view. The gasification process produces a combustible gas which can be used for steam and power generation in many ways. Several studies have shown that the power output from a heat and power cycle integrated with black liquor gasification has potential to get a higher energy efficiency than today's heat recovery technology. Especially with pressurized gasification and a gas-turbine-based cogeneration system, the power output will be significantly improved. However, the gas turbine is very sensitive to corrosive elements. The gas cleaning equipment in the gasification system must therefore have a high removal efficiency and a high reliability. The ambition is to keep the gasification capacity constant during the year, but the fuel consumption for the gas turbine increases at low ambient temperatures. The seasonal variation will cause the gas turbine to operate at partial load and, consequently, there will be a decrease in the gas turbine efficiency. An alternative combined cycle with high power efficiency is given by a hybrid plant in which the gas turbine is fired with natural gas while the fuel gas from the pressurized gasifier is used as a supplementary fuel for the Rankine cycle. A major advantage of the hybrid system is the use of a high purity fuel gas in the gas turbine. The system also allows for variations in pulp capacity which is difficult in an integrated gasification combined cycle (IGCC). This study compares the effect of using an IGCC system and a hybrid combined plant instead of a conventional recovery system. The results indicate a potential to double the power output if the conventional system is replaced by an IGCC system. A hybrid combined cycle system has also a higher net power efficiency than the conventional recovery system. Furthermore, the hybrid system can make the mill self-supporting on power and allows an increase in the heat consumption.

Clean coal technologies

Power generation in Europe and elsewhere relies heavily on coal as the source of energy and this reliance will increase in the future as other fossil fuels become progressively more expensive. The existing stock of coal-fired power stations mainly use pulverized fuel boilers and present designs based on ultrasupercritical steam cycles are as efficient and as low in SOx and NOx emissions as is possible without incurring excessive additional costs. This paper examines the options for coal-based power generation technologies and compares their technical, environmental and economic performance. These options include atmospheric and pressurized fluidized bed combustion and a range of integrated gasification combined cycle systems. Integrated gasification combined cycles give good efficiency and very low emissions, but further optimization is required to make them economically attractive. Conceptual cycles based on pressurized pulverized combustion, dual fuel hybrid cycles, fuel cells and magnetohydrodynamics are also covered in outline.

97/00557 Influence of maceral and rank on combustion characteristics of coal

Initiatives to limit carbon dioxide (CO2) emissions have drawn considerable interest to integrated gasification combined-cycle (IGCC) power generation. With its higher efficiency, this process can reduce CO2 production. It is also amenable to CO2 square, because CO2 can be removed before combustion and the associated dilution with atmospheric nitrogen. This paper presents a process-design baseline that encompasses the IGCC system, CO2 transport by pipeline, and land-based sequestering of CO2 in geological reservoirs.The intent of this study is to provide the CO2 budget, or an “equivalent CO2” budget, associated with each of the individual energy-cycle steps. Design capital and operating costs for the process are included in the full study but are not reported in the present paper. The value used for the “equivalent CO2” budget will be 1 kg CO2/kWhe.The base case is a 470-MW (at the busbar) IGCC system using an air-blown Kellogg Rust Westinghouse (KRW) agglomerating fluidized bed gasifier, U.S. Illinois #6 bituminous coal feed, and in-bed sulfur removal. Mining, feed preparation, and conversion result in a net electric power production of 461 MW, with a 0.830 kg/kWhe CO2 release rate. In the CO2 recovery case, the gasifier output is taken through water-gas shift and then to Selexol, a glycol-based absorber-stripper process that recovers CO2 before it enters the combustion turbine. This process results in 350 MW at the busbar. A 500-km pipeline takes the recovered CO2 to geological sequestering. The net electric power production in the recovery case is 320 MW, with a 0.234 kg/kWhe CO2 release rate.

Oxygen-blown gasification combined cycle: Carbon dioxide recovery, transport, and disposal

This project emphasizes CO2-capture technologies combined with integrated gasification combined-cycle (IGCC) power systems, CO2 transportation, and options for the long-term sequestration of CO2. The intent is to quantify the CO2 budget, or an “equivalent CO2” budget, associated with each of the individual energy-cycle steps, in addition to process design capital and operating costs. The base case is a 458-MW (gross generation) IGCC system that uses an oxygen-blown Kellogg-Rust-Westinghouse (KRW) agglomerating fluidized-bed gasifier, bituminous coal feed, and low-pressure glycol sulfur removal, followed by Claus/SCOT treatment, to produce a saleable product. Mining, feed preparation, and conversion result in a net electric power production for the entire energy cycle of 411 MW, with a CO2 release rate of 0.801 kg/kWhe. For comparison, in two cases, the gasifier output was taken through water-gas shift and then to low-pressure glycol H2S recovery, followed by either low-pressure glycol or membrane CO2 recovery and then by a combustion turbine being fed a high-hydrogen-content fuel. Two additional cases employed chilled methanol for H2S recovery and a fuel cell as the topping cycle, with no shift stages. From the IGCC plant, a 500-km pipeline takes the CO2 to geological sequestering. For the optimal CO2 recovery case, the net electric power production was reduced by 37.6 MW from the base case, with a CO2 release rate of 0.277 kg/kWhe (when makeup power was considered). In a comparison of air-blown and oxygen-blown CO2-release base cases, the cost of electricity for the air-blown IGCC was 56.86 mills/kWh, while the cost for oxygen-blown IGCC was 58.29 mills/kWh. For the optimal cases employing glycol CO2 recovery, there was no clear advantage; the cost for air-blown IGCC was 95.48 mills/kWh, and the cost for the oxygen-blown IGCC was slightly lower, at 94.55 mills/kWh.

Hot-gas cleanup—sulfur recovery technical, environmental, and economic issues

Advanced high-efficiency integrated gasification combined cycle (IGCC) power systems employing hot-gas cleanup are being developed to produce electric power from coal. Hot-gas cleanup consists of hot particulate removal and hot-gas desulfurization (HGD) technologies that match or nearly match the temperature and pressure of the gasifier and turbine generator. HGD is carried out using solid regenerable metal oxide sorbents that can remove the sulfur down to low parts per million and can be regenerated with air for multicycle operation. Economic studies have shown that HGD results in lower capital and operating costs than conventional cold gas desulfurization. Development of efficient sorbent desulfurization-regeneration reactor and tailgas treatment subsystems properly integrated with the overall IGCC systems is a key requirement for successful commercialization of HGD.

Modeling uncertainties in advanced technologies: Application to a coal gasification system with hot-gas cleanup

Uncertainties in the performance, emissions, and cost of advanced process technologies in early stages of development pose a challenge to process evaluation. Failure to account properly for uncertainties may result in misleading estimates that are then used for making decisions about technology selection and research planning. A new stochastic modeling capability has been developed for the ASPEN chemical process simulator that allows uncertainties in any process technology to be represented using probability distributions. This capability is briefly described. A detailed case study of an advanced integrated coal gasification combined cycle (IGCC) system is presented to illustrate the application of this capability. The case study involves identification and characterization of uncertainties in model inputs, propagation of uncertainties through the model, and interpretation of model results. The value of stochastic modeling is in the ability to evaluate the simultaneous effect of multiple uncertainties in a process technology and to develop more realistic estimates of process performance and cost than would otherwise be obtained from deterministic (point-estimate) analysis.

Gasification combined cycle: Carbon dioxide recovery, transport, and disposal

Initiatives to limit carbon dioxide (CO 2) emissions have drawn considerable interest to integrated gasification combined-cycle (IGCC) power generation. With its higher efficiency, this process can reduce CO 2 production. It is also amenable to CO 2 square, because CO 2 can be removed before combustion and the associated dilution with atmospheric nitrogen. This paper presents a process-design baseline that encompasses the IGCC system, CO 2 transport by pipeline, and land-based sequestering of CO 2 in geological reservoirs. The intent of this study is to provide the CO 2 budget, or an “equivalent CO 2” budget, associated with each of the individual energy-cycle steps. Design capital and operating costs for the process are included in the full study but are not reported in the present paper. The value used for the “equivalent CO 2” budget will be 1 kg CO 2/kWh e. The base case is a 470-MW (at the busbar) IGCC system using an air-blown Kellogg Rust Westinghouse (KRW) agglomerating fluidized bed gasifier, U.S. Illinois #6 bituminous coal feed, and in-bed sulfur removal. Mining, feed preparation, and conversion result in a net electric power production of 461 MW, with a 0.830 kg/kWh e CO 2 release rate. In the CO 2 recovery case, the gasifier output is taken through water-gas shift and then to Selexol, a glycol-based absorber-stripper process that recovers CO 2 before it enters the combustion turbine. This process results in 350 MW at the busbar. A 500-km pipeline takes the recovered CO 2 to geological sequestering. The net electric power production in the recovery case is 320 MW, with a 0.234 kg/kWh e CO 2 release rate.