Integrated Gasification Combined Cycle Power Research Articles

Techno-economic and life cycle assessment of the integration of bioenergy with carbon capture and storage in the polygeneration system (BECCS-PS) for producing green electricity and methanol

Bioenergy with carbon capture and storage (BECCS) has the potential to produce negative emissions. This study assessed the overall energy efficiency and carbon dioxide (CO2) avoidance costs and emission footprint following the integration of BECCS with a polygeneration system (BECCS-PS) for the co-production of green electricity and methanol. The process was simulated in Aspen Plus and Aspen HYSYS v.11. Oil palm empty fruit bunches were used as the feed in a biomass integrated gasification combined cycle power plant. The flue gas, which contained CO2, was captured for methanol synthesis and carbon storage. Green hydrogen for use in methanol synthesis was produced through proton exchange membrane (PEM) electrolysis powered by solar PV (PV-PEM) and geothermal power with double-flash technology (GEO-PEM). The environmental impacts of the process were investigated by a life cycle assessment and the economic aspects were evaluated using the levelized cost method. The overall system efficiency was higher in the PV-PEM scenario than in the GEO-PEM scenario. For any production capacities, the green electricity generated from the BECCS-PS plant resulted in negative emissions. A biomass power plant with a low production capacity generated higher production and CO2 avoidance costs than that with a larger production capacity. The CO2 − eq emissions and costs for methanol production in the PV-PEM scenario were larger than those in the GEO-PEM scenario, with values of -0.83 to -0.70 kg CO2 − eq/kg MeOH and 1,191–1,237 USD/ton, respectively. The corresponding values were − 1.65 to -1.52 kg CO2 − eq/kg MeOH and 918–961 USD/ton, respectively, for the GEO-PEM scenario.Graphical

Basic intensity regulation of layered double oxide for CO2 adsorption process at medium temperature in coal gasification

High purity hydrogen for integrated gasification combined cycle power generation (IGCC) can be produced by efficient adsorption of CO2 after water gas shift reaction in coal gasification. Based on adjustability of composition in layered double hydroxides (LDH) precursor, basicity intensity was modified and exhibited different adsorption capacity. Relationship among basic sites, CO2-bound modes, and adsorption capacity were established. Furthermore, by utilizing LDH anionic exchangeability, we introduced laurate ion into LDH interlamellar, and further mediated surface structure using methyl cellulose with long carbon chain. As-obtained Mg3Al-LDO-C12-MC effectively increased the number of medium/strong basic sites. Consequently, CO2-adsorption capacity at medium temperature of 300 °C was further increased to 0.85 mmol/g with the maximum rate of 0.37 mmol/g·min. This work develops a strategy to regulate basic site of adsorbents according to structural mechanism for CO2 elimination under medium temperature, and thus improve adsorption performance in industrial coal gasification process.

Integration of membrane technology for decarbonization of gasification power plants: A techno-economic and environmental investigation

• Integration of membrane technology for decarbonization of gasification power plants. • Techno-economic and environmental assessment of decarbonized gasification plants. • Membrane-based CO 2 capture system increases the overall plant energy efficiency. • Membrane reduces capital cost (9%), operational cost (10%) and electricity cost (7%). • Decarbonized gasification plants are economic viable for current 75 €/t carbon tax. Membrane technology is one promising technology for CO 2 capture from industrial gases. The application of membrane system in gasification-based power plants is particularly appealing considering the elevated pressure of syngas subject to decarbonization resulting in lower energy and economic penalties for CO 2 capture. As key novelty element of this work, the membrane technology was evaluated in both alone and hybrid configuration with gas-liquid absorption in view of decarbonization of Integrated Gasification Combined Cycle power plants. Assessed decarbonized gasification-based power plant concepts produce about 450 MW net output with 90% CO 2 capture rate. An integrated techno-economic and environmental evaluation methodology (based on modelling, simulation and process integration) was applied to quantify the most important plant performance indicators. For comparison, similar IGCC designs without decarbonization feature or with decarbonization by chemical and physical gas-liquid absorption were also analysed. The overall conclusion is that the membrane technology has important techno-economic benefits in comparison to chemical and physical absorption e.g. greater overall net energy efficiency (up to about one net percentage point), lower specific capital investment costs (down to 9%), lower operational & maintenance costs (down to 10%), lower electricity production costs (down to 7%), lower CO 2 capture costs (down to 50%).

Optimization of Integrated Gasification Combined-Cycle Power Plant for Polygeneration of Power and Chemicals

Efficient and flexible operation is essential for competitiveness in the energy market. However, the CO2 emissions of conventional power plants have become an increasingly significant environmental dilemma. In this study, the optimization of a steam power process of an IGCC was carried out, which improved the overall performance of the plant. CCPP with a subcritical HRSG was modelled using EBSILON Professional. The numerical results of the model were validated by measurements for three different load cases (100, 80, and 60%). The results are in agreement with the measured data, with deviations of less than 5% for each case. Based on the model validation, the model was modified for the use of syngas as feed and the integration of heat into an IGCC process. The integration was optimized with respect to the performance of the CCPP by varying the extraction points, adjusting the steam parameters of the extractions and modifying the steam cycle. For the 100% load case, a steam turbine power achieved increase of +34.2%. Finally, the optimized model was subjected to a sensitivity analysis to investigate the effects of varying the extraction mass flows on the output.

A cadmium-magnesium looping for stable thermochemical energy storage and CO2 capture at intermediate temperatures

Thermochemical energy storage (TCES) based on the carbonation/decarbonation cycle of metal oxide/carbonate is an attractive technology to address the intermittent problems of renewable energy and to recover industrial waste heat. The alkali metal salt-promoted MgO-based sorbent materials are promising for TCES at intermediate temperatures but suffer from severe thermal instability owing to the high decarbonation temperature of MgCO3 in pure CO2. In this study, we for the first time reported a novel Cd-Mg looping whereby CdO and MgCO3 with the aid of molten NaNO3 can be rapidly and reversibly converted into CdMg(CO3)2 through carbonation/partial decarbonation, which enabled a low working temperature and thus enhanced the stability of the NaNO3-promoted Cd-Mg containing materials. The effect of Cd/Mg atomic ratio on the property, activity and stability of the materials was systematically studied; moreover, the carbonation/decarbonation mechanism was carefully explored. The promising candidate containing equimolar amounts of Cd and Mg can not only perform stable intermediate-temperature TCES in 100 cycles, but also convert the low-concentration waste CO2 in integrated gasification combined cycle power plants into pure CO2. These findings offer new opportunities for TCES and CO2 capture at intermediate temperatures.

Emergy evaluation of the integrated gasification combined cycle power generation systems with a carbon capture system

An Integrated Gasification Combined Cycle (IGCC) power generation system has a significant effect on improving resource utilization efficiency. Carbon capture and storage (CCS) has been widely adopted to control greenhouse gas emissions. The integration of the two systems can further reduce CO2 emissions but cause elevated investment costs. As an effective tool to evaluate resource utilization efficiency and environmental impact, emergy analysis on coal and biomass based IGCC power generation systems with/without CCS is conducted in this paper. The coal based IGCC systems are simulated in Aspen plus to obtain the electricity generated under different CCS scales. For other systems, the data for emergy evaluation are from references. The sustainabilities under different CO2 tax values are compared. The factors impacting the sustainabilities are discussed. The results show that when CCS is not considered, all IGCC systems are superior to coal and biomass direct-fired systems in terms of sustainability. After CCS is integrated, the sustainability of biomass based IGCC system is still higher than that of biomass direct-fired systems, while coal based IGCC systems are less sustainable than coal direct-fired systems under low CO2 tax. The sustainabilities of Texaco-IGCC systems increase with CCS scales when CO2 tax is higher than 0.0220 $/kg, emphasizing CCS at a larger scale. For the Shell-IGCC systems, a higher CO2 tax (0.3880 $/kg) is preferred for the promotion of large scale CCS. In the scenario that the cost emergy transformity improves, the CO2 tax value at the point of sustainabilities reversal will decrease.

Design and Modeling of a Carbon Capturing Membrane for Integrated Gasification Combined Cycle Power Plant

The main idea of this research paper is to provide an innovative way of capturing carbon dioxide emissions from a coal powered power plant. This research paper discusses the design and modeling of a carbon capturing membrane which is being used in an IGCC power plant to capture carbon dioxide from its exhaust gases. The modeling and design of the membrane is done using CFD software namely Ansys workbench. The design and modeling is done using two simulations, one describes the design and structure and the second one demonstrates the working mechanism of the membrane. This paper also briefly discusses IGCC which is environmentally benign compared to traditional pulverized coal-fired power plants, and economically feasible compared to the Natural Gas Combine Cycle (NGCC). IGCC power plant is more diverse and offers flexibility in fuel utility. This paper also incorporates a PFD of integrated gasification power plant with the carbon capturing membrane unit integrated in it. Index Terms: Integrated gasification combined cycle power plant, Carbon capture and storage, Gas permeating membrane, CFD based design of gas permeating membrane.

Cogasification of Coal and Biomass in an Integrated Gasification Combined Cycle Power Plant: Effects on Thermodynamic Performance and Gas Composition

AbstractTaking inspiration from one of the most significant experiences of coal and biomass cogasification, such as that undertaken in the Willem-Alexander Centrale (WAC) power plant located in Bug...

Emergy evaluation of power generation systems

With the increasing demand of power sources, it is of great significance to evaluate different power generation systems and optimize the energy structure. The emergy is proved to be a comprehensive and powerful way to evaluate the sustainability of a system. In this paper, emergy is used to compare ten power generation systems by two calculation methods of emergy indices. The emergy data of integrated gasification combined cycle and wind power generation systems are gathered from the studies of life cycle assessment, while those of the other eight systems are taken from existing emergy evaluations and converted to the same baseline. The study of hydropower generation systems shows the influence of technical progress and geographical location to the sustainability. The comparison of ten power generation systems shows that the hydropower generation system has the best sustainability while the wind and solar systems demonstrate relatively low sustainability. Besides, the sustainability is relative to the carbon dioxide tax. The sustainability of wind and concentrated solar power generation systems is tend to be better than that of integrated gasification combined cycle power generation system with an increase in the carbon dioxide tax. The results indicate that the technology, investment cost and carbon dioxide emission are essential factors to sustainability of power generation systems.

Life cycle environmental impact assessment of coupled underground coal gasification and CO2 capture and storage: Alternative end uses for the UCG product gases

Underground coal gasification (UCG) has the potential to provide a source of energy or chemical feedstock derived from coal seams, where traditional mining methods are not suitable or are uneconomical. This paper presents the life cycle inventory models developed for the UCG processes and three alternative syngas utilisation options with and without CO2 capture and storage. The paper compares the life cycle carbon footprint of two different conventional above ground coal fired power generation options with UCG Integrated Gasification Combined Cycle power generation with/without CCS for two different lignites and one bituminous coal. One of the lignites is then used to compare the life cycle performance of different syngas utilisation options: power generation, ammonia production with power generation, and methanol production with power generation. It was found that the life cycle carbon footprint of conventional above ground coal fired power generation is very much dependent on the in-situ methane content of the coal used, and methane emissions experienced during mining and accompanying upstream processes, whereas the same for UCG-IGCC power depends more on the process dependent syngas composition. UCG methanol production with associated power and CCS is shown to release more life cycle CO2-eq emissions per tonne of lignite consumed than that of UCG ammonia production with associated power and CCS and UCG CCGT power generation with CCS. Furthermore, when chemicals production from UCG is considered as the main objective, the most substantial improvements in comparison to conventional methods are associated with UCG ammonia process per tonne of chemical produced.

Thermo-economic analyses of concepts for increasing carbon capture in high-methane syngas integrated gasification combined cycle power plants

An integrated gasification combined cycle (IGCC) power plant with transport gasifier and advanced pressure swing adsorption based warm gas CO2 removal technology for carbon capture is analyzed with respect to its maximum carbon capture yield. The carbon capture was limited to 88.6% due to high CH4 content in the syngas. The plant efficiency in this scenario is 33.76% resulting in a 1st year cost of electricity (COE) of 136.0 $/MWh with CO2 transport, storage and monitoring (TS&M). The high CH4 content in the syngas is a result of employing a highly efficient, low temperature gasifier designed for low rank feedstocks such as subbituminous coal, lignite and biomass. In order to increase the carbon capture in high methane syngas IGCCs to reach the U.S. Department of Energy target of 90% carbon capture, three pathways also based on warm gas CO2 removal were studied: (1) combustion of syngas in the CO2 purification section while raising steam, (2) syngas reforming in an external adiabatic reformer and (3) syngas recycling to the gasifier. Although the recycling option (3) has the highest efficiency, the combustor option (1) was the most economical with a COE of 138.1 $/MWh with TS&M. For scenario (1), the 1st year carbon capture cost with TS&M is 53.3 $/tonne compared to a corresponding IGCC without carbon capture and 75.0 $/tonne compared to a supercritical boiler plant (SCBP) without carbon capture. For the 1st year of operation, the avoided cost with TS&M compared to the corresponding IGCC without carbon capture is 65.4 $/tonne. Compared to the SCBP without carbon capture the 1st year avoided cost is 87.2 $/tonne.

Metal sulfide-based process analysis for hydrogen generation from hydrogen sulfide conversion

Fossil fuel power plants often generate sulfur species such as hydrogen sulfide or sulfur dioxide due to the sulfur content of the raw feedstocks. To combat the associated environmental, processing, and corrosion issues, facilities commonly utilize a Claus process to convert hydrogen sulfide (H2S) to elemental sulfur. Unfortunately, the potential for H2 production from H2S is lost in the Claus process. In this study, two chemical looping process configurations utilizing metal sulfides as chemical intermediates for sulfur recovery are investigated: (1) sulfur recovery (SR) system for sulfur production; (2) sulfur and hydrogen (H2) recovery (SHR) system for sulfur and H2 and production utilizing staged H2 separation. Since, H2 yield and sulfur recovery in a single thermal decomposition reactor is limited by low H2S equilibrium conversion, a staged H2 separation approach is used to increase H2S conversion to H2 using the SHR system. Steady-state simulations and optimization of process conditions are conducted in Aspen Plus (v10) simulation software for the chemical looping process configurations and the Claus process. An energy and exergy analysis are done for the Claus and chemical looping processes to demonstrate the relative contribution to exergy destruction from different unit operations as well as overall exergy and energy efficiency. The two chemical looping process configurations are compared against the conventional Claus process for similar sulfur recovery in a 629 MWe integrated gasification combined cycle power plant. The SHR system is found to be the most efficient option due to a 97.11% exergy efficiency with 99.31% H2 recovery. The overall energy and exergy efficiencies of this chemical looping system are 14.74% and 21.54% points higher than the Claus process, respectively, suggesting more efficient use of total input energy.

Experimental Flame Front Characterisation in a Lean Premix Burner Operating with Syngas Simplified Model Fuel

The recent growing attention to energy saving and environmental protection issues has brought attention to the possibility of exploiting syngas from gasification of biomass and coal for the firing of industrial plants included in the, so called, Integrated Gasification Combined Cycle power plants. In order to improve knowledge on the employ of syngas in lean premixed turbulent flames, a large scale swirl stabilized gas-turbine burner has been operated with a simplified model of H2 enriched syngas from coal gasification. The experimental campaign has been performed at atmospheric pressure, with operating conditions derived from scaling the real gas turbines. The results are reported here and consist of OH-PLIF (OH Planar Laser Induced Fluorescence) measurements, carried out at decreasing equivalence of air/fuel ratio conditions and analysed together with the mean aerodynamic characterisation of the burner flow field in isothermal conditions obtained through LDV (Laser Doppler Velocimetry) and PIV (Particle Image Velocimetry) measurements. The OH concentration distributions have been analysed statistically in order to obtain information about the location of the most reactive zones, and an algorithm has been applied to the data in order to identify the flame fronts. In addition, the flame front locations have been successively interpreted statistically to obtain information about their main features and their dependence on the air to fuel ratio behaviour.

Development and implementation of advanced control strategies for power plant cycling with carbon capture

In this paper, three model predictive control (MPC) strategies are developed and implemented for coal-fired power plant cycling applications. These strategies correspond to a dynamic matrix control (DMC)-based linear MPC, the proposed nonlinear MPC (NLMPC) and a nonlinear MPC from the literature (L-NMPC) as benchmark. For application purposes, dynamic models of two different coal-fired power plants with carbon capture are addressed: an integrated gasification combined cycle power plant with a water-gas shift membrane reactor (IGCC-MR) and a supercritical pulverized coal-fired power plant with monoethanolamine-based post-combustion carbon capture (SCPC-MEA). Successful MPC implementations on IGCC-MR system and SCPC-MEA carbon capture subsystem are addressed, including cycling trajectory tracking and disturbance rejection scenarios. The closed-loop results show that the proposed nonlinear MPC (NLMPC) improves the control performance by up to 96% when compared to the DMC controller in terms of the integral squared error (ISE) results.

Power Load Dispatch Philosophy among Multiple Generator Units in Integrated Gasification Combined Cycle Power Plant

Power load dispatch philosophy among multiple generator units in Integrated Gasification Combined Cycle power plant is proposed in this paper. The proposed power load dispatch philosophy is to dispatch power load on a combined cycle block rather than a single unit basis. It is better to designate one or two combined cycle blocks for local facility load and dispatch the remaining blocks for grid dispatch.

Life Cycle Analysis of Integrated Gasification Combined Cycle Power Generation in the Context of Southeast Asia

Coal remains a major source of electricity production even under the current state of developments in climate policies due to national energy priorities. Coal remains the most attractive option, especially to the developing economies in Southeast Asia, due to its abundance and affordability in the region, despite the heavily polluting nature of this energy source. Gasification of coal running on an integration gasification combined cycle (IGCC) power generation with carbon capture and storage (CCS) represents an option to reduce the environmental impacts of power generation from coal, but the decarbonization potential and suitability of IGCC in the context of Southeast Asia remain unclear. Using Singapore as an example, this paper presents a study on the life cycle analysis (LCA) of IGCC power generation with and without CCS based on a generic process-driven analysis method. We further evaluate the suitability of IGCC with and without CCS as an option to address the energy and climate objectives for the developing economies in Southeast Asia. Findings suggest that the current IGCC technology is a much less attractive option in the context of Southeast Asia when compared to other available power generation technologies, such as solar photovoltaic systems, coal with CCS, and potentially nuclear power technologies.

A comparative study of biomass integrated gasification combined cycle power systems: Performance analysis

The Biomass Integrated Gasification Combined Cycle (BIGCC) power system is believed to potentially be a highly efficient way to utilize biomass to generate power. However, there is no comparative study of BIGCC systems that examines all the latest improvements for gasification agents, gas turbine combustion methods, and CO2 Capture and Storage options. This study examines the impact of recent advancements on BIGCC performance through exergy analysis using Aspen Plus. Results show that the exergy efficiency of these systems is ranged from 22.3% to 37.1%. Furthermore, exergy analysis indicates that the gas turbine with external combustion has relatively high exergy efficiency, and Selexol CO2 removal method has low exergy destruction. Moreover, the sensitivity analysis shows that the system exergy efficiency is more sensitive to the initial temperature and pressure ratio of the gas turbine, whereas has a relatively weak dependence on the initial temperature and initial pressure of the steam turbine.

Optimal plant-wide control of the wet sulfuric acid process in an integrated gasification combined cycle power plant

This paper discusses plant-wide control system design of the wet sulfuric acid (WSA) process, which is part of an integrated gasification combined cycle power plant. The regulatory control structure, which ensures energy efficiency and operational stability, was designed by addressing the requirements and constraints of each key unit in the process. We used sensitivity analysis and simple stoichiometric calculation to obtain optimum set points for the controlled variables, which has a direct effect on the energy usage and production rate in the WSA process. In this work, we proposed several controller schemes that ensure efficiency and stability of the WSA process. The results of this work will contribute to improving the process efficiency, thereby facilitating energy efficient and stable operation of the WSA process.

Analysis of integrated gasification combined cycle power plant incorporating chemical looping combustion for environment-friendly utilization of Indian coal

The concern on the effect of global warming due to greenhouse gases has been increasing. Carbon dioxide is the most powerful greenhouse gas and more than 40% of its emission is from fossil fuelled power plants. So the efficient use of fossil fuel with carbon dioxide capture is the best method for achieving the energy demands with less pollutant emissions. But the conventional capture technologies are more energy intensive and cause a drop in net power production. This energy penalty can be overcome by using Chemical looping combustion technique. In this technique, combustion occurs in two reactors – Air reactor and Fuel reactor. The former is fluidised by air and the later by fuel. Metal oxides called oxygen carriers loop in between two reactors carrying oxygen and heat required for combustion to the fuel reactor. So there is no direct contact between air and fuel and results in pure combustion products- carbon dioxide and water. Therefore a separate air separation or gas separation unit is not required which are energy eating units in conventional capture methods. This work presents steady state simulations of three systems: Integrated Gasification Combined Cycle power plant (i) without carbon dioxide capture, (ii) with pre-combustion capture and (iii) integrated with chemical looping combustion. All the simulations are carried out using Aspen plus simulation package. High ash Indian coal is used as the fuel. The performance of each case is compared in terms of overall energy efficiency and carbon dioxide capture rate. The efficiencies of the system without capture, with looping combustion and with pre-combustion capture are found to be 42.69%, 40.2% and 35.8% respectively. The respective capture efficiencies of looping combustion and pre-combustion capture are 99.97% and 94%. It can be seen that the reduction in the overall efficiency is marginal in the case of chemical looping combustion. This shows the superiority of chemical looping combustion technique over the pre-combustion capture technique in terms of higher capture efficiency and overall plant thermal efficiency. An exergy analysis is also carried out to identify the units having higher exergy destruction rates. Parametric studies are carried out on these units to observe their effect on the overall plant performance. Thus, a process for an energy efficient and environment friendly utilization of high ash Indian coal is presented in this paper.

Technical and Economic Assessments of Ionic Liquids for Pre-Combustion CO2 Capture at IGCC Power Plants

This study evaluates the feasibility and cost of ionic liquids (ILs) for precombustion carbon dioxide (CO2) capture at integrated gasification combined cycle power plants. The ionic liquid 1-hexyl-3-methylimidazolium bis(trifluoromethylsulfonyl)imide is selected as a physical solvent for CO2 capture. Using newly developed performance and cost models, our analysis shows that the energy penalty of the IL-based capture system mainly arises from powering various compressors and solvent pumps, and compressors and absorbers are the dominant capital cost components. Using the Integrated Environmental Control Model (IECM) for power plant assessments, the cost of CO2 avoided by the IL-based capture system is estimated to be $62/t CO2 in constant 2011 USD. The preliminary comparisons of performance and cost between IL- and Selexol-based capture systems show that an IL-based capture system could be a viable alternative to current liquid solvent processes.