IGCC System Research Articles

Thermal efficiency of advanced integrated coal gasification combined cycle power generation systems with low-temperature gasifier, gas cleaning and CO2 capturing units

Advanced integrated coal gasification combined cycle (A-IGCC) systems have been proposed to obtain higher thermal efficiency than that of IGCC systems by recuperating exhaust heat from a gas turbine to provide the heat source for a gasifier. The performances of the A-IGCC systems with a low-temperature dual-bed fluidized bed gasifier, gas cleaning, CO2 capturing, and the most advanced (1650°C-class) gas turbine units were evaluated using Aspen Plus®. Net thermal efficiency of the A-IGCC model with hot gas desulfurizing unit using ZnO and TiO2 was 53.6% and that with cold gas desulfurizing unit using Selexol® process was 52.0% without CO2 capturing when the cold gas efficiency (CGE) in the gasifier was 80.1%. The net thermal efficiency can be increased to 54.7–57.2% by improving CGE from 80.1 to 85.0%, suggesting the improvement of cold gas efficiency in the gasifier is critical. CO2 emission factors of the A-IGCC system are 505–520kg-CO2/MWh (CGE=80.1%) and 468–490kg-CO2/MWh (CGE=85.0%), and can be decreased to 39.7–112kg-CO2/MWh with 80–95% of CO2 capturing. Compliance to the CO2 emission factor target (<499kg-CO2/MWh) for coal-fired power generation systems can be achieved without CO2 capturing by developing gasifiers whose CGE is 85.0% and integration with 1650°C-glass gas turbine.

No.12 Oxy-Fuel IGCC石炭ガス化炉の数値解析(ガス化・燃焼・液化(3))

No.12 Oxy-Fuel IGCC石炭ガス化炉の数値解析(ガス化・燃焼・液化(3))

Use of Recycle for H2s Removal by Mdea Scrubbing in Igcc Systems

Use of Recycle for H2s Removal by Mdea Scrubbing in Igcc Systems

CO&lt;sub&gt;2&lt;/sub&gt;回収型クローズドIGCCシステム検討と実証計画

CO&lt;sub&gt;2&lt;/sub&gt;回収型クローズドIGCCシステム検討と実証計画

Numerical investigation of effects of CO2 recirculation in an oxy-fuel IGCC on gasification characteristics of a two-stage entrained flow coal gasifier

Effects of CO2 recirculation within an oxy-fuel IGCC plant on a gasification characteristics of a two-stage entrained flow coal gasifier was numerically investigated by means of a three-dimensional unsteady Reynolds-averaged Navier-Stokes(RANS) simulation. The RNG k−ε model and the Eulerian-Lagrangian manner were used to consider the effect of turbulence and the particles' motions, respectively. A char gasification model in which the Langmuir-Hinshelwood formulation was coupled with the random pore model was employed to estimate gasification reaction rate. Results showed that the gasification performance such as the per pass carbon conversion efficiency for the oxy-fuel condition in which CO2 replaced N2 in the primary and secondary gas flows was in the same level for the air-blown condition in which O2 flowed into the gasifier with N2, while the gaseous temperature drastically decreased for the former case. It was also found that the gaseous temperature was recovered to the same level for the air-blown condition with at least more than 35% of oxygen concentration in the gasifying agent and simultaneously the highly gasification performance was observed. It is essential to control O2 and CO2 concentrations in the gasifying agent to turn the CO2 recirculation to advantage in utilization of the O2-CO2 blown gasifier in the oxy-fuel IGCC system.

Study on different zero CO2emission IGCC systems with CO2capture by integrating OTM

Study on different zero CO₂emission IGCC systems with CO₂capture by integrating OTM

Lignite-fired air-blown IGCC systems with pre-combustion CO2capture

Detailed analyses based on mass and energy balances of lignite-fired air-blown gasification-based combined cycles with CO2 pre-combustion capture are presented and discussed in this work. The thermodynamic assessment is carried out with a proprietary code integrated with Aspen Plus® to carefully simulate the selective removal of both H2S and CO2 in the acid gas removal station. The work focuses on power plants with two combustion turbines, with lower and higher turbine inlet temperatures, respectively, as topping cycle. A high-moisture lignite, partially dried before feeding the air-blown gasification system, is used as fuel input. Because the raw lignite presents a very low amount of sulfur, a particular technique consisting of an acid gas recycle to the absorber, is adopted to fulfill the requirements related to the presence of H2S in the stream to the Claus plant and in the CO2-rich stream to storage. Despite the operation of the H2S removal section representing a significant issue, the impact on the performance of the power plant is limited. The calculations show that a significant lignite pre-drying is necessary to achieve higher efficiency in case of CO2 capture. In particular, considering a wide range (10–30 wt.%) of residual moisture in the dried lignite, higher heating value (HHV) efficiency presents a decreasing trend, with maximum values of 35.15% and 37.12% depending on the type of the combustion turbine, even though the higher the residual moisture in the dried coal, the lower the extraction of steam from the heat recovery steam cycle. On the other hand, introducing the specific primary energy consumption for CO2 avoided (SPECCA) as a measure of the energy cost related to CO2 capture, lower values were predicted when gasifying dried lignite with higher residual moisture content. In particular, a SPECCA value as low as 2.69 MJ/kgCO2 was calculated when gasifying lignite with the highest (30 wt.%) residual moisture content in a power plant with the advanced combustion turbine. Ultimately, focusing on the power plants with the advanced combustion turbine, air-blown gasification of lignite brings about a reduction in HHV efficiency equal to almost 1.5 to 2.8 percentage points, depending on the residual moisture in the dried lignite, if compared with similar cases where bituminous coal is used as fuel input. Copyright © 2016 John Wiley & Sons, Ltd.

Development of high-efficiency oxy-fuel IGCC system

Development of high-efficiency oxy-fuel IGCC system

CO2 enhanced in-situ oxy-coal gasification based carbon-neutral conventional power generating systems

UCG (Underground coal gasification) is an economic and a viable in-situ clean coal technology in exploiting deep underground coal resources. Sustaining a combustion front in the in-situ gasification of high ash coal is difficult if steam acts as a gasifying medium. In addition, the use of superheated steam causes the transportation problem for deep coal seam. Conversely, these problems could be avoided if CO2 is used as the gasifying medium. In order to implement a CCS ready system in existing plants, the present study investigates the feasibility of integration of CO2/O2 gasification of in-situ coal with conventional power generating systems such as steam turbine and combined cycle power plants performing in a CO2/O2 mode of combustion. The effect of operating pressure and the ratio of CO2/O2 input to an UCG system on the net thermal efficiency of the IGCC system are evaluated. A detailed energy analysis of the CO2 enhanced IUGCC (UCG integrated with the combined cycle) shows a high net thermal efficiency of 41% with CCS (carbon capture and storage) at the UCG operating pressure of 27 bar. IUGST (Integration of low pressure UCG with a steam turbine cycle) system shows a net thermal efficiency of 27% with CCS.

ICOPE-15-1037 Development of Advanced Integrated coal Gasification Combined Cycle (A-IGCC) Power Generation Systems with a Gas Treating Unit

Advanced Integrated coal Gasification Combined Cycle (A-IGCC) systems have been proposed to obtain higher power generation efficiency than IGCC systems by recycling the exhaust heat from a gas turbine as the heat source of the gasifier. To date, the A-IGCC system including gasification, gas treating including CO_2 capturing and combined cycle power generation units has not been designed. In this study, the performances of A-IGCC systems with these units were evaluated by using process simulator Aspen Plus[○!R] ver. 7.2. Results showed the net thermal efficiencies of A-IGCC models with water gas shift (WGS) and CO_2 capturing units were lower than that of models without these units by 3.5-5.2% because of reduction in gas turbine and steam turbine outputs and additional heat and electricity input to CO_2 capturing unit. Net thermal efficiency of the A-IGCC system with the hot gas desulfurization unit was higher than that with the cold gas desulfurization unit (CGDU) by 1.4-3.1% owing to decrease in heat loss in coolers at CGDU, subsequent increase of heating value of fuel gas into the gas turbine combustors. The CO_2 emission factor can be reduced from 744-769 kg-CO_2/MWh to 117-137 kg-CO_2/MWh by capturing of approximately 85% of CO_2 after WGS.

ICOPE-15-C126 The Research and Optimization on the Thermal System of a New Reheat IGCC System

ICOPE-15-C126 The Research and Optimization on the Thermal System of a New Reheat IGCC System

F124 H_2O/CO_2中における石炭ガス化燃料と酸素の燃焼特性(OS9 熱・流動(2))

In a gas turbine combustor for high-efficiency oxy-fuel IGCC system, it is necessary to burn coal gasified fuel and oxygen near stoichiometric condition in CO_2-rich diluent including H_2O. In this study, in order to grasp the combustion characteristics, the atmospheric pressure combustion tests with a small diffusion burner have been carried out and the influence of combustion conditions on the combustion efficiency has been experimentally examined. As the results, the combustion efficiency rises slowly with the increase of residence time, and the combustion efficiency at shorter residence time such as an actual condition is low compared with that of a combustion test using air as oxidant and diluent. The combustion efficiency is affected by the diluent composition (H_2O/CO_2 ratio) and the fuel composition (H_2/CO ratio) depending on the coal type, and the combustor efficiency rises with the increase of the H_2O/CO_2 ratio and the H_2/CO ratio. The influence of the combustion gas temperature on combustion efficiency is not confirmed in the range of the combustion test conditions.

S0810103 H_2O/CO_2中における石炭ガス化燃料と酸素の基礎燃焼特性 : 燃料中微量成分(NH_3)の排出特性

As a gas turbine for high-efficiency oxy-fuel IGCC system corresponds to a semi-closed type gas turbine, there is concern that a very small amount of ingredient contained in fuel and oxygen affects the purity of captured CO_2. In this study, the atmospheric pressure combustion tests were performed by using fuel including NH_3 as minor components and by using diluent including NO as the exhaust circulation gas, and NOx emission characteristics were examined. As the results, the conversion ratio to NOx from NH_3 was approximately 30% when NH_3 concentration was 2000ppm, and the most of the NOx emission consisted of NO. And when NH_3 is contained in fuel and NO is contained in diluent corresponding to the exhaust circulation gas, it was confirmed that NOx emission corresponds to the sum of NOx emission formed by NH_3 in fuel and NOx emission formed by NO in diluent.

ICOPE-15-1174 Development of High-Efficiency Oxy-Fuel IGCC System

Carbon Capture and Storage (CCS) is regarded as a countermeasure for global warming, but introduction of conventional CCS system deteriorates thermal efficiency of power station. As a solution, a project has started by NEDO to develop the High-efficiency Oxy-fuel IGCC system, which can keep high efficiency more than 42% even after capturing CO_2. In this system, gasifying agent and combustion air is substituted by oxygen diluted by exhaust gas recirculated from gas turbine combustor. The target of this project was set as to achieve net thermal efficiency more than 42%, which is equivalent to state of the art coal-fired power station. Various approaches were done to confirm the concept of this system and to develop fundamental technologies necessary for achieving this system. This project is a joint development by CRIEPI and Kyushu University. This paper introduces the latest status of this project executed by CRIEPI by referring several related papers.

Influence of the Selected Parameters on the Effectiveness of IGCC System Integrated With CCS Installation

Abstract The paper presents the basic input data and modelling results of IGCC system with membrane CO2 capture installation and without capture. The models were built using commercial software (Aspen and GateCycle) and with the use of authors’ own computational codes. The main parameters of the systems were calculated, such as gross and net power, auxiliary power of individual installations and efficiencies. The models were used for the economic and ecological analysis of the systems. The Break Even Point method of analysis was used. The calculations took into account the EU emissions trading scheme. Sensitivity analysis on the influence of selected quantities on break-even price of electricity was performed

Coal Based Cogeneration System for Synthetic/Substitute Natural Gas and Power With CO2 Capture After Methanation: Coupling Between Chemical and Power Production

Cogeneration of synthetic natural gas (SNG) and power from coal efficiently and CO2 capture with low energy penalty during coal utilization are very important technical paths to implement clean coal technologies in China. This paper integrates a novel coal based cogeneration system with CO2 capture after chemical synthesis to produce SNG and power, and presents the energetic and exergy analysis based on the thermodynamic formulas and the use of ASPEN PLUS 11.0. In the novel system, instead of separation from the gas before chemical synthesis traditionally, CO2 will be removed from the unconverted gas after synthesis, whose concentration can reach as high as 55% before separation and is much higher than 30% in traditional SNG production system. And by moderate recycle instead of full recycle of chemical unconverted gas back into SNG synthesis, the sharp increase in energy consumption for SNG synthesis with conversion ratios will be avoided, and by using part of the chemical unconverted gas, power is cogenerated efficiently. Thermodynamic analysis shows that the benefit from both systematic integration and high CO2 concentration makes the system have good efficiency and low energy penalty for CO2 capture. The overall efficiency of the system ranges from 53%–62% at different recycle ratios. Compared to traditional single product systems (IGCC with CO2 capture for power, traditional SNG system for SNG production), the energy saving ratio (ESR) of the novel system is 16%–21%. And compared to IGCC and traditional SNG system, the energy saving benefit from cogeneration can even offset the energy consumption for CO2 separation, and thus zero energy/efficiency penalties for CO2 capture can be realized through system integration when the chemicals to power output ratio (CPOR) varies in the range of 1.0–4.6. Sensitivity analysis hints that an optimized recycle ratio of the unconverted gas and CPOR can maximize system performance (The optimized Ru for ESR maximum is around 9, 4.2, and 4.0, and the corresponding CPOR is around 4.25, 3.89, and 3.84, at τ = 4.94, 5.28 and 5.61), and minimize the efficiency penalty for CO2 capture (The optimized Ru for minimization of CO2 capture energy penalty is around 6.37 and the corresponding CPOR is around 3.97 at τ = 4.94, ε = 16.5). The polygeneration plant with CO2 capture after chemical synthesis has a good thermodynamic and environmental performance and may be an option for clean coal technologies and CO2 emission abatement.

Techno-economic analysis of biomass/coal Co-gasification IGCC systems with supercritical steam bottom cycle and carbon capture

In recent years, integrated gasification combined cycle technology has been gaining steady popularity for use in clean coal power operations with carbon capture and sequestration (CCS). This study focuses on investigating two approaches to improve efficiency and further reduce the greenhouse gas (GHG) emissions. First, replace the traditional subcritical Rankine steam cycle portion of the overall plant with a supercritical steam cycle. Second, add different amounts of biomass as feedstock to reduce emissions. Employing biomass as a feedstock has the advantage of being carbon neutral or even carbon negative if CCS is implemented. However, due to limited feedstock supply, such plants are usually small (2–50 MW), which results in lower efficiency and higher capital and production costs. Considering these challenges, it is more economically attractive and less technically challenging to co-combust or co-gasify biomass wastes with low-rank coals. Using the commercial software, Thermoflow®, this study analyzes the baseline plants around 235 MW and 267 MW for the subcritical and supercritical designs, respectively. Both post-combustion and pre-combustion CCS conditions are considered. The results clearly show that utilizing a certain type of biomass with low-rank coals up to 50% (wt.) can, in most cases, not only improve the efficiency and reduce overall emissions but may be economically advantageous, as well. Beyond a 10% Biomass Ratio, however, the efficiency begins to drop due to the rising pretreatment costs, but the system itself still remains more efficient than from using coal alone (between 0.2 and 0.3 points on average). The CO2 emissions decrease by about 7000 tons/MW-year compared to the baseline (no biomass), making the plant carbon negative with only 10% biomass in the feedstock. In addition, implementing a supercritical steam cycle raises the efficiency (1.6 percentage points) and lowers the capital costs ($300/kW), regardless of plant layout. Implementing post-combustion CCS consistently causes a drop in efficiency (at least 7–8 points) from the baseline and increases the costs by $3000–$4000/kW and $0.06–$0.07/kW-h. The SOx emissions also decrease by about 190 tons/year (7.6 × 10−6 tons/MW-year). Finally, the CCS cost is around $65–$72 per ton of CO2. For pre-combustion CCS, sour shift appears to be superior both economically and thermally to sweet shift in the current study. Sour shift is always cheaper, (by a difference of about $600/kW and $0.02-$0.03/kW-h), easier to implement, and also 2–3 percentage points more efficient. The economic difference is fairly marginal, but the trend is inversely proportional to the efficiency, with cost of electricity decreasing by 0.5 cents/kW-h from 0% to 10% biomass ratio (BMR) and rising 2.5 cents/kW-h from 10% to 50% BMR. Pre-combustion CCS plants are smaller than post-combustion ones and usually require 25% less energy for CCS due to their compact size for processing fuel flow only under higher pressure (450 psi), versus processing the combusted gases at near-atmospheric pressure. Finally, the CO2 removal cost for sour shift is around $20/ton, whereas sweet shift's cost is around $30/ton, which is much cheaper than that of post-combustion CCS: about $60–$70/ton. Copyright © 2014 John Wiley & Sons, Ltd.

Simulation Research on Performance of IGCC System with Brown Coal/Liquid CO&lt;sub&gt;2&lt;/sub&gt; Slurry Feed

A simulation research on IGCC process adopting the technique of coal/liquid CO2 (CO2(l)) slurry was proposed. A model of a brown coal slurry fed IGCC system with CO2 capture unit was developed in ASPEN Plus. This model was used to investigate the thermal performance of the IGCC process under different operating conditions. Three kinds of Chinese brown coal were employed in this work. The simulation results show excellent performance of IGCC system when brown coal/CO2(l) slurry feed in gasification system. Enhanced carbon conversion rate and net plant efficiency can be observed with less coal consumption meanwhile. H2O/CO ratio decreases because of more CO and less H2O in the syngas with brown coal /CO2(l) slurry feeding. The net CO2 output from IGCC system also decreases as the advantage of CO2 capture and reuse in coal/CO2(l) slurry.

Development of High-efficiency Oxy-fuel IGCC System

CO2 emission control is a significant issue as a countermeasure for a global warming problem. Carbon dioxide capture and storage technology is regarded as one of the methods of reducing CO2 emission, but it leads to a drop in a thermal efficiency. It is important to maintain thermal efficiency as high as possible for an efficient use of limited fossil fuel resources. CRIEPI started a joint project with Kyushu university to develop “High-efficiency oxy-fuel IGCC”, a high thermal efficiency integrated coal gasification combined cycle power generating system with CO2 capture, which can keep its efficiency more than 40% (HHV). This system gasifies coal with mixed gas of O2 and recirculated exhaust gas mainly composed by CO2, just as oxy-fuel combustion boiler. This paper is to introduce latest achievements done by CRIEPI on this project by quoting latest papers. In order to clarify the effect of CO2 enrichment on coal gasification reaction, coal gasification experiments were executed using pressurized entrained flow coal gasifier whose fuel capacity is 3TPD. And in order to evaluate characteristics of O2- CO2 gasifier by numerical simulation, pressurized drop tube experiments were performed to obtain reaction data necessary for constructing high precision reaction model for numerical simulation code. The data clarified difference between O2 gasification and CO2 gasification on soot behaviour. When we start this project, this system had a problem to be solved. That is carbon deposition on the surface of hot gas clean-up sorbent, installed to improve thermal efficiency. As CO concentration of syngas is so high that carbon particles are supposed to deposit on desulfurization sorbent. But fundamental experiments showed an appropriate countermeasure for carbon deposition, whose impact on thermal efficiency is quite small. Now it is time for us to summarize achievements and propose the next steps toward realization of this system.

A Study of CO2 Capture in Advanced IGCC Systems by Ammonia Scrubbing

This paper deals with post-combustion CO2 capture by aqueous ammonia in air-blown gasification-based combined cycles and follows previous authors’ investigations of CO2 capture by MEA scrubbing. Based on the calculations, CO2 capture seems to be more penalizing when realized by chilled ammonia instead of MEA. As a matter of fact, chilling down to 7°C both the exhaust gas and the ammonia solution results in significant power consumption of chillers, which is only partly balanced by the lower consumption for CO2 compression and lower steam extraction from the bottoming cycle compared to the MEA case. Cases with cooled instead of chilled ammonia are investigated as well. In particular, raising the process temperature up to 20°C seems to be an interesting solution, since temperature control in the absorber can be realized by passing the aqueous ammonia solution through an heat exchanger, using ambient-temperature water as refrigerant medium and removing the chillers from the system.