Integrated Gasification Combined Cycle Power Plant Research Articles

A systematic approach to the modeling and simulation of a Sorption Enhanced Water Gas Shift (SEWGS) process for CO2 capture

Dynamic operation of a multi-train Sorption Enhanced Water Gas Shift (SEWGS) system, based on a Pressure Swing Adsorption (PSA) process, is investigated by a detailed dynamic modeling and simulation. The multi-train SEWGS system, which consists of eight reactors in each train, operating in parallel, treats the feed syngas being produced continuously in a gasifier of an Integrated Gasification Combined Cycle (IGCC). Syngas is converted to a H2-rich product and a separate CO2-rich stream is also produced. The SEWGS system is designed for pre-combustion CO2 capture in the IGCC power plant. Therefore dynamic characteristic of the system at different loads of feed syngas is interesting for investigation of the performance of IGCC power plant at different Gas Turbine (GT) load levels. Simulation results reveal performance of the system in terms of components breakthrough curves and steam consumption of the system with a CO2 recovery rate of 95% and 99% purity of the recovered CO2. The H2-rich product purity achieved is around 81%. It is found that changing the rinse and purge steam amount affects the CO2 purity and recovery rate. However, the H2-rich product purity remains almost unchanged. Simulation results at different loads of feed syngas shows that to maintain the CO2 recovery and purity of the design case as the target performance, in addition to changing the rinse and purge steam loads, duration of the feed step and thus the cycle time should be varied as well. The H2-rich stream flow rate is found to undergo a periodic fluctuation of around ±33%, which should be minimized due to the GT requirements. It is tried to reduce the fluctuations by scheduling operation of the trains with time lags. Operation of the SEWGS system under two different scheduled operation scheme is investigated. H2-rich stream flow rate fluctuations are decreased from ∼±33% in the basic operation scheme to ∼±14% and ∼±11% in the first and second scheme. However, compared to the basic scheme, the H2-rich stream overall production rate drops around 5.5% and 6.2% on average, respectively.

Analyzing the possibility of constructing the air heating system for an integrated solid fuel gasification combined-cycle power plant

Combined-cycle power plants operating on solid fuel have presently been implemented only in demonstration projects. One of possible ways for improving such plants consists in making a shift to hybrid process circuits of integrated gasification combined-cycle plants with external firing of solid fuel. A high-temperature air heater serving to heat compressed air is a key element of the hybrid process circuit. The article describes application of a high-temperature recuperative metal air heater in the process circuit of an integrated gasification combined-cycle power plant (IGCC). The available experience with high-temperature air heating is considered, and possible air heater layout arrangements are analyzed along with domestically produced heat-resistant grades of steel suitable for manufacturing such air heater. An alternative (with respect to the traditional one) design is proposed, according to which solid fuel is fired in a noncooled furnace extension, followed by mixing the combustion products with recirculation gases, after which the mixture is fed to a convective air heater. The use of this design makes it possible to achieve considerably smaller capital outlays and operating costs. The data obtained from thermal and aerodynamic calculations of the high-temperature air heater with a thermal capacity of 258 MW for heating air to a temperature of up to 800°C for being used in the hybrid process circuit of a combined-cycle power plant are presented.

Selecting the process arrangement for preparing the gas turbine working fluid for an integrated gasification combined-cycle power plant

Introduction of a combined-cycle technology based on fuel gasification integrated in the process cycle (commonly known as integrated gasification combined cycle technology) is among avenues of development activities aimed at achieving more efficient operation of coal-fired power units at thermal power plants. The introduction of this technology is presently facing the following difficulties: IGCC installations are characterized by high capital intensity, low energy efficiency, and insufficient reliability and availability indicators. It was revealed from an analysis of literature sources that these drawbacks are typical for the gas turbine working fluid preparation system, the main component of which is a gasification plant. Different methods for improving the gasification plant chemical efficiency were compared, including blast air high-temperature heating, use of industrial oxygen, and a combination of these two methods implying limited use of oxygen and moderate heating of blast air. Calculated investigations aimed at estimating the influence of methods for achieving more efficient air gasification are carried out taking as an example the gasifier produced by the Mitsubishi Heavy Industries (MHI) with a thermal capacity of 500 MW. The investigation procedure was verified against the known experimental data. Modes have been determined in which the use of high-temperature heating of blast air for gasification and cycle air upstream of the gas turbine combustion chamber makes it possible to increase the working fluid preparation system efficiency to a level exceeding the efficiency of the oxygen process performed according to the Shell technology. For the gasification plant’s configuration and the GTU working fluid preparation system be selected on a well-grounded basis, this work should be supplemented with technical-economic calculations.

석탄가스화 복합발전소 건설의 에너지안보 확보편익 추정

석탄가스화 복합발전소는 기존 석탄화력 발전소에 비해 온실가스 및 대기오염물질을 적게 배출할 뿐만 아니라 국제적으로 쉽게 확보할 수 있는 저렴한 저품위 석탄을 사용할 수 있어서 연료를 안정적으로 공급받을 수 있다. 이에 본 논문에서는 석탄가스화 복합발전 건설의 에너지안보 확보편익을 추정하고자 한다. 이를 위해 무작위로 추출된 전국 600가구를 대상으로 설문조사를 수행한 후 얻은 자료에 조건부 가치측정법을 적용하여 분석한 결과를 제시한다. 통계적 효율성의 확보를 위해 이중경계 모형을 적용하며 영(0)의 응답자료를 적절하게 다루기 위해 스파이크 모형을 적용한다. 분석결과 석탄가스화 복합발전소로부터 생산되는 전력 1kWh에 대해 응답자들은 평균적으로 6.05원의 추가적인 지불의사액을 가졌다. 즉 석탄가스화 복합발전소로부터 생산되는 전력에 대한 에너지안보 확보편익은 6.05원/kWh이다. 올해 완공되는 태안 석탄가스화 복합발전소의 예상 연간 발전량은 2.27TWh이므로 에너지안보 확보편익은 연간 13,740백만원으로 추정된다. Integrated gasification combined cycle (IGCC) power plants not only emit less greenhouse gases and air pollutants than conventional coal-fired power plants, but also use low-price, low-quality, and internationally easily procurable coal. Thus we can benefit from safeguarding energy security through building the IGCC power plant. This paper attempts to value the benefits of energy security enhanced by IGCC power plant. To this end, we report here the results from a contingent valuation survey of randomly selected 600 households. A combination of a double-bounded model and a spike model is applied for the purpose of increasing statistical efficiency and dealing with zero(0) willingness to pay data, respectively. The results show that the respondents are additionally willing to pay 6.05 won for 1kWh of electricity generated from IGCC power plant. In other words, the benefits from safeguarding energy security through building the IGCC power plant are 6.05 won per kWh. Given that the expected amount of generation from the Taean IGCC power plant that is scheduled to be built in late 2015 is 2.27 TWh per year, the benefits are estimated to be 13.74 billion won per year.

Simultaneous integration and optimization of an IGCC plant

An Integrated Gasification Combined Cycle (IGCC) is a promising green technology applied for thermal power plants. It offers an efficient way to generate electricity from coal, biomass or any other suitable solid or liquid fuels with lower impact to the environment. The biggest challenge of making IGCC to become a viable technology is its high energy production cost. This creates a barrier for this green technology to enter into the stage of a highly competitive electricity market. An IGCC plant is a complex process system which involves processing units operated in very extreme conditions. Proper material and energy integration may provide a hope for cost reduction. In this paper, a mathematical model of an IGCC plant was built that includes a gasification unit, an Air Separation Unit (ASU) and a Combined Cycle unit. A modified Gibbs free energy model is used for predicting the composition of the syngas taking into account material and energy balances. The proposed gasification model results in syngas composition similar to the experimental data provided in literature. What’s more, Combined Cycle unit is simulated with isentropic assumption plus efficiency. While ASU is simulated mainly using the rigorous distillation model. Although individual processing unit optimization plays a significant role in enhancing the plant performance, an optimal integration among the three units still has significant potential to improve the efficiency, availability, and operability of a coal-fed IGCC power plant. The proposed mathematical model allows material and energy integration to be performed within and among different processing units while optimizing the IGCC plant as a whole. Different material and energy integration schemes were considered with respect to the overall thermal efficiency of the IGCC plant. The good performance is shown by about 2 % overall efficiency increment in the case study.

Energy and exergy analysis of chemical looping combustion technology and comparison with pre-combustion and oxy-fuel combustion technologies for CO2 capture

Carbon dioxide (CO2) emitted from conventional coal-based power plants is a growing concern for the environment. Chemical looping combustion (CLC), pre-combustion and oxy-fuel combustion are promising CO2 capture technologies which allow clean electricity generation from coal in an integrated gasification combined cycle (IGCC) power plant. This work compares the characteristics of the above three capture technologies to those of a conventional IGCC plant without CO2 capture. CLC technology is also investigated for two different process configurations—(i) an integrated gasification combined cycle coupled with chemical looping combustion (IGCC–CLC), and (ii) coal direct chemical looping combustion (CDCLC)—using exergy analysis to exploit the complete potential of CLC. Power output, net electrical efficiency and CO2 capture efficiency are the key parameters investigated for the assessment. Flowsheet models of five different types of IGCC power plants, (four with and one without CO2 capture), were developed in the Aspen plus simulation package. The results indicate that with respect to conventional IGCC power plant, IGCC–CLC exhibited an energy penalty of 4.5%, compared with 7.1% and 9.1% for pre-combustion and oxy-fuel combustion technologies, respectively. IGCC–CLC and oxy-fuel combustion technologies achieved an overall CO2 capture rate of ∼100% whereas pre-combustion technology could capture ∼94.8%. Modification of IGCC–CLC into CDCLC tends to increase the net electrical efficiency by 4.7% while maintaining 100% CO2 capture rate. A detailed exergy analysis performed on the two CLC process configurations (IGCC–CLC and CDCLC) and conventional IGCC process demonstrates that CLC technology can be thermodynamically as efficient as a conventional IGCC process.

IGCC Precombustion CO2 Capture Using K2CO3 Solvent and Utilizing the Intercooling Heat Recovered From CO2 Compressors for CO2 Regeneration

CO2 capture (CC) using hot K2CO3 solvent in integrated gasification combined cycle (IGCC) plant is a promising technology for CO2 emission reduction. Based on pilot scale trials, an innovative IGCC system with CC using hot K2CO3 solvent is proposed, in which the intercooling heat between CO2 compressors is recovered for CO2 regeneration (IGCC + CC + HR). Thermodynamic performance and exergy and energy utilization diagram (EUD) analysis are presented. Results show that recovery of the intercooling heat between CO2 compressors reduces the steam extraction requirement from turbines for CO2 regeneration by around 18% and enhances the efficiency of IGCC with CO2 capture (IGCC + CC) plant by 0.3–0.7 percentage points. With 90% CC, the efficiency of the IGCC + CC + HR plant is around 35.4% which is higher than IGCC + CC plant using Selexol technology. Compared to IGCC, the energy penalty for CC in IGCC + CC + HR plant is mainly caused by the exergy losses in CO2 separation (45.2%), water gas shift (WGS) (28.5%), combined cycle (20.7%) and CO2 compression units (5.6%). EUD analysis shows that the IGCC + CC + HR plant realizes good match of the energy levels between the intercooling heat and the recovered steam for CO2 regeneration, thereby obviously reducing the exergy losses in CO2 compression and separation units and improving the plant efficiency. The results presented in this paper confirm the sources causing the energy penalty for CC in IGCC power plant and the new IGCC + CC + HR system helps to reduce the energy penalty for CC in IGCC power plant based on solvent technologies.

An experimental and modeling study of CO2-selective membranes for IGCC syngas purification

In recent years, integrated gasification combined cycle (IGCC) technology has gained significant attention for large-scale power generation with carbon capture. In an IGCC power plant, the syngas is typically directed to the gas turbine (for power generation) after CO2 and H2S removal. This work describes the transport properties of the CO2-selective polymeric facilitated transport membranes for syngas purification at different pressures (2–15bar) and 107°C. These membranes contain amines as CO2-carriers that are dispersed in a crosslinked polyvinylalcohol (PVA) matrix. Furthermore, a two-stage membrane process is proposed for CO2 removal from syngas in an IGCC plant. A process modeling and cost-sensitivity analysis of the proposed two-stage membrane process was performed. The effects of feed pressure, temperature, membrane permeance, and selectivity on the overall increase in the cost of electricity (COE) were analyzed. An increase in the COE of 14–18% was estimated for 90% CO2 removal and >99% H2 recovery using the two-stage membrane process in an IGCC power plant.

CO2-selective membranes for hydrogen production and CO2 capture – Part II: Techno-economic analysis

Syngas processing often requires separation of CO2 and hydrogen for hydrogen production, and the resulting CO2-enriched stream presents an opportunity for simultaneous CO2 capture. For example, syngas-based integrated gasification combined cycle (IGCC) power plants are envisioned as an efficient means of producing power from coal where CO2 capture technologies can be applied relatively easily. Membrane technology is an attractive approach for CO2 capture because of inherent process advantages such as simplicity, reliability, compactness and modularity. This paper (Part II of a two-part study) performs techno-economic analysis for CO2-selective membranes in three hydrogen production or utilization applications: methane reformer/pressure swing adsorption processes, oxygen-blown coal-fired IGCC power plants using GE gasification technology, and air-blown coal-fired IGCC power plants using Transport Integrated Gasification (TRIG) technology. These processes require membranes with CO2/H2 selectivities of 10–20, which can be provided using PolarisTM membranes. Hybrid approaches using a combination of membrane and cryogenic processes are evaluated for the production of high-pressure liquid CO2 ready for utilization or sequestration. The optimal membrane CO2/H2 selectivity and influence of CO2 capture rate on the cost of CO2 capture are determined, providing general guidelines for future membrane development. The cost of CO2 capture with these membrane processes depends not only on the feed CO2 partial pressure, but on the feed CO2 concentration as well.

Development of life cycle water-demand coefficients for coal-based power generation technologies

This paper aims to develop benchmark coefficients for water consumption and water withdrawals over the full life cycle of coal-based power generation. This study considered not only all of the unit operations involved in the full electricity generation life cycle but also compared different coal-based power generating technologies. Overall this study develops the life cycle water footprint for 36 different coal-based electricity generation pathways. Power generation pathways involving new technologies of integrated gasification combined cycle (IGCC) or ultra supercritical technology with coal transportation by conventional means and using dry cooling systems have the least complete life cycle water-demand coefficients of about 1L/kWh. Sensitivity analysis is conducted to study the impact of power plant performance and coal transportation on the water demand coefficients. The consumption coefficient over life cycle of ultra supercritical or IGCC power plants are 0.12L/kWh higher when conventional transportation of coal is replaced by coal-log pipeline. Similarly, if the conventional transportation of coal is replaced by its transportation in the form of a slurry through a pipeline, the consumption coefficient of a subcritical power plant increases by 0.52L/kWh.

Power Supply Efficiency Analysis and Techno-Economic Evaluation of IGCC Projects

Integrated gasification combined cycle (IGCC) is an efficient, low-pollution clean coal power generation technology and efficient use of IGCC technology is helpful to realize clean conversion and comprehensive utilization of coal resources in China. This paper analyzed the factors that influence the power supply efficiency of IGCC power plants, determined assessment model for power supply efficiency of IGCC power plants. Then based on IGCC power plant construction specific data including power supply efficiency, combining the general technical and economic evaluation of the project, the technical and economic evaluation step of IGCC plant was determined. The economic evaluation of IGCC power plant was carried out as well as sensitivity analysis in terms of static total investment, utilization hours and standard coal tax price. The results showed that introduced IGCC of 40 megawatt had higher tariff and utilization hours had maximum impact on tariff.

Control Structure Selection for the Elevated-Pressure Air Separation Unit in an IGCC Power Plant: Self-Optimizing Control Structure for Economical Operation

The air separation unit (ASU) is one of the core elements of integrated gasification combined cycle (IGCC) power plants. The ASU separates air into pure oxygen and nitrogen, to be sent to the gasifier and the gas turbine, respectively. This system consumes about 10% of the gross power output generated in IGCC, so its economical operation is important for lowering the overall power generation cost. The use of an elevated-pressure air separation unit (EP ASU), in which the operating pressure is higher than in a conventional ASU, is known to lead to significant energy savings. In this research, controlled variable selection for an EP ASU was studied, considering both the controllability and economics, that is, with the objective of maintaining economically near-optimal operations in the presence of anticipated load changes. The main tool used for this was the so-called “minimum singular value rule” within the overall framework of self-optimizing control (SOC). For the purpose of selecting and testing self-optimizing control structures, equation-based modeling of EP ASU was carried out and implemented on the commercial software platform gPROMS. Then, the minimum singular value rule was applied using steady-state gain matrices (obtained from the simulator) to select a small number of candidate sets for controlled variables, to which rigorous analyses based on nonlinear simulation and optimization could be applied to pick the top choice. Before the minimum singular value rule was applied, however, certain process insights and heuristics were used to reduce the number of candidate sets down to a manageable level. The economic losses as a result of adopting a fixed control structure were assessed by comparing the hourly operating costs achieved under SOC with the equivalent values obtained by performing full nonlinear optimizations for the given scenarios. In addition, for the suggested control structure, proportional plus integral (PI) control loops were designed, and their dynamic performance was tested in order to make sure that it is attractive in terms of not only economics but also controllability. The finally selected control structure is compared with those presented in previous works.

Economic evaluation of pre-combustion CO2-capture in IGCC power plants by porous ceramic membranes

Pre-combustion-carbon-capture is one of the three main routes for the mitigation of CO2-emissions by fossil fueled power plants. Based on the data of a detailed technical evaluation of CO2-capture by porous ceramic membranes (CM) and ceramic membrane reactors (WGSMR) in an Integrated-Gasification-Combined-Cycle (IGCC) power plant this paper focuses on the economic effects of CO2-abatement. First the results of the process simulations are presented briefly. The analysis is based on a comparison with a reference IGCC without CO2-capture (dry syngas cooling, bituminous coal, efficiency of 47.4%). In addition, as a second reference, an IGCC process with CO2 removal based on standard Selexol-scrubbing is taken into account. The most promising technology for CO2-capture by membranes in IGCC applications is the combination of a water gas shift reactor and a H2-selective membrane into one water gas shift membrane reactor. For the WGSRM-case efficiency losses can be limited to about 6%-points (including losses for CO2 compression) for a CO2 separation degree of 90%. This is a severe reduction of the efficiency loss compared to Selexol (10.3% points) or IGCC–CM (8.6% points). The economic evaluation is based on a detailed analysis of investment and operational costs. Parameters like membrane costs and lifetime, costs of CO2-certificates and annual operating hours are taken into account. The purpose of these evaluations is to identify the minimum cost of electricity for the different capture cases for the variation of the boundary conditions. Fixing 90% CO2 separation the analysis identifies clearly that the economic minimum for cost of electricity and maximum thermodynamic efficiencies do not coincide. The cost of electricity for the reference case was 67€/MWh and for the WGSMR integration with 90% CO2 separation 57€/MWh, if certificate costs of 30€/tCO2, membrane costs of 300€/m2 and 8000 operating hours/year are considered. Further studies on the sensitivity of cost of electricity on the technical and commercial boundary conditions will be presented.

CO2-selective membranes for hydrogen production and CO2 capture – Part I: Membrane development

Syngas operations require separation of CO2 and hydrogen for hydrogen production at refineries and petrochemical plants, and potentially for combined hydrogen production and CO2 capture at integrated gasification combined cycle (IGCC) power plants. Membranes that selectively permeate CO2 have attracted significant interest, because the purified hydrogen is retained at high pressure, thus avoiding costly downstream recompression. In this work, Polaris™ thin film composite membranes were evaluated for CO2 removal from syngas: these membranes are highly permeable to CO2 and reject the other major components of syngas, including hydrogen, carbon monoxide and methane. Part I of this study describes the three-stage development of Polaris membranes for CO2/H2 separation, including: laboratory parametric tests of membrane stamps using pure- and mixed-gas streams, pilot-scale tests of membrane modules using real syngas at a coal-fired gasification plant, and field demonstration of a membrane system producing liquid CO2. The gasification plant where the field tests were conducted is at the National Carbon Capture Center (NCCC) in Wilsonville, AL. The membrane demonstration system processed 227 kg/h of syngas (equivalent to a 0.15MWe IGCC power plant) containing ~9% CO2, and produced a liquid CO2 stream containing 95+% CO2. Part II of this study will explore the potential opportunities for the use of CO2-selective membranes in commercial hydrogen purification and CO2 capture, including the results of techno-economic analyses for various process designs.

石炭ガス化複合発電プラント向け高速負荷変化技術の開発

The IGCC (integrated gasification combined cycle) is emerging as one of the most advanced and effective systems for electric energy generation. The IGCC consists of pressure vessels such as a gasifier, syngas cooler and gas cleanup unit with the large time constants, so dynamic response of the power plant is delayed. On the other hand, the fluctuating power generation of renewable energies creates the need for flexible operations (e.g. fast start-up and rapid load change) of thermal power plants including IGCC power plants. This paper describes: (1) two new control methods for IGCC power plants that are combined as the proposed control method to reduce the gasifier pressure rise when rapid load changes are required; and (2) a plant-wide dynamic simulation to consider the operability and controllability of the plants. Simulation results showed the gasifier pressure rise rate was reduced from 7.4% to 3.6% due to the new proposed control method, recycle gas flow rate and steam flow rate control, with load change from 100% to 65% at 20%/min. In the case of 15%/min load change, the gasifier pressure rise rate was 2.8% and less than the maximum permissible value of 3.0%.

Selection of Control Structure of Elevated Pressure Air Separation Unit in an IGCC Power Plant for an Economical Operation

IGCC (Integrated Gasification Combined Cycle) is an alternative power generation system that can utilize fossil fuels in a more eco-friendly way than the conventional pulverized coal-fired plant. An IGCC plant requires an (Elevated Pressure) Air Separation Unit (EP ASU) that separates the air into pure oxygen and nitrogen, to be sent to the gasifier and the gas turbine, respectively. The ASU consumes about 10% of the gross power output generated in IGCC, so an economical operation of the ASU is important for lowering the overall power generation cost. In this research, controlled variable selection for an EP ASU is studied from the viewpoint of economics, i.e., with the objective of maintaining an economically (near-)optimal operation in the presence of load changes. Instead of the full-scale real-time optimization (RTO), we adopt a simpler approach known as self-optimizing control (SOC), which attempts to achieve the objective through a systematic selection of controlled variables. For the purpose of designing and testing a self-optimizing control structure, equation-based modeling of EP ASU is carried out using the software platform of gPROMS. Then, the SOC approach is applied based on the model to select the best set of controlled variables, which will lead to the most economical operation in the presence of load changes. Finally, PI control loops are designed and their dynamic control performances are tested. In addition, the economic loss in the presence of load changes is analyzed and compared with that achievable from the use of RTO.

Assessment of selected CCS technologies in electricity and synthetic fuel production for CO2 mitigation in South Africa

One of the actions proposed to reduce greenhouse gas (GHG) emissions in South Africa (SA) is to install carbon capture and storage (CCS) at new energy-producing plants. This paper aims to evaluate the costs and GHG emissions of implementing CCS at a coal-fired integrated gasification combined cycle (IGCC) power plant, at a coal fired ultra-supercritical (USC) power plant, at a synthetic fuel coal-to-liquid (CTL) plant and at a gas-to-liquid (GTL) plant for SA. The approach for comparing of these CCS applications is based on a combination of a techno-economic analysis with a life-cycle assessment. As expected, the generating costs in plants with CCS are higher than without CCS for all case studies. GHG-abatement costs in 2040 are shown to be the lowest for the IGCC power plant at 173 ZAR07/t CO2eq, followed by the USC power plant at 227 ZAR07/t CO2eq. These costs are considerably higher for the CTL and GTL plants. The results show that from an economic perspective, CCS might be an attractive option for CO2 mitigation in SA especially for the electricity sector. However, a prerequisite for the implementation of CCS is that the technology reaches commercial scale for the investigated options and is socially accepted.

Comparative performance assessment of USC and IGCC power plants integrated with CO2 capture systems

In recent years coal-fired power plants have increased their role in the global energy scenario and in this framework environmental issues require a sustainable use of coal and great efforts for greenhouse gas reduction.With this aim, this paper reports on a comparative performance assessment of two power generation technologies: the Ultra Super Critical (USC) steam plant and the Integrated Gasification Combined Cycle (IGCC) plant. Performances were assessed referring to typical commercial size plants (400–500MW) integrated with CO2 capture systems. The study is based on simulation models specifically developed through Aspen-Plus® and Gate-Cycle® software platforms.The USC plant is integrated with a SNOX section that removes simultaneously nitrogen and sulfur oxides without producing process wastes and with lower power requirements compared to traditional FGD systems. The USC plant is also integrated with a low temperature CO2 capture/compression section based on a MEA chemical absorption process.The IGCC plant is based on a Texaco entrained bed gasifier, fed by a coal–water slurry and high purity oxygen, integrated with a triple-pressure reheat combined cycle. The IGCC is integrated with a syngas cooling and treatment section composed of radiant and convective coolers, a water gas shift section and a low temperature CO2 capture system based on a physical absorption process.The performance assessment of USC and IGCC power plants was carried out by varying the main operating parameters of both power sections and gas treatment sections. For both plants an in-depth analysis of performance penalties due to the CO2 capture systems was carried out, evaluating the influence of CO2 removal technology and efficiency.

CO2emissions reduction technologies in IGCC: ELCOGAS's experiences in the field

This paper introduces the main research, development and innovation (R&D&I) activities of ELCOGAS related to CO2 emissions reduction. The largest R&D&I investment in the last decade focused on CO2 capture, with the aim of (i) demonstrating the feasibility of CO2 capture and H2 production in an integrated gasification combined cycle (IGCC) that uses solid fossil fuels and residues as feedstock and (ii) obtaining representative economic data. Its main milestone was the commissioning in 2010 of a carbon capture pilot plant integrated in Puertollano IGCC power plant which captured 100 t/d of CO2 while producing 2 t/d of high purity H2, using proven and commercial technology. In this paper, technical results obtained, lessons learnt during the project, as well as, economic data using this pilot plant are reported. ELCOGAS is also acquiring relevant knowledge in the field of co-gasification of biomass. The most recent milestone in this subject is the execution in 2012 of real tests at two levels (2 and 4% in weight) and with two different kinds of biomass (olive oil residue and grape seed meal) pointing at assessing the influence of biomass in the IGCC process including CO2 capture within FECUNDUS (RFCR-CT-2010–00009). ELCOGAS S.A. is a Spanish company which operates the Puertollano 335MWISO IGCC demonstration power plant. © 2013 Society of Chemical Industry and John Wiley & Sons, Ltd

Design and evaluation of an IGCC power plant using iron-based syngas chemical-looping (SCL) combustion

Chemical-looping combustion (CLC) is a novel and promising combustion technology with inherent separation of the greenhouse gas CO2. This paper focuses on the design and thermodynamic evaluation of an integrated gasification combined-cycle (IGCC) process using syngas chemical looping (SCL) combustion for generating electricity. The syngas is provided by coal gasification; the gas from the gasifier is cleaned using high-temperature gas desulfurization (HGD). In this study, the oxygen carrier iron oxide (Fe2O3) is selected to oxidize the syngas in a multistage moving-bed reactor. The resulting reduced iron particles then consist of FeO and Fe3O4. To create a closed-cycle operation, these particles are partially re-oxidized with steam in a fluidized-bed regenerator to pure Fe3O4 and then fully re-oxidized in a fluidized-bed air combustor to Fe2O3. One advantage of this process is the co-production of hydrogen diluted with water vapor within the steam regenerator. Both the HGD and CLC systems are not under commercial operation so far. This mixture is fed to a gas turbine for the purpose of generating electricity. The gas turbine is expected to exhibit low NOx emissions due to the high ratio of water in the combustion chamber. Cooling the flue gas in the HRSG condenses the water vapor to yield high-purity CO2 for subsequent compression and disposal. To evaluate the net efficiency, two conventional syngas gasifiers are considered, namely the BGL slagging gasifier and the Shell entrained-flow gasifier. The option of using a CO2 turbine after the SCL-fuel reactor is also investigated. A sensitivity analysis is performed on the SCL-air reactor outlet temperature, this being a key design parameter. It was found that the best net efficiency of 43% (based on HHV) can be obtained using a BGL gasifier without a CO2 turbine at an air reactor temperature of 1000°C including CO2 compression for transport and storage. Simulation data are based on software Aspen Plus® and EES (Engineering Equation Solver).