• Energy Research

In the 1970 and 1980s, gasifiers were envisaged for synthesising substitute natural gas (SNG) as well for IGCC (integrated gasification combined cycle) systems. Component temperatures were above 700°C, but stainless alloys did not have the required corrosion resistance. Experimental alloys developed in the UK were alumina formers, incorporating Ta, W, and Mo as gettering elements for sulphidation resistance. Sulphidation corrosion is solvable, but attack by HCl in gasification environments seems intractable. The supposed materials problems of gasification, plus the complexity of IGCC, have led to them being sidelined for power generation. However, commercial IGCC plants are not dependent on high temperature materials and offer higher efficiency than Rankine cycle steam. Best near term prospects for IGCC are for CO2 capture, but this constrains the type of gasifier. Gasifiers incorporating carbon capture and storage produce hydrogen, or with less capture, SNG. Such systems will supply SNG for space heating...

This paper evaluates various calcium-based chemical looping concepts to be applied in Integrated Gasification Combined Cycle (IGCC) plants for decarbonised energy vectors polygeneration (with emphasis on power generation and hydrogen and power co-generation). Two calcium-based chemical looping configurations were analysed. The first concept is based on post-combustion capture using the flue gases resulted from the power block (combined cycle gas turbine). The second concept is based on pre-combustion capture, the calcium-based chemical looping systems being used simultaneous to capture carbon dioxide (by sorbent enhanced water gas shift) and to concentrate the syngas energy in the form of hydrogen-rich gas. The paper assess in details coal-based IGCC with calcium carbonate looping cycle used for power generation. Net power output is in the range of 550e600 MW with more than 95% carbon capture rate. Critical design and operation factors like process integration, heat and power integration, quality specification of captured CO2 stream were evaluated in details. The hydrogen and power co-generation scenario (in the range of 0e200 MW hydrogen) was also evaluated as a potential way to improve the plant flexibility. IGCC power plant without carbon capture was also considered to quantify the energy penalty for carbon capture cases.

Power generation is one of the industrial sectors with major contribution to greenhouse gas emissions. For climate change mitigation, a special attention is given to the reduction of CO2 emissions by applying capture and storage techniques in which CO2 is captured and then stored in suitable safe geologic locations. Carbon capture and storage (CCS) technologies are expected to play a significant role in the coming decades for curbing greenhouse gas emissions and to ensure a sustainable development of power generation and other energy-intensive industrial sectors (e.g. cement, metallurgy, petro-chemical etc.). This paper evaluates super-critical coal-based power plants with and without carbon capture. The analysis is geared toward quantification of main plant performance indicators such as: fuel consumption, gross and net energy efficiency, ancillary energy consumption, carbon capture rate, specific CO2 emissions, capital costs, specific capital investments and operational costs etc. For CCS configurations, two post-combustion CO2 capture options were considered. The first option is based gas-liquid absorption using a chemical solvent (methyl-diethanol-amine – MDEA etc.). The second option is based on calcium looping cycle, in which the carbonation/calcination sequence of CaO/CaCO3 system is used for carbon capture. The power plant case studies investigated in the paper produces around 950 – 1,100 MW net power with at least 90 % carbon capture rate. The mathematical modelling and simulation of the whole power generation schemes will produce the input data for quantitative techno-economic and environmental evaluations of power plants with carbon capture (similar power plant concept without CCS was used as reference for comparison). Mass and energy integration tools were used to assess the integration aspects of evaluated carbon capture options in the whole power plant design, to optimise the overall energy efficiency and to evaluate the main sources of energy penalty for CCS designs.

Abstract Integrated Gasification Combined Cycle (IGCC) is a power generation technology in which the solid feedstock is partially oxidized with oxygen and steam to produce syngas. In a conventional IGCC design without carbon capture, the syngas is purified for dust and hydrogen sulphide removal and then sent to a Combined Cycle Gas Turbine (CCGT) for power generation. Carbon capture technologies are expected to play an important role in the coming decades for reducing the greenhouse gas emissions. In a modified IGCC design for carbon capture, the syngas is catalytically shifted to maximize the hydrogen level and to concentrate the carbon species in the form of carbon dioxide which can be later captured in a pre-combustion arrangement. After carbon dioxide capture, the hydrogen-rich syngas can be either purified in a Pressure Swing Adsorption (PSA) unit and exported to the external customers (e.g., chemical industry, PEM fuel cells) or used in a CCGT for power generation. This paper investigates the most important energy and process integration issues for hydrogen and electricity co-production scheme based on coal gasification process with carbon capture and storage (CCS). The evaluated coal-based IGCC case produces around 400 MW net electricity and has a flexible hydrogen output in the range of 0–200 MW (LHV) with a 90% carbon capture rate. The principal focus of the paper is on the evaluation of energy integration aspects so as to maximize the overall plant energy efficiency. Optimization includes heat and power integration of the main plant sub-systems (e.g., integration of steam generated in gasification island, with the requirements for syngas treatment, power generation in the combined cycle, best use of PSA tail gas in the power block, heat and power demand for acid gas removal unit, integration of air separation unit and gas turbine compressor etc.), sensitivity analysis (e.g., influence on ambient conditions).

Energy and economic penalties for CO2 capture are the main challenges in front of the carbon capture technologies. Chemical Looping Air Separation (CLAS) represents a potential solution for energy and cost-efficient oxygen production in comparison to the cryogenic method. This work is assessing the key techno-economic performances of a CLAS system using copper oxide as oxygen carrier integrated in coal and lignite-based oxy-combustion and gasification power plants. For comparison, similar combustion and gasification power plants using cryogenic air separation with and without carbon capture were considered as benchmark cases. The assessments were focused on large scale power plants with 350–500 MW net electricity output and 90% CO2 capture rate. As the results show, the utilization of CLAS system in coal and lignite-based oxy-combustion and gasification power plants is improving the key techno-economic indicators e.g., increasing the energy efficiency by about 5–10%, reduction of specific capital investments by about 12–18%, lower cost of electricity by about 8–11% as well as lower CO2 avoidance cost by about 17–27%. The highest techno-economic improvements being noticed for oxy-combustion cases since these plants are using more oxygen than gasification plants.

Abstract Reducing CO2 emissions from energy sector and other fossil fuel-intensive industrial applications is of main importance today. The iron and steel industry is one of the largest industrial sources of CO2 (about 6% of total CO2 emissions). Two post-combustion CO2 capture methods based on reactive gas-liquid and gas-solid systems are evaluated to be used in an integrated steel mill in conjunction with the plant sub-systems with the highest CO2 emissions e.g., captive power plant, hot stoves, coke ovens, lime kilns, etc. The gas-liquid absorption using chemical solvents (e.g., alkanolamines) and Calcium Looping (CaL) are assessed. The carbon capture rate is set to be at least 90%. The paper evaluates a conventional size of integrated steel mill emphasizing the energy integration aspects and the influence of various carbon capture options on the overall steel mill performances. The evaluated designs (captive power plants and carbon capture units) were modelled and simulated, the results being used to assess the overall indicators. For comparison reason, various captive power plant configurations of integrated steel mill without carbon capture were also considered. The assessments show that CaL system has significant advantages compared not only to benchmark cases without capture but also to the gas-liquid absorption cases.

Production of synthetic natural gas (SNG) offers an alternative way to valorize captured CO2 from energy intensive industrial processes or from a dedicated CO2 grid. This paper presents an energy-efficient way for synthetic natural gas production using captured CO2 and renewable hydrogen. Considering several renewable hydrogen production sources, a techno-economic analysis was performed to find a promising path toward its practical application. In the paper, the five possible renewable hydrogen sources (photo fermentation, dark fermentation, biomass gasification, bio photolysis, and PV electrolysis) were compared to the two reference cases (steam methane reforming and water electrolysis) from an economic stand point using key performance indicators. Possible hydrogen production capacities were also considered for the evaluation. From a technical point of view, the SNG process is an efficient process from both energy efficiency (about 57%) and CO2 conversion rate (99%). From the evaluated options, the photo-fermentation proved to be the most attractive with a levelized cost of synthetic natural gas of 18.62 €/GJ. Considering the production capacities, this option loses its advantageousness and biomass gasification becomes more attractive with a little higher levelized cost at 20.96 €/GJ. Both results present the option when no CO2 credit is considered. As presented, the CO2 credits significantly improve the key performance indicators, however, the SNG levelized cost is still higher than natural gas prices.