Alfons Kather

The oxycoal process with cryogenic oxygen supply

Due to its large reserves, coal is expected to continue to play an important role in the future. However, specific and absolute CO2 emissions are among the highest when burning coal for power generation. Therefore, the capture of CO2 from power plants may contribute significantly in reducing global CO2 emissions. This review deals with the oxyfuel process, where pure oxygen is used for burning coal, resulting in a flue gas with high CO2 concentrations. After further conditioning, the highly concentrated CO2 is compressed and transported in the liquid state to, for example, geological storages. The enormous oxygen demand is generated in an air-separation unit by a cryogenic process, which is the only available state-of-the-art technology. The generation of oxygen and the purification and liquefaction of the CO2-enriched flue gas consumes significant auxiliary power. Therefore, the overall net efficiency is expected to be lowered by 8 to 12 percentage points, corresponding to a 21 to 36% increase in fuel consumption. Oxygen combustion is associated with higher temperatures compared with conventional air combustion. Both the fuel properties as well as limitations of steam and metal temperatures of the various heat exchanger sections of the steam generator require a moderation of the temperatures during combustion and in the subsequent heat-transfer sections. This is done by means of flue gas recirculation. The interdependencies among fuel properties, the amount and the temperature of the recycled flue gas, and the resulting oxygen concentration in the combustion atmosphere are investigated. Expected effects of the modified flue gas composition in comparison with the air-fired case are studied theoretically and experimentally. The different atmosphere resulting from oxygen-fired combustion gives rise to various questions related to firing, in particular, with regard to the combustion mechanism, pollutant reduction, the risk of corrosion, and the properties of the fly ash or the deposits that form. In particular, detailed nitrogen and sulphur chemistry was investigated by combustion tests in a laboratory-scale facility. Oxidant staging, in order to reduce NO formation, turned out to work with similar effectiveness as for conventional air combustion. With regard to sulphur, a considerable increase in the SO2 concentration was found, as expected. However, the H2S concentration in the combustion atmosphere increased as well. Further results were achieved with a pilot-scale test facility, where acid dew points were measured and deposition probes were exposed to the combustion environment. Besides CO2 and water vapour, the flue gas contains impurities like sulphur species, nitrogen oxides, argon, nitrogen, and oxygen. The CO2 liquefaction is strongly affected by these impurities in terms of the auxiliary power requirement and the CO2 capture rate. Furthermore, the impurity of the liquefied CO2 is affected as well. Since the requirements on the liquid CO2 with regard to geological storage or enhanced oil recovery are currently undefined, the effects of possible flue gas treatment and the design of the liquefaction plant are studied over a wide range.

Thermodynamic and Economic Aspects of the Hard Coal Based Oxyfuel Cycle

The present study shows a new approach in modelling the hard coal fired Oxyfuel Cycle on the whole. The static process model comprises an Oxyfuel combustion principle applied to an existing state-of-the-art hard coal power plant located in Rostock, Germany. It includes the air separation unit and the flue gas liquefaction unit, which are modelled in detail. As one of the main advances to previous work, the closed simulation of all components in one model delivers a coherent solution with a significantly reduced number of assumptions. The model needs no interfaces between different stand alone simulation tools or manual iteration and transfer of internal variables. Results from a thermodynamic and economic feasibility study on this process are shown and areas relevant for future research are identified. The present study shows the feasibility and prospective key figures of the technology under realistic, comparable and reproducible assumptions and boundary conditions. The basic engineering of the process with a detailed study of the necessary gas separation and flue gas handling technologies is undertaken in the effort to a first stage optimisation of the process. The flowsheet tool Aspen Plus (TM) was used to simulate the overall process. This particular tool was chosen because it offers an advanced data library on chemical substances and allows the calculation of phase equilibria and real gas behaviour during air separation and flue gas liquefaction. Emissions, coal consumption and investment costs of the Oxyfuel power plant are compared to those of the original state-of-the-art hard coal power plant which is used as the reference case.

A Unified Control Scheme for Coal-Fired Power Plants with Integrated Post Combustion CO2 Capture

Abstract Within the DYNCAP project, a unified control scheme for coal-fired power plants with integrated CO 2 capture cycle is developed. For seamless integration into existing power plant technologies, the German technical guideline VDI3508 for conventional thermal power plants is taken as starting point. Interactions between steam cycle and post-combustion carbon dioxide capture cycle are identified and communication interfaces between its control units are defined. An according extension of VDI3508 is implemented on the computer using the library ClaRaCCS written in Modelica. By direct computer simulation the validity of the novel control scheme is demonstrated under transient operation of the power plant coupled to the carbon capture cycle. The simulation results are discussed and recommendations for further improvement of the scheme are given.

23 – Power plant integration methods for liquid absorbent-based post-combustion CO2 capture

When integrating a liquid absorbent-based post-combustion CO2 capture (PCC) plant into a coal-fired steam power plant, basic integration and heat integration have to be distinguished. Whereas the basic integration leads to a significant reduction of the net output of the power plant and thus a lower net efficiency, the heat integration leads to a reduction of the losses caused by the basic integration. Around two-thirds of the losses due to basic integration occur due to the heat duty for the reboiler of the desorber. The remaining third of the losses is due to auxiliary power for CO2 compression, for electrical consumers in the PCC plant and for additional cooling water pumps. To determine the loss due to the heat duty for the reboiler without using a complex steam power plant model, the Power Loss Factor (PLF) can be used. Its dependence on the specific heat duty of the reboiler, the original design intermediate pressure/low pressure (IP/LP) crossover pressure of the turbine, the original design condenser pressure of the turbine, and the reboiler temperature is shown in detail. The determination of the mentioned auxiliary powers is described accordingly. For heat integration, the power gain factor is defined. Its dependence on process values is shown exemplarily for the specific heat duty of the reboiler and the maximum temperature of the waste heat while the other influencing factors are kept constant. All studies are carried out for the integration of the capture plant into a new built power plant (greenfield) as well as a retrofit of an existing one. In the final section, the use of the power loss factor is demonstrated for capture plants using monoethanolamine (MEA) and piperazine based solutions.