Siemens sees a future for IGCC – and now it has the technology1 October 2007
About 18 months ago Siemens became a key player in the gasification business through its acquisition of Freiberg based Future Energy (from Sustec)?and its GSP entrained flow technology, now called SFG (Siemens Fuel Gasification). Developed at Schwarze Pumpe in Eastern Germany over many years, a particular attraction of the process is its ability to use low rank fuels such as lignite, with a robust gasifier wall concept – a "cooling screen" (or cooled wall) – that avoids the use of troublesome refractories.
In power generation, using coal as fuel can have major advantages. In particular countries with indigenous coal reserves and a high dependency on fuel imports such as oil and gas can reduce this dependency by shifting to coal. Many countries have substantial coal reserves and coal will remain plentiful for years to come. Also, compared with oil and gas, most coal reserves are much cheaper to develop, and coal markets offer far greater price stability. Therefore, coal-fired power generation has gained renewed interest recently.
Coal-fired power plants currently account for 40% of electricity produced worldwide. In countries with large and cheaply exploited coal reserves, the share is even much higher. In China, coal power plants produce over 80% of the total electricity, in India about 66%, in the United States almost 50%. But many European countries also rely on coal-fired power generation, for example, in Germany around 47% of the total electricity is produced from coal while in Poland the share is as much as 92% or even more.
Demand for new power plants is soaring. Growing electricity consumption, especially in developing countries like China, India and other Asian countries, leads to a push for additional generating capacity, while at the same time many ageing plants have reached an operating lifetime of 30 to 40 years and need to be replaced. Electricity consumption is expected to almost double over the next 20 years. It is most likely that by 2020 more than three quarters of world electricity will be generated in fossil fired plants. And among the fossil fuels, coal will certainly dominate in the power generation sector.
The major drawback of coal is however the higher emissions of CO2 and other air pollutants compared with gas fired generation. The specific carbon emissions from coal are nearly twice as high as natural gas. Therefore, coal fired power plants are responsible for more carbon emissions than any other type of power plant. And that is where the potential for CO2 reduction in power generation technology is the greatest.
CO2 as a driver for IGCC
For carbon capture in modern coal fired power plants, three technologies are under development: IGCC (integrated gasification combined cycle) with pre-combustion capture; steam turbine power plants with post-combustion capture; and "oxyfuel" plants incorporating combustion in pure oxygen, with subsequent CO2 capture. At this point, it is not known which of these three methods will prevail. However we see major potential for the IGCC process – particularly when efficiency is considered. In the longer term, IGCC plants with CO2 capture should be able to achieve an efficiency of around 43%.
The simplest concept is post-combustion capture, in which CO2 is separated from the flue gas of a conventional steam turbine power station by means of scrubbing. The drawback here is that, since nitrogen from the combustion air is diluted in the flue gas at atmospheric pressure, a large gas stream has to be processed with low CO2 concentration.
In the oxyfuel concept, because the coal is burnt with pure oxygen, the flue gas mainly consists of CO2 and water. The CO2 is separated by removal of the water using "simple" cooling and condensation processes.
In IGCC, the carbon content is separated from syngas as CO2 before combustion. To achieve this the CO component of the syngas is converted as completely as possible into CO2, which is then separated out by an additional unit. The remaining syngas, mainly consisting of hydrogen, is used in the gas turbine of a combined cycle power plant. Compared with post-combustion capture, the smaller gas volume at high pressure and the much higher CO2 concentration enables smaller, more efficient scrubbing units to be used. The process steps needed for CO2 capture are well established commercially in the gas processing industry.
IGCC with capture
An IGCC power plant incorporates a gasifier operating at high pressure and producing raw gas which is cleaned of most pollutants and burned in the combustion chamber of the gas turbine for power generation. The sensible heat of the raw gas and hot exhaust gas from the turbine are used to generate steam, which is also used for power generation in the steam turbine (see Figure 1).
The gasification processes which are preferred today for IGCC applications are oxygen blown systems where oxygen is used as the gasification agent. As part of the concept, an air separation unit (ASU) is used to produce oxygen from ambient air. The ASU also co-produces nitrogen, which can be used for diluting the syngas prior to combustion in the gas turbine. The process air supply for the ASU can be supplied with a separate air compressor and/or extracted from the gas turbine compressor.
The raw gas generated in the gasifier has to be cleaned of trace contaminants such as dust and sulphur to meet emission requirements and the limitations set by the fuel quality requirements of the gas turbine.
For IGCC plant concepts with pre-combustion CO2 capture, an additional process step, the so-called CO shift conversion, is included as a part of the syngas treatment chain. In this additional step, CO is converted with H2O (steam) to CO2 and H2. The CO2 is then removed, leaving the remaining gas stream with a higher hydrogen content than syngas without CO2 capture.
Siemens Fuel Gasification technology
In 2006, Siemens Power Generation Group acquired the GSP* entrained flow gasifier technology from Sustec (via the purchase of Future Energy).
The technology is equally suitable for both IGCC and industrial applications. It has been renamed Siemens Fuel Gasification (SFG) technology. The standard reactor size is currently 500 MWt, with the first plant scheduled for commissioning in China in early 2009 (for production of chemicals from coal).
The SFG entrained-flow gasifier is based on technology developed in the 1980s in Eastern Germany specifically for saliferous lignite (Figure 2). Because of the low rank of lignite and the high salt content in the ash of this coal the process placed special requirements on the feeding system and on the gasifier itself. A commercial scale (200 MW input) gasifier was installed at Schwarze Pumpe, Germany, in 1984 and operated successfully on lignite for several years. Since then, improvements have been made to the technology to allow the gasifier to operate with a wide range of fuels.
The feedstock together with oxygen and steam is supplied via a specially designed burner located on top of the reactor (see Figure 3). Conversion takes place in a homogeneous flame reaction. The oxygen-to-fuel ratio is trimmed to keep the gasification temperature at a level at which the inorganic matter melts, flows vertically downward in parallel with the gasification gas and leaves the gasifier through a special discharge unit. Carbon conversion rates of over 99% are achieved.
A distinctive feature of the gasifier is that it is not lined with refractory but equipped with what is called a "cooling screen", or cooled wall (Figure 4). This consists of a spiral-wound coil embedded in compacted SiC. A layer of solidified slag builds up on the surface of the SiC, providing protection against the high reaction temperatures, which are in the range 1300 to 1800°C. The liquid slag from the reaction phase only comes into contact with the solidified slag layer, and hence no corrosion of the reactor wall takes place. The cooling screen concept means the gasifier can operate for long periods before requiring repair or relining. The industrial scale installation at Schwarze Pumpe has amassed more than 20 years of proven experience with this technology.
The cooling screen is insensitive to high ash content (ie, inorganic residues) or fluctuating ash composition, in contrast to conventional refractory linings commonly used in gasifiers.
The SFG reactor design requires the gasification feedstock to have an ash content of at least 1-2% by weight to allow the solidified slag layer to constantly regenerate. This is the case for most coals, but may not be feasible with petroleum coke feedstock. If low ash fuels are to be used with the cooling screen system they need to be mixed with ash-rich coal or fluxing agents.
With no refractory to heat up, the SFG gasifier can be started or shut down within minutes. A cold start can be completed in less than two hours.
After the reaction chamber, raw gas and slag discharge into a quench section arranged beneath the reaction chamber. By injection of water the gas is cooled to moderate levels and the molten slag solidifies in the water bath. The vitrified slag granulates, accumulates in the water-filled quench bottoms and discharges via a lock hopper, while the raw gas is passed to mechanical cleaning stages.
Water quenching is a simple and cost-effective way of reducing the gas temperature to around 200-230°C, which is required for the subsequent treatment stages. Also, for applications which require a CO shift, such as IGCC with carbon capture and most chemical syntheses, it provides the large amounts of water that the syngas needs to contain.
In the CO shift reactor, the shift reaction, CO + H2O D CO2 + H2, requires there to be more water vapour in the syngas than it contains immediately following the gasification reaction. By water quenching the gas coming from the gasification chamber, the necessary amount of water can be added while at the same time the required cooling of the syngas is done in a simple and reliable way. Thanks to the quantity of moisture introduced in the quench section, no auxiliary steam injection is needed for the shift reaction.
For solid fuels, dry feeding is used, based on a pneumatic dense-phase feeding system. Pulverised solid feedstock is first supplied into lock hoppers and pressurised to gasifier operating pressure. From there, it passes into a feeder vessel and subsequently into the gasifier, at controlled rates. The pulverised fuel flow is controlled by the pressure difference between feeder vessel and gasification reactor.
Dry fed systems generally have higher cold gas efficiencies (the ratio of the heating value of the product syngas to the heating value of the feedstock) than slurry fed systems, since no extra fuel has to be combusted to heat and evaporate the slurry water to process conditions. Hence, dry fed gasifiers also require less oxygen, about 20% less. Dry fed systems allow the use of low-rank fuels with high ash and/or high moisture content. Slurry feeding is less suitable for such fuels since the ratio of water/inerts to carbon is not conducive to obtaining the high temperatures required for gasification. Dry-feeding does have a drawback, however: the feed system is more complex.
During the last year, we have embarked on an extensive R&D programme focusing on the availability, reliability, and competitiveness of the SFG process. Improvements are currently being implemented in coal feeding, burner design, and instrumentation and control.
Improving plant performance and competitiveness are key goals in the development of the next generation of IGCC plants. Siemens' gasification R&D goals include better matching of the gasifier section with downstream processes to maximise efficiency while maintaining high reliability. This has led to two key R&D projects: scaling up the gasifier to match downstream process units; and maximising efficiency and heat recovery.
Up-scaling the gasifier helps to optimise overall plant performance, in both IGCC and chemical applications. For IGCC, an optimised plant concept is a "one gasifier per single shaft power train" configuration. Gasifier size would match the fuel input required by the gas turbine, taking into account variations in feedstock characteristics, and syngas treatment for CO2 capture. Larger gasifier sizes are also required in chemical applications, so that economies-of-scale can be achieved.
Maximum efficiency is one of the key requirements, especially for IGCC (but also for other applications). Therefore, optimal integration (notably in terms of heat recovery and utilisation) between gasifier island and combined cycle is of key importance and a major focus of our R&D. We are currently working with industrial and academic partners to develop a gasifier with partial quench and combined heat recovery boiler.
The proposed design combines the quench section with a high temperature heat exchanger. First, raw gas and slag coming from the gasification chamber are quenched by water injection to temperatures below the ash melting point, typically around 700-900°C. This ensures that the slag solidifies and can be discharged easily at the bottom of the quench chamber.
The heat recovered from the hot raw gas is used to produce high pressure steam which can be supplied to the steam turbine of the combined cycle power plant. An increase of around 1.5 percentage points in overall efficiency is envisaged for a complete IGCC plant.
Integrated plant concepts
Adjusting mass and heat flows in an IGCC system offers further potential to optimise overall plant efficiency and economics. In particular, integration of the air separation unit and gas turbine offers advantages with regard to auxiliary power consumption, gas turbine performance and ASU design (see Figure 5). Integration can be done in two ways. First, by providing part or all of the air required by extracting it from the gas turbine compressor instead of the internal ASU compressor (air-side integration). Second, by taking part of the nitrogen, which may be used for dilution of the syngas before it enters the gas turbine, from the ASU. Nitrogen dilution helps reduce gas turbine flame temperature (and hence NOx emissions) and flame speed.
Options range from full integration (all air is compressed in the gas turbine, thus the ASU needs to run at higher pressure levels than usually required, and nitrogen can be easily recovered for dilution) to zero integration (all air is compressed in the ASU at a lower pressure level, and little or no nitrogen needs to be pressurised for dilution). Investigations have shown that in the case of full integration the savings in auxiliary power on the one hand and the increased power needed for higher pressure levels in the ASU on the other hand tend to even out. There is also a loss of operational flexibility with this configuration.
Another promising concept is humidification of the syngas in a saturator, which increases the mass flow and partial water pressure of the fuel gas going into the turbine, and hence the net power extractable from the turbine and the net efficiency of the plant. However, there is a trade-off in operating the saturator. For a syngas water content of up to about 10% (by mass), low-temperature heat (about 150-200°C) can be used. For higher partial water pressures, steam with higher temperature and pressure levels must be used, which is therefore not available for use in the steam turbine of the combined cycle and can lead to a decrease in overall efficiency. Thus gas conditioning in an IGCC needs very careful optimisation.
The SFG technology is ideally suited for coal fuelled IGCC power plants with integrated CO2 capture, especially for low-rank fuels such as lignite with high ash and moisture content.
During the last year, SFG has been ordered or pre-selected for a number of projects in China, North America, and other countries. The first gasifiers will be used in coal-to-chemicals and synthetic fuels applications and will start operation in 2009 and 2010, using a wide range of coals, from Chinese anthracite to Illinois bituminous coals. The experience gained will provide a strong experience base for future IGCC plants.
The authors can be contacted at Siemens Fuel Gasification Technology, Halsbruecker Str 34, 09599 Freiberg, Germany. email@example.com