The conference was attended by about 200 people. This is only about 20% of that of its USA counterpart (the GTC event) but all major parties were represented and the smaller attendance has the advantage that it favours more in depth discussions.

Pierre Dechamps of the European Commission mentioned in his keynote speech that the EC expects power production to double in the period to 2030 and a large part has to come from coal. Further a large number of programmes on all aspects of power from coal including CO2 sequestration are now underway. This positive outlook for power from coal is somewhat at odds with the fact that there are currently only ten IGCC plants in full commercial operation (see table below), and only four are using coal as their primary fuel.

The conference title “Gasification – effective carbon control” is indicative of the fact that, certainly in the medium term, gasification has to be seen in conjunction with carbon (dioxide) storage. However, in practice there are hardly any projects including CO2 storage. Capture readiness is really the talk of the day. Politically this goes down pretty well and apart from minor adjustments to the plant design and reserving plot space nothing has to be done.

The safety of the transport lines is likely to emerge as one of the main objections against CO2 storage, particularly in industrialised areas, where this will be a major problem. For technological and economic reasons the CO2 pipelines will have a pressure of around 100 bar and the density of the medium will be about the same as that of water.

This implies that a rupture or leak will result in the blanketing of a large area with a suffocating gas with a density of 1.5 times that of air. The danger of CO2 became very clear with the lake Nyos disaster in Cameroon in 1986. To a lesser extent this problem has to be addressed when building a large scale gasification complex where the carbon monoxide is converted with steam into gas containing hydrogen and CO2. In such cases one has to ensure that the removed CO2 has sufficient buoyancy when leaving the stack.

Given this danger it is not surprising that Milton Catelin of the World Coal Institute mentioned in his keynote speech that he expected the legal and environmental issues associated with carbon capture would be more difficult to resolve than the technological challenges.

A major difference with previous conferences was that this time the emphasis was more on the economics of the process than on efficiency. This is illustrated by the fact that some gasification suppliers using a dry coal feed system try to eliminate the syngas cooler and go for water quench designs. Although one reason given for this move is that it is an elegant way of introducing the steam required for the CO shift, an important or possibly the most important reason is to reduce the overall capital cost of the plant. Syngas coolers are expensive and complex. This is the reason that they cannot be manufactured in low wage countries such as India and China and constitute a significant part of the equipment cost. However, water quenching results in a lower efficiency and this is not very desirable when stressing the importance of lowering CO2 emissions.

As far as capital costs are concerned there is an even more serious problem. The booming economy in many countries and the increase in gasification projects under construction and planned (mainly for chemical industry applications, and many of them in China) make it a seller’s market for gasification equipment. Shell mentioned that the costs of an IGCC plant without carbon capture had increased from 1600 US$/kW a few years ago to around 2500 US$/kW currently. Moreover RWE mentioned that the cost of carbon capture and storage is much higher than previously reported.

Nonetheless there remains a strong interest in gasification. Not so much for IGCC but mainly for the production of hydrogen for ammonia, methanol and coal to liquids (CTL) projects. This is in places where there is access to coal and either no natural gas at all or of no attractively priced natural gas.

For ammonia and hydrogen production all CO in the gas leaving the gasifier has to be shifted. This implies that all the carbon in the gas leaving the gasifier is converted into CO2. For methanol, Fischer-Tropsch and SNG synthesis only part of the CO has to be shifted and the remainder is incorporated in the products. All these plants are very suitable for carbon capture without an efficiency penalty.

Coal gasification for power and/or heat generation is different. Without removing CO2 from the fuel gas high efficiencies are possible, 48% LHV basis, with currently available equipment. For IGCC projects CO2 capture from the fuel gas comprises both an economic and an efficiency penalty because of the CO shift. For dry coal feed entrained gasifiers the heating value of the gas consisting of about two-thirds CO drops by 10% corresponding to an efficiency penalty for the power station of about 5%. Moreover the CO2 removal per se and the compression consume an additional energy penalty of 4-5 %. The total energy penalty is therefore 9-10%, resulting in a net efficiency of below 40%. It is not clear whether this loss is included in the cost of CO2 removal of US$ 20/ton.

The energy penalty of the CO shift can be avoided by removing the CO2 from the flue gas instead of from the fuel gas. In case of an IGCC this implies that flue gas recycle over the gas turbine becomes mandatory as otherwise the concentrations of the gases to be removed are prohibitively low and the amount of flue gas to be treated is correspondingly higher (as I have previously argued in MPS). At the conference flue gas treatment got hardly any attention from the presenters. The exception was KBR, which is working on an amine based process for removing CO2 from flue gas.

Another way to avoid the disadvantage of the CO shift for power generation would be to use the hydrogen in fuel cells that then have to have at least a 10% higher efficiency than the alternative of a combined cycle.

One of the advantages of an IGCC is that such a power station is a modest fresh water consumer as most power is generated in the gas cycle. CO shifting has the disadvantage that it results in appreciably higher water consumption. With fresh water becoming a scarce resource in places this may affect the choice of location of GTL projects.

Notable among current proposals for IGCC plants discussed at the conference is the Magnum project in the Netherlands. This comprises a 1200 MWe power station where 750 MWe is generated in a coal fired base load IGCC with three gasifiers and the remainder with natural gas. One of the purposes of the Magnum project is to replace older assets. The unit will be built carbon capture ready. The final decision to go ahead with the project will be made in the fourth quarter of 2007.

It was mentioned that, compared with the Buggenum plant, there will be less integration between the ASU and the gasifier and that the whole system will be built for a lower pressure drop over the gasifier plus gas treating train. Assuming carbon capture is installed the most likely storage place for the resulting CO2 will be a depleted gas field or a gas field that is suitable for enhanced natural gas recovery.

Early in 2006 RWE also announced plans to build a 450 MWe commercial IGCC Rhenish brown coal based power plant with carbon capture to be completed in 2014, and this was also the subject of a paper at the conference.

RWE mentioned that carbon capture is the most important critical path element in their designs. Costs for carbon capture were reported as being very sensitive to economies of scale.

The RWE plant will have a net efficiency of 40% basis LHV. This is the same efficiency as claimed for the HRL process for IGCC power generation based on Victorian brown coal in Australia. RWE is proposing to use lignite drying (WTA process) of which no details were divulged.

Gasifiers being considered for the RWE project are the dry coal feed type: Shell SCGP; Siemens GSP (now called SFG); and the HTW (High Temperature Winkler) process. The latter fluid bed process is reportedly only suitable for brown coal.

Siemens and Shell, both represented in the conference programme, are now proposing combinations of a water quench and a syngas cooler, but Siemens, unlike Shell, first quenches with water from 1500 to 900ºC in order to render the slag entrained in the gas non-sticky and then uses the sensible heat remaining in the gas for raising steam. Siemens considers 1000 ton coal/day as the current maximum size for their gasifier and also mentioned a new apparatus for measuring the viscosity of liquid slags up to 1500 ºC.

One of Siemens’ first gasification projects is at Shenhua Ningxia Coal industry Group Co Ltd (SNCG) in China comprising five gasifiers with a thermal capacity of 500 MW each. The main product of the complex will be 500 000 tons per year of polypropylene.

Shell has many projects in China but, like Siemens, none announced so far are for power generation. Most of them are in fact aimed at making coal the feedstock for ammonia plants.

Shell, which now offers plants with a maximum capacity of 2700 tons coal/day, stresses the importance of a water quench for which they developed special water nozzles that spray in a large vessel. Apparently they offer both a complete water quench and one where they adhere to their conventional gas quench followed by a water quench when the gas has been gas cooled to 900 ºC. Water quenching offers its main advantages where a complete CO shift is required, as for hydrogen and ammonia production.

Sasol Lurgi Technology Company (SLTC) offerings, also outlined at the conference, cover a wide spectrum of processes in the field of (synthesis) gas to liquids (GTL) and synthetic natural gas (SNG). Their main experience base is of course the Sasol GTL plants in South Africa and the SNG plant in North Dakota.

For SNG in particular, the Lurgi dry ash gasifier has the big advantage that the gas already contains a fair percentage of methane, about 15 mole%. Moreover the oxygen consumption is the lowest of all gasifiers. Disadvantages remain the extensive tar and liquor formation. Moreover the gas leaving the gasifier needs partial CO-shifting before it can be used for Fischer-Tropsch or SNG synthesis.

The most efficient process for making SNG from coal is the British Gas Lurgi (BGL) slagging gasifier that produces far less tar and liquor. Advantica presented a paper on the HICOM process, which comprises a BGL gasifier and a single process for converting a CO containing gas into methane with an overall efficiency of 70% HHV basis, which is 10% more efficient than using a dry coal feed entrained gasifier.

Together with Uhde, Exxon/Mobil presented information about some new developments in the methanol-to-gasoline (MTG) field. One is a fluid bed version of the reactor resulting in better temperature control.

The first commercial MTG unit in New Zealand was shut down in the mid-nineties due to the low price of conventional gasoline! Currently a new 100 000 ton/year MTG plant is being constructed at the Shanxi Jincheng Anthracite Coal Mining Company in China, to start operation late 2008. The MTG process is the only CTL process that produces a good quality gasoline with a high selectivity.

Only one paper, that by Clean Energy Systems, Inc, was on the subject of oxy-fuel. Combustion with oxygen in the gas turbine of an IGCC results in a flue gas that after condensing out the water consists essentially of CO2 and some SO2 and NOx. It would be ideal if all these acid gases could be sequestered as a mix thus obviating the need for deSOx and deNOx.

An interesting development is that Stamet, manufacturer of an elegant rotating solids pump, who were on the original programme but whose paper was withdrawn, has been bought by GE. This is somewhat surprising as GE for some years has been owner of the Texaco gasification technology, which uses coal-water slurry feed. Is GE becoming convinced that dry coal feeding is more efficient than their present low temperature slurry fed gasifiers? An alternative reason, to deny this technology to other dry coal feed processes such as those of Shell and Siemens, is unlikely as the Stamet development was DOE sponsored and therefore the technology should be in the public domain.

MAN Turbo of Switzerland gave a fine presentation on their compressor portfolio. Compressors are important in both ASUs and for CO2 compression. Apart from the very large compressor in the gas turbine these are the major parasitic energy consumers in an IGCC.

Various papers (eg, those by Foster Wheeler Italiana and IEA) proposed that the hydrogen produced in IGCC plants could be stored for ironing out erratic power demand shifts, a problem that will be exacerbated when more wind and solar power is produced. The hydrogen could be stored in depleted natural gas fields. In relation to hydrogen it was encouraging that GE mentioned they can now fire gases with up to 90% hydrogen in their turbines.

How to be GHG neutral

As with so many of these conferences, the only greenhouse gas mentioned was CO2. Not a word about methane that has a greenhouse gas effect that is per molecule 20-25 times worse than CO2. The ventilation gas from deep coal mines contains typically 0.5 mole% methane and therefore has per unit volume the same greenhouse gas effect as the flue gas from a natural gas fired power station using a Rankine cycle. Employing ventilation mine gas as combustion air for a power station not only makes use of the heat of combustion of the mine gas but contributes substantially to reducing greenhouse gas emissions.

A coal fired IGCC would, when using ventilation mine gas as combustion air in the gas turbine, be greenhouse gas neutral! There is even a bonus because of the methane combustion.

The problem is that such an IGCC would need to be located at the mine site. For IGCCs in countries with deep coal reserves this should not be a problem as power transmission, at least over land, is cheaper than transporting coal. Perhaps the greenhouse-gas-neutral IGCC would be a suitable topic for IChemE’s next gasification conference.