The increasing interest in gasification technologies in general, and in the annual Gasification Technologies Conference in particular, as reported last year, is continuing. The most obvious indicator was attendance at the event, which increased from about 350 last year to some 500 this year. Someofthe increase may have been due to the fact that the conference was held in Washington, DC, rather than in San Francisco. But other factors driving up attendance include high oil and gas prices and the many gasification projects in China.

There have also been some recent encouraging developments in the USA. AEP (American Electric Power) is working on a 1000 MWe IGCC (integrated gasification combined cycle) plant (although no detailed timetable has been given), while Cinergy/PSI, GE and Bechtel have signed a letter of intent to study the feasibility of constructing an IGCC, possibly on the site of the Edwardsport coal plant, the first project under the new GE–Bechtel IGCC alliance. The USDoE is also continuing to support IGCC development, for example recently announcing a grant of $36 million to the 531 MWe Mesaba Energy Project to be constructed by Excelsior Energy and ConocoPhillips.

Drivers of growth

About 400 modern gasifiers are now operating in the world, corresponding to about 46 000 MWt. Half of this capacity is gasifying coal. It is expected that in the coming four years the total capacity will increase by about 25000 MWt. However, when it comes to applications, virtually all growth is in the chemical sector and there are still only four coal based IGCC plants in the power generation sector – a number that has not changed for nearly ten years.

In North America, in particular, the increase in the price of natural gas (about US$7/MMBtu compared with US$1.25/MMBtu for coal) is currently the main driver for coal gasification.

In the United States alone there are about 200 natural gas fired power stations with a total capacity of 120 GW that represent about 12% of the power production and 10% of the US gas consumption. The majority of these power stations have access to coal but the sites are often too small to store coal and to supply the additional space required for processing equipment. An additional problem when changing from NGCC (natural gas combined cycle) to IGCC is that the latter plants will also have to comply with the severe NOx spec of 3 ppm now required for NGCC plants.

The option of removing CO2 is also in the USA considered as attractive but the adoption of sequestering without any benefit, such as that deriving from enhanced recovery of oil, natural gas or methane from coal beds, is unlikely.

In Canada the most likely application would be replacing the natural gas used in steam reforming units for the production of hydrogen for upgrading tar sands, by gasification of tar sands residues. Gasification of these heavy residues has also potential for the co-production of power in such refineries.

Worldwide the production of synthesis gas and power from coal will benefit from the high prices of crude oil and natural gas. Naphtha, still often used as a feed for gasification in countries such as India for the production of hydrogen can in principle be replaced by coal.

Until recently the maxim was that whereas the prices of oil and gas were volatile that of coal hardly fluctuated because it was abundant, independent of OPEC, etc. This is still true for the coals that because of their poor quality do not lend themselves to transport over large distances and hence do not compete with internationally traded coals. Examples are most Indian coals, brown coal and lignite and coal rejects.

Prices for high grade eastern US hard coal, such as Pittsburgh No8, have increased in the last 18 months, from 26 US$/ton to US$ 63/ton, whereas the cost of PRB lignite remained virtually constant at 6-7 US$/ton in the same period. Similar trends apply worldwide. Prices of good internationally traded coals, with about 10% ash and an S content of about 1%, increased in price whereas the price of Victorian brown coal in Australia remained virtually constant.

Last year I reported on the lack of cross fertilisation amongst technologies. It was disturbing that this year it appeared that technology wise the situation had not changed and that a clear provincialism can be observed, depending on whether the project is located inside or outside the USA. Inside the USA, at the time of the conference, only the Texaco process (now owned by General Electric), comprising a coal–water slurry feed and a bricklined gasifier, had been considered, whereas outside the United States dry-coal-fed gasifiers with a membrane wall are mainly preferred.

However, the situation seems to be improving as shortly after the conference it was announced that Black & Veatch and Uhde have formed an alliance to “leverage Shell coal gasification technology” in the United States.

The rationale for adopting gasification in US power generation differs from that in other countries. In the USA the replacement of natural gas by coal and the reduction of mercury emissions play a predominant role, in addition to the other environmental advantages expected from gasification. In Europe and Australia environmental advantages and the option of isolating a concentrated CO2 steam for subsequent sequestering and a possible higher efficiency for the power station are the important considerations. In China and India, with their large coal but limited oil and gas reserves, the production of chemicals such as ammonia and methanol from coal rather than from naphtha are the main drivers.

Operating record

As far as coal gasification in IGCC power stations is concerned, the only plants that are currently operating are the 250 MWe Tampa Electric power station in Florida, which uses a Texaco gasifier, the 350 MWe Elcogas project in Puertollano in Spain, which uses the Krupp-Uhde Prenflo gasifier, and the 250 MWe Buggenum plant in the Netherlands, now owned by NUON, employing an SCGP (Shell Coal Gasification Process) gasifier. The latter shows by far the best performance, with an availability of about 90% in the period August 2003 to May 2004. In 2004 the unit returned to base load operation and it is expected that this will increase the availability. In relation to the availability of the unit it should be recognised that in many cases it is not only the gasifier that causes the non-availability but also the gas turbine and the air separation unit.

Looking at coal gasifiers in general (as opposed to those in IGCC plants) the best availability for a gasifier per se is obtained at the Eastman Kodak facility in Tennessee, where the gas is used for the production of chemicals. A figure of 98% is reported for this unit. However, this high availability is partly due to the fact that the unit has a spare gasifier.

In the field of coal gasification as a whole, Texaco and Shell are increasingly the dominant players. Shell now has 12 serious projects in China. All of them are for chemicals and apparently the claimed advantage of Texaco that a coal–water slurry feed facilitates the conversion of (part of) the CO into the hydrogen that is always required for these applications does not outweigh the advantage of the higher efficiency of a dry-coal-feed gasifier, as used in the Shell process. Shell is now confident that it can process coals with a high ash content, over 30%.

The Noell process, now owned by Future Energy, is of interest as it combines dry coal feeding with a top-fired gasifier with a membrane wall and a common outlet for slag and gas at the bottom resulting in a simple low cost gasifier. The main problem with its development is that it has mainly operated with lignite at a capacity of 130 MWt.

With GE becoming the owner of the Texaco gasification technology it is clear that change of ownership remains a characteristic feature of the gasification technology business. The only process that is still in the hands of the original developer is the Shell Coal Gasification Process. Could this have been a factor in the success they have had in China?

IGCC versus USC

In terms of efficiency there is as yet little difference between IGCC and ultrasupercritical (USC) technology. Both claim efficiencies of about 46-48% and although the scope for higher efficiencies is somewhat better for IGCC it should be realised that this will only become possible if a large part of the sensible heat in the gas leaving the gasifier becomes available for the subsequent gas turbine based (combined) cycle. This is possible with fuel gas treatment limited to hot gas filtering, but then flue gas recycle is required over the gas turbine for the removal of SO2 and, optionally, NOx and mercury. If flue gas recycle is applied the thermal NOx will be low but not enough is known about what happens with ammonia and HCN in the gas turbine combustor. It is therefore possible that as well as a de-SOX unit a de-NOX unit will also be required when applying flue gas treatment in the gasification context.

New technologies

As regards new developments in gasification technology itself there was little to report from the conference. IEC (Institut für nergieverfahrungstechnik und Chemieingenieurwesen) in Freiberg, Germany, is working on the PHTW process comprising a combination of the HTW fluidised bed process and a BGL type slagging gasifier. The idea is to convert the leachable ash from a fluidised bed gasifier, with a carbon content of 10-30%, in a slagging stage, to inert slag containing no carbon, implying a virtually 100% carbon conversion for the overall process.

Another new development, by British Oxygen, comprises oxygen production by a Pressure Swing Adsorption (PSA) process at 350 °C.

Although high on the gasification agenda the topic of carbon dioxide capture and sequestration is mostly politically driven. The only new successful project comprises

routing 9.5 MMscft/day of CO2 from the Dakota Gasification Company to the Weyburn Oil Fields in Canada for secondary recovering of oil. Such a project can also be economically attractive. However, as already noted, without such an additional benefit it is doubtful whether sequestering will really take off in such a way that it will contribute substantially to diminishing anthropogenic greenhouse gas production.

If any progress is made on processes that remove CO2 from flue gases in an economically attractive way this will be beneficial for both IGCC and power plants based on the Rankine cycle.


Prices quoted for coal based IGCC plants vary from 1000 to 1500 US$/kW. Apart from obvious ways to reduce costs such as making use of carbon copies, increasing plant size and manufacturing in low wage countries, non-utility financing was mentioned as a way to bring costs down. Realistic figures are probably 1200-1400 US$/kW for construction in most OECD countries and 100-150 US$/kW lower for China and India. The higher figures are on a par with figures given for USC power plants.

The process economics now benefit from the high price for sulphur of 50 US$/ton. Whether this figure may be used in future evaluations is doubtful, as more and more sulphur will become available from refineries.

IGCC on the up down under

In Australia there are now serious plans for an IGCC project. Rather than using export quality coals or run of mine hard coal that can fetch a good price on the international coal market, high ash rejects and brown coal are the preferred feedstocks considered for an IGCC.

Very popular in Australia is using the sensible heat in hot gas leaving the gasifier for drying coal in a co-current direct contact drier. A flow scheme for high moisture Victorian brown coal, as shown in the figure below, illustrates this principle, which was demonstrated by HRL at 10 MW scale in the late nineties (photo, right). The dried brown coal was gasified in an air blown fluidised bed gasifier having a temperature of about 950°C.

The same principle of using the sensible heat in the hot gas leaving the gasifier for drying can also be used for evaporating the water from reject slurries. The dried material will then be gasified in an oxygen blown entrained slagging gasifier. After passing a cyclone and a filter where the dried coal is separated from the gas stream, the gas can be directly routed to the gas turbine. This is an attractive option in Australia where there is less concern about SOx emissions due the low sulphur content of the available feedstocks. Moreover flue gas desulphurisation can always be added later as an end of pipe treatment.

Much the same holds for de-NOx processes. The syngas leaving the gasifier/drier can also be further cooled and subjected to conventional fuel gas treatment before being routed to the gas turbine. In the latter case the sulphur can be removed from the fuel gas and the gas can, after a CO-shift, etc, be used in synthesis reactions for the production of chemicals (methanol, ammonia, Fischer-Tropsch liquids) and for the production of hydrogen. Moreover CO2 can optionally be separated and sequestered.

The main advantage of the integrated drying is that no separate dryers are required and that no expensive syngas cooler (waste heat boiler) is required. In the case of brown coal dry lockhoppering of the feed is still required but in the case of rejects the feedstock can be introduced to the gasification system as a water slurry thus obviating the use of the more expensive lockhoppers.

There is very good work being done in Australia on ash and slag properties. Detailed studies are being done to characterise coal and slag performance in gasifiers such as understanding the impact on the efficiency of fluxes to reduce ash melting points.

Author’s note: Apart from huge coal reserves Australia has large uranium reserves. It is therefore striking that for political reasons even in long term energy scenarios no mention is made of the nuclear option. This is all the more remarkable as there is great concern about greenhouse gas emissions. The Australians seem to be making life more difficult for themselves by the exclusion of this option.