(IGCC) Integrated Gasification Combined Cycle for Carbon Capture & Storage

IGCC plus CCS – an Objective Analysis

By F.Starr : Claverton Group Conference Paper – October 20081. Introduction

IGCC Based Power Plants for Carbon Capture and Storage


F.Starr PhD. FIMMM. C.Eng 

A Claverton Group Paper: 11th February 2009




This paper endeavours to give an objective account of the background to gasification based processes for power generation with carbon capture. Such processes are a development of IGCC plant designs in which coal or heavy fuel oil is first gasified to produce a fuel gas for  a CCGT unit. Although the IGCC concept does lend itself, very well, to high levels of carbon capture, and could lead the way to the hydrogen economy, it does create some important technical challenges. In particular, it restricts the type of gasifier that can be used to the high temperature entrained flow type. Furthermore, because the fuel gas that is produced in an IGCC consists of over 90% hydrogen, this will reduce the efficiency of the plant. Given that the hydrogen economy is some decades away, a more reasonable gasification-type option would be to produce natural gas from coal. This substitute natural gas could be used as a fuel gas in standard gas turbines (with no efficiency penalty) and can be used to supplement the UK and EU fast declining reserves of natural gas. The main drawback is that only about half as much carbon would be captured as in the IGCC “clean coal” systems currently being envisaged.       



1. Introduction

2. The UK Background to Carbon Capture    

3. Which Gasification Process for CCS ?

4. Recent Efforts on IGCC plus CCS

5. Entrained Flow Gasification Processes

6. IGCC-Hydrogen-CCS

6.1 Process Conditions    

6.2 Efficiency Considerations

6.3 Fuel Aspects Including Biomass and Waste

7. Impact of Wind and Solar Renewables on IGCC Operation 

8. Development of the Hydrogen Economy

9. IGCCs Producing Substitute Natural Gas with CCS

10. Comparison of IGCC Based Options

11. Conclusions

1. Introduction 

This paper is based on one that was posted last year on the Claverton website. Although the author has reservations about carbon capture, these are mainly based on the fact that in Europe it will lead to a significant increase in the amount of coal that must be imported, compared to that needed for non-capture plants. One estimate suggests that depending on the type of plant, the amount of coal required will be between 14 and 24% extra [1]. In this respect, it is not generally recognised that Europe only produces about 300 million tonnes as hard coal equivalent, and has to import another 150 million tonnes for its  electricity generation and CHP plants. Although coal use in Europe, in the mid term is expected to increase, the output from mines and opencast sites, in the EU, of coal and lignite, will continue to decline. The main coal exporter in the EU is Poland, where output is now past its peak

The situation is particularly critical in the UK where coal production is now less than 20 million tonnes, and where we have to import almost 40 million tonnes a year. Carbon capture will add another ten million tonnes. There really is no alternative to continuing and massive coal imports.   The occasional reopening of a UK coal mine, although important to the local economy, does not presage the resurrection of the UK coal industry, however excited journalists want to get. The UK is  a long way from its post war peak of 220 million tonnes, or even the pre-Thatcher output of 125 million tonnes. But this effort to reduce our emissions this will only result in the UK having reduced the global anthropogenic release of CO2 by less than 0.5%. Accordingly, if carbon capture is to be implemented, it should be first done  in those countries in which coal is mined and used. For example, India, China, the USA, Australia and South Africa. 

2. The UK Background to Carbon Capture     

The British Government has recently indicated that it will only support “post combustion capture” schemes for the removal of CO2 from the flue gases of new-build power plant. Essentially the plant would be of the conventional type, in which coal is burnt in a boiler to produce steam, which is used to drive a steam turbine. In post combustion capture generating plants,  the idea is that just before the flue gases, from the combustion process, are vented up the stack, the CO2 is removed by washing the gases with an alkaline solution, in this case MEA.

The advantage of such a post combustion scheme is that the plant can be built, “capture ready”. That is it will be put into operation before the CO2 pipeline and underground storage reservoir is available for use. Furthermore, the plant, in this capture ready condition, can be operated as a normal power plant. The drawbacks of this apparently easy option is that the flue gases are ambient pressure, the CO2 concentration is low, and the treatment of the flue gas to remove the sulphur oxides has to be done to a high level. 

Cynics would say that once built, the plant will be run as a none-clean coal plant for evermore. If the Government were truly committed to carbon capture, it would insist that a pipeline should be built, from the plant, to a location somewhere on the North Sea coast, at the same time as the power plant is being constructed. This is because, it is often extremely difficult to get permission from land owners and local authorities to lay new pipelines, especially when the environmental groups are of the opinion that the fluid being transported is toxic. It will be another excuse to do nothing.     

The competition to coal fired steam plants comes from those of the “pre-combustion type”. Here a fuel gas is produced by a gasification process, which is then treated or modified to remove all the carbon containing gases it contains, before the gas is burnt. In practice, this results in a fuel gas that contains over 90% hydrogen. The same process steps result in the carbon in the coal forming carbon dioxide. Since the gas mixture is at high pressure and the CO2 is at a high concentration, this gas can easily be removed, being washed out of the hydrogen rich fuel gas using various solvents. In one such concept the solvent used was MDEA [2]. The fuel gas would then be burnt in a CCGT (Combined Cycle Gas Turbine) to produce electricity.

An important feature of this type of plant is that a very high level of carbon capture can be achieved, providing that the gasifier is of the right type, and a highly active solvent is used. In practice it is usual to aim at 90% carbon capture, which compares favourably with the 85% level of conventional steam plant equipped with a CO2 removal system.      

It is claimed by some that IGCC plus CCS, that is Integrated Gasifier Combined Cycle plus Carbon Capture and Storage is more of an unknown than a conventional power plant plus CCS. This is not really correct. However, he writer has some sympathy with the UK Government’s position. One particular, concern of the author’s, is that a number of these schemes, like the European Hypogen and American Futuregen, have become tied in with the search for a quick route to the Hydrogen Economy. Realistically, the large scale use of hydrogen for transport is something which is decades away, although there are niche uses for hydrogen in petrochemical complexes around Teesside or Rotterdam.  Unfortunately, the Government, by more or less dismissing precombustion processes out of hand, has closed itself off to what is possibly a much better approach, and one which fits in with energy use in the UK. This more realistic approach involves producing natural gas as well as electricity and is discussed in Section 9 of this paper.

3.  Which Gasification Process for CCS ?

The remit given in writing this paper for the Claverton Group was to give some background on the use of coal based gasification processes for power production and carbon sequestration. But where does one start? The gasification of coal, by heating coal so that it emits hydrogen and methane, leaving a substantial mass of coke behind, goes back to 1820. Indeed this form of gas production was the world’s first energy conversion process. Later on, vertical retorts came into use, where steam and air was used help gasify all the coal rather than a small fraction. 

The disadvantage of these processes is that the gas produced was at ambient pressure. Hence in the 1930s a high pressure gasifier was developed in Germany by the Lurgi company. Two such plants were operated in Britain, but one of the main disadvantages is that they could only operate on highly reactive coals, typically of the lignite type.

During the 1970’s there was new burst of activity. Many of the new processes were aimed at producing a clean fuel gas at high pressure that could be burnt in gas turbines, these being part of a combined cycle. Hence the term IGCC came into being. With the ending of the seventies energy crisis, interest waned. Nevertheless, a simpler variation, using the crud, or “bottom of the barrel” oil was used on many refineries to produce hydrogen for hydrocracking and hydroforming.          

Most of these gasifiers, although perfectly suitable for a straight forward IGCC are not really suited for capturing carbon, unless complex purification equipment was added. Typical drawbacks are that:  

  • They are air blown so that the raw gas contains a high level of nitrogen reducing cold gas efficiency
  • The methane content of the gas is high. This has to be reduced to around 1% if a high carbon capture rate is to be achieved
  • They work at such low temperatures that much of the coal does not react and has to be burned, requiring another CO2 capture system

These issues are fully explained in an EU report by Starr, Tzimas and Peteves and in a presentation by Cormos et al [3, 2]. Here it needs to be emphasised that IGCC is a complex process, even when the type of gasifier being used is “ideal”. If the gasifier is one in which in which extra processing steps are required to reduce the levels of methane or nitrogen to acceptable levels, this will inevitably add to the already high capital costs. And clearly, if the gasifier is one which only partially gasifies the coal, leaving a significant amount to be burnt in a boiler, this does defeat the main objective of the gasification route.

The argument that is sometimes put forward, which is that a lower level of capture could be accepted (from gasifiers producing methane), has little to commend it. One of the main arguments for accepting the complexity and unfamiliar technology of IGCC (at least to power plant engineers, who know how to boil water and not much else), is that gasification processes are much better at capturing carbon than steam plants.      

For effective carbon capture what is required are processes which gasify all of the coal in one step, so that nothing solid is left except an ash or slag. That is the combustible matter in the coal is used to produce a fuel gas. A vital secondary requirement is that the “raw gas” should contain a maximum of hydrogen, carbon monoxide and a minimum of methane, carbon dioxide and nitrogen. The issue about low carbon dioxide, may seem strange, but if it is at a high level (over 20%) at this initial stage, it implies that the fuel gas from the gasifier will be of poor quality.     

Although giving some background to gasification processes, I want to focus on the issue of how well gasification could fit into the UK and European energy systems, and, if this was to be done, whether it would bring CCS closer.

4. Recent Efforts on IGCC plus CCS

IGCC plus CCS has received support from both Europe and the USA, under the Futuregen, Hypogen and Dynamis Programmes and Projects, as plants such as these  can produce hydrogen from coal, with the hydrogen then being burnt in a CCGT. In principle, the hydrogen can be distributed to the consumer via long distance high pressure pipelines. In this way the IGCC-CCS is expected to “kick start” the hydrogen economy. The difficulty is, of course, that there are few users of hydrogen, and until this market grows, there is little incentive to build plants or to construct long distance hydrogen pipelines.

There is a somewhat naive belief that it will be possible to convert the existing natural gas network, gas cookers, gas fires, and central heating systems over to hydrogen. This can be done, but one feels that the proponents of this idea have no experience of the cost and disruption of such a “conversion” programme.  The conversion programme, in switching over the UK from towns gas to natural gas, took about four years, and over one billion pounds at 1970’s prices. So we could be looking at about 10 billion pounds if we went through the same conversion saga today.  

Some of the main supporters of the hydrogen economy have been the fuel cell protagonists.  But in many types of fuel cell, the gas has to be highly pure. In PEM fuel cells the required levels of carbon monoxide should be less than 10 ppm, and ideally less than 1 ppm in the delivered hydrogen. Given that the raw gas coming from a typical gasifier will contain 600,000 ppm (i.e. 60% by volume), it has major implications on plant costs. Since there are very few fuel cells units operating commercially, in the author’s view, a more realistic level for carbon monoxide would be at the 2%, when it could be burnt without problems in conventional car engines 

5. Entrained Flow Gasification Processes

There are about 90 commercial gasifiers in operation. As noted, most run on heavy oil, and are intended to produce a gas for subsequent processing to produce hydrogen for hydrofining, ammonia synthesis or methanol production. Apparently about 10% World’s ammonia used for fertiliser producution is derived from coal.  In contrast there are only a few gasifiers used in an IGCC for electricity production. These are effectively large prototype or demonstrator installations. However almost any type of gasifier can be employed for this purpose. Most of the coal based gasifiers, for the production of hydrogen, and hydrogen containing feedstocks for the manufacture of chemicals are of the entrained flow type. In these a stream of coal particles is reacted with oxygen in the 1400-1600°C range. This is the best type, if a high level of CO2 is to be captured.

The feeding in of particles of coal into a pressure vessel operating at 30-70 bar pressure and at 1600°C can be best described as “tricky”. In the GE system, (formerly developed by Texaco), the coal is slurried with water, which simplifies the injection of the fuel. Gasifier efficiency is lower than its competitors since it is necessary to burn fuel to evaporate the water. The advantage is that the capital cost is relatively low.  The entrained flow gasifiers that directly compete with that of GE are built by the Dutch company Shell and the German company Siemens. Here the coal is entrained into the gasifier using high pressure nitrogen rather than water.

In all of the entrained flow gasifiers the coal particles pass through an oxy-fuel burner. See Fig 1.  However, the quantity of oxygen is insufficient to completely burn the coal, so the resulting gas has a high level of carbon monoxide, with lesser amounts of hydrogen and carbon dioxide. The hydrogen partly comes from the hydrogen in the coal (coal “compound” has very roughly the composition of C1H1), but the injection of steam or water also provides a hydrogen source.

Strangely enough, the product that is not wanted at this stage is carbon dioxide. A high level of this gas reduces the proportion of carbon monoxide which can be formed. And, as will be shown, at a later stage in the process  the carbon monoxide is used to generate more hydrogen.

An important feature of gasification is the removal of droplets of molten slag, which are carried along by gas stream, after the coal has reacted with the oxygen. In the GE and Siemens designs water is sprayed in the base of the gasifier to quench the gas. The solidified slag is then carried out of the gasifier along with the “quench” water. The Shell gasifier has an arrangement by which much of slag drains out of the gasifier into a quench water bath. But to remove white-hot dust from the gas stream in the Shell process, cool “recycled” gas is mixed with that coming from the gasifier. This reduces the temperature of the dust to below the sintering point. The dust can then be removed using a combination of cyclone plus a filtration system…



Fig 1:  Schematic of Entrained Flow Gasifier with Water Quench for the Slag

Because the temperature is so high, the gas emerging from the gasifier contains a large proportion of carbon monoxide, with lesser amounts of hydrogen, carbon dioxide and superheated steam. The main gaseous impurity is hydrogen sulphide.

In a conventional IGCC, once the fuel gas has been cooled to room temperature, and the steam condensed out, the gas is directly burnt in the gas turbine of a CCGT, providing that the H2S is first removed using a liquid solvent. The H2S is released from the solvent at ambient pressure, and then burnt with air in a Claus kiln, to produce pure sulphur, which drains away as a liquid. The fuel gas going to the gas turbines contains about 60% carbon monoxide, with about 30% hydrogen. There is obviously no carbon capture.

To maximise efficiency, the boilers and heat exchangers in the gasifier process train are integrated with those of the boilers and heat exchangers in the CCGT. The drawback is that this makes the plant inflexible, and makes it more difficult to start up than a steam plant. There are also questions about the efficiency at reduced loads, although there is some practical evidence from the IGCC at Buggenum in the Netherlands, that load changing can be rapid.

A picture of a typical IGCC plant is shown in Fig 2. Such a plant has the gasifier as a core, which is supplied with oxygen from cryogenic (liquid oxygen) air separation unit.   The picture also shows the H2S removal system, which is of substantial size, especially as a Claus plant is needed to prevent the H2S escaping the atmosphere. After cooling, the purified gas is sent to a CCGT, where the gas is used as the fuel to an industrial gas turbine, which produces about 140 MW of power. The waste heat in the gas turbine, at about 550°C, is then used to raise steam in a Heat Recovery Steam Generator (HRSG). This steam is combined with that from the gasification “process train” boilers, to drive the steam turbines. A typical plant output is around 250 MW. Plant output is determined by the size of the gas turbines, and is significantly less than the what a CCGT plant using the same gas turbine would generate. The drop in output comes results from the amount of power needed to drive the plant ancillaries, that is cryogenic plant, coal grinding and pumps on the H2S removal system   


Fig 2 : IGCC at Puertollano in Central Spain

There was a lot of interest in the IGCC in the 1970’s, when there was concern about SOx emissions. The ability to remove H2S to low levels, and the possibility of offering efficiencies well above 40% was attractive. But against this was high first cost, because of plant complexity. There were also concerns about the need for staff who had experience in the design and operation of chemical processing plants, and the overall reliability.

6. IGCC-Hydrogen-CCS

6.1 Process Conditions    

The revival of interest in the IGCC has stemmed from the belief that this is a viable way of getting the hydrogen economy going. Furthermore, the production of hydrogen involves the capture of CO2. This again is off-the-shelf technology, but it does mean that the plant becomes even more complex. See Fig 3.

The basic change is the incorporation of a shift converter in the plant. Here, the gas, after some cleaning and cooling to about 300°C, is passed through a pressure vessel containing a catalyst. This promotes the reaction of carbon monoxide with superheated steam.


CO + H2O = CO2 + H2


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Figure 3: General Layout of IGCC-Hydrogen-CCS Plant

In this way, the carbon monoxide is “converted” into hydrogen. The “shift reaction” is exothermic and the heat is used to produce steam for power generation. After this process, the cooled gas, mainly consisting of hydrogen and carbon dioxide, plus H2S as an impurity, is put through an “Acid Gas Removal” or AGR process. Here the H2S is removed first, and then in a separate part of the AGR, the CO2 is absorbed. The solution continually recycles around the AGR, and these two gases are released in appropriate sections of the equipment, the H2S going off to a Claus Kiln and the CO2 to a CO2 pipeline compressor. A complicating factor is the need for the CO2 to have a reasonable degree of purity. If much more than 1-2% hydrogen, or carbon monoxide, is carried off in the CO2 stream, plant efficiency will be compromised

The hydrogen, at this point is contaminated by percentage levels of CO, CO2, N2, Ar and small amounts of methane. It is fine for burning in gas turbines, but as mentioned, it needs to be brought to close to “Five Nines” purity for fuel cell applications (i.e. 99.999% pure). This is accomplished in a Pressure Swing Adsorption system.  

6.2 Efficiency Considerations

It will be seen that although everything is technically feasible, the modification of the gasifier process train, to produce hydrogen, will require an increase in capital investment. There are other factors that affect the economics and confidence in the future of the IGCC-Hydrogen-CCS concept.

A big issue is the down grading of plant efficiency in an IGCC-CCS plant.  An inherent problem in using hydrogen as a fuel is that it burns to produce steam, and unless this steam can be condensed in a useful way, almost 20% of the heat which is developed in the burning process is effectively lost. This is the situation in the CCGT boilers, so power production is compromised. There is also concern by some manufacturers that high flame temperatures, which occur when hydrogen is burnt, will result in high NOx levels. Hence, they are, at present only prepared to offer E-type gas turbines, which further compromises efficiency (The most advanced designs on the market are the F and H classes). The result is that IGCC-Hydrogen-CCS plants have efficiencies of about 35% or less. Nevertheless, this is about the same level as might be expected from a good post combustion capture steam based plant.

6.3 Fuel Aspects Including Biomass and Waste 

One important advantage of entrained flow gasifiers is that the operating temperature, 1450-1650ºC within the gasifier, ensures that 99% of carbon in the coal reacts to produce carbon monoxide or carbon dioxide. Here it should be noted that the burn out of coal in a conventional power plant is not 100%, especially when the burners are of the low NOx type. Accordingly, almost any carbon bearing fuel can be used .This includes scrap wood and, apparently, the residues from processing chickens. These would have been used at the Dutch IGCC in Buggenum, were it not for the intervention of bird flu, which prevented the transport of chicken carcasses.

The main issue with fuels is that their water content should be low. The energy needed to evaporate the water and raise the temperature of the steam, which is produced, to 1600º C, comes from the combustion of some of the fuel. Hence gasifier efficiency falls.  It follows that lignite, which has a “trapped” water content of up to 50%, has to be dried before being used. Waste heat from the gasification process, as pointed out by Cormos, can be used for this purpose. The same technology as used in conventional steam type power plants, using lignite, would be suitable.

Corrosion and fouling of power plant heat exchangers and boiler from the sulphur, chlorine and alkali content in coal, biomass and waste is a serious issue in conventional steam plant. With coal, corrosion of superheaters becomes a critical factor once steam temperatures reach the 565º mark. Expensive, corrosion resistant steels are needed. The problems with combustion of biomass and waste are even more serious. Here, corrosion becomes unacceptable once steam temperatures reach the 450ºC level. This is one reason why the efficiency of waste incineration plants is under 30%.

It seems likely, in contrast, that high temperature corrosion issues, with some types of entrained flow gasifiers, will be minimal. Water quenching of the gas, once it leaves the gasifier should eliminate much of the chlorine (as HCl), and alkali compounds (as dust). This leaves the hydrogen sulphide, which providing metal temperatures do not exceed 450ºC will be tolerable. This will be the case in a gasifier system modified to produce hydrogen, as temperatures need to be kept at below this level to maximise hydrogen production in the shift reaction. This is different to a “conventional” IGCC where there is a big incentive to superheat steam to around 600ºC, if the waste heat in the raw gas coming from the gasifier is to be properly utilised.            

7. Impact of Wind and Solar Renewables on IGCC Operation  

The issue, which few people besides the author and his colleagues at the Institute for Energy have raised, is the need for all types of power plants to “two shift” during the later stages in their life [4]. Two shifting implies the need to shut down overnight and start up during the morning as the demand for electricity changes. Conventional power plants have this ability, but it seems unlikely that this will be possible with entrained flow gasifiers. Other gasifiers, particularly those of the fixed bed type can be shut down overnight, and restarted the following day, but these are not really suitable for hydrogen production.

At the present time, if this issue is being considered at all, it is purely in terms of the day to night variation in demand. However, in the future, there will be a big expansion of wind and solar based renewable energy, and in these circumstances fossil fuel based power plants will have operate in a very irregular or flexible manner. When the wind blows, fossil plants will have to run at low output or be taken off line. This situation might prevail for a few days or even weeks. But then, if a big anticyclone develops, coal and gas fired plants will need to be at full output within a few hours. This aspect has been considered in Germany in some detail. Figure 4 shows how the fossil fuel plant sector might be expected to operate on a typical week during 2050 when most of power in Germany will be of the renewable type ( The figures on the horizontal axis are hours through a week). Note that all the power plants are off during most of Thursday and Friday, but then have to zoom up to almost full output during Saturday night. It does not seem realistic to operate any kind of carbon capture plant, steam or IGCC, in this way 

8. Development of the Hydrogen Economy

The biggest current deterrent to the construction of IGCC-Hydrogen-CCS plants is the absence of a large number of consumers who require hydrogen. The only big user of hydrogen is the petrochemical industry. Although the number of potential users is small, there is quite a lot of interest in building entrained flow gasifiers for hydrogen production and combining this with power generation.

One concept is to build such plants next to refineries and then begin to pipe hydrogen to surrounding communities. As noted the Rotterdam area, in the Netherlands, and at Teesside, in the UK, are possible future locations. But this is not an option for all power plants, and even where this is a possibility, it does mean that long term contracts may have to be signed with the petrochemical companies. It forces the vendors of hydrogen to make commercial deals in which fuel costs and plant reliability cannot be stated with certainty.

Once a large-scale hydrogen infrastructure is in place, however, IGCC-Hydrogen-CCS does begin to score over its more conventional post combustion competitors, simply because of the need to two shift and be responsive to the vagaries of wind and solar renewables. In a plant which produces hydrogen as a fuel gas, the plant can be kept operating when there is no demand for electricity. The hydrogen can be diverted to a pipeline, which acts as a storage system, and the CO2 capture section of the plant can continue to operate at design capacity at all times. This feature becomes more important as wind and solar energy takes up a bigger proportion of the market. In contrast, an electricity-only steam plant would have to shut down at times of reduced electricity demand. Even if this did not cause operational difficulties, it would certainly have an impact on the cost of electricity. 

9. IGCCs Producing Substitute Natural Gas with CCS

A compromise option, which requires no changes to the existing energy infrastructure, other than the construction of pipelines to take the captured CO2 to the geological storage sites, is to produce Substitute Natural Gas (SNG) from coal instead of hydrogen. The SNG would be transmitted to gas consumers using the existing transmission system Unlike an IGCC producing hydrogen this  would not need changes to burners, gas governors, pipeline compressors etc. See Fig 5. 

Fig 5 : IGCC-SNG-CCS Plant and its Relationship to the Natural Gas Pipeline System

In this concept, after cooling the gas from the gasifier to about 300°C, and removing dust and H2S, the CO, CO2 and H2 are made to combine in a methanation reaction. 

CO+ 3H2    =     CH4 + H2O

CO2 +4H2  =  CH4 +2H2O

From these equations, it is apparent that the proportion of hydrogen in the gas has to be increased to maximise the formation of methane. This will require some of the CO in the raw gas to be shifted to produce hydrogen. 

These extra process units will add complexity to the plant, but the most important (apparent) shortcoming of the process is that it only removes about half the carbon. This can be seen from a reaction which represents the overall coal-to-SNG process.

2C + 2H2O  =  CH4 +CO2. 

Whether it is such a drawback is arguable.  The coal-to-SNG efficiency, with the right kind of gasifier, is around 70%. If this gas were then burnt in a modern CCGT, the coal to electricity efficiency would be just below 40%. More importantly, the most sensible way of using the gas would be in CHP units, in which coal-to-useful energy would approach 60%.

Here again the technology for this process route requires no new developments. Indeed, in the case of CCGT, no modifications are needed of the gas turbines at all, and the Coal-SNG-CCS can ride on the back of advances in the industrial gas turbine field. An important feature is that the capture of CO2, in this case, does not require additional energy, as with the hydrogen option. And being cynical, if the CO2 storage system is not built, plants like this can produce electricity at only a little less efficiently than conventional power plants, and can supplement our fast diminishing reserves of natural gas. 

What is less apparent is that since the aim of the process is to produce methane, it allows the use of a far wider range of gasifiers than the high temperature entrained flow types. These other gasifiers are the moving bed and fluidised bed types. The outlet temperatures of these processes are in the 600-1050°C range, and because of this the raw gas contains up to 10% methane.

6. Comparison of  IGCC Based Options

Table 1 itemises the differences between a conventional electricity only IGCC, and those which produce hydrogen or SNG as a fuel gas




Conventional IGCC










High Pressure but

entrained flow


Entrained Flow



Best types completely gasifiy coal and produce high levels of methane

H2S Removal



Standard Claus

MDEA or Selexol


Claus with Oxygen




Standard Claus

Shift Converter


Very Large Sour


Sweet Shift

Further Upgrading of

Product Gas


Pressure Swing Adsorption

( for fuel cells)


Gas Turbine Mods

Limited Range


Off-the Shelf


Hydrogen Rich


to be


Basically Standard


Gas Turbines

Energy Outputs








SNG and H2


  • 43-45%
  • 33-35% Electricity
  • 55% Hydrogen
  • 37-40% Electricity
  • 65-70% SNG

Turndown on Electricity

Practical Range









Every one of these concepts either has been built or could be built now. We are not dealing with  unknown or untried technology as the Government seems to believe. Electricity only IGCCs without carbon capture are now in operation. The process chain of such gasifiers has to incorporate a shift converter produce a gas in which all the carbon is available for capture as carbon dioxide. The resulting fuel gas, containing over 90% hydrogen, can be burnt in some of the E type gas turbines. However, if the gas was needed for fuel cells a pressure swing adsorption unit would be required bring the gas purity to the 99.995% level of purity

The IGCC-SNG-CCS is probably the most capital intensive plant, but probably not much more than the 99.995% hydrogen option. Its main drawback is the perception that it does not capture more than 50% of the carbon. But this disadvantage is compensated by the fact that all of the existing gas and electricity networks can be used without modification. Furthermore, the plant has a higher energy efficiency than its competitors and has the flexibility needed to fit in with in with wind and solar renewables.   

11. Conclusions

The aim of this paper is to try to give an objective account of the pros and cons of gasification as a method of removing carbon from a coal based energy system. The view has been taken that the time is not opportune for IGCC-Hydrogen-CCS, because so much has to be put in place before it can be viable.

But in this context, post combustion capture is not without its drawbacks too. The most challenging issues is the question of how any power plant can respond to the need to two shift and whether they can be part of an energy system in which wind and solar renewables are a significant component. This seems problematical for steam plant with carbon capture, if not a two shift regime, it will become a headache once wind and solar renewables begin to dominate the Grid.

But as has been shown, the option of producing Substitute Natural Gas from coal, and using this in an IGCC with carbon capture, although apparently not so good at capturing CO2 as the hydrogen route, has a lot going for it. If we consider SNG as an energy stream, rather than electricity, the difference is not so great. But the important issue is that IGCC-SNG-CCS provides, in the form of methane rich gas, and electricity at 50 Hz, forms of energy that are used across the globe and have an existing infrastructure which fits with this new cleaner technology.  

The final point, which the author would like to make, goes back to his concern about how carbon capture will affect fuel imports. An IGCC-SNG-CCS plant, which burnt its gas in one of the more advanced CCGT plants would be generating electricity at an efficiency very close to that of a modern steam plant, without carbon capture. Hence the impact on fuel imports would be minimal. However the production of natural gas from coal would reduce the UK’s and EU’s need to import gas. As the recent hike in gas prices have shown, it is vital that Europe minimises its dependence on supplies from outside of the European Union (and this includes Norway and well as Russia!). IGCC to electricity plus SNG, with or without carbon capture, provides the UK and the rest of the European Union with another option.             



1. Rubin, E.S., Rao, A.B., Chen, C., 2003. “The Cost of CO2 Capture and Sequestration for Fossil Fuel Power Systems”

2. C. C. Cormos, F. Starr, E. Tzimas, S. Peteves, A. Brown “Gasifier Concepts for Hydrogen and Electricity Co-Production with CO2 Capture

3. Starr F., Tzimas E., Peteves S.D, “Near-Term IGCC and Steam Reforming Processes for the Hydrogen Economy: The Development Issues”

4. F. Starr, E. Tzimas, M. Steen and S.D. Peteves,  “Flexibility in the Production of Hydrogen and Electricity from Fossil Fuel Power Plants”



4 comments on “(IGCC) Integrated Gasification Combined Cycle for Carbon Capture & Storage

  1. Hi,
    Very lucky to read your articles,
    would you kindly tell me any difference with coal-gas and syngas coming from petro-refinery source?
    Email me for any discovery now

  2. What about DCFCs (Direct Carbon Fuel Cells) technology?
    ? Turns carbon (coal, bio-char) directly in to electricity at 80%+ efficiency demonstrated (100% theoretical, same principle as H2 fuelcell but more efficient)
    ? Waste product is pure CO2 – 100% CO2 capture possible
    ? Hi Temperature operation so some of 20% waste heat can be used to produce steam to drive steam turbine, increasing efficiency further.
    ? Plant capital costs predicted to be significantly lower than conventional coal fired plants, even without CCS!
    ? Fast response – can be used for base and peak load.

    Why not?
    ? Still in research stage – commercial 5-10 years off
    HOWEVER by the time CC is sorted out DCFC could be in use and at far higher efficiency and lower cost.
    ? Politics & vested interests?

    Note on piped H2.
    Volumetric energy density of H2 is very low so piping H2 over long distances will incur significant pumping energy losses compared to the energy transported.

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