IGCC plus CCS - an Objective Analysis

By F.Starr : Claverton Group Conference Paper - October 2008

1. Introduction

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. In such schemes the idea is that just before the flue gases are vented up the stack, the CO₂ is removed by washing the gases with an alkaline solution, in this case MEA. The process is not too dissimilar in principle from the removal of SO₂ and SO₃, which is done to prevent the occurrence of acid rain.

The advantage of such a post combustion scheme is that the plant can be built, “capture ready”. That is  put into operation before the CO₂ pipeline and underground storage reservoir is made ready. 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 there is little intention to go ahead with the construction the infrastructure for sequestering CO₂ .  Accordingly, once built, the plant will be run as a none-clean coal plant for evermore.

The competitor to this form of clean coal plant is 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 which contains over 90% hydrogen. It also results in the carbon compounds being reacted to form carbon dioxide, which can easily be removed, since the gas mixture is at high pressure and the CO₂ is at a high concentration. . The CO₂ can be washed out of the hydrogen rich fuel gas using various solvents. In one such concept, which the writer helped design, the solvent used was MDEA. The fuel gas is then burnt in a CCGT ( Combined Cycle Gas Turbine) to produce electricity.

It is claimed by some that this IGCC plus CCS, that is Integrated Gasifier Combined Cycle pus Carbon Capture and Storage is more of an unknown than a conventional power plant plus CCS. This is not really correct. However the writer has some sympathy with the Government’s position. Unfortunately, the Government,  by more or less dismissing  precombustion processes out of hand, it 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 is discussed in Section 5 of this paper.

The remit I was given in writing this paper for the Claverton Group was to give some background  on the use of coal based gasification processes . One major problem is that there are a large number of high pressure gasifiers on the market, some of which have been used since the 1920’s. Most of them are not really suitable for capturing carbon.  And  the gasification of coal, by heating coal so that it emits hydrogen and methane, leaving a substantial mass of coke behind, goes back even further to 1820. Indeed this form of gas production was the worlds first energy conversion process. But now we are discussing the complete gasification of coal, 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.

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.

2. Recent Background to IGCC plus CCS

IGCC plus CCS has received support from both Europe and the USA, as it can produce hydrogen from coal and the hydrogen can then be 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 was 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 long distance hydrogen pipelines.

There is a 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 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 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), this has major implications on plant costs. Since there are very few fuel cells units operating commercially, in the writer’s view, a more realistic level for carbon monoxide would be at the 2%

3. Gasification Processes

There are about 90 commercial gasifiers  in operation. 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. There are  just a gasifiers that are used in an IGCC for electricity production. Most of the coal based gasifiers are of the entrained flow type in which 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. However, providing this is not a requirement, virtually any type of gasifier can be used in an IGCC.

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, (formally developed by Texaco), the coal is slurried with water which simplifies the injection of the fuel. Gasifier efficiency is lowered  since it is necessary to burn fuel to evaporate the water, but the capital costs of the system are relatively low.  The two processes which compete with the GE system, are from, respectively,  Shell and Siemens, . Here the coal is entrained into the gasifier using high pressure nitrogen.

In effect 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. The product which is not wanted at this stage is carbon dioxide. A high level of this reduces the proportion of  CO which can be formed. As will be seen, at a later stage in process the carbon monoxide is used to generate more hydrogen.

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

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 system has a system by which slag drains out of the gasifier into a quench water bath. But to remove dust from the gas stream in the Shell process, cool “recycled” gas is mixed with that coming from the gasifier. A cyclone plus filtration completes the removal of the dust.

Because the temperature is so high, the gas which emerges 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.

Once fuel gas has been cooled to room temperature, and the steam condensed out, the gas can and is directly burnt in the gas turbine of a CCGT, providing that the H₂S is first removed. This is done with the similar type of liquid solvent as is used for capture of the CO₂.  But because the fuel gas is so rich in carbon monoxide  there is 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 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  system, 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. This steam is combined with that from the gasification process train boilers, to drive the steam turbines. In total the plant output is around 250 MW.

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 the 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 reliability of IGCCs.

3. IGCC-Hydrogen-CCS

As stated in the Introduction, the revival of interest in the IGCC has stemmed from the belief that this is a viable way of getting the hydrogen economy going. This also means that 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

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, then in a separate part of the system, the CO₂ is absorbed. The solution continually recycles around the AGR, and these two gases are released in appropriate sections of the plant, the H₂S going off to a Claus Kiln and the CO₂ to the CO₂ pipeline compressor. A complicating factor in all this is the need for the CO₂ to have a high degree of purity.

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 “Five Nines” purity for fuel cell applications ( i.e 99.999% pure). This is accomplished in a Pressure Swing Adsorption system.

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 issues which affect the economics and confidence in the future of the IGCC-Hydrogen-CCS concept.

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

A big issue is the plant efficiency.  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. Furthermore, at the present time, there is 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 result is that IGCC-Hydrogen-CCS plants have efficiencies of about 35% or less. This is about the same level as might be expected from postcombustion capture plants.

The issue, which few people besides the author have raised, is the need  for power plants at the later stages in there life to “two shift”. Two shifting implies the need to shut down overnight and start up during the morning as the requirement 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.

4. Infrastructure Issues

The biggest 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, and here 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. The Rotterdam area, in the Netherlands, and 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 puts vendors of hydrogen in making commercial deals.

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. 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 and this will cause operational difficulties.

5. IGCCs Producing Substitute Natural Gas with CCS

A  rather different 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, and unlike the hydrogen option would not need changes to burners, gas governors, pipeline compressors etc. See Fig 4.

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.

This 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 +CO_2.

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 was 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, and the Coal-SNG-CSS 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 systems is not built, plants like this can operate producing electricity at only a little less efficiently than conventional power plants, and supplementing 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 temperature are in the 600-1050°C range and because of this the raw gas contains up to 10% methane.

Fig 4 : IGCC-SNG-CCS Plant and it Relationship to the Natural Gas Pipeline System

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

Every one of these gasifiers could built now providing that some compromises were accepted.  Electricity only IGCC without carbon capture are now in operation. The  gasifier processing 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. It 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, and that the plant has a higher energy efficiency than it competitors and has the flexibility needed to fit in with in with wind and solar renewables.

7. 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 the main component.

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, energy which is used universally, and 200 years of industrial development have given us an infrastructure which fits with this new cleaner technology.

F.Starr: 5^th Oct 2008