It is inevitable that renewable resources and/or nuclear power will replace fossil fuels for power production. However, this is a transition that will take a very long time. In the meantime, fossil fuels will be eked out and used in a way that minimises environmental effect and maximises economic return in line with free market forces.
The UK government has been advised by its Performance and Innovation Unit (PIU) that it will be sufficient to rely solely on natural gas as the interim fossil fuel of choice while renewable technologies are being developed and implemented.
The consequence of this decision, which has been mirrored in many other countries by normal commercial forces, will be to confirm the monopoly of natural gas as the only acceptable fossil fuel for baseload power generation. The “dash for gas” will continue.
The PIU has stated that there is no shortage of natural gas, with worldwide reserves at 150 x 103 bcm, and therefore government support and funding can and should be confined solely to the development of renewable energy. There is a longer term possibility of investment in carbon capture and sequestration for fossil fuel sources, but legal issues and international agreements to share the burden fairly will delay any actions to curb carbon dioxide emissions.
The dual pressures of official sanction and commercial competition will further accelerate the increase in the proportion of natural gas used for electricity generation. What will be the result?
Currently, the natural gas supply infrastructure is coping adequately, and low wholesale prices reflect a healthy surplus of supply over demand. However there are some step changes due in both supply and demand.
A new generation
Over the last twenty years, the power generation technology of choice has changed from the boiler/steam turbine to the combined cycle. This tenet also applies to biomass and waste fuels, but of course these require considerable upstream treatment to produce a suitable gas turbine fuel.
The phenomenal growth in gas turbine application could only happen with synergetic availability of suitable fuel.
Natural gas now generates 144 TWh/year of electricity in the UK, 40 per cent of the total, consuming 30 bcm/year. Coal burning and nuclear plants together supply 54 per cent of current demand, with renewables supplying 2.8 per cent. Following the guidance of the PIU report this mix will be changed to 20 per cent renewables with 80 per cent of generation capacity provided by natural gas.
With energy consumption projected to grow by 1 per cent per annum to 2020, this means that total gas consumption will exceed 170 bcm, an increase of nearly 60 per cent on today’s figure.
This switch away from coal burning has had two major benefits:
• The UK now enjoys the lowest cost electricity ever and among the cheapest in Europe.
• The replacement of low-efficiency coal-burning power stations with high efficiency natural gas combined cycle plants has helped the government to achieve its targets under the Kyoto Protocol.
On the other hand:
• Natural gas has become the monopoly fuel for combined cycle plants with competition in the market being confined to the transfer and distribution of fuel, and not to the actual supply.
• Natural gas combined cycle plants still emit carbon dioxide, albeit at a greatly reduced rate per MW of electricity produced than from coal-fired stations, and this will need to be reduced.
The latest UK government statistics indicate that UK gas reserves have fallen for the last four years for which figures are available. This is despite record winter price spikes, which should have led to remedial measures. Reserves are now at their lowest level for nearly twenty years.
More impressive are the two flow reversals of the gas Interconnector during the winters of 2000/1 and 2001/2. The UK is already a net gas importer during that period of the year when additional supplies are neither readily available nor cheap.
More reserves will be discovered in the North Sea and elsewhere around the UK, but they will be small and in increasingly remote and hostile regions. Development of these reserves will only occur when banks and other investors forecast consistently higher prices for natural gas.
An alternative to natural gas
Integrated gasification combined cycle (IGCC) plants have had a chequered history since 1983 when the first commercial unit was commissioned at Cool Water in California.
The market at that time demanded “high merit rating” designs to minimise feedstock consumption, if necessary, at the expense of high capital cost.
The later European IGCC demonstration plants, at Buggenum in The Netherlands and at Puertollano in Spain, also complied with the requirement for high efficiency. Both plant designs incorporate costly waste heat boilers or syngas coolers directly coupled to the gasifiers and have a complex integration between the ASU and the gas turbine whereby the turbine provides compressed air for the ASU in return for a nitrogen supply to suppress NOx formation in the combustors. The resultant demonstrated efficiency is 43.2 per cent, the highest yet achieved in a coal-based IGCC.
These coal based demonstration plants are intended for a demand driven market, ie to make baseload electricity. The biggest commercial scale IGCC ventures to date, the three refinery based plants, ISAB Energia, Sarlux and API Energy, all built in Italy in the 1990s, are supply driven. They are directly linked to on-line refineries. These supply them with feedstock and in return rely on utilities delivered from the IGCC, which means that the highest possible level of reliability and availability is essential.
All these plants use water quench gasifiers, and two are serviced by remotely located ASUs, which supply oxygen and nitrogen by pipeline.
The hot gases (and slag) emerging from the gasifier are immediately mixed with water, raising large volumes of medium pressure steam which is intimately mixed with the syngas. Heat recovery is by means of medium and low pressure boilers or through saturation of the syngas before it is sent as fuel to the gas turbine. The water vapour content of the fuel reduces the turbine flame temperature, and hence NOx formation.
ISAB, in particular, uses a proprietary flow scheme known as Simple CPG (Clean Power Generation). The gasifier operates at a higher pressure than that required for the fuel pressure to the gas turbine. Hence the condensing temperature of the water evaporated in the quench is sufficiently high to drive a large proportion of the gasification waste heat around the sulphur removal unit to the fuel gas saturator in the form of hot water.
The high availability of the water quench gasifier had been previously established before the three Italian projects were initiated. For example, in Japan, at Ube Chemicals, and at Eastman Chemicals, high pressure coal gasifiers have been in continuous commercial operation since 1983, making syngas for chemicals manufacture. Further quench coal plants were installed in China during the 1990s.
Eastman today enjoys a gasification availability of over 98 per cent.
A shift to the better
Quench gasifiers are also used in conjunction with a shift reactor. Most of these plants are designed to produce hydrogen for refineries and for the synthesis of bulk ammonia for the fertiliser industry. A carbon monoxide (CO) shift catalyst reactor installed downstream of a water quench gasifier reacts the steam mixed with the syngas to “shift” the carbon monoxide in the syngas to hydrogen and carbon dioxide. This facilitates both the removal and “capture” of carbon prior to combustion, and the extraction of hydrogen from the syngas. The shift increases the CO2 content of the syngas typically from 15 per cent to 40 per cent and the hydrogen from 40 per cent to 60 per cent.
The onset of the debate on global warming and the potential requirement to capture and sequester carbon dioxide emitted by fossil fuel power stations produced a plethora of IGCC studies for the pre-combustion capture of CO2. All of these studies compared the cost and performance penalties for CO2 capture by comparing the performance and cost of two totally different flow schemes, one without shift and one with. The differences were substantial and it was generally concluded that pre-combustion CO2 capture would incur substantial commercial penalties.
In 2000, ChevronTexaco commissioned the Jacobs Consultancy to investigate what the comparative penalties would be if the same flow scheme, incorporating a shift reactor, were used for both non-capture and capture modes of operation. The results of this study of “Catalytic CPG” were reported at the October 2001 Gasification Technologies Conference in San Francisco, and again at the European Gasification Conference in the Netherlands in April 2002.
The reduction in plant efficiency when capturing carbon dioxide was found to be two points of efficiency, with the capital cost increasing by less than 10 per cent. These do not make any allowance for the cost of sequestration in respect of the compression and drying of the carbon dioxide.
The advantages of using a shift reactor in an IGCC go beyond that of making it possible to capture carbon dioxide. The shift also promotes:
• more efficient waste heat recovery (less low-grade heat to recover);
• COS hydrolysis with the same catalyst;
• Simplified hydrogen extraction;
• easier NOx control; and
• the possibility of an independent (rather than integrated) gasification combined cycle.
However, an important feature of this scheme is that it is possible to construct an IGCC today that has a built-in option for capturing CO2. Initially, the plant can be operated to advantage by continuing to pass the CO2, along with the rest of the syngas, to the gas turbine.
This scheme was highlighted in a recent UK DTI review looking at the case for a cleaner coal IGCC demonstration plant.
Even better
The Jacobs Consultancy has continued to develop and optimise the catalytic flow scheme.
It was decided to increase the amount of shift conversion to obviate the need for any further NOx suppressant measures other than that effected by the high CO2 content of the syngas fuel. This level can be achieved in a single adiabatic catalyst bed. It was discovered that it was then possible to replace the cooling of the syngas with a desaturator fed with the make-up water required by the quench/shift system, thence recycling the low grade heat.
Early this year, the Jacobs Consultancy was appointed to apply this scheme in a 430 MW coal IGCC to be built for Coalpower at their Hatfield Colliery in South Yorkshire.
The extra advantages of the flow scheme to be used at Hatfield over the generic version published in the gasification conference papers are:
• Overall efficiency up from 41 to 43 per cent.
• No gas saturator or nitrogen additions needed when operating in non-CO2 capture mode.
• No syngas condensers and knock-out pots required.
• Simple multi-purpose syngas production system.
• No cooling water required for gasifier and gas treatment train. And
• Minimum treatment for plant make-up water.
The option to capture carbon dioxide is retained.
Introducing GEM
However compact and ingenious the technology, IGCC plants cost in the same order of magnitude as traditional coal-burning power stations fitted with SOx and NOx reduction devices. This means that independent power producers will favour natural gas combined cycle investment – whenever natural gas is available.
This preference and the “dash for gas” has led to an over capacity of installed power production and doubts regarding the long-term viability of low cost gas.
A feature of the Hatfield type IGCC design is that it produces very dry gas fuel (< 0.1 per cent water) at high pressure (> 50 bar). The gas conditions are therefore ideal for transporting the fuel gas to a stranded combined cycle unit.
The waste heat steam constitutes some 10 per cent of the useful energy output of the gasification unit. It is possible to utilise the steam within the gasification unit itself.
Jacobs has called this a Gasification Enabling Module or GEM. There is enough energy in the steam and from the part expansion of the syngas to make the GEM self-supporting in power during normal operation. This includes the power requirements of the ASU.
There are several ways of implementing a GEM and the optimum method is site specific, determined by such factors as local demand for steam and the availability of imported power for black start-up. The option to capture CO2 is retained in the overall plant configuration. Proven techniques exist to boost the GEM output for peaking purposes.
This concept is still undergoing detailed evaluation and will be the subject of a future technical article.
We believe that the coal industries should consider an additional business strategy on top of merely selling coal for power generation in traditional coal burning stations. This new strategy would encompass making and selling contract fuel gas for gas turbines. Fuel gas supply competition against natural gas would be commercially preferable to competition in electricity generation.
A GEM needs only an external power supply for start-up, and a water supply. It can be located remotely from the serviced gas turbine.
Locally held coal stocks would be a reliable safeguard against expensive or stretched imported gas supplies.
