B. M. Igoe and M. J. Welch, Demag Delaval Industrial Turbomachinery Ltd. (DDIT), Lincoln, UK
Biomass integrated gasification combined cycle (BIGCC) could provide a cost-effective way of generating electricity from biomass. A number of pilot schemes are helping to develop the technology and overcome technical challenges.
Generation of affordable power from non-fossil fuel sources has been widely debated, especially in the period since the initial concept of the Kyoto Protocol. Power generation from waste material has shown the potential to be an increasing and more economically viable solution in meeting many industrial and non-industrial targets in renewable energy.
Renewable feedstock is widely available in many parts of the world, from agricultural residues, forestry waste, and the potential use of municipal solid waste (MSW), which is mostly subject to landfill. A number of observers see biomass integrated gasification combined cycle (BIGCC) as providing a cost effective solution for generating electricity from biomass.
The challenge facing the manufacturers of industrial gas turbines is the wide range of different gases produced by gasification technologies. These range from low calorific value (LCV) fuels (4-5 MJ/m3), with low volumes of combustible components to medium calorific value (MCV) fuels (20 MJ/m3 and higher) containing high levels of hydrogen and carbon monoxide.
Figure 1. Effect of Wobbe on burner pressure drop mixtures without hydrogen
The use of biomass to produce both power and heat is not new, as many schemes have operated for several years. Boilers, from a simple grate type to fluidized beds, are used to raise steam to feed a steam turbine generator. However, while these are proven technologies, they are relatively inefficient, especially on a small scale.
The use of biomass in gasification schemes offers a significant increase in energy conversion efficiency, as the syngas produced can be combusted in a high efficiency prime mover, such as an industrial gas turbine. These schemes even have the potential for higher efficiency by creating combined cycle systems.
There are many forms of gasification technology and the list continues to grow with new emerging designs and hybrids of existing designs. All have their own advantages and disadvantages, and all produce fuel gases of different compositions, hence calorific value. They can be categorized as follows:
- Air blown process producing fuel gas of very low calorific values; 3.5-7 MJ/m3
- Oxygen-blown and hybrid process producing low calorific value gases; 7-15 MJ/m3
- Pyrolysis processes producing medium calorific value gases; 15-25 MJ/m3.
Atmospheric systems have the advantage of being based on relatively simple technology, and can operate independently of the gas turbine. The main disadvantage of such a system is its reliance on fuel gas compression prior to the gas turbine. Gases from pyrolysis systems also need some compression, but offer a potential efficiency advantage over the air blown gasification processes, due to the reduced volume of gases that need to be compressed. MCV gases offer a further advantage in that the changes to the core gas turbine and all its ancillary equipment are little changed from the standard design. This also allows the potential to use state-of-the-art combustion technology with resultant low exhaust emissions to the atmosphere.
MCV and DLE
Early experience in Demag Delaval Industrial Turbomachinery (DDIT) with LCV and MCV gases utilized special, bespoke, diffusion flame burner arrangements, where the gas fuel nozzle was sized to pass the increased fuel flow necessary to provide the input energy. In order to meet the needs of gasification or pyrolysis technologies described, a different approach has been adopted using DDIT’s Dry Low Emissions (DLE) combustion system. A major development programme has been undertaken to expand the DLE capability into medium CV fuels in the Wobbe Index (WI) range 15-36 MJ/m3. Two types of fuels have been considered, those typically comprising methane and inerts (CO2, N2) and those fuels derived from gasification or pyrolysis processes, which typically contain relatively high concentrations of carbon monoxide and hydrogen.
A significant benefit in adopting and adapting the DLE combustion system to these lower calorific value fuels is the potential exhaust emissions signature. The DLE system has typically a
DLE exhaust emissions provide both low levels of NOx and CO and are achieved using a lean pre-mixed combustion configuration. This system is a simple robust design, employing no moving parts, relying on the accurate control of fuel to the main and pilot burner components and the fixed geometry of the air swirler.
For gas fuels of a lower calorific value compared to pipeline quality fuels the size of the gas fuel metering holes is critical, and much attention has been paid to achieving the best results in terms of:
- Low NOx
- Low CO
- Pilot burner tip temperatures
- Combustion dynamics
- Onset of flashback (for high H2 content fuels).
The facilities supporting the combustor development programme required a major upgrade and investment prior to initiating the programme. A high pressure air facility (HPAF) provides air to a combustion rig at correct engine conditions (i.e. correct pressure, temperature and mass flow for a single combustor rig). This was originally configured for natural gas and No.2 distillate fuel. The facility was expanded to include a gas fuel mixing facility, allowing inerts to be added to natural gas (simulates, for example depleted wells or typical landfill gas), or more complex mixtures including inerts, hydrogen and carbon monoxide and even rich fuels such as butane and propane.
The DLE combustion system is fully proven on pipeline quality gases in the WI range 37-49 MJ/m3 and the current programme is to extend the lower limit to 15 MJ/m3. To date the programme has concentrated on the 4.7 MWe Typhoon and 12.9 MWe Cyclone gas turbine. This covers two extremes of the DDIT small gas turbine range, and due to the generic nature of the DLE combustion design, read-across into the other products will be concluded in due course.
A systematic approach has been adopted to ensure the combustor performance achieves the desired impact of working with the reduced calorific value gas fuels. As there are so many variable parameters to consider initially, the burner development hardware was limited to WI changes and increased levels of hydrogen. Carbon monoxide was not included at this early stage until the most promising burner design emerged.
The development programme concentrated initially on full load conditions, with the fuel gas composition varied by increasing the amount of CO2 or N2. For the same WI the relative effect of these inerts was investigated and showed no significant difference. A limited number of part load conditions were covered to determine the potential turndown characteristic.
The high pressure rig and gas mixing facility, now configured with both hydrogen and carbon monoxide capability, allowed the development programme to investigate combustion builds with these gases. Initially, these species were investigated independently, then the interaction of CO with H2 was considered. It was clear from the earliest tests that the interaction of CO with H2 gave results worse than with the individual species, and this would prove the most complex part of the programme.
Throughout all of these tests the combustion performance was monitored in terms of:
- Typical exhaust species, NOx, CO, UHC, CO2, O2
- Dynamic pressure fluctuations, both in the combustor and the surrounding casing
- Burner tip temperature
- Propensity to flashback (established in terms of H2 content of the fuel mixture).
Effect of WI: The WI was reduced to 15 MJ/m3 by increasing the content of inert gas, either N2 or CO2. The monitoring of exhaust gas species, especially NOx, showed approximately 50 per cent reduction in such emissions. No discernible change to CO or UHC was seen. Little difference was noted whether N2 or CO2 was used.
Effect of H2: Increasing the amount of H2 into the fuel gas had an immediate and detrimental impact on NOx formation. The NOx increased significantly when 25 per cent v/v hydrogen was introduced into the fuel. However, no change in CO or UHC emissions was noted. Also seen were increases in both pilot burner temperature and a change in low frequency combustion noise. Introducing hydrogen into the gas fuel increases the flame speed, and an increased tendency for the flame to lose ‘control’, with ‘flashback’ resulting in combustion damage. This occurred when H2 volume concentrations exceed 35 per cent.
Effect of CO: The effect of introducing CO into the mixed fuel had a similar impact to hydrogen. On its own, CO at 40 per cent v/v increased the NOx signature by a factor of three, but with no significant impact on the CO or UHC emissions. Again, combustor component metal temperatures increased along with some increase in combustor casing low frequency noise.
Effect of CO and H2: The effect of introducing CO with H2 had an immediate impact in reducing the amount of H2 that could be used without flashback. This aspect of operation is under extensive investigation using both analytical and practical tools.
The development programme concentrated on the Typhoon gas turbine with the view of releasing hardware to cover mixtures typically containing natural gas with increasing amounts of inerts, but limiting the H2 content to
Development work is also progressing on the Cyclone size of combustor, using a biogas with significant volumes of both CO and H2. This work is targeted at fuels produced from gasification. One such application uses the Ferco SilvaGas gasification process with a typical biogas composition detailed in Table 1.
Fiscal incentives for ‘green’ electricity in a growing number of countries has led to consideration of a number of high efficiency BIGCC schemes. Some of these proposed schemes are at a reasonably advanced stage of project development, with detailed planning applications and Environmental Impact Assessments being prepared.
Two BIGCC schemes have already been built, both designed to use the Typhoon gas turbine. The first was the Värnamo demonstration plant in Sweden operated by Sydkraft. This scheme, employing a pressurized air-blown circulating fluidized bed gasifier, was constructed to prove that gasifiers of this type could operate on a wide variety of biomass feedstocks and that suitably modified gas turbines could operate on the synthetic gas produced. This demonstration project successfully concluded its three year life in 2000, having gained around 10 000 hours of operation on the gasifier and 4000 hours of syngas operation on the gas turbine. A net electrical efficiency of 32 per cent was achieved, but with further optimization of both overall plant and individual component design, a net efficiency of approximately 36 per cent is possible. By increasing the scale of the plant and using larger, more efficient gas turbines, a net efficiency of 42 per cent or higher is potentially achievable.
The second plant, ARBRE project in Yorkshire, UK, was envisaged to be a commercial demonstrator for air-blown atmospheric circulating fluidized bed gasification technology operating on a forestry residue/willow coppice mix. Unfortunately the plant was put into administration before commissioning could be completed. It now has new owners who are carefully considering the options available to them before restarting the plant.
Other gasification or pyrolysis schemes are planned in Europe and North America. One such scheme is the Winkleigh biomass project in Devon, UK. This scheme, a 20 MW plant based around a Cyclone gas turbine and a Ferco gasifier, is currently undergoing the approval process. Winkleigh will be one of the ‘next generation’ plant which will benefit from previous demonstration projects and ongoing technology development programmes, as well as economies of scale. It is envisaged that Winkleigh will generate 27 MW (gross) electricity with a net plant efficiency of 36 per cent at a cost of around $2300/kW. This cost brings BIGCC schemes close to those of conventional, high efficiency, boiler/steam turbine schemes, but with 3-4 percentage points improvement on net efficiency. In the future, replication of plant design will help reduce the costs further, with costs of $1500/kW installed potentially achievable.
There are also potential projects based on the use of MSW as the feedstock. Here, the higher efficiency of a BIGCC scheme comes at a cost already equivalent to that of a modern incinerator plant with state-of-the art flue gas cleaning systems. Initial design work indicates that a BIGCC scheme will comply with all the emissions legislation associated with a new build incineration scheme with a smaller footprint. BIGCC technology can also make smaller scale waste-to-energy plant, requiring less than 200 000 t/year of waste, economically viable. While MSW pyrolysis is actually a well-proven technology (some plants have nearly 20 years operational experience), no scheme yet involves a gas turbine, although possible schemes are being considered.
Gasification and pyrolysis technologies can produce clean biogas fuels suitable for use in gas turbines from a variety of feedstocks. Combining both technologies offers the possibility of highly efficient combined cycle power generation. The ability to burn these biogas fuels in an industrial gas turbine configured with a dry low emissions combustion system allows for low exhaust pollutants to be emitted to the atmosphere.
Figure 2. Effect of hydrogen on NOx formation
Development has progressed, allowing applications with varying levels of inerts to be considered, but work is continuing to extend the capability to gas compositions with high levels of H2 and CO.
To fully support this development programme DDIT has made a considerable investment in rig facilities. This includes changes to the high pressure rig as well as provision of a gas mixing facility. Commercial exploitation of this technology is dependent on a range of external factors, and it may be necessary for governments to play a much larger role if BIGCC is to become a commercially acceptable technology.
Comparison of various technologies
When making a comparison of the various methods of energy conversion the same parameters are considered and used throughout. In this article, net efficiency is used to review the various technologies. Net efficiency is defined as the ratio of the net electrical output (or electricity available for use or export) compared to the energy content of the biomass fed into the system. The net electrical output is the gross plant output minus the plant’s auxiliary power requirements.