Gasification could bring respectability to co-firing

The co-firing of biomass with fossil fuels has the potential to establish itself as the leader in cost effective, environmentally sound renewable electricity generation. However, in order to achieve this admirable distinction, co-firing must first overcome regulatory hurdles and nagging technical issues that delay its widespread adoption at existing power plants. An approach is described here that addresses both concerns. This alternate method employs fluidised bed gasification to convert the energy of the solid biomass into a low Btu syngas to be directly fired in the boiler. Additionally, the biogas can be used as a reburn fuel to significantly reduce nitrogen oxide (NOx) and other emissions at the existing plant.

Biomass benefits and costs

Biomass has been used as an energy source for more than 1 million years. Even today, about 11 per cent of the world's primary energy comes from biomass, according to the International Energy Agency.

Biomass is any material of recent biological origin. Biomass fuels include items as diverse as farmyard litter, urban wood waste, and dedicated energy crops. Compared to coal, biomass fuels are generally less dense, have a lower energy content, and are more difficult to handle. With some exceptions, these qualities generally economically disadvantage biomass compared to fossil fuels.

But environmental benefits help make biomass an economically competitive fuel. Unlike fossil fuels, biomass is viewed as a carbon-neutral power generation option. While carbon dioxide is emitted during biomass combustion, an equal amount of carbon dioxide is absorbed from the atmosphere during the biomass growth phase. Thus, biomass fuels "recycle" atmospheric carbon, minimising its global warming impact. Further, biomass fuels contain little sulphur compared to coal, and so produce less sulphur dioxide (SO2). Finally, unlike coal, biomass fuels typically contain only trace amounts of toxic metals, such as mercury, cadmium, and lead. To the extent that reductions of emissions are assigned economic value, biomass is more competitive.

To date, development of stand-alone biomass power systems has been limited by its relatively high cost. A typical 25 MW dedicated biomass power plant burning wood waste costs about 2 500 US$/kW and generates power for about 7 US cents/kWh (see Table 1). By comparison, reported capital costs for large new wind projects in the United States are near US$1,000/kW with power sales prices near 2 US cents/kWh (including a 1.8 US cents/kWh tax credit).

Traditional co-firing concerns

A major challenge to biomass power is that the dispersed nature of the feedstock and high transportation costs generally preclude plants larger than 75 MW. By comparison, coal power plants rely on the same basic power conversion technology but have much higher unit capacities, exceeding 1 000 MW. Due to their scale, modern coal plants are able to obtain much higher efficiency at lower cost. Through co-firing, biomass can take advantage of this high efficiency at a much more competitive cost than stand-alone biomass.

In the United States, which has the largest installed biomass power capacity in the world, biomass power plants provide 6 200 MW of power to the national power grid. Of the total electricity produced in 2001, coal accounted for 1.9 trillion kWh, or 51 per cent. Conversion of as little as five per cent of this generation to biomass co-firing would nearly quadruple electricity production from biomass.

Most of the biomass co-firing investigations to date have focussed on introducing solid biomass into the boiler furnace through existing coal burners. Whether the biomass is pre-mixed with coal, or has its own feed system, it is required to be clean, dry, and small in size to minimise the impact on the equipment and boiler performance. The conclusion of these technical reviews has been to limit the energy contribution of biomass to typically 10 per cent or less of the boiler heat input. Even at these limited co-firing rates, plant owners have raised numerous concerns about negative impacts on plant operations. These include:

• negative impact on plant capacity;

• negative impact on boiler performance;

• ash contamination impacting ability to sell coal ash;

• increased operation and maintenance costs;

• limited potential to replace coal (generally accepted to be 10 percent on an energy basis);

• minimal NOx reduction potential;

• boiler fouling/slagging due to high alkali in biomass ash; and

• negative impacts on selective catalytic reduction air pollution control equipment (catalyst poisoning).

All of the above factors have the potential to degrade the economic competitiveness of coal fired power plants. Further, they result in significant operational and maintenance headaches for plant managers to deal with a major barrier to widespread implementation of biomass co-firing.

The gasification alternative

An alternative method of biomass co-firing that virtually eliminates the concerns with traditional co-firing has been investigated by Black & Veatch and Energy Products of Idaho (EPI). This alternative method employs fluidised bed gasification to convert the energy of the solid biomass into a low energy gas ("syngas") to be fired in the boiler. Additionally, the syngas can be used as a reburn fuel to significantly reduce NOx emissions. In addition to NOx reductions, the system would reduce emissions of sulphur dioxide, mercury, carbon dioxide and other pollutants. These reductions have economic value in addition to the value of the green power produced.

Syngas co-firing rates greater than 10 per cent can be readily accommodated. In fact, theoretically, biomass gasification could be used to completely re-power an existing coal plant, provided sufficient biomass was available in the area. This may be an attractive option for utilities with ageing coal fleets that have to meet new renewable energy mandates.

There are two basic alternatives for the gasification co-firing system. The first is a fluidised bed gasifier followed by a cyclone to remove char and ash from the syngas stream before it is delivered to the boiler. Although this is not essential, for maximum efficiency the char and ash are fed to a secondary fluidised bed combustor that burns the char. The resulting energy is used to preheat the gasifier primary air. The second alternative eliminates the cyclone and the associated char combustor and supplies a mixture of syngas, char and ash directly to the boiler. The first alternative minimises negative impacts on the coal furnace, particularly with regard to ash issues such as slagging/fouling and contamination of saleable coal ash. The second alternative is a more simple approach and has a lower capital cost. It may be preferred for low-ash, low-alkali biomass fuels such as wood waste. Fuels such as poultry litter are better suited to the first alternative.

The proposed technology outlined in the diagram opposite. This diagram also includes some advanced concepts. For example, advanced gas clean-up systems could be used to remove most of the particulate matter form the hot syngas. After clean-up, the syngas can be utilised in a number of applications such as chemical synthesis and advanced power generation systems (such as combustion turbines). Further, the ash and char can be segregated with solids-separation technology and used in fertiliser production and carbon beneficiation, respectively. Potential uses of the carbon char require research, but include catalytic NOx control and activated carbon sorbets for mercury control.

Feasibility study

Biomass gasification for co-firing has been evaluated at several coal-fired power plants. The first evaluation Black & Veatch and EPI performed was for the Nebraska Public Power District (NPPD), which operates several coal units in the Midwestern United States. The US Department of Energy's Western Regional Biomass Energy Program partially funded the study.

Black & Veatch and EPI evaluated the technical feasibility and economic viability of the system as a biomass gasification retrofit at the NPPD Sheldon Station, a power plant south of Lincoln, Nebraska. The objectives of the project were to produce low cost renewable energy and reduce NOx and other emissions at the coal plant.

The biomass gasification system was sized to displace about 17 per cent of the unit 1 coal heat input. Unit 1 is a cyclone fired boiler, rated at 105 MW. Biomass co-firing would produce the equivalent of about 18 MW of green power, from an energy input of approximately 195 MBtu/h. By comparison, in a stand-alone biomass power plant the same quantity of biomass would most likely produce only 11 to 14 MW.

While various fuel sources were initially evaluated, and there are a wide variety of agricultural residues in the area, railroad tyres were selected as the most probable fuel source for a long-term supply. At about $1.00/MBtu, railroad tyres are a relatively inexpensive biomass fuel source. This cost is higher than current coal costs at the plant, but it would be very competitive in other regions of the country. The fluidised bed design of the gasifier makes it suitable for a wide variety of other agricultural and opportunity waste fuels.

The estimated cost for the biomass gasification system varied from $8 to $13 million, depending on options for biogas cleanup and modifications to the existing boiler systems. This is $450 to $725/kW (of biomass capacity), which is much lower than a stand-alone biomass power plant and other renewable energy options (see Table 1).

Performance modelling

Using input from the current boiler operations, Black & Veatch modelled boiler performance under existing and proposed co-firing conditions. The analysis featured the use of VISTA, an evolution of the widely used coal quality impact model (CQIMTM) that Black & Veatch developed with the Electric Power Research Institute in 1989. The VISTA analysis provided a complete examination of the effects of the biomass gas on the existing unit's performance, availability, fuel costs, operation and maintenance costs and other parameters. Predicted performance from the model compared favourably with existing data, and validated the use of the model for performance predictions.

The results of the VISTA analysis show that the introduction of biomass derived syngas into a reburn zone above the main coal cyclone burner level can significantly reduce emissions of NOx and maintain system performance. In the best case, NOx levels were projected to decrease from 0.94 lb/MBtu to 0.55 lb/MBtu. It is possible that, depending upon individual boiler configurations and operating parameters, significantly higher reductions of NOx might be obtained. Based on the analyses of the existing coal fuel and the proposed biomass fuel, the predicted emissions of other pollutants such as SOx and mercury are also reduced. Considering the renewable content of the biomass portion, the CO2 cycle emissions are also significantly improved.

Based on the analysis, negative impacts on boiler performance are largely avoided. In fact, the model predicted maintenance of boiler capacity while achieving a slightly higher boiler efficiency. The model also predicted slight improvements in coal plant operations and maintenance cost, auxiliary power consumption and unit availability. These are largely owing to the reduced coal handling requirements and reduction of ash passing through the unit. Savings in these areas are essentially offset by the increased requirements of the biomass gasification equipment.

Economic drivers

Information from the VISTA analysis was combined with other information to develop a comprehensive economic model of the proposed project. The strongest impacts on project economic viability are:

• cost of coal;

• cost and availability of biomass;

• environmental regulations (availability of credits for reductions in NOx, CO2, SOx, etc); and

• renewable energy mandates and incentives.

All of these variables are determined largely by the plant location. Unfortunately for the proposed project, NPPD has very low coal costs, limited biomass availability, no driving economic regulations, and no current renewable energy mandates or incentives. Nevertheless, even in this "worst case" scenario only a small green premium of 1.4 to 1.8 US cents/kWh would be required to ensure economic viability. As shown in Table 1, this premium is competitive with other renewable energy options, even in this location. The premium could be provided through retail green energy programmes, the sale of wholesale renewable energy credits, or expanded tax incentives for renewable generation. (In the US, the 1.8 ¢/kWh tax credit enjoyed by wind has been proposed for biomass co-firing.)

Even without the premium, there are many locations where a combination of higher coal costs, credits for emission reductions (NOx, SO2, CO2, mercury, etc) and renewable energy mandates make the project economically attractive. In fact, given the right combination of factors, gasification for biomass co-firing could be a "negative cost" renewable energy resource that reduces coal plant emissions without negative consequences for existing plant operations.