Oscar Braunbeck, Isaias Macedo and Luis A. B. Cortez

6.1. BIOMASS AVAILABILITY CAN BE ENHANCED IN BRAZIL

The most important biomass sources in Brazil are sugarcane and forest residues. The Brazilian sugar industry is almost as old as the country itself. It was based on traditional production systems for many centuries but had a turning point in 1930 when president Vargas created the Sugar and Alcohol Institute (IAA). The earliest experiments utilizing cane ethanol date from that period. However, radical changes would not take place until the Brazilian Alcohol Program (PROALCOOL) was created in the 1970s, leading to a significant expansion of sugarcane plantations in Brazil.

Today, Brazil is the largest sugarcane producer in the world, being responsible for nearly 25 per cent of the total cane production, 13.5 per cent of the sugar production and 55 per cent of the world’s ethanol. The cultivated area covered by sugarcane plantations reaches more than 5 million ha or 1.5 per cent of the total arable land in the country. Sugarcane production reached 340 million tons of cane in the 2003/04 season resulting in 24 million tons of sugar and 14 billion liters of ethanol.

The ethanol industry provides fuel for approximately four million cars driven exclusively with ethanol and approximately 24 per cent of the fuel being used in the rest of the country’s car fleet. The sugar and ethanol industry generates a turn over of US$ 12 billion and creates 600000 direct jobs in activities from agriculture to industry. It is a sector almost entirely owned by local entrepreneurs that has a significant potential to increase its participation in the country’s economy through a more intensive use of by-products.

Traditionally, sugarcane has been harvested by hand requiring the elimination of leaves by combustion in the fields. The cane-burning technique destroys nearly 25 to 30 per cent of the energy potential in the cane, which is a strong drawback seen from the perspective of the surplus energy that can be generated. However, environmental laws are being issued restricting cane burning, especially near urban areas, which is paving the way for green cane harvesting practices. By green cane harvesting, we

75 Bioenergy — Realizing the Potential

© 2005 Dr Semida Silveira Published by Elsevier Ltd. All rights reserved.

mean that the burning process is eliminated allowing for the full utilization of the cane biomass material. Green cane harvesting will require a significant move towards mechanization, a process that has only started in the Brazilian sugarcane sector.

In this chapter, we evaluate the technologies available for green cane harvesting, how they need to be improved, and how they can help enhance the biomass available for energy conversion in Brazil. We analyze some of the difficulties and barriers that need to be addressed in favor of the adoption of such technologies. We focus particularly on the technological barriers, showing how productivity of sugarcane production systems can be improved, while also helping improve the overall economy of this industry.

Capital costs of biomass-based power plants vary widely from around 1000US$/kW to 4000 US$/kW depending on the technology used for electricity generation. The calculation of the installation-related components of the specific energy cost of a typical power plant is given here.

Fuel and maintenance cost

It is estimated that a land area of 0.5-1 ha is required per kilowatt of power plant capacity, with the power plant operating at an annual plant factor of 60 per cent. Assuming that the power plant operates at an average overall efficiency of 20 per cent, 1.2 kg of fuelwood is required to generate 1 kWh.

Total cost of fuelwood = 32.4 US$/ton

Cost of fuelwood = 3.88 US cents/kWh (at a consump­

tion rate of 1.2kg/kWh of electricity generated)

Initial observations give the impression that the forest sector in Lithuania is resistant to change and thus not open to the new activities and routines needed to foster bioenergy use. A more attentive observation, however, indicate that the barriers to overcome are more complex than simply conservative thinking. Lack of incentives and coordinated policies, lack of established management practices for harvesting and marketing residues, weak internal demand, the small size of private forests as well as their risk aversion and lack of capital are some of the most difficult issues that need to be addressed.

As a starting point in this process, a project was designed to address the various elements of bioenergy systems in the Lithuanian context using the Swedish experi­ences as a reference track. A number of studies and assessments were carried out. The idea was to collect enough local information for the establishment of demon­stration projects in Rokiskis public forests, which would then provide the basis for capacity building and dissemination of know-how related to bioenergy systems in the country. Some 15 to 20 per cent of the total national fellings are performed in this region, of which approximately half takes place in state-owned forests and the other half in private properties.

Table 7.1 summarizes the main studies that were carried out in the state-owned Rokiskis forests, indicating questions that these studies were striving to answer and the main methodologies used. The following section addresses some of the major results that emerged from the various studies.

For all or most of the tests to determine the physical-mechanical and chemical fue properties, standards are important to assure the comparability of results. Most ol the fuel deliveries are settled on the basis of on-site measurements to determine moisture content, particle size and size distribution and other main fuel properties Therefore, there is a strong requisite for standards for the on-site tests. The tests should be suitable to determine the fuel properties and to assess the fuel qualitj and value at the point of fuel delivery. These on-site test methods do not need tc have the same accuracy as the actual laboratory methods but rather be simple, yei reliable and inexpensive, while being a representative assessment of the fuel value Smaller plant owners have been reluctant about this idea, as they fear that new elaborate standards for sampling and testing may force them to hire externa consultants and services from specialized laboratories. This would obviously raist the costs for bioenergy.

Three cofiring alternatives are analyzed in this study. Case A corresponds to the full displacement of natural gas for biomass in combined cycle power plants. Case В concerns a partial use of biomass, complementing natural gas in combined cycle power plants. Finally, Case C regards the use of biomass only to increase steam production, which is then used in the bottoming cycle (Rankine cycle) of a combined cycle.

All results presented here are based on computational simulations. For the purpose of simulation, some characteristics of the GE PG6101(FA) (a machine developed to operate continuously with low-heating-value fuel) were considered. Only one com­plementary result regarding Case В is based on GE Frame 7 class gas turbines, for which some characteristics of the GE PG9171(E) were taken.

The BIG-CC system considered in Cases A and В is based on an atmospheric air-blown gasifier. The gasification technology taken into account here — as well as the subsequent low-pressure gas cleaning system — is similar to that proposed by the Swedish company TPS (Termiska Processer AB). Some of the biomass projects that are aimed at the provision of electricity and are under development at pre­sent are based on atmospheric gasification technology. BIG-CC systems based on pressurized gasification are also an alternative and possibly would be more feasible for the range of capacities considered here. Atmospheric systems will probably present a lower biomass to electricity conversion efficiency but, on the other hand, in the short term, fewer problems can be expected with syngas production and its cleanup.

BIG-GT technology (generally speaking, gas turbine cycles integrated to bio­mass gasification) is still under development. The main technological issues in the demonstration of BIG-GT are concerned with (i) scaling-up the gasifier and gas­cleaning technologies and (ii) gas turbine adaptation to low-heating-content fuel. However, the main problems with the current demonstration projects seem to be the initial costs of first generation plants and the difficulties of arranging a reliable fuel supply for the lifetime of the project at a reasonable cost (Walter et al., 2000).

The simulation of BIG-CC systems is based on the schemes and hypothesis presented by Consonni and Larson (1996). Design conditions considered for the bagasse drying result in a moisture content of 15 per cent by weight at the gasifier entrance, the gas being used for drying is the HRSG flue gas. Gasification takes place with air injection, and the syngas leaves the gasifier at about 870°C.

Raw syngas composition was evaluated based on previous results of gasifier simulation performed by ASPEN® — Advanced System for Process Engineering (Walter et al., 1998b). As proxy, it was considered that sugarcane trash has the same ultimate analysis as bagasse. Bagasse and syngas compositions (raw and clean) considered in this study are presented in Table 9.1.

A code was used to evaluate gas turbine off-design performance, i. e. the gas turbine operation with syngas. Details of the procedure can be seen in Walter et al. (1998a). To avoid very high compressor pressure ratio that could dangerously reduce compressor surge margin, gas turbine derating was considered. The rise of pressure ratio under certain limits can be eventually accepted for the compressor of some industrial gas turbines (Corman and Todd, 1993) but, in general, high-pressure ratio imposes unacceptable problems concerned with the increase of shaft torque and thermal loads on airfoils, making this option very aggressive to the equipment (Johnson, 1990). For syngas burning, it was assumed that the maximum GT com­pressor pressure ratio is 16.4, while its nominal pressure ratio at ISO basis is 14.9.

A common way to derate gas turbines, i. e. to reduce their output power, is through the reduction of the maximum temperature, which is accomplished with the reduction of fuel flow. The term derating is used here to indicate a strategy for gas turbine control to avoid machine operation with a high pressure ratio. In fact,

gas turbine derating is one of the possible strategies that would allow machine conversion from natural gas to syngas. Other strategies are (i) reducing compressor air flow through control of inlet guide vanes — IGVs, (ii) enlarging the expander cross-sectional area in a permanent change, and (iii) promoting blast-air extraction after the compressor. From the viewpoint of the whole system performance, and consequently from the viewpoint of electricity generating costs, derating is the worst solution (Rodrigues et al., 2003a). However, owing to its simplicity, for the first generation of BIG-CC systems, this is most probably the way gas turbines would be converted to syngas firing.

To simplify the modeling procedure, it was considered that steam is produced in an unfired HRSG at just one pressure level, without reheating. This is a reasonable hypothesis for stand-alone BIG-CC cycles due to the requirement of a minimum temperature for HRSG exhaust gases (Consoni and Larson, 1996), but it is not the case for combined cycles burning natural gas. Indeed, it is well known that high efficiency combined cycles require two or three steam pressure levels besides reheat­ing (Bathie, 1996). For instance, for the combined cycle based on PG6101(FA), when natural gas is burned, three steam pressure levels and reheating at the intermediate pressure level is recommended. It is considered that the steam pressure at the turbine entrance is 100 bar. Steam temperature is a function of the GT exhaust gases tem­perature, while the maximum steam temperature was assumed to be 538°C. Steam is extracted from the steam turbine at 0.48 MPa to feed the deaerator, while the remaining flow is condensed at 9.6 kPa. The temperature of the HRSG feed water is assumed to be constant in all the simulated cases (120°C).

9.4. SIMULATION AND FEASIBILITY RESULTS Case A

Simulation results considering combined cycle operation using only natural gas or biomass-derived gas are presented in Table 9.2. A detailed information about this alternative can be found in Walter et al. (1998b). These simulation results correspond to combined cycle operations under the ISO basis. As can be seen, despite derating, the thermal efficiency of a gas turbine operating with syngas is higher than with natural gas, owing to the increase on gas mass flow and to the higher GT compressor pressure ratio. With syngas firing, more power is also produced by the steam bottoming cycle due to the increase of GT exhaust gas flow, but steam is produced at a lower temperature (lower exhaust gas temperature). Albeit more power production both at the gas turbine and at the steam cycle, the system net power is lower when syngas is burned due to high power consumption of plant auxiliaries (mainly the syngas compressor). As mentioned before, the simulation results for natural gas combined cycle are not optimized as it is considered that steam is generated at just one pressure level at the HRSG. A single combined cycle unit (one gas turbine, one HRSG and one steam turbine) of the same capacity can operate with efficiency as high as 53 per cent (Gas Turbine World, 2000).

For current commercial natural gas combined cycles (NG-CC), data of unit capital costs were taken from the literature (Gas Turbine World, 2000). The turnkey unit capital cost of a combined cycle based on PG6101(FA) is estimated at 680US$/kW. The levelized electricity generating cost was calculated considering the following assumptions: 30-year life, 12 per cent real pretax discount rate, capacity factor 0.85,

O&M (operation and maintenance) costs at 0.4 cents/kWh, and natural gas cost equivalent to 2.5 S/MMBTU. All costs in this study are presented in 1999 US$.

For BIG-CC systems based on atmospheric air-blown gasifiers, the installed investment cost was estimated using Eq. (1). This equation is primarily based on estimates available in the literature for the first commercial plant and incorpo­rates “learning effects” (progress ratio 0.80 and the 5th similar commercial unit). Estimates given by this equation are very close to the estimates presented by other authors for BIG-CC systems of the same net capacity.

kA igcc = 5612 (MW)’0’2953 [$/kW] (1)

For BIG-CC systems, the nonfuel operation and maintenance cost was estimated at 8.2 US$/MWh. The average cost of biomass (bagasse and trash) was estimated at 8 US$/t. To assure a proper comparison with NG-CC results, some assumptions are common in both cases as, for instance, plant-year life, real discount rate and plant capacity factor.

Estimated levelized electricity generating costs are presented in Table 9.3. The feasibility analysis is based on the evaluation of the internal discount rate (IDR) of the investment. Besides the aforementioned assumptions, it was also considered that (i) the plant construction time is two years in all cases, and 80 per cent of the investment is made during the first year, (ii) taxes are evaluated over the net revenue (as a simplification, a 15 per cent duty was considered), and (iii) the depreciation was calculated along 10 years, using a linear model. Revenues were calculated consi­dering that all electricity can be sold at 45 US$/MWh. Actually, this assumption does not correspond to the reality of the electricity market post deregulation since, in a competitive environment, investors need to define their prices either based on their actual generating costs or on their own profit expectation.

The cofiring case presented in Table 9.3 corresponds to the substitution of fuel, from natural gas to biomass. It was considered that the investment leading to this

substitution starts after four years of operation with natural gas. After the sixth year of operation, just syngas is burned at the gas turbine. The investment required for the substitution was estimated as the difference of the installed unit capital cost for both the options.

The feasibility analysis also includes the evaluation of the impact of credits based on avoided emissions of carbon dioxide. These credits could be paid, for instance, by international funds on the context of the Clean Development Mechanism to boost projects aimed at reducing carbon dioxide emissions. It was considered that these credits are free of tax duties. Simplifying the analysis, it was also considered that sugarcane has a nil carbon balance. As can be seen in Table 9.3, each dollar earned per ton of carbon dioxide not released could imply an increment on the IDR of about 0.2 per cent. The results considered two options for the natural gas combined cycle — 46 per cent, that is the simulation result, and 53 per cent, that is the expected thermal efficiency of a single combined cycle unit based on a Frame 6(FA) gas turbine (steam produced at three pressure levels, with reheating).

Another carbon finance project serves as a good example of how carbon finance can play an instrumental role as a key financing tool. The NovaGerar Landfill Project consists of a sanitary landfill site being developed in southern Brazil, in which the sponsors aim to flare the methane generated on site and generate electricity from its combustion. However, as in the Plantar case, the project sponsors did not have up-front capital to invest in the required equipment.

The project sponsors could have tried to obtain a bank loan using the power purchase agreement (PPA) from the sale of energy to the grid as collateral. However, since the energy sector in Brazil has been facing serious regulatory problems since 2000, energy distributors are highly reluctant to commit themselves through long­term PPAs. Since the project’s cash income was risky, its whole viability was doubtful and the project would probably have struggled to obtain financing for the necessary investment.

However, due to the emission reductions generated by the project and the World Bank’s commitment to acquire all the emission reductions generated until 2012
(as trustee of the Netherlands Clean Development Mechanism Facility — NCDMF) the sponsor’s supplier (i. e. a British producer and operator of flaring and energy systems) agreed to lease their equipment to the sponsor using the emission reductions income as annual payments on the lease. Therefore, the emission reductions allowed the equipment and technology supplier to provide the supplier’s credit facility necessary for the project’s implementation.

The high content of carbon dioxide equivalents in the methane generated by landfills resulted in an incremental project Internal Rate of Return of almost 25 per cent, exclusively based on the revenue streams from emission reduction. Due to the high volume of greenhouse gas emission reductions generated by the project, the carbon component not only allows for the full recovery of the supplier’s investment in the flaring system, but it can also compensate potential losses in the electricity generation cash flow. The supplier agreed with the project sponsor to be paid through a percentage of the cash income from the emission reductions. The agreement between the parties has the same period as the ERPA and also requires the emission reductions payments to be made directly in the supplier’s account in the United Kingdom, with a financial structure similar to that described in Figure 13.2.

The same sponsor is now being approached and has advanced negotiations with another international bank which may provide working capital resources for this project, using the revenues from the remaining emission reductions (i. e. the emission reductions not committed for the lease payment) as a loan repayment quite similar to the Plantar deal.

Sugarcane production in Brazil increased from 224 million tons in 1989 to 300 million tons in 1998 and 340 million tons of cane in 2003/04. The fraction of sugarcane used for ethanol production was close to 50 per cent in 1998 as opposed to approximately 65 per cent in 1989. Thus the ratio of ethanol to sugar has decreased, but still half of the cane is being used for ethanol production.

As shown in Table 6.1, the average energy balance (output renewable energy/fossil input ratio) in the Brazilian ethanol production is 9.2, an exceptional figure also when compared with other biomass systems (i. e. ethanol from corn in the US). It should be kept in mind that the figures provided in Table 6.1 are based on the current average situation of sugarcane mills in Brazil. The majority of them use bagasse to meet their needs for electric power and thermal energy, but utilize low efficiency steam-based cogeneration systems for this purpose (Goldemberg et al., 1993). As will be gathered from the discussions here, there are opportunities to further improve this balance.

In 1998, the sugarcane industry contributed nearly 200000 barrels of oil equivalent of ethanol per day to the Brazilian energy system. This contrasts with the Brazilian domestic production of nearly 1.4 million barrels of oil per day. In addition, the bagasse was being used in the cogeneration of electric, mechanical and thermal power. Bagasse is used at a rate of 0.14 ton dry matter per ton of cane, leading to an annual production of 40 million tons (dry matter). Nearly all the power from bagasse is used in-house at the mills. Estimates indicate a use of 3600 GWh for electric power plus 4500 GWh for mechanical drives, in addition to all the thermal energy requirements for processing sugarcane to ethanol and sugar.

A recent legislation is the restriction of sugarcane burning in the largest produc­tion areas of Brazil. It is expected that at least 50 per cent of the cane in the major producing areas will be harvested without burning and with mechanized techno­logies in the next 10 years. This shall result in a substantial increase in biomass availability. Together with more efficient technologies, this shift can significantly improve the overall energy balance of the system as a whole.

Table 6.2 shows an evaluation of the biomass that can be made available for energy generation as the new practice is established. The figures are based on an average trash availability of 10 tons dry matter/ha when approximately 55 per cent of the total planted area is harvested without burning the cane (55 per cent is an approximate value for the sugarcane area which can be harvested mechanically with today’s technology). Table 6.2 provides calculations for 50 and 100 per cent trash recovery since this may vary depending on agronomic considerations. The following variables have been accounted for:

• Average amount of trash in sugarcane (tops and leaves);

• Main agronomic routes to harvest green cane with trash recovery;

• Soil properties with trash left on field;

• Advantages of trash left in field for herbicide elimination;

• Trash properties as fuel;

• Recovery costs;

• Utilization of biomass as boiler fuel or for gasification;

• Environmental impacts of trash recovery/utilization.

For an annual yield of 300 million tons of cane, with a trash recovery of only 50 per cent in 55 per cent of the planted area, the annual amount of new biomass available will be around 11 million tons (DM). This biomass can be effectively used for the purpose of energy generation. Conventional technologies can be employed, such as traditional biomass fired steam boilers and furnaces. Other technologies are also being seriously considered, particularly gasification and power generation with gas turbines, and hydrolysis followed by fermentation to produce ethanol. Pilot plant developments in both areas are underway.

However, it is important to point out that the potential utilization is attractive even with conventional technologies. The development of the cogeneration energy market in Brazil is overdue. The privatization of the electricity markets, the energy crisis of 2001 and the Kyoto Protocol to the Climate Convention have raised the interest for these new opportunities which can be gradually realized as the Brazilian economy recovers. Yet, the future development is not to be taken for granted. Gas markets based on imported gas from Bolivia shall become a strong competitor in many applications (see also Walter et al., Chapter 9). Thus, there is a risk that the better environmental choice based on domestic biomass resources is left behind.

The average specific cost of energy from the biomass-based generation plant con­sidered here can be finally determined as:

Specific Cost associated with plant installation = 3.35 US cents/kWh

Maintenance cost of power plant (assumed 10% of above) = 12 US cents/kWh Cost of fuelwood =4 US cents/kWh

Total Specific Cost = 29.4 US cents/kWh

The contributions to the final unit cost from different cost components are shown in Table 10.5. It can be seen that the major components of the unit energy cost are those associated with plant installation and felling and processing.

The variation of specific energy cost with plant factors at a typical installation cost of US$ 1500 per kW, is given in Figure 10.3. It can be seen that even at an optimistic annual plant factor of 80 per cent, the specific energy cost is as high as 7 US cents/kWh. To maintain this plant factor, a 100 kW plant needs an energy plantation of 50 ha, continuously being planted, maintained and harvested.

It is generally accepted that renewable energy sources become more attractive in comparison to traditional means of electricity generation, when lower discount rates are used for economic analysis. The variation of specific energy cost with the discount rate is shown in Figure 10.4. Even at a discount rate as low as 2 per cent, the specific energy cost tends to be as high as 5.3 US cents/kWh. This is mainly because of relatively high operational costs associated with biomass-based power plants compared with other forms of renewable energy based electricity generating systems.

When considering possible involvement of the private sector in the development of biomass-based electricity generation, it is important to investigate the effect of the

power purchase tariff of the utility on the Internal Rate of Return on Equity (ROE) of the investor. Figure 10.5 shows the variation of power purchase price to be agreed with the utility for different ROE expectations of the developer of a biomass-based plant.

In Figure 10.5, it is assumed that the plant is offered with a grant component of approximately 30 per cent, while the remaining 70 per cent comes from the developer as equity. The plant is assumed to be operating at a plant factor of 60 per cent. Private sector developers usually expect an ROE of at least 20 per cent and such ROE expectations result in a required minimum power purchase price of approximately

9.5 US cents/kWh.

The motivation for developing fuel supply systems horizontally and vertically integrated with forest activities include opportunities for further development of the traditional activities themselves and future industrial expansion. Section 7.4 summarized some of the studies carried out with the purpose of evaluating resource

Table 7.1. Assessing forest fuel production in Rokiskis forest enterprise Study Main questions being asked Methodologies used

Source: Based on Studies on forestry, technology and economy of forest fuel production in Rokiskis forest enterprise prepared by the Lithuanian Forest Research Institute.

potentials and models for forest management. The models are aimed at a sustainable exploration of residues for energy purposes while also improving traditional forestry activities. Analyses and tests were conducted to screen the most cost-efficient methods and most suitable equipment for local conditions, and to verify the best ways to introduce the new practices. This section provides a brief review of the results obtained.

The extraction and processing of logging residues, such as round wood or small trees, for fuel purposes can technically be carried out in many different ways. The amount of fuel supply depends largely on the size of the felling operations, level of mechanization and how forestry activities are carried out. The main factors influ­encing the cost of forest fuel production for boiler houses include worker skills, methods used for felling, intensity of extraction, extraction distance, actual pro­ductivity of the wood chipper and transportation distance to boiler houses. The extraction costs are lowest in final cuttings due to the concentration of fuels.

Precommercial thinnings are first of all aimed at improving conditions for tree growth, but may yield a profit if aimed at fuel production. This will depend on stand conditions, productivity of machinery and labor, and fuel prices. Considering the effects on the whole forest productivity, the option should be economically attractive even if the chip price only covers production costs. In fact, producing forest fuel may considerably reduce the costs of precommercial thinnings (see Table 7.4).

More time is used to handle the felled trees in precommercial stands than in commercial or final cuttings. This is due to the small diameter breast height (dbh) and large number of stems and longer distance to the technical corridors. In addition, the collection of trees is more complicated due to the remaining stands. Forest fuel production in precommercial thinnings using hand tools diminishes the losses by 61 Lt/ha as the income for the forest fuel covers some of the traditional cost for this measure. Motor chainsaw with felling handle tools should only be used in precom­mercial thinning stands where silvicultural measures have been carried out before or in conflict stands where dbh are no less than 5 cm.

Forest fuel production in precommercial thinnings is a novelty for foresters and workers in Lithuania. The forest workers can increase their productivity by 30 per cent when using machinery. Even when handle tools are used, such as in precommercial thinnings, and additional operations need to be performed, a pro­ductivity increase of 20 per cent can be achieved among workers performing tree cutting and storage operations. But there is no sufficient knowledge of working under these new technological requirements yet. Observations indicated that the psychological attitude of the worker towards the new technologies and practices affected the results significantly but, in general, comfort levels could be achieved after a couple of days of experience, which indicates that productivity increases can be made normative rather rapidly.

The cost of forest fuel extraction depends on many factors. In Rokiskis forests, the structure of forest fuel cost was analyzed following logging operations and various cost factors from cutting to handling and transporting to boiler houses. First of all, the cost will depend on the type of cuttings. The cost is lowest in Final cuttings, and highest in precommercial cuttings for reasons explained earlier. The total cost of forest fuel produced in commercial thinning with integrated methods is 34-35 Lt/solidm3 (excluding overhead costs) chipped and transported to the heat­ing plant, while in the clear cutting the cost is 30Lt/solidm3.

Another important cost factor is machinery productivity. When the productivity of the chipper is increased from 10 to 50m3/h, the fuelwood cost may fall approx­imately 1.5 times. A third cost factor is extraction distance. With an increased transportation distance from 5 to 30 km, the cost increases by more than 50 per cent. Forest fuel transportation cost is greatly influenced by the transport equipment used. When transporting by MAZ 5516 with the trailer of 45 m3 for 30 km, forest fuel costs decrease by 25 per cent in comparison with transportation by the tractor T-150 with a trailer of capacity 25.3 m3.

In short, chipping accounts for 38.7 per cent of the final forest fuel cost in Final cuttings, this being the most significant cost factor. Transportation and extraction make up about 23-24 per cent of the total cost each (see Figure 7.2). A closer inspection indicates that machinery costs excluding fuel account for 60 per cent of the cost composition while raw material costs amount to 17.6 per cent of the total only (see Figure 7.3). This means that increased productivity of machinery through longer hours and more days of operation per year can have a substantial impact on the Final fuelwood cost.

Lithuanian stand thinning models already have high productivity. There is no particular need for radical changes here but some modifications of thinning systems

can bring advantages. This refers not to the intensity of cutting, but to the aspects of stand species composition. In addition, it is not advisable to extract all non­merchantable wood from the forests in Lithuania, not even in commercial thinnings. Forest soils can be exhausted after taking out the wood without compensation for fertilization. Some experts in Lithuania are in favor of extracting all merchantable branches and up to 30 per cent of nonmerchantable branches. However, it is advis­able that the amount of nonmerchantable branches used as fuelwood in thinnings be reduced down to 20 per cent. At this moment, there are no obstacles for forest fuel extraction in forestry legislation.

A number of advantages were observed in cuttings with integrated forest fuel production. For example, in final cuttings, lesser quantity of branches were used for technical corridors and this avoided the so-called “widening” of technical corridors. In conflict, for stands of spruce with broadleaves, some amount of broadleaves can be left to reach 15 years of age to accumulate additional amount of wood and keep the productivity of the stand at a homogeneous level. In general, the amount of produced forest fuel increases with integrated forest fuel handling technology. Table 7.2 shows the observed variations in the amount of cubic meters of forest fuel obtained per hectare when applying traditional and integrated technologies in commercial and final cutting. Integrated technologies can help increase the amount of fuel extracted to a factor of 15.

The smallest amount of forest fuel was produced in typical commercial thinnings where technical corridors had been made in the previous cutting. The amount of forest fuel produced in clear cutting areas was 58-112 solid cubic meters per hectare.

The largest amount of forest fuel was produced in aspen stands with dense understorey while smaller amounts were produced in spruce and pine stands. The amount of forest fuels increases with extraction from precommercial thinning stands, the average figure of extracted forest fuel from the precommercial thinning stands being 56 m3 solid volume per hectare.

The production cost for traditional industrial assortments decreases with inte­grated forest fuel handling. Due to more rational handling, some cost for handling the traditional industrial assortment turns over to the forest fuel assortment at the same time as the total productivity increases. Table 7.3 shows the gains obtained at each step. As shown, using integrated technology, the costs for extraction of indus­trial wood can be reduced by up to 15 per cent while fuelwood is also generated.

Comparing with traditional technology, when all branches and tops are used for technical corridors, the technology with integrated forest fuel production is very promising. However, it requires a new way of thinking about silviculture. The inte­gration of forest fuel handling requires a mobile drum wood chipper for acceptable decomposition of the forest fuel. With a better knowledge of the methodology and more skilled personnel performing the operations, the results from the integrated forest fuel handling methods can be further improved.

Activities on standardization have to be followed by the development of quality assurance systems relevant for biofuel provision and utilization. Currently, there is no quality assurance system that takes into account the whole provision chain of solid biofuels. A standard for quality assurance will be developed within CEN/ TC335/working group II (see Table 11.3).

Theoretically, quality assurance systems can be introduced in all processes of the provision chain. Figure 11.1 gives an overview of the biofuel chain, the different processes, the basic conditions and an illustration of factors influencing quality along the chain. In practice, the first step is to identify the points where the relevant physical and/or chemical parameters can be measured and controlled easily.

A motivation for quality assurance is to guarantee that the processes follow environmental laws (e. g. emission limits) or meet technical requirements at the conversion plants (e. g. avoiding corrosion). The quality of the fuel can be controlled, for example, when chemical and/or physical parameters are modified in crop pro­duction processes (e. g. modifying the nitrogen content of whole grain crops by nitrogen fertilization) or in harvesting and fuel preparation (e. g. modifying the water content of wood by storage). At the conversion plant, technical solutions are available for emissions reduction (e. g. primary and secondary measures for NOx — emissions reduction).

Measures that affect quality should be identified preferably where the costs are lower along the chain. Although different control points are practicable, it is believed that a quality assurance system shall start at the combustion plant, in coopera­tion between the fuel traders and combustion plant operators, which will ensure a trouble-free and low emission business. Additionally, the manufacturers of equip­ment for biofuel handling and combustion should take quality assurance among their considerations in the technical development of their equipment.

Specific research is being conducted to optimize the biofuel production chains and to recommend the most promising biofuel classes (respectively supply chains) for different markets. In Germany, for example, various options to modify solid biofuel characteristics such as nitrogen and water content have been identified within the production and provision of certain biofuels. This includes fertilization and storage practices. Also, options to reduce emissions within biomass burning have been studied (Thran et al., 2001). An example for the case of straw is provided here to illustrate how quality improvements can be accomplished.

Theoretically, different options are available to modify the chlorine content of straw respectively, the HCl-emissions in crop production, harvesting/preparation as well as conversion. Figure 11.2 illustrates measures for reducing chlorine content in

straw. It follows the different steps of information along the chain of production, provision and energetic utilization of straw. The arrows give an overview of straw chlorine and HC1 reduction measures potentially available, especially within crop production and biofuel conversion. The first hatched rectangle describes the feasible chlorine content that can be achieved through crop production measures (0.1 to 0.6 per cent). The second rectangle indicates the maximum tolerable chlorine contents (0.1 to about 0.4-0.5 per cent), which are derived from technical limits set by plant corrosion problems and/or emissions regulations. These measures for chlorine reduction are discussed in turn.

Crop production. One way to modify chlorine content is to make a targeted selection of straw for energetic purposes. Investigations show that the chlorine content in wheat straw varies within a lower range than oats straw. Fertilization of the grain has an important influence on straw biofuel quality. A K2S04-fertilizer, for instance, reduces the chlorine content of straw by 0.3 per cent as compared to the application of a KCl-fertilizer (Vetter and Hering, 1999).

The harvest date also influences the chlorine content. Harvesting the grain at the time of dead ripeness[14], compared to the time of full ripeness, allows further chlorine reduction (Vetter and Hering, 2000). Another option is to extend the period between harvest and straw collection from the field. One reason why this can reduce chlorine is that the straw may be washed by rain. Vetter and Hering (1999) observed that the chlorine content from (winter) barley straw was reduced from 1.12 to 0.5 per cent based on a three week “storage” on the field before straw collection (baling). Comparable conditions provided a chlorine content reduction from 0.4 to about 0.13 per cent for triticale straw.

Preparation and harvesting. Within the process of straw preparation, the chlorine content may be washed out by technical means (Nikolaisen et al., 1998). Investment costs are on the order of DKK 200 million (Danish crowns)[15] for a plant that “cleans” about 125000 to 150000 tons of straw per year. Such high costs indicate that this measure is not very attractive as a first step, the reason why it is not considered in Figure 11.2.

Conversion. Filters are often required at the conversion plant to reduce dust emissions from the stack. At the same time, these filters contribute to reduce HC1 emissions. Another measure for HC1 reduction is the use of a sorbent (e. g. lime hydrate). This allows for about 90 per cent reduction of HC1 emissions, as the chlorine is incorporated in the ash.

The example of quality assurance of the chlorine content in straw shows that there are many options to accomplish improvements in the crop production field. A lower chlorine content reduces technical risks such as corrosion at the plant, as well as emissions. Thus a quality assurance system for straw has to include crop production measures besides the options available at the conversion plant.

However, a clear and detailed description of the various steps and aspects of a quality system has to take into account the local and regional conditions for crop production, the economic implications of the various measures, and the practical experiences of the various stakeholders (farmers, supervisor at the conversion plant). More knowledge on economic and technical advantages of the different measures and processes shall allow for a more specific discussion on the options available at the regional and national levels.