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Waste Gasification

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We advocate and support greater use of Waste Gasification, and provide the
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Waste Gasification is similar to Biomass Gasification, the only difference being the materials going into the gasification plant.

Both systems operate in one of several differing manners. Some gasification systems heat the waste to high temperatures inside of a retort with minimal oxygen (creating what is known as "synthesis gas" which is a mixture of mostly hydrogen and carbon monoxide).

Gasifiers typically use a combustion reaction with some of the waste as fuel inside of the gasifier that produces the heat required for gasification. Others gasifiers use superheated steam as a catalyst to gasify red-hot coke or charcoal (resulting in "water gas", which is carbon monoxide and hydrogen).

Whichever technology or gasifier used, waste gasification turns waste into a fuel that can then be used to fuel a cogeneration, trigeneration, or combined cycle power plant.

In the chemical industry, synthesis gas is a 2:1 mixture of hydrogen and carbon monoxide. Synthesis gas is the main product produced from Biomass Gasification and Waste Gasification processes.

Another method of bioremediation and/or disposing of hazardous, toxic and MSW wastes is Plasma Pyrolysis.

Plasma Pyrolysis is the process which involves heating waste in a sealed container without outside air. The synthesis gas that is produced from Plasma Pyrolysis normally has a higher btu rating than gasification gas. Liquids are also produced as a result of the Plasma Pyrolysis process.

Waste is placed into a gasifier which is a vessel that heats waste in the absence of oxidizing air to turn it into a synthesis gas without actually burning it.

The resulting synthesis gas is mostly hydrogen (H2) and carbon monoxide (CO). These are both valuable fuel gases. Other gases such as sulfur dioxide, nitrogen oxide, water, hydrogen chloride, and carbon dioxide are also present and most of these will be removed by the scrubber.

The synthesis gas can be used in several ways. It can be burned in a reciprocating piston engine to generate mechanical energy for electricity generation. This is the least efficient way of utilizing the synthesis gas. Another method is the combustion turbine, which allows mechanical energy to be produced, and the waste heat can be used for further heat or power generation. The synthesis gas can also be used in industrial process heating or it can be fired in a traditional boiler to produce steam. The synthesis gas may also be compressed for later use.

In the biomass gasification sector, there are a large number of companies that offer a wide range of biomass gasification technologies. Some of these biomass gasification technologies are very old and highly inefficient at converting biomass to synthesis gas, in the waste to energy or waste to fuel equation. Some of these are operating as low as 27% efficiency. As a result, a large percentage of biomass is "wasted" and the

Many companies with organic waste couple a Biomass Gasification system with a cogeneration power plant, which is fueled by the Synthesis Gas, for a sustainable power and energy solution.

which converts organic waste materials into Synthesis Gas, which is then converted into E100 Ethanol, green gasoline, B100 Biodiesel, or other renewable fuels. Alternatively, the Synthesis Gas can be used as an alternative to natural gas, and used as a fuel to run a cogeneration or trigeneration power plant.

We start at the beginning and perform Biomass Gasification feasibility studies which determines the optimum solution in terms of equipment for each biomass gasification project.

Just because one company's biomass gasification unit works well at one location, and with one particular feedstock, does NOT mean it will even work for your location or feedstock. Our Biomass Gasification Feasibility Study, while costly, may save your business millions of dollars, by selecting the wrong company with the wrong biomass gasification technology.

We know of several companies that have been "living" off DOE or EPA government grants thinking they had a viable biomass gasification technology. Several of these companies, some for over 20 years, have made their only living making wild claims about their biomass gasification plant - when in reality, they were really just snake oil salesmen (and women) attempting to fleece investors (or the federal government). We know who these companies are as well as which companies have had their government grants terminated because their technology was neither viable and never made it out of their garage or warehouse.

Our Biomass Gasification Feasibility Studies are led by one or more Professional Engineers - some with Ph.D.s in engineering. All have the knowledge and experience in biomass gasification and insuring our clients have the best solution and technology - "the right equipment for the right biomass feedstock." We will only provide recommendations for proven biomass gasification companies, that have a proven track record, with at least 5 operational biomass gasification plants in continuous operation (except for routine maintenance) , for at least 5 years, that our customers are welcome to tour.

Why Choose Us?

First and foremost, we are "vendor-neutral." We are only concerned with the best biomass gasification technology, for our client's location and feedstock.

We provide solutions that can reduce or completely eliminate your company's waste stream and liabilities, and convert them to assets and profits. Our engineers have the technical expertise, depth of knowledge and and industry experience that are on the cutting edge of biomass gasification technologies.

Frequently Asked Questions

How does our company receive credit for our early actions at reducing our Greenhouse Gas Emissions?

Before taking action independently, companies should first contact us so that we can help them establish a Greenhouse Gas Emissions "inventory" which we can provide as a qualified third-party.

What is the generally accepted format for sustainability reports?

At present, most companies are using the Global Reporting Initiative (GRI) protocols as this provides for the "triple bottom line" reporting which includes social, economic and environmental performance measurements. We also focus of helping our customers maximize a "triple bottom line" solution that emphasizes "people, planet and profit."

Introduction to Electricity Generation via Biomass Gasification
The following article adapted from the Department of Energy web site by same title

The U.S. economy uses biomass-based materials as a source of energy in many ways. Wood and agricultural residues are burned as a fuel for cogeneration of steam and electricity in the industrial sector. Biomass is used for power generation in the electricity sector and for space heating in residential and commercial buildings. Biomass can be converted to a liquid form for use as a transportation fuel, and research is being conducted on the production of fuels and chemicals from biomass. Biomass materials can also be used directly in the manufacture of a variety of products.

In the electricity sector, biomass is used for power generation. The Energy Information Administration (EIA), in its Annual Energy Outlook 2002 (AEO2002) reference case, projects that biomass will generate 15.3 billion kilowatt hours of electricity, or 0.3 percent of the projected 5,476 billion kilowatt hours of total generation, in 2020. In scenarios that reflect the impact of a 20-percent renewable portfolio standard (RPS) and in scenarios that assume carbon dioxide emissions reduction requirements based on the Kyoto Protocol, electricity generation from biomass is projected to increase substantially. Therefore, it is critical to evaluate the practical limits and challenges faced by the U.S. biomass industry. This paper examines the range of costs, resource availability, regional variations, and other issues pertaining to biomass use for electricity generation. The methodology by which the National Energy Modeling System (NEMS) accounts for various types of biomass is discussed, and the underlying assumptions are explained.

Biomass has played a relatively small role in terms of the overall U.S. energy picture, supplying 3.2 quadrillion Btu of energy out of a total of 98.5 quadrillion Btu in 2000. The vast majority of it is used in the pulp and paper industries, where residues from production processes are combusted to produce steam and electricity. The industrial cogeneration sector consumed almost 2.0 quadrillion Btu of biomass in 2000. Outside the pulp and paper industries, only a small amount of biomass is used to produce electricity. There are power plants that combust biomass exclusively to generate electricity and facilities that mix biomass with coal (biomass co-firing plants). The electricity generation sector (excluding cogeneration) consumed about 0.7 quadrillion Btu of biomass in 2000. The remaining 0.5 quadrillion Btu of biomass was consumed in the residential and commercial sectors in the form of wood consumption for heating buildings. To put these numbers in perspective, the electricity generation sector consumed 20.5 quadrillion Btu of coal and 6.5 quadrillion Btu of natural gas in 2000.

Biomass played a significant role among renewables in 2000, however, providing 48 percent of the energy coming from all renewable sources. In EIA’s AEO2002 reference case projection, growth in demand for biomass is expected to be modest. In the AEO2002 high renewables case projection, the demand for biomass is higher than in the reference case due to assumptions of reduced initial capital cost and increased supply. In aggressive RPS cases, the demand for biomass is much higher than projected even in the high renewables case.

Among many reasons for increased biomass utilization in those cases, environmental benefits are the most important. Compared with coal, biomass feedstocks have lower levels of sulfur or sulfur compounds.Therefore, substitution of biomass for coal in power plants has the effect of reducing sulfur dioxide (SO₂) emissions. Demonstration tests have shown that biomass co-firing with coal can also lead to lower nitrogen oxide (NO_x) emissions. Perhaps the most significant environmental benefit of biomass, however, is a potential reduction in carbon dioxide emissions.

A closed-loop process is defined as a process in which power is generated using feedstocks that are grown specifically for the purpose of energy production. Many varieties of energy crops are being considered, including hybrid willow, switchgrass, and hybrid poplar. If biomass is utilized in a closed-loop process, the entire process (planting, harvesting, transportation, and conversion to electricity) can be considered to be a small but positive net emitter of carbon dioxide emissions. It is not precisely a net zero emission process in a life-cycle sense, because there are carbon dioxide emissions associated with the harvesting, transportation, and feed preparation operations (such as moisture reduction, size reduction, and removal of impurities). However, those carbon dioxide emissions are not the result of combustion of biomass but result instead from fuel consumption (mostly petroleum and natural gas) for harvesting, transportation, and feed preparation operations.

Although biomass-based generation is assumed to yield no new net carbon dioxide emissions because of the sequestration of biomass during the planting cycle, there are environmental impacts. Wood contains sulfur and nitrogen, which yield SO₂ and NO_x in the combustion process. However, the rate of emissions is significantly lower than that of coal-based generation. For example, per kilowatt hour generated, integrated gasification combined-cycle (IGCC) fueled by biomass, generating plants can significantly reduce particulate emissions (by a factor of 4.5) in comparison with coal-based electricity generation processes.

NO_x emissions can be reduced by a factor of about 6 for dedicated IGCC plants compared with average pulverized coal-fired plants.

Both dedicated biomass and biomass co-firing are used in the electricity generation sector. New dedicated biomass capacity is represented in NEMS as BIGCC technology. It is assumed that hot gas filtration will be used for gas cleanup purposes in this technology. Hot gas cleanup technology is relatively new, and the U.S. Department of Energy (DOE) and many industrial partners are conducting tests to demonstrate the technology. The alternative to hot gas cleaning is low-temperature gas cleaning. In low-temperature cleaning the gas is quenched with water, and particulates are removed in a series of cyclone vessels. There are advantages and disadvantages associated with both processes.

The advantages of cold gas cleaning are that it is commercially available, the capital cost is relatively low, and the systems are easier to operate than hot gas cleanup systems. The disadvantages of cold gas cleanup are that the cooling process, the cold gas cleanup system, and fuel gas recompression systems reduce the overall process efficiency by up to 10 percent. The gas turbines downstream of the biomass gasifiers that require the gas at high temperatures and pressure, and therefore the gas that has just undergone cooling for cleanup purposes must be re-pressurized and reheated in order to conform to gas turbine inlet specifications. The advantages of the newer hot gas cleanup technology are that it allows the process to be operated at higher efficiencies and it generates less waste water than the cold gas cleanup processes. The disadvantages of the hot gas cleanup technology are that operational experience is limited, it has higher costs, and it adds complexity to the process; however, it is considered to be the technologically more advanced choice for new dedicated biomass plants.

The McNeil Generating Station demonstration project in Burlington, Vermont, is an example of a biomass gasification plant. It has a capacity of 50 megawatts and supplies electricity to the residents of the City of Burlington. This is an existing wood combustion facility whose feedstock is waste wood from nearby forestry operations, including forest thinnings and discarded wood pallets. To this existing wood combustion facility a low-pressure wood gasifier has been added that is capable of converting 200 tons per day of wood chips into fuel gas. The fuel gas, fed directly into the existing boiler (Figure 1) augments the McNeil Station’s capacity by an additional 12 megawatts. The system was designed and constructed in 1998 and attained fully operational status in August 2000.

In addition to the Vermont project, DOE has funded five new advanced biomass gasification research and development projects beginning in 2001. A company in Salt Lake City, Utah, will test new IGCC and integrated gasification and fuel cell (IGFC) concepts based on new biomass gasifiers that use segregated municipal solid waste, animal waste, and agricultural residues. A company in Minnesota, has begun a project on an atmospheric gasifier with gas turbine at a malting facility, using barley residues and corn stover. A company in Iowa is developing a new combined-cycle concept that involves a fluidized-bed pyrolyzer and uses corn stover as a feedstock. A company in Connecticut, has begun a project that will test a biomass gasifiers coupled with an aero-derivative turbine with fuel cell and steam turbine options, using clean wood residues and natural gas as feedstocks. A company in North Carolina, will develop a biomass gasification process that will produce a reburning fuel stream for utility boilers, using clean wood residues. After completion of research and development tests, these projects are candidates for commercialization over the next few years.

Biomass co-firing involves combining biomass material with coal in existing coal-fired boilers. Coal-fired boilers can handle a pre-mixed combination of coal and biomass in which the biomass is combined with the coal in the feed lot and fed through an existing coal feed system. Alternatively, boilers can be retrofitted with a separate feed system for the biomass such that the biomass and coal actually mix inside the boiler.

Tacoma Public Utilities is a municipal utility that provides water, electricity, and rail services. Tacoma Steam Plant uses a fluidized bed gasification plant that can co-fire wood, refuse-derived fuel, and coal. The plant runs for only as many hours as necessary to burn the refuse-derived fuel it receives. The City of Tacoma Refuse Utility has modified its resource recovery facility to produce refuse-derived fuel. The generating plant is paid $5.50 per ton to accept the refuse-derived fuel from the Refuse Utility. A memorandum of understanding between the Refuse Utility and Tacoma Public Utilities commits the latter to burn the refuse-derived fuel for electricity generation. Coal is the most expensive fuel for the plant, making it desirable to burn as much biomass as possible. The fuel mix varies from season to season, depending on the availability of biomass feedstock. The cost of renovating the steam plant to co-fire the biomass fuel was about $45 million. Washington State’s Department of Ecology provided a grant of $15 million to partially offset the renovation costs.

Biomass for electricity generation is treated in four ways in NEMS: (1) new dedicated biomass or biomass gasification, (2) existing and new plants that co-fire biomass with coal, (3) existing plants that combust biomass directly in an open-loop process, and (4) biomass use in industrial cogeneration applications. Existing biomass plants are accounted for using information such as on-line years, efficiencies, heat rates, and retirement dates, obtained through EIA surveys of the electricity generation sector.

The biomass fuel price is calculated from regional supply curves, which are an input to the model. The raw data for the supply schedules are available at the State or county level. These are aggregated to form the regional supply schedule by North American Electric Reliability Council (NERC) region. Supply schedules are aggregated for four fuel types: agricultural residues, energy crops, forestry residues, and urban wood waste/mill residues. Table 2 shows the biomass supply available in the United States. The data in Table 2 are based on survey and modeling work by ORNL and the USDA. Table 2 represents the maximum supply available in the various regions at a price of $5 per million Btu. A brief description of each type of biomass is provided below:

By 2020, the United States is estimated to have a maximum of 7.1 quadrillion Btu of biomass available at prices of $5 per million Btu or lower. Agricultural residues, forestry residues, and urban wood waste/mill residues are currently available. EIA also assumes that energy crops can become available on a commercial basis beginning in 2010. By 2020, the four biomass types are projected to be fairly evenly divided, with agricultural residues providing most of the supply and urban wood waste/mill residues providing the least amount at the high end of the supply curves.

Figure 2 shows the variation in the resource as a function of price. A relatively small portion of the supply is available at $1 per million Btu or less. Feedstock cost is a contributing factor that keeps the growth of biomass-based electricity generation at low levels under AEO2002 reference case conditions. The available low-cost feedstock (<$1 per million Btu) is almost exclusively urban wood waste and mill residues. This category of biomass continues to be the only significant resource available at prices up to about $2 per million Btu. At that price level, agricultural residues become viable as a second source of biomass. Energy crops and forestry residues begin to make significant contributions at prices around $2.30 per million Btu or higher. A brief description of the methodology by which the supply curves are derived is provided below. Table 3 shows the biomass quantities, expressed in various units, that are projected to be available at different price levels.

The underlying assumption behind the agricultural residue supply curve is that after each harvesting cycle of agricultural crops, a portion of the stalks can be collected and used for energy production. Agricultural residues cannot be completely extracted, because some of them have to remain in the soil to maintain soil quality (i.e., for erosion control, carbon content, and long-term productivity). It is assumed that 30 to 40 percent of the residues could be removed from the soil, depending on the State. In terms of acreage, the most important agricultural commodity crops being planted in the United States are listed in Table 4. Corn, wheat, and soybeans represent about 70 percent of total cropland harvested.

The agricultural residue supply curve used in NEMS incorporates only the residues available from corn stover and wheat straws. While this may appear to understate the agricultural residues that are potentially available for energy production, there are compelling reasons for excluding other types of commodity crops. In the case of hay, the whole crop is harvested and fed to livestock; therefore, it is assumed that there would be no useful amount of residue available. An attempt has been made to produce alfalfa, pellet the leaves using adhesive materials, and use the stems as biomass. The processing costs were too high, however, and there was no market for alfalfa pellets in the United States. In the case of tobacco the whole plant is used, leaving little or no residue. Residue from soybeans is relatively small and tends to deteriorate rapidly in the field, making it unsuitable for collection and energy extraction. Barley, oats, rice, and rye are produced in relatively small geographical areas and thus are not likely to have an impact on the national biomass supply curve.

The procedure for estimating the agricultural residue supply curve is as follows. Data on the quantities of corn and wheat produced in each State are available from the USDA. From the harvested quantities of corn and wheat grain, a certain amount must be subtracted, representing the amount that the farmer needs to leave on the soil in order to maintain organic matter and prevent erosion. The quantity of residue that must remain depends on the crop type and rotation, soil type, weather conditions, and the tillage system. ORNL is currently preparing detailed estimates of how much residue needs to remain on the soil, taking into consideration these factors. For NEMS, only State-wide average yields and soil carbon needs using a reduced till practice (somewhat similar to mulch till and continuous crop rotations) are being considered.

The price of corn stover and wheat straw includes three components: the cost of collecting the residues, a transportation cost for transporting the material from the farm gate to the energy conversion facility, and a premium paid to farmers to encourage participation. For each harvest operation, a list of needed equipment is determined. Using standard engineering estimates consistent with those used by the USDA, the time per acre required to complete each operation and the cost per hour of using each piece of equipment are calculated.

Both the premiums to farmers and the transportation costs are based on current market practices. Several companies purchase corn stover or wheat straw to produce bedding, insulating materials, particle board, paper, and chemicals. These firms typically pay $10 to $15 per dry ton ($0.58 to $0.87 per million Btu) to farmers to compensate for any lost nutrient or environmental penalties (such as land erosion) that result from harvesting the residues. Studies have shown that transporting giant round bales of switchgrass costs $5 to $15 per dry ton ($0.29 to $0.87 per million Btu) for distances of less than 50 miles. Because agricultural residue bales would be of similar size, weight, and density as switchgrass bales, it is assumed that the cost of transporting bales from the farm gate to the energy conversion facility would be $10 per dry ton ($0.58 per million Btu). It is assumed by ORNL that the premium that would have to be paid to farmers would amount to $10 per dry ton ($0.58 per million Btu), for a total premium and transportation cost of $20 per dry ton ($1.16 per million Btu).

Energy crops are not currently being commercially grown in the United States. Demonstration programs are underway with DOE funding in Iowa and New York, including IES Utilities Inc.’s biomass co-firing project at its Ottumwa Station plant in Iowa, for which there are plans to produce 200,000 tons of switchgrass harvested from 40,000 to 50,000 acres of land; and NRG’s Dunkirk Station at Dunkirk, New York, where willow from 400 acres of farmland is being co-fired with coal. Therefore, the energy crop supply curve in NEMS represents future resources that could be more profitable at different market prices for farmers to plant in place of existing uses of cropland. An important assumption is that energy crops will not become commercially available until 2010.

The energy crop supply curve prepared by ORNL for EIA has three components: hybrid poplar, hybrid willow, and switchgrass. ORNL uses a model called the Policy Analysis System (POLYSYS) to estimate the quantities of energy crops that could be produced at various prices. POLYSYS is an agricultural sector model that forecasts the production of major agricultural crops. In addition, it has a livestock sector and food, feed, industrial, and export demand functions. POLYSYS was developed and is maintained by the Agricultural Policy Analysis Center at the University of Tennessee and is also used by the USDA Economic Research Service to conduct economic and policy analysis. The underlying assumption in the POLYSYS model is that a farmer will plant and harvest energy crops only if the crop can be sold at a price that assures a profit higher than the profit made by producing conventional agricultural crops on the same piece of land. POLYSYS captures the interaction between energy crops and conventional crops when land is switched from conventional crops to energy crop production. As a joint project between USDA and DOE, POLYSYS has been modified to include dedicated energy crops. POLYSYS uses the 1999 USDA crop and livestock projection as a baseline and can be used to estimate deviations from that baseline.

POLYSYS considers the availability of four types of cropland in the United States: acreage that is currently being planted with traditional crops, idled acreage, acreage in pasture, and acreage in the CRP. The model assumes that energy crop production will be limited to areas that are climatically suited for their production, thus excluding all States in the Rocky Mountain and Western Plains regions. The rationale for these exclusions is that there is a natural rain gradient in the United States, as a result of which land to the west of the gradient generally requires irrigation for crop production, which may have significant environmental penalties. Irrigation has been excluded as a viable management practice for energy crop production. All land east of the rain gradient has been included in POLYSYS, but land to the west has been excluded. Future genetic improvements in energy crops could, however, extend this range.

A POLYSYS model run using assumptions that optimize the yield of biomass was used for NEMS. These assumptions apply only to the acreage under CRP programs and not to acreage currently planted, in pasture, or idle. Different management practices are assumed for CRP and non-CRP acres, because the CRP acres are among the most environmentally sensitive cropland and because CRP is explicitly an environmental program.

Energy crop yields in the supply curve vary within and between States and are based on field trial data and expert opinion. Table 5 shows the energy crop yield assumptions that have been used for POLYSYS. The variation in yields is due to differences in weather and soil conditions across the country. The lowest yields are assumed to be in the Northern Plains and the highest in the heart of the corn belt, as is the pattern observed with traditional crops. In addition, POLYSYS assumes that different varieties of switchgrass, hybrid poplar, and willow are produced in different parts of the country, with different yield assumptions. Energy crop production costs are estimated using the same full-cost accounting approach that is used by USDA to estimate the cost of producing conventional crops. The approach includes both fixed costs (such as equipment) and variable costs (such as labor, fuel, seed, and fertilizers).

Switchgrass stands are assumed to remain in production for 10 years before replanting, to be harvested annually, and to be delivered as large round bales. The plants can regenerate, and the same plant can continue to produce switchgrass for up to 10 years. It is assumed that new switchgrass varieties will have been developed after 10 years, and that it will be financially beneficial to plow under the existing switchgrass stand and replant with a new variety. Once established, a switchgrass field could be maintained in perpetuity, but the advantages of new, higher yield varieties would warrant periodic replanting.

Hybrid poplars are assumed to be planted at spacings of 8 feet by 10 feet (545 trees per acre) and to be harvested after 6, 8, and 10 years of growth in the Pacific Northwest, southern United States, and northern United States, respectively. Harvesting is assumed to be by custom operation, and the product is assumed to be delivered as whole tree chips.

Willow production is assumed only in the northern United States. Willows can technically be grown throughout the entire eastern United States, but limited research has been done for areas outside the Northeast and North Central regions. Willows are produced in a coppice system with a replant every 22 years. They are planted in 2 x 3 double rows (6,200 trees per acre) with first harvest in year 4 and subsequent harvests every 3 years for a total of 7 harvests. Willow is delivered as whole tree chips.

In terms of product quality, hybrid poplar and willow contain about 45 to 50 percent moisture when harvested. The trees would typically be fed into a wood chipper, which generally would provide chips between 0.5 and 1 inch square and less than 0.25 inch thick. Switchgrass is harvested at about 15 percent moisture, baled, and generally ground in a tub grinder before use.

It is assumed in POLYSYS that energy crops are produced if they generate a profit equal to or greater than those earned for existing agricultural uses of cropland. Energy crops compete for land not only with existing uses but also with each other. Under the assumed yields and management practices, switchgrass dominates the biomass supply curve due to higher average yields and lower average production costs than hybrid poplar or willow. POLYSYS provides an estimate of the farm-gate price. To that price, an average transportation cost of $10 per dry ton (1997 dollars) is added to determine the plant-gate price.

The forestry residue supply curve was derived on the basis of work done by the USDA Forest Service (USDA-FS) and ORNL. The ORNL estimate of the availability of forestry residues is based on a 1984 USDA-FS study which analyzed several types of data, including forestry inventory, logging and chipping costs, hauling distances and costs, stocking densities, wood types, slope, and equipment operability constraints. The study is the only such analysis with national coverage. More recent studies exist, but they are local or regional in scope. The fundamental approach used in the study still remains valid.

The input data were used to estimate regional supply schedules for softwood and hardwood chips for 1983 and to provide projections for 1990, 2010, and 2030. The USDA-FS study used estimates of “recoverability factors” that reduced the size of the inventory. Recoverability is used to account for the accessibility of the resource (i.e., existence of roads), whether the resource occurs in stands that are available, and how much of the resource can be retrieved (taking into account gathering problems with small pieces, breakage, etc.). The original data for the study came from a national inventory of “waste wood,” which was defined as logging residues, rough rotten salvable wood, excess sapling, and small pole trees.

The forestry residue supply curve used in NEMS is based on the 1984 USDA-FS analysis and a 1994 ORNL study by Turhollow and Cohn, which was revised in 1995 by Decision Analysis Corporation under contract to EIA. The amount of waste wood available has been updated using the most recent USDA-FS inventory data. Other adjustments to reflect the availability of waste wood include (1) the exclusion of sapling and small pole trees, (2) changes to the recoverability factors, (3) the addition of a nominal stumpage fee, and (4) conversion from 1980 dollars to 1998 dollars based on an index of agricultural prices paid. The modifications were implemented by ORNL, based on the following rationale:

1. Saplings as a source of waste wood generally do not become available below costs of $6 per million Btu (1998 dollars). Because of the relatively high cost of recovering sapling waste wood, it was excluded from the updated supply curves. The USDA-FS defines polewood as trees with greater than 5 inch dbh (diameter breast high) but smaller than saw timber trees. Although large quantities of pole trees become available at costs of about $3.60 per million Btu (1998 dollars) or higher, the polewood has potential to grow into future pulpwood or future saw timber inventory and, therefore, is not likely to be harvested by the forest products industry.

2. The recoverability factor is a resource reduction factor that takes into account three site-specific considerations: retrieval efficiency due to technology or equipment, site accessibility or existence of roads, and steepness of slopes. In modifying the recoverability factors, ORNL did not change the retrieval efficiency assumptions from those in the USDA-FS study (i.e., 50 percent of inventory is assumed to be recoverable); however, ORNL’s changes to the site access and steep slope factors reduced the inventory of softwood and hardwood that could potentially be recovered to 54 percent and 43 percent of the existing inventory, respectively. ORNL assumed that cable or helicopter logging would be necessary on steep slopes, and that in either situation it would not be economical to haul out much of the low-value wood, such as cull or branches.

3. For live cull, sound dead wood, and logging residues a stumpage fee of $2 per dry ton was assumed. The stumpage fee represents a cost to acquire the materials, based on data that was provided to ORNL by USDA’s Southern Research Station.

4. ORNL subtracted the cost of transporting forestry residues from collection sites to power plants. Therefore, the ORNL data for forestry residues represent the supply schedule at the collection point (i.e., at the edge of the forest). EIA assumes a transportation cost from the collection point to the power plant of $10 per dry ton, which is added to the forestry residue supply curve from ORNL. This constant transportation cost is applied to all regions in all years for agricultural residues, forestry residues, and energy crops.

The spatial distribution of agricultural residues, energy crops, and forestry residues varies considerably. Transportation costs are dependent on spatial distribution and on the quantity needed by a facility.³¹ Therefore, the estimation of transportation costs is highly problematic for these resources. For example, the estimated transportation cost for supplying switchgrass to hypothetical facilities in Tennessee varies by 50 percent among facilities of the same size and increases on average by 30 percent when the facility demand changes from 100,000 dry tons per year to 630,000 dry tons per year. Similar or even larger variations can be expected with agricultural residues, because less is removed per acre at harvest, and thus the hauling distances would have to be greater to supply a given quantity of feedstock. There are also regional differences that result from differences in road regulations and labor costs.

Estimating transportation costs for forestry residues is especially difficult, because they vary significantly depending on whether the chips are hauled on primary or secondary roads. There are no national studies that have examined the variations in transportation costs for different feedstocks, different regions, and different facility demands. For this reason, a uniform transportation cost of $10 per dry ton was assumed. The transportation cost for urban wood waste/mill residues, which are point sources of biomass, is calculated somewhat differently, as described below.

Most of the residues in this category are waste wood from manufacturing operations and wood that would otherwise be landfilled. Urban wood waste is further broken down into wood yard trimmings, construction residues, demolition residues, and other waste wood, including discarded consumer wood products. The mill residues are further broken down into bark residues and wood residues, both from primary mills. When available, State-level data from existing reports were used to construct supply curves of urban wood waste and mill residues. When published State-level data were not available, quantities were estimated by disaggregating reported national quantities. The dis-aggregation from national to State-level data was done by using accepted “indicators” (such as housing start data) that are correlated with residue generation.

The cost at which these residues can be obtained was estimated using processing costs, State-specific landfill tipping fees, and transportation costs. If a residue is typically landfilled, it was assumed that a 50-percent reduction in tipping fees would be offered at a waste collection facility as an incentive for people to take their wood waste to the collection facility instead of a landfill. The maximum distance beyond which transporting the residues would become prohibitive was assumed to be 100 miles from a potential biopower site. Costs were estimated for each residue type for hauling distances of 25, 50, 75, and 100 miles.

An important assumption in this analysis, was that urban wood waste and mill residues would be considered to be available only if they are not currently being used for other productive purposes. In other words, it was assumed that if urban wood waste and mill residues are currently being used for any purpose, it would not be economically attractive to divert them to electricity generation at any price.

Table 6 shows representative characteristics for different subcategories of urban wood waste and mill residues. The collection and processing costs are obtained from the available literature. While these are average collection and processing costs, the actual costs are expected to range from $0 to $8 per wet ton for mill residues and from $10 to $14 per wet ton for urban residues. A transportation cost is added to the collection and processing costs. The total expenditure in local transportation costs in 1996 was reported to be $122 billion (in 1996 dollars).³² Local trucking accounted for 506 billion ton-miles in 1996.³³ This implies a national average local freight charge of about $0.24 per ton-mile (1996 dollars). For distances of 50, 75, and 100 miles around a co-firing facility, this would translate to transportation costs of $12, $18, and $24 per dry ton ($0.70, $1.05, and $1.40 per million Btu), respectively.

The national average was converted to State averages using transportation price indexes for different geographical areas. For pallets, construction debris, and demolition debris, a particular State’s major urban-based transportation indexes were used. For primary mill residues, the State’s lowest transportation index was used to reflect the more rural nature of the location of wood processing centers. A supply curve for urban wood waste and mill residues was constructed using this methodology.

Although a significant amount of effort has gone into estimating the available quantities of biomass supply, the following uncertainties still are associated with the numbers:

Given these uncertainties, the current supply curves represent our best understanding of the availability of biomass at this point in time. Responses of the biomass, solid waste, agricultural waste, and forestry communities to market changes will determine the ultimate availability of biomass materials in the United States.

NEMS represents both dedicated biomass (BIGCC) and biomass co-firing plants for new capacity. BIGCC is treated in the same way as any other generation option in NEMS. In addition to the supply curves, which provide feedstock costs, NEMS needs the following BIGCC-specific inputs in order to generate the biomass forecast: capital cost, operating and maintenance cost (fixed and variable), project life, production tax credits, and heat rate. Table 7 shows the overnight capital costs assumed for BIGCC projects in the AEO2002 reference case. BIGCC plants are assumed to have a 4-year construction lead time. Therefore, for projects initiated in 2001, the earliest time that a plant could come on line would be 2005. The BIGCC capital cost assumption in the reference case is derived from a 1997 estimate published by DOE and the Electric Power Research Institute.³⁴ The DOE/EPRI costs are adjusted upward to take into account greater uncertainties concerning the costs for the gasification portion of the plant as opposed to the gas conditioning/power generation portion of the plant. EIA assumptions are used in place of the published values for interest during construction and contingency costs. Figure 3 shows the capital costs used in NEMS for biomass, compared with the costs used for several other technologies. BIGCC, at $1,536 per kilowatt, has a relatively high capital cost in comparison with coal- and natural-gas-based generation technologies. BIGCC capital costs are higher than coal IGCC capital costs mainly as a result of the need for additional feed preparation equipment. Capital costs are assumed to decline over time as more units are built.

Biomass co-firing is represented in NEMS by assuming that coal-fired capacity can be retrofitted for biomass co-firing at levels up to 5 percent on a heat input basis. It is assumed that, for such low levels of co-firing, no additional capital or operating and maintenance costs would be incurred. The biomass would be commingled with coal, and the mixture would be fed into the boiler through the existing coal feed system. Therefore, no new capital expenditure would be required. The existing coal feedlot operators would be able to manage the tasks of mixing biomass and coal without the need for additional labor.

It is also assumed that the biomass co-firing limits will vary by region (Table 8). The regional limits are based on the availability of biomass and of coal-fired capacity. These are the maximum upper bounds on biomass co-firing. NEMS chooses lower levels of co-firing, depending on the other generation options available in each region. It has been suggested, based on demonstration-scale tests, that biomass co-firing could be carried out at higher levels by incurring an incremental capital cost. Incorporation of this capability into NEMS is currently being investigated.

Figure 4 shows the AEO2002 reference case projection for biomass use in electricity generation. Biomass continues to be the largest nonhydroelectric renewable technology throughout the forecast horizon, growing from a capacity of about 6.7 gigawatts in 2000 to about 10.4 gigawatts by 2020, including dedicated biomass and industrial cogeneration (Table 9). In comparison, wind capacity, which has a much lower utilization rate than biomass, is projected to grow from about 2.4 gigawatts in 2000 to 9.1 gigawatts in 2020. Similarly, generation from biomass grows from 38.0 billion kilowatthours in 2000 to 64.3 billion kilowatthours by 2020 (Table 10).

AEO2002 also includes a high renewables case that assumes more favorable cost and performance characteristics for nonhydroelectric renewable energy technologies, including biomass, than are assumed in the reference case. The assumptions in the high renewables case include lower capital costs, lower operating and maintenance costs, and increased availability of biomass fuel supplies. Capital costs are assumed to be similar to those in the publication Renewable Energy Technology Characterizations. The costs are about 3 percent lower than those assumed in the reference case in the early years of the forecast period due to more optimistic assumptions about the costs for the gasification portion of the plant. In addition, it is assumed that operation and maintenance costs would be 14 percent lower than in the reference case, also based on the same document. The biomass supplies are increased by 10 percent at each step of the supply curve. Fossil and nuclear technology assumptions remain unchanged from those in the reference case.

The basic trends in the high renewables case are similar to those in the reference case, but biomass capacity increases to 12.3 gigawatts by 2020 instead of 10.4 gigawatts in the reference case (Table 9). Generation from biomass plants increases to 76.0 billion kilowatt-hours by 2020, as compared with 64.3 billion kilowatthours in the reference case (Table 10).

EIA has analyzed the impact of imposing 10-percent and 20-percent renewable portfolio standards by 2020.³⁸ The 10% RPS case assumed that a legislatively mandated nationwide RPS would require 10 percent of the Nation’s electricity to be generated from non-hydroelectric renewable energy sources in 2020 and beyond. Similarly, the 20% RPS case assumed that a legislatively mandated nationwide RPS would require 20 percent of the Nation’s electricity to be generated from non-hydroelectric renewable energy sources in 2020 and beyond. The RPS cases assumed the same NO_x and SO₂ caps as mandated by the Clean Air Act Amendments of 1990, which is the assumption made in the AEO2002 reference case.

The biomass supply curves used for the RPS cases are the same as those used for the AEO2002 reference case. The emissions caps are applied only to the electricity generation sector (excluding cogeneration) and are assumed to cover emissions from both utility-owned and independently owned electric power plants. In the 20% RPS case, as a result of the assumed nationwide legislative mandate, renewables are projected to enter the market much more rapidly than in the reference case (Tables 9 and 10). Figure 5 shows projected biomass consumption in the different cases. In the 20% RPS case, dedicated biomass is projected to provide 3.8 quadrillion Btu of energy for electricity generation by 2020. An additional 0.7 quadrillion Btu of biomass energy is projected to be consumed for co-firing and as ethanol derived from cellulose. Ethanol from cellulose utilizes biomass from the same supply curve as dedicated biomass and biomass co-firing, and thus the three biomass applications compete with each other for their respective feedstocks.

The growth of biomass generation depends on the level of renewables required by the RPS. A low RPS requirement (such as 10 percent or less by 2020) would first be met by wind, which is more economical than biomass. In addition, biomass co-firing with coal is sensitive to the growth of other electricity generation technologies. In general, biomass co-firing with coal is more economical than biomass gasification; however, it is less economical than biomass gasification in scenarios where large amounts of coal-fired capacity are projected to be retired, such as cases which assume that U.S. emission reduction targets under the Kyoto Protocol will be met exclusively through reductions in domestic carbon dioxide emissions. In the 20% RPS case, biomass gasification grows substantially by 2020, and this translates into a large demand for biomass feedstocks, which increases the feedstock cost for co-firing, making the use of biomass for co-firing uneconomical relative to biomass gasification.

The projected growth of biomass consumption in the 20% RPS case raises the question of whether or not there would be sufficient land to sustain the required level of biomass production. An analysis of the results of the 20% RPS case shows that there would be a requirement for approximately 9.6 to 14.4 million acres of land devoted to energy crops by 2020, depending on the yield obtained. There were 932 million acres of land in U.S. farms and ranches in 1997. The acreage devoted to farms and ranches has been declining steadily since the 1950s, at a rate of about 4.9 million acres per year. It is possible to grow biomass energy crops on CRP lands. Under the Farm Security and Rural Investment Act of 2002, signed into law on May 13, 2002, the acreage that can be enrolled in the CRP has been increased to 39.2 million acres. Therefore, in the 20% RPS case, if all the energy crops were planted on CRP land, approximately 24 percent to 37 percent of the CRP land would have to be devoted to energy crop production by 2020. Land use for biomass-based energy consumption is not expected to conflict with land requirements for crop production, because the land requirements for energy crops are far smaller and less than the land that has been removed from agricultural production as a result of improvements in farm productivity.

EIA’s estimation of biomass resources shows that there are 590 million wet tons (equivalent to 413 million dry tons) of biomass available in the United States on an annual basis. Historically, biomass consumption for energy use has remained at low levels, although it is the largest non-hydroelectric renewable source of electricity in the United States (considering both industrial cogeneration from biomass and electricity sector generation). The main impediment has been the cost of obtaining the feedstock. Of the estimated total resource of 590 million wet tons, only 20 million wet tons (equivalent to 14 million dry tons, or enough to supply about 3 gigawatts of capacity) is available today at prices up to $1.25 per million Btu.

Biomass use for power generation is not projected to increase substantially by 2020 in the AEO2002 reference case because of the cost of biomass relative to the costs of other fuels and the higher capital costs relative to those for coal- or natural-gas-fired capacity. Slightly more growth is projected in the high renewables case, but the difference from the reference case projection is relatively small. In the 20% RPS case, significantly more use of biomass for electricity generation is projected than in the reference case, because electric utilities would be required to generate a portion of their power from renewable resources, including biomass.

Biomass Gasification Development Services including;
Engineering, Environmental, Feasibility Studies, Feedstock,
Finance/Investments, Legal, Onsite Power Generation, Power Purchase Agreements,
Waste to Energy and Waste to Fuel Solutions

Anything that can be made from fossil fuels and petroleum products -
can also be made from biomass.

It's time we start producing "green" natural gas, gasoline and diesel fuels
from Biomass Gasification - instead of fossil fuels! It's sustainable
and far less expensive to produce the fuels we need from biomass
instead of fossil fuels!

Further evidence: when oil equals $60 per barrel, the equivalent
biomass cost equals $0.18 cents per pound

Recent pricing of biomass (wood waste) was $50 per dry ton.
This equals about $0.025 (2.5cents) per pound, or a savings of
over 15 cents per pound over oil, on an equivalent basis.

BIOMASS GASIFICATION PLANTS
NOW AVAILABLE
FOR THE FOLLOWING BIOMASS FEEDSTOCK:

Agricultural Waste
Breweries
Coal
C&D - Construction and Demolition Debris/Waste
Corn Stover
Cotton Gin Waste
Cow Manure
Crop Residues
Dairy Manure
DDGS
Distilleries
Ethanol Plants
Food Processing
Food Waste
Forest Residue
Forestry Waste
Glycerin
Lignite
MSW - Municipal Solid Wastes
Paper Sludge
Peanut Hulls
Peat
Petroleum Coke
Poultry Litter
Railroad Ties
Refuse Derived Fuel
Rice Husks
Sewage Sludge
Timber
Urban Wood Waste
Waste Coal
Wastewater
Wineries
Wood/Wood waste
Wood Chips

If your city, wastewater treatment plant, landfill or other
biomass or agricultural operation doesn't have a
Biomass Gasification plant,
you're "wasting waste" and wasting money!

We help client turn liabilities and waste
into assets and profits through
our "Waste to Energy" and "Waste to Fuel" Technologies!

Biomass gasification is NOT new. Biomass gasification has been in continuous use for over 100 years and offers the best solutions for solving energy and waste problems. Many of today's biomass gasification technologies are based on the "fluidized bed gasification" process and are the result of 20 years of research and development.

Biomass Gasification Technologies is a new company that was formed to develop own and operate biomass gasification plants that feature our cogeneration or trigeneration power plants. We are "vendor-neutral" and seek the optimum biomass gasification solution for our clients and our own biomass gasification projects.

With the pending Cap and Trade regulations and ever-increasing need for our customers to reduce their Greenhouse Gas Emissions, we are finding that more and more customers are interested in replacing their fossil fuels (natural gas, coal, diesel, etc.) or electricity with our "clean power generation" technology that generates Synthesis Gas. Synthesis Gas is produced with our clients biomass through our biomass gasification plant - a real win-win-win solution for our clients, the environment, and their bottom-line!

Our biomass gasification plants are fueled with biomass waste streams that can include most any biomass or organic material, or "waste."

Is your business, city or landfill "Wasting Waste"?

Cities and landfill owners are "wasting waste" and losing out on a huge environmental and economic opportunity!

Biomass materials and organic waste materials are now being wasted by every city and landfill, when these valuable "wastes" are disposed of in overcrowded landfills. Because there are so many landfills that have limited space - and for some cities that need this valuable real estate, we are very interested in assisting cities and landfill owners with "Landfill Reclamation."

Did you know that most landfills contain - on average - 65% organic materials that could be used as fuel in our biomass gasification plants?

In addition to about 65% of the waste streams being wasted by landfilling them, our biomass gasification plants can also convert most any carbon-based (biomass or organic) waste stream, including: urban wood waste, lawn and grass clippings, sewage sludge, railroad ties, saw dust, forestry waste, crop residues, agricultural waste, corn stover, straws and grasses, construction and demolition materials, Refuse Derived Fuels, Municipal Solid Wastes, food waste, shipping pallets, animal manure, tires and many more!

In association with the Renewable Energy Institute and our gasification technology provider, we have have developed a win-win solution and business model that helps cities (and their citizens and taxpayers) and associated landfills reduce or completely eliminate; Carbon Emissions, Carbon Dioxide Emissions and Greenhouse Gas Emissions that are associated with 65% of the wastes presently being disposed of in landfills. Better still, we can arrange to sell the green power we generate from these biomass wastes and our biomass gasification plant back to your city at a preferred price.

We also provide; biomass feasibility, biomass feedstock and biomass engineering studies. For more information and to learn if your city (or landfill) qualifies for our turnkey waste to energy solution, call/email us for more information.

We are engaged by new clients after they have identified a potential biomass feedstock. We require an initial retainer from new clients. The amount of the retainer is based upon the number of hours and resources for the specific Biomass Gasification project. Biomass Gasification engineering and biomass feedstock engineering studies are led by Professional Engineers that have expertise in biomass gasification. Clients usually want the optimum Biomass Gasification solution and technology that provides the highest return on investment for a particular feedstock or waste stream. To determine the optimum Biomass Gasification solution, we start by supplying our customers with a Biomass Engineering Feasibility and Economic Study. The fee is dependent on the number of variables and the final, agreed upon Scope of Services Agreement.

In the event that the client has a study, and is satisfied with the results, we can begin by starting the EPC (Engineering-Procurement-Construction) process.

INITIAL BIOMASS GASIFICATION ENGINEERING DESIGN SERVICES:

On a strictly "vendor-neutral" basis, we help client's with their Biomass Gasification goals, objectives and budget through our Initial Biomass Gasification Engineering Design.

Our Initial Engineering Design service is the primary instrument most of our clients use to make a "go - no go" decision regarding specific Biomass Gasification projects. In addition, our Initial Engineering Design service oftentimes helps our clients secure additional investment capital or otherwise provides project financing.

Our Initial Engineering Design service typically includes the following deliverables:

Our Detailed Engineering Design service typically includes the following deliverables:

We can also provide " turn-key" Biomass Gasification services which, in addition to engineering, also includes; equipment procurement, project construction, project management and project commissioning services.

We provide Biomass Gasification Feasibility Studies for clients considering Biomass Gasification under a strict "vendor neutral" basis.

Our Biomass Gasification Feasibility Studies form the basic foundation in our client's decision-making process and the critical answers they seek regarding Biomass Gasification - do we move forward with our plans to build a Biomass Gasification plant? Where should it be built? What are the optimum biomass feedstocks for this location? What size plant should we build? Who should build it? Which Biomass Gasification plant do we choose? Can we sell our excess power to the grid?

Our Biomass Gasification Feasibility Study will answer these important questions and more. In the event you decide to move forward with our Biomass Gasification Engineering and Feasibility Study. We require a 50% deposit to begin work.

What is "Biomass"?

Biomass is any sort of vegetation, including trees, grasses, and plant parts such as leaves, stems, and twigs. During photosynthesis, plants form carbohydrates, which form the building blocks of biomass. The solar energy that drives photosynthesis is stored in the chemical bonds of the biomass.

What is the difference between Biofuels, Biopower, and Bioproducts?

In practice, we tend to use these three different terms for three different end uses — transportation, electric power or heat, and products such as chemicals and materials. "Biofuel" is short for biomass fuel. We use the term biofuels for liquid transportation fuels, such as ethanol and biodiesel, that can be produced from biomass. We tend to use "biopower" for biomass power systems that generate electricity or industrial process heat and steam, such as combined heat and power (CHP) systems. The term "bioproduct" is short for biomass products and can be used to describe a chemical, material, or other product derived from renewable biomass resources. Renewable bioproducts are products created from plant- or crop-based resources such as agricultural crops, crop residues, and forestry residues. These products may include fabrics, plastics, and chemicals. Many of the products that could be made from renewable resources are now made from petroleum.

How much biomass is used for energy today?

Worldwide, biomass is the fourth largest energy resource after coal, oil, and natural gas. It is used for heating (such as wood stoves in homes), cooking, transportation (fuels such as ethanol and biodiesel), and for electric power generation. Researchers estimate that there are about 278 quadrillion Btu of installed biomass capacity worldwide. According to the Energy Information Administration, U.S. biomass energy consumption was more than 2.8 quadrillion Btu in 2004.

What is biomass power?

Biomass power, or biopower, uses biomass feedstocks instead of conventional fossil fuels (natural gas or coal) to generate electricity. Biomass is one of the oldest fuels known to humanity. Although primitive, the campfire illustrates the nature of using biomass for power. When the biomass is burned, it produces heat. In a power plant, this heat is used to turn water into steam. The steam is then used to turn turbines, which are connected to electric generators. Biomass Gasifiers heat the biomass to convert it into a gas that can be used in power systems such as combustion turbines or fuel cells.

Is it possible to use biomass to fuel a backup electrical generation system for wind energy?

According to the U.S. Department of Energy, Biomass Gasification is emerging as a promising technology to supply electricity and heat - especially to rural areas and businesses. These rural Biomass Gasification systems use locally available biomass fuels such as wood, crop waste, animal manures, and landfill gas.

Won't producing enough biomass for substituting petroleum require tying up our valuable agricultural land, which we need to meet our food needs?

If the question for biomass production food versus fuel, then this would be significant limits to how much energy we could produce from our land. But this is not what happens today. Choosing to produce ethanol from corn grain does not eliminate that grain from the food supply. The starch in the grain is what we use to produce ethanol. The rest of the corn kernel is processed into animal feed and other food products. Any sustainable scenario for energy production on the farm will involve both food and energy production. That said, however, we recognize that land is ultimately the limiting factor in our ability to replace petroleum with biomass.

What are energy crops?

Energy crops are grown for the specific purpose of producing energy (electricity or liquid fuels) from all or part of the resulting plant. Switchgrass, alfalfa, willow, poplar, and eucalyptus are examples of plants that can be grown as energy crops.

What is Biomass Feedstock?

Biomass Feedstock is the organic materials used in the production of biofuels such as: Biomethane, B100 Biodiesel, E100 Ethanol and Synthesis Gas.

What are Biofuel Feedstocks?

Biofuel feedstocks are the organic materials used in the production of biofuels such as: Biomethane, B100 Biodiesel, E100 Ethanol and Synthesis Gas.

Biomethane (also known as "Renewable Natural Gas") generates the highest net energy balance of all biofuels which means that it's much more efficient and economic to produce Biomethane with ANY of the potential biofuel feedstocks that may have been otherwise used to produce B100 Biodiesel or E100 Ethanol.

The most efficient method of generating Biomethane is through a process called Biomass Gasification.

Examples of biofuel feedstocks include:

For Biomethane: any organic materials - i.e. grass, leaves, corn, sugar beets, sugar cane, crude canola oil, crude coconut oil, crude jatropha oil, crude palm oil, crude rapeseed oil, which are those typical biofuel feedstocks used to produce B100 Biodiesel or E100 Ethanol.

What are "biofuels"?

Biofuels are "biorenewable energy" resources that replace non-renewable fossil fuels (crude oil, gasoline, propane, natural gas, etc.).

Since the carbon found in biofuels are found in plants and therefore "grown" through photosynthesis of plants, there are no net carbon emissions when biofuels are burned or combusted. This means that when biofuels replace non-renewable fossil fuels, greenhouse gas emissions, and carbon dioxide emissions are reduced.

For example, Biomethane is the "Renewable Natural Gas" that is produced from the anaerobic decomposition of organic material in a landfill. While Biomethane normally contain about half the btu content of typical natural gas sold by gas companies, Biomethane is a substitute form and completely replaces natural gas. Similarly, Synthesis Gas can also be used like Biomethane and natural gas (methane or CH4) and is also "carbon neutral."

Likewise, B100 Biodiesel is a substitute and completely replaces petroleum diesel on a gallon for gallon basis as does E100 Ethanol, which replaces gasoline on a gallon for gallon basis.

What is the difference between ethanol from crops like corn and from cellulosic biomass?

Grain crops such as corn yield starch or sugar, which can be readily fermented to ethanol. There is already a large, thriving, corn-to-ethanol industry in this country, and a substantial portion of the dry mill ethanol plants are owned by farmer cooperatives. Wet mill plants tend to be much larger and owned by large companies. Dry mill plants produce ethanol and animal feed (distillers dried grains).

Cellulosic biomass includes crop residues such as corn stover, as well as wood residues and wood and herbaceous energy crops, like yellow poplar and switchgrass respecively, which consists primarily of cellulose, hemicellulose, and lignin. The first two can be broken down into their component sugars for subsequent fermentation, but that breakdown (hydrolysis) is a complex and challenging task.

What is "Closed-loop Biomass"?

"Closed-loop biomass" means "any organic material from a plant which is planted exclusively for purposes of being used at a qualified facility to produce electricity."

What is "Open-loop Biomass"?

"(ii) any solid, nonhazardous, cellulosic waste material which is segregated from other waste materials and which is derived from -

"(I) any of the following forest-related resources: mill and harvesting residues, precommercial thinnings, slash, and brush,

"(II) solid wood waste materials, including waste pallets, crates, dunnage, manufacturing and construction wood wastes (other than pressure-treated, chemically-treated, or painted wood wastes), and landscape or right-of-way tree trimmings, but not including municipal solid waste, gas derived from the bio-degradation of solid waste, or paper which is commonly recycled, or

"(III) agriculture sources, including orchard tree crops, vineyard, grain, legumes, sugar, and other crop by-products or residues.

"Such term shall not include closed-loop biomass or biomass burned in conjunction with fossil fuel (cofiring) beyond such fossil fuel required for startup and flame stabilization."

Biomass Gasification Basics

Biomass fuels such as firewood and agriculture-generated residues and wastes are generally organic. They contain carbon, hydrogen, and oxygen along with some moisture. Under controlled conditions, characterized by low oxygen supply and high temperatures, most biomass materials can be converted into a gaseous fuel known as producer gas, which consists of carbon monoxide, hydrogen, carbon dioxide, methane and nitrogen. This thermo-chemical conversion of solid biomass into gaseous fuel is called biomass gasification. The producer gas so produced has low a calorific value (1000-1200 Kcal/Nm3), but can be burnt with a high efficiency and a good degree of control without emitting smoke. Each kilogram of air-dry biomass (10% moisture content) yields about 2.5 Nm3 of producer gas. In energy terms, the conversion efficiency of the biomass gasification process is in the range of 60%-70%.

Multiple Advantages of Biomass Gasification

Conversion of solid biomass into combustible gas has all the advantages associated with using gaseous and liquid fuels such as clean combustion, compact burning equipment, high thermal efficiency and a good degree of control. In locations, where biomass is already available at reasonable low prices (e.g. rice mills) or in industries using fuel wood, Biomass Gasifiers offer definite economic advantages. Biomass gasification technology is also environment-friendly, because of the firewood savings and reduction in CO2 emissions.

Biomass gasification technology has the potential to replace diesel and other petroleum products in several applications, foreign exchange.

Applications for Biomass Gasification

Thermal applications: cooking, water boiling, steam generation, drying etc. Motive power applications: Using producer gas as a fuel in IC engines for applications such as water pumping Electricity generation: Using producer gas in dual-fuel mode in diesel engines/as the only fuel in spark ignition engines/in gas turbines.

What are Biomass Gasifiers?

Biomass Gasifiers are reactors that heat biomass in a low-oxygen environment to produce a fuel gas that contains from one fifth to one half (depending on the process conditions) the heat content of natural gas. The gas produced from a Biomass gasifiers can drive highly efficient devices such as turbines and fuel cells to generate electricity.

Thermal decomposition - sometimes referred to as "thermolysis" - is a chemical reaction wherein a chemical substance splits or decomposes into at least two chemical substances when heated. The reaction is usually endothermic as heat is required to break the chemical bonds of the material(s) undergoing decomposition. The decomposition temperature of a substance is the temperature at which the substance decomposes into its' constituent atoms.

Biomethane is "renewable natural gas" made from organic sources - which starts out as "biogas" but then is cleaned up, removing the impurities in the biogas, such as carbon dioxide and hydrogen sulfide (H2S).

"Cleaned-up" and ready for use in an onsite cogeneration or trigeneration power plant, the Biomethane could also be sold to a pipeline company and completely replace the "natural gas" that is typically transported to markets via the vast underground pipeline system.

Biomethane will some day replace the "methane" that is sold by the local gas companies.

Biomethane has an unlimited supply, whereas the methane sold by gas companies has a limited supply. Biomethane is renewable, whereas the methane sold by your gas utility company is not renewable. Biomethane recovery, use and production generates "Greentags" or a "Renewable Energy Credit" for the owners and is GOOD for our environment. The production and use of the natural gas sold by the gas company does NOT generate these incentives and new revenue streams and is NOT good for our environment.

As previously mentioned, Biomethane is "naturally" produced from organic materials as they decay. Sources of Biomethane include; landfills, POTW's/Wastewaster Treatment Systems, and every tree or agricultural product that is no longer living. Biomethane also generated from animal operations where manure can be collected and the Biomethane is generated from anaerobic digesters where the manure decomposes.

Biomethane, after installation of the Biomethane equipment is essentially free, as opposed to buying natural gas, presently costing around $10.00/mmbtu.

Methanogenesis, also called Biomethanation, is the production of CH4 and CO2 by biological processes that are carried out by methanogens. Unlike the price of natural gas, which has been around $6.00/mmbtu to as high as $17.00/mmbtu this past year, Biomethane prices will tend to be more stable over the years as more and more Biomethane is produced, and produced in reliable and sustainable methods that can fuel the energy needs until a better fuel is found.

What are Fluidized Bed Boilers?

In the typical, older coal-fired boilers, coal is crushed into very fine particles (called pulverized coal) which is then blown into the boiler, and ignited. Other types of coal-fired boilers locate the burning coal on grates.

With a rather new energy technology, "fluidized bed boilers," pulverized coal coal particles "float" inside the boiler with the coal being "suspended" on upward-blowing jets of air. The red-hot mass of "floating" coal is referred to as the "bed." The floating coal on its bed, bubbles and tumbles around like the boiling lava inside a volcano. Scientists call this process and the floating coal as being "fluidized." This is how the term, "fluidized bed boiler" came about.

Why do "fluidized bed boilers" burn coal cleaner than other boiler?

First of all, a fluidized bed boiler burns coal cleaner due to the "tumbling" action which allows limestone to be mixed in with the coal.

Limestone acts as a sulfur "sponge" in that the sulfur absorbs sulfur pollutants. As the coal burns in a fluidized bed boiler, it releases sulfur. And just as rapidly, the limestone tumbling around beside the coal captures the sulfur. A chemical reaction occurs, and the sulfur gases are changed into a dry powder that can be removed from the boiler. (This dry powder — called calcium sulfate — can be processed into the wallboard we use for building walls inside our houses.)

The second reason a fluidized bed boiler burns cleaner than other types of boilers is that a fluidized bed boiler burns "cooler" at about 1,400 degrees F. The older coal-fired boilers that fluidized bed boilers are now replacing operate at temperatures nearly over twice that - at 3,000 degrees F.!

Nitrogen Oxides (NOx) form when a fuel burns hot enough to break apart the nitrogen molecules in the air which causes nitrogen atoms to join with oxygen atoms. However, 1,400 degrees isn't hot enough for this to happen, so very little NOx forms in a fluidized bed boiler.

The result is that a fluidized bed boiler can burn very dirty coal and remove 90% or more of the sulfur and nitrogen pollutants while the coal is burning. Fluidized bed boilers can also burn just about anything else — wood, ground-up railroad ties, and nearly every type of biomass / biomass feedstock.

Fluidized bed boilers are operating or being built that are 10 to 20 times larger than the small unit built almost 20 years ago at Georgetown University. There are more than 300 of these boilers around this country and the world. The Clean Coal Technology Program helped test these boilers in Colorado, in Ohio and most recently, in Florida.

A new type of fluidized bed boiler makes a major improvement in the basic system. It encases the entire boiler inside a large pressure vessel, much like the pressure cooker used in homes for canning fruits and vegetables — except the ones used in power plants are the size of a small house!

Burning coal in a fluidized bed boiler produces a high-pressure stream of combustion gases that can spin a gas turbine to make electricity, then boil water for a steam turbine — two sources of electricity from the same fuel!

Fluidized bed boilers are more efficient in generating power from coal. In fact, future boilers using this system will be able to generate 50% more electricity from coal than a regular power plant from the same amount of coal. That's like getting 3 units of power when you used to get only 2.

"Fluidized bed boilers" are one of the newest ways to burn coal cleanly. But there is another new way that doesn't actually burn the coal at all.

The electric power generation, transmission and distribution system (the electric "grid") is changing and evolving from the electric grid of the 19th and 20th centuries, which was inefficient, highly-polluting, very expensive and “dumb.”

The carbon clock tracks total carbon dioxide emissions in metric tons since 1750.

Since 1750, humans have emitted over 5 trillion pounds of carbon dioxide into the atmosphere. Roughly half of this has ended up in the oceans where it is beginning to damage the coral reefs. The other half is still in the atmosphere and causing global warming. Each pound of CO2 takes up as much space as a 500 pound person.

The formula (which should be good for a year or two) is:
C(t) = 2.58 ×1012 + 1240×t, where t is seconds since the start of 2007.

C is tonnes (metric tons) of carbon dioxide emissions.
2205 x C gives pounds of carbon dioxide emissions.

That comes to over 43 billion tons/year or over 86 trillion pounds/year.

Carbon dioxide (2) = 1 carbon atom with 2 oxygen atoms.
Carbon has relative weight 12 and Oxygen 16.
So it takes only 12 pounds of carbon to make 12+16+16 = 44 pounds of CO2.

This Means that 65% of America's Energy Supplies are Now Imported from Suppliers from Foreign Countries.

Simply put, about 65% of the gasoline in your car's gas tank, comes from a foreign country.

EVERY day, the U.S. must IMPORT over 13 million bbls of oil from foreign countries and foreign suppliers to meet demand.

At $80/barrel of oil, this also means that $1,040,000,000.00 American Dollars leave our country, EVERY DAY, to foreign countries/suppliers of our fossil fuels, to pay for the energy we need.

That's $1 Billion EVERY day leaving our economy, and going to support a foreign country's economy.

Talk about our foreign trade deficit..... nearly $400 Billion each year, leaves our country to pay for our oil addiction and the energy we need. To be exact, that's $379,600,000,000.00 American Dollars.

Millions of new and sustainable American jobs would be created here at home, if we would end our addiction to foreign fossil fuels, and quickly transition to an economy based on renewable energy and renewable fuels, produced here in the U.S.A.

According to Monty Goodell, Founder and Chairman of the Renewable Energy Institute, "our increased dependence and reliance on foreign energy supplies represents a Clear and Present Danger to our national security, our economy, and the lives and livelihood of every American. Energy - including the energy we use from imported fossil fuels, is the very "lifeblood" of the American economy as it is for every industrialized country. An economy dies without it's lifeblood of energy. This Clear and Present Danger we face is far more serious than the problems related to greenhouse gas emissions. And while greenhouse gas emissions are very serious issue, in the long-term, pales in comparison to America's vital national security interests and America's economic stability in the short term. For this reason alone, America needs to transition away from its addiction to foreign energy supplies. And America's abundant renewable energy resources such as the energy we receive from the sun, and renewable energy technologies such as concentrated solar power (CSP) plants - can supply 100% of America's power requirements with a concentrating solar power plant measuring 75 miles by 75 miles, located in the Southwest U.S. By generating America's power from concentrating solar power plants, America resolves its' short-term Clear and Present Danger as it relates to importing its energy from foreign countries, and the long-term problems relating to greenhouse gas emissions."

Continuing, Mr. Goodell states that "too many Americans have forgotten what happened to us in 1973, when the Arabs and OPEC brought the United States economy to a screeching halt during the OPEC Oil Embargo. This happened because they (mainly the country of Saudi Arabia) disagreed with our foreign policy and is the reason why they "turned off the tap" of our need for their oil supplies. When Saudi Arabia and OPEC stopped the vital flow of oil to our country in 1973, they caused an "oil shock" that severely and negatively impacted our economy.

Mr. Goodell's question for us to ponder is, "do these countries who sell us 60% of our daily energy requirements, like us and our foreign policy, or might they leverage our addiction to their fossil fuels, and turn off the tap to make us adjust or revise our foreign policy?? Like any addict, America's foreign policy may be held hostage to its addiction, and in this case, our addiction to foreign oil, may over-ride our national interests."

Have American's forgotten the gas shortages and long lines at
their gas stations to get gas during the Arab Oil Embargo of 1973?

"Apparently so." Mr. Goodell states that "in 1973, America was 'addicted' and 'over the barrel' of foreign oil to the amount of 40%. Forty percent of our energy 'needs' in 1973 came from countries - many of which didn't like us then, and I'm afraid, many of them still don't. The difference between 1973 and today - is that today we receive 50% MORE foreign oil now than we did in 1973. And now we know about the problems relating to greenhouse gas emissions that we didn't know then. America needs to change course, and change course now, in terms of its' energy supplies and how we keep America's economy strong, without the threat of being held hostage to a middle-east tyrant or regime, that could once again, turn on us, and turn off our supply of foreign oil."

"Sadly," Monty Goodell continues, "most Americans have forgotten the long lines of people waiting in their cars - lined up and waiting for gasoline at their nearby gas station, with lines that were many blocks long. And, after waiting 4-5 hours, many even waiting overnight in many places, to finally take their turn to fill up their car with gasoline, only to find that the gas station had run out of gas."

"Let me Repeat.... That was 1973 when we imported 40% of our daily energy requirements in the form of crude oil from overseas, and from foreign countries - and many of these from countries that don't like us.

Today, over 35 years later, America has yet to learn the lesson. We cannot continue our reliance on energy from foreign countries that supply us with 60% of the crude oil that our refineries use as a feedstock for producing gasoline and diesel fuel for our cars and trucks comes from overseas.

America is "over the barrel" and it's not our barrel, but the barrels of oil that we are addicted by and owned by other countries. Why have we not learned the lessons we needed to learn in 1973 when we were cut-off from the vital energy supplies we need?

Countries like China, are growing rapidly, and have an insatiable need for crude oil. China, with their booming economy, is increasingly growing in its clout and control over international supplies of crude oil - whether they do this through their ability to buy as much oil as they need on a daily basis, or whether they simply but American drilling rigs, technology, and explore and produce oil and gas from their own fields. China, is buying large amounts of oil for their country, and causing upward pricing on declining supplies. What happens if Russia, with all of their oil and natural gas, along with China and Venezuela, with or without the help of OPEC, decided to NOT sell oil to us????

America's reliance for 60% of our energy "needs" coming from foreign suppliers is un-acceptable.

The "driver" to get America to begin reducing and eliminating fossil fuel use should be our nation's national security and the welfare and safety of its citizens. And this can all begin with developing and investing in our own renewable energy resources and renewable energy technologies, let's start by putting solar on every rooftop that has a clear and unobstructed view of the Southern sky. See www.RooftopPV.com or www.DistributedPV.com for more information. Let's create incentives begin with adopting a national "Feed In Tariff" as Germany did in 1990.

	Fluidized Bed Boiler

	In a fluidized bed boiler, upward blowing jets of air suspend burning coal (or biomass) allowing it to mix with limestone that absorbs the sulfur pollutants.


Fluidized bed boiler