Fluidized Bed Gasification | Fluidized Bed | Gasification | Biomass | Waste to Energy | Syngas

Fluidized Bed Gasification
www.FluidizedBedGasification.com

Fluidized Bed Gasification

Biomass Gasification * Engineering * CHP Systems * Project Development

Plasma Gasification * Research and Development * Waste to Energy * Waste to Fuel

This Ad Space Available Through the Renewable Energy Institute

* New Customers
* Greater Market Share
* Increased Sales Revenues
* Durable Competitive Advantage
* Long-term sales and marketing solution

Fluidized Bed Gasification, Biomass Gasification
and Plasma Gasification Plants Generate

"Synthesis Gas" a "Carbon Free Energy" resource, is a renewable
fuel similar to Biomethane = Renewable Natural Gas

The Renewable Energy Institute provides Research and Development, Capital, Funding,
Business Development and Strategic Marketing Services for customers and companies engaged in:

Biomass Gasification * Plasma Gasification * Syngas Cleanup * Synthesis Gas

Waste Gasification * Waste to Energy * Waste to Fuel

There's Only One:

www.FluidizedBedGasification.com

www.FluidizedBedGasifier.com

www.FluidizedBedGasifiers.com

For more information, call/email
The Renewable Energy Institute

info@FluidizedBedGasification.com

Fluidized beds suspend solid fuels on upward-blowing jets of air during the combustion process. The result is a turbulent mixing of gas and solids. The tumbling action, much like a bubbling fluid, provides more effective chemical reactions and heat transfer. Fluidized bed combustion evolved from efforts to find a combustion process able to control pollutant emissions without external emission controls (such as scrubbers). The technology burns fuel at temperatures of 1,400 to 1,700 degrees F, well below the threshold where Nitrogen Oxides form (at approximately 2,500 degrees F, the nitrogen and oxygen atoms in the combustion air combine to form nitrogen oxide pollutants).

The mixing action of the fluidized bed results brings the flue gases into contact with a sulfur-absorbing chemical, such as limestone or dolomite. More than 95 percent of the sulfur pollutants in coal can be captured inside the boiler by the sorbent.

Pressurized Fluidized bed combustion (PFBC) builds on earlier work in atmospheric fluidized-bed combustion technology. Atmospheric fluidized bed combustion is crossing over the commercial threshold, with most boiler manufacturers currently offering fluidized bed boilers as a standard package. This success is largely due to the Clean Coal Technology Program and the Energy Department's Fossil Energy and industry partners’ R&D.

The popularity of fluidized bed combustion is due largely to the technology's fuel flexibility - almost any combustible material, from coal to municipal waste, can be burned - and the capability of meeting sulfur dioxide and nitrogen oxide emission standards without the need for expensive add-on controls.

The Clean Coal Technology Program led to the initial market entry of 1st generation pressurized fluidized bed technology, with an estimated 1000 megawatts of capacity installed worldwide. These systems pressurize the fluidized bed to generate sufficient flue gas energy to drive a gas turbine and operate it in a combined-cycle.

The 1st generation pressurized fluidized bed combustor uses a "bubbling-bed" technology. A relatively stationary fluidized bed is established in the boiler using low air velocities to fluidize the material, and a heat exchanger (boiler tube bundle) immersed in the bed to generate steam. Cyclone separators are used to remove particulate matter from the flue gas prior to entering a gas turbine, which is designed to accept a moderate amount of particulate matter (i.e., "ruggedized").

A 2nd generation pressurized fluidized bed combustor uses "circulating fluidized-bed" technology and a number of efficiency enhancement measures. Circulating fluidized-bed technology has the potential to improve operational characteristics by using higher air flows to entrain and move the bed material, and re-circulating nearly all the bed material with adjacent high-volume, hot cyclone separators. The relatively clean flue gas goes on to the heat exchanger. This approach theoretically simplifies feed design, extends the contact between sorbent and flue gas, reduces likelihood of heat exchanger tube erosion, and improves SO2 capture and combustion efficiency.

A major efficiency enhancing measure for 2nd generation pressurized fluidized bed combustor is the integration of coal gasification to produce Synthesis Gas. This fuel gas is combusted in a topping combustor and adds to the combustor's flue gas energy entering the gas turbine, which is the more efficient portion of the combined cycle. The topping combustor must exhibit flame stability in combusting low-Btu gas and low-NOx emission characteristics. To take maximum advantage of the increasingly efficient commercial gas turbines, the high-energy gas leaving the topping combustor must be nearly free of particulate matter and alkali/sulfur content. Also, releases to the environment from the pressurized fluid bed combustion system must be essentially free of mercury, a soon-to-be regulated hazardous air pollutant.

To reduce cost and carbon dioxide emissions, new sorbents are being evaluated. Sorbent utilization has a major influence on operating costs, and carbon dioxide emissions streams can result in the production and use of alkali-based sorbents.

Efforts are ongoing at the Power Systems Development Facility (PSDF) in Wilsonville, Alabama to ensure critical components and subsystems are ready for demonstration of 2nd generation pressurized fluidized bed combustion. The PSDF is operated by Southern Company Services under DOE contract to conduct cooperative R&D with industry.

Tests conducted at the PSDF in 1998 verified that a newly developed multi-annular swirl burner (MASB) provided the needed flame stability and low-NOx performance characteristics. Tests of promising new hot gas filter components and systems are continuing at the PSDF. Advances made to date in this critical technology area include the development of clay-bonded silicon carbide candle filters and the associated filter vessel. Efforts are currently focused on improved candle filter materials for enhanced durability under extreme temperatures and corrosive environment. New ceramics and ceramic-metallic composites are showing promise. Those passing laboratory screening tests will undergo testing at the PSDF.

Dry Sorbent Injection is a post-combustion technology wherein a reactive calcium or
sodium based sorbent is injected into the upper part of the furnace to react directly with the products of combustion that effectively and economically mitigates potential emissions problems in the flue gas including HCI, HF, SO2 and SO3.

Dry Sorbent Injection advantages include lower equipment costs (first cost) as well as decreases in operations and maintenance costs - and have a lower life-cycle cost than other technologies. Commonly used sorbents include reactive calcium, sodium and powdered activated carbon.

Controlling pollutants such as SO2 can also be accomplished by converting the products of combustion into sulfuric acid, or SO3, by passing the flue gas over a catalyst bed.

Fluidized Bed Combustion allows for greater than 90 percent reduction of harmful emissions (such as SO2) and also reduces the amount of thermal NOx formed because plants are operating at a much lower temperature than conventional boilers.

A "Circulating Fluidized Bed" plant eliminated most of the pollutants inside the furnace as the biomass or coal is burned. Crushed limestone, when added to the coal as it enters the combustor, captures 90 percent of sulfur pollutants. Fluidized Bed Combustion allows for a “slow burn” that reduces the formation of NOx. Integrated Gasification Combined Cycle plants involve the gasification of coal or biomass, cleaning the gas, and combusting it in a gas turbine generator to produce electricity.

What is a Circulating Fluidized Bed Boiler?

A Circulating Fluidized Bed Boiler is a fully contained state-of-the-art technology for processing solid fuels where fuel is suspended in a mixture of superheated air and sand, collectively called the "fluid bed." Reagents like limestone are added, and temperatures are controlled to directly capture the sulfur and reduce formation of Nitrogen Oxides.

Circulating Fluidized Bed Boilers produce 90% fewer emissions compared to typical coal fired power plants.

Fluidized Bed Boilers, a Bed for Burning Coal?

It was a wet, chilly day in Washington DC in 1979 when a few scientists and engineers joined with government and college officials on the campus of Georgetown University to celebrate the completion of one of the world's most advanced coal combustors.

It was a small coal burner by today's standards, but large enough to provide heat and steam for much of the university campus. But the new boiler built beside the campus tennis courts was unlike most other boilers in the world.

A Fluidized Bed Boiler

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

It was called a "fluidized bed boiler."

In a typical pulverized coal boiler, coal is crushed into very fine particles, blown into the boiler, and ignited to form a long, lazy flame. In other types of boilers, the burning coal simply rests on grates. But in a "fluidized bed boiler," crushed coal particles "float" inside the boiler, suspended on upward-blowing jets of air. The red-hot mass of floating coal — called the "bed" — would bubble and tumble around like boiling lava inside a volcano. Scientists call this being "fluidized." That's how the name "fluidized bed boiler" came about.

Why does a "fluidized bed boiler" burn coal cleaner?

There are two major reasons fluidized bed boilers are cleaner, and superior to typical coal fired power plants. One, the tumbling action allows limestone to be mixed in with the coal. Remember - limestone is a "sulfur sponge" in that it absorbs sulfur pollutants. As coal burns in a fluidized bed boiler, it releases sulfur. But 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 used for building walls inside our houses.)

The second reason a fluidized bed boiler burns cleaner is that it burns "cooler." Cooler in this sense as it is still fairly hot at about 1400 degrees F. But older coal boilers operate at temperatures nearly twice that (almost 3000 degrees F). Also, recall that nitrogen oxides form when a fuel burns hot enough to break apart the nitrogen molecules in the air and cause the nitrogen atoms to join with oxygen atoms. But 1,400 degrees isn't hot enough for that to happen, so few nitrogen oxides forms in a fluidized bed boiler.

Coal Gasification

Don't think of coal as a solid black rock. Think of it as a mass of atoms. Most of the atoms are carbon. A few are hydrogen. And there are some others, like sulfur and nitrogen, mixed in. Chemists can take this mass of atoms, break it apart, and make new substances — like gas!

One of the most advanced - and cleanest - coal power plants in the world is Tampa Electric's Polk Power Station in Florida. Rather than burning coal, it turns coal into a gas that can be cleaned of almost all pollutants. This technology is called coal gasification.

How do you break apart the atoms of coal? You may think it would take a sledgehammer, but actually all it takes is water and heat. Heat coal hot enough inside a big metal vessel, blast it with steam (the water), and it breaks apart. Into what?

The carbon atoms join with oxygen that is in the air (or pure oxygen can be injected into the vessel). The hydrogen atoms join with each other. The result is a mixture of carbon monoxide and hydrogen — this is called "Synthesis Gas."

Now, what do you do with the Synthesis Gas?

You can burn Synthesis Gas - very cleanly - and use the hot combustion gases to spin a gas turbine to generate electricity. The exhaust gases coming out of the gas turbine are hot enough to boil water to make steam that can spin another type of turbine to generate even more electricity. But why go to all the trouble to turn the coal into gas if all you are going to do is burn it?

A major reason is that the impurities in coal — like sulfur, nitrogen and many other trace elements — can remove practically all of the pollutants when coal is changed into Synthesis Gas through Coal Gasification. In fact, scientists have ways to remove 99.9% of the sulfur and small dirt particles from the coal gas. Coal Gasification is one of the best ways to clean pollutants out of coal.

Another reason is that the coal gases — carbon monoxide and hydrogen, or simply "Synthesis Gas" — don't have to be burned. They can also be used as valuable chemicals. Scientists have developed chemical reactions that turn carbon monoxide and hydrogen into everything from liquid fuels for cars and trucks to plastic toothbrushes! Today, in Tampa, Florida, and West Terre Haute, Indiana, there are power plants generating electricity through "coal gasification" instead of burning it. At a plant in Kingsport, Tennessee, coal gas is being used to make plastic for photographic film and to make methanol (a fuel that can be burned in automobile engines).

Coal Gasification could be one of the most promising ways to use coal in the future to generate electricity and other valuable products. Yet, it is only one of an entirely new family of energy processes called "Clean Coal Technologies" — technologies that can make fossil fuels future fuels.

New technologies in the "natural gas to liquids" industry decreases expenses through increased efficiencies and converts natural gas to ultra clean fuel. These facilities typically consist of three primary components: an autothermal reformer that converts the natural gas into synthesis gas, a mixture of carbon monoxide and hydrogen; a Fischer-Tropsch unit that produces synthetic crude oil from the synthetic gas; and a refining unit that upgrades the synthetic crude to ultra clean fuels. These fuels, which can then be transported through existing pipelines, are now being tested in bus fleets operated by the Washington, DC, Metropolitan Area Transit Authority and the National Park Service in Denali, Alaska.

Secure and reliable energy supplies are the backbone to
our country's freedom and economic viability

While the United States is home to an abundant supply of both natural gas and oil, there exists a supply and demand gap because much of the conventional resource base has been harvested.

Future sources of supply will come from more remote locations, increasingly complex and deeper reservoirs, and more environmentally sensitive areas. New technologies will certainly be needed to develop these resources in an environmentally and economically acceptable manner. With advanced technologies, our Nation can continue producing these valuable domestic resources while also meeting environmental protection goals.

Clean Power Generation

The clean-burning properties of natural gas make it a preferred fuel for power generation. Indeed, natural gas consumption in the power generation sector is projected to increase from 5.0 trillion cubic feet in 2003 to 9.4 trillion cubic feet in 2025. Cost-effective production, processing, transmission, and storage technologies will enable natural gas to fulfill this central role in meeting our Nation’s growing electricity needs.

However, with the recent problems relating to the price of natural gas as well as the potential harm all fossil fuels may be causing to the climate and the planet, now is the time to begin placing greater emphasis on the production of energy from fuels that do not cause such economic and environmental liability.

Best of all, all of these renewable fuels and produced in the USA - most produced from waste streams from wastewater treatment plants, landfills/municipal solid waste, and agricultural waste streams such as corn stover, rice hulls and the manure from dairy farms, chicken farms and hog farms.

Turnkey Biomass Gasification Plants,
Biomass Gasification Engineering and Feasibility Studies

We provide turnkey Biomass Gasification plants as well as Engineering and 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.

We now offer turnkey Biomass Gasification plant development services, including feasibility studies or a vendor neutral basis. Biomass Gasification plants generate "carbon free energy" and "pollution free power" and can operate on virtually every biomass feedstock. Biomass Gasification plants provide our clients with maximum returns, which means the highest revenues with the lowest operating costs, from practically any biomass feedstock. Our knowledge and expertise will help you maximize Biomass Gasification revenues at your facility.

The Synthesis Gas is then used like any other fuel, such as natural gas, which is not a renewable fuel.

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.

Biomethane is "renewable natural gas" which is produced in our Anaerobic Digesters. Biomethane is also generated by the decomposition of organic materials buried in landfills. We provide "Landfill Gas To Energy" technologies that utilize "methane recovery" systems to recover the Biomethane. The process of Biomethane production begins with organic materials and organic waste streams. Biogas is first produced from the decomposition of these organic materials but because biogas is dirty, and would destroy engines and gas turbines, the biogas first needs to be purified and cleaned - this "biogas to biomethane" process removes 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" or most of the methane that is sold by the local gas companies - the methane they presently provide is all generated from "fossil fuels."

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.

Sewage Sludge
www.SewageSludge.com

We Turn Your City or County's Sewage Sludge Problems
into Profits and Green Energy!

Renewable Energy Ventures provides the following power and energy project development services:

According to the United Nations: "It is estimated that Greenhouse Gas Emissions trading markets could be worth $2 Trillion by 2012."

As Biomethane and Synthesis Gas are near perfect fuels, in that they are renewable, eliminate new carbon emissions to the climate, and utilize "waste to fuel" technologies such as Anaerobic Digesters and Biomass Gasification - one of the first questions to answer is, "what is the size of the potential biomass resource supply in the U.S.?"

In April 2005, the DOE and the U.S. Department of Agriculture (USDA) co-published a report assessing the potential of the land resources in the U.S. for producing sustainable biomass: Biomass as Feedstock for a Bioenergy and Bioproducts Industry: The Technical Feasibility of a Billion-Ton Annual Supply. Looking at forestland and agricultural land, the two largest potential biomass sources, this study estimates that the U.S. can sustainably produce up to 1.3 billion tons of biomass feedstock by mid-century. This would be enough feedstock to produce 60 billion gallons of B100 Biodiesel and E100 Ethanol with today's technologies.

This study doesn't address the opportunities for Synthesis Gas production from biomass feedstock or Biomass Gasification technologies. Some recent estimates indicate that Biomethane and Synthesis Gas could replace up to 50% of present natural gas consumption in the U.S. and in some countries, such as Iceland, Biomethane already provides 100% of the natural gas requirements.

There are many assumptions in the Billion Ton Study report that impact these estimates for increased use of Synthesis Gas, but we believe the estimates reasonably reflect the potential availability and impact of biomass resources.

Of the total estimated resource, the study suggests that forestlands in the contiguous United States can produce approximately 368 million dry tons annually. This projection includes 52 million dry tons of fuelwood harvested from forests and woodlands, 145 million dry tons of residues from wood processing mills and pulp and paper mills, 47 million dry tons of urban wood residues including construction and demolition debris, 64 million dry tons of residues from logging and site clearing operations, and 60 million dry tons of biomass from fuel treatment operations.

By "converting" biomass wastes – such as municipal solid waste, sewage sludge, crop residues, energy crops, and manure – into biofuels, this will resolve the energy, environmental and political problems in an economical and environmentally sound manner - that will produce over one million new jobs.

According to Jeff Seisler, Director of the European Natural Gas Vehicle Association, "Biomethane has an outstanding potential as a multifaceted solution to multifaceted social problems: urban and agricultural waste management, water purification, and clean air. Urban and agricultural waste can be processed into usable methane, as can the sewage during the water purification process. Cleaning and compressing the gas for use in vehicles then provides cleaner air than petroleum-consuming vehicles."

Continuing, Mr. Seisler states about Biomethane; "this environmental 'closed loop waste-to-energy-to-fuel used in vehicles that again truck the next load of waste to the energy processing plants-substitutes fossil fuels with a renewable resource and reduces greenhouse gases 100% as compared to over gasoline vehicles (on a well-to-wheel basis).

According to Peter Boisen Chairman, of ENGVA, "various well respected European research institutes now estimate more than three times better fuel output per hectare of land used than if going for ethanol or biodiesel. Sweden currently has a 51% Biomethane share, and Switzerland 37%. France, Norway, Germany and Austria use smaller amounts for vehicles. Iceland, completely without natural gas, uses 100% biomethane in its NGVs," Boisen says. Continuing, Boisen adds, "China, India, Korea, the Ukraine, Spain and Italy are other examples of countries now starting up projects where Biomethane will be used as a vehicle fuel."

"With the energy efficiency of the gas production process at 50% to 70% it's hard to think of a more socially acceptable and economic energy value for the transportation sector," Boisen says.

"Governments need to get out of their liquid fuel paradigm to refocus and balance their policies and communications to support the development of a Biomethane infrastructure. In Europe Biomethane has the potential to replace 20% of the petroleum consumed in the transport sector by 2030."

Thursday, 29 June 2006
Sacramento, California USA and Sweden

In a ceremony held at the Ministry of the Environment in Stockholm, representatives of the Kingdom of Sweden and the State of California signed an agreement pledging the two governments and their related industries to work together to develop bioenergy, with a particular emphasis on Biomethane.

“Through a strong working relationship between its industry and government, Sweden is showing how bioenergy can be developed in a cost-effective manner that benefits its economy and environment. We are extremely pleased to have signed this Memorandum of Understanding (MOU) that will provide a basis for intensified collaboration between Swedish and California officials to develop a thriving bioenergy industry in California,” said Joe Desmond, Undersecretary for the California Resources Agency.

In particular, Sweden has been a global leader in terms of converting biowaste, largely agricultural material and residues, into usable Biomethane. This gas is then used to either generate electricity, residential heating, or as a transportation fuel.

More than 8,000 vehicles in Sweden are powered by a combination of natural gas and Biomethane. The vehicles include transit buses, refuse trucks, and more than 10 different models of passenger cars. There are more than 25 Biomethane production facilities in Sweden and 65 filling stations. The Swedish Biomethane industry has been growing at an annual rate of about 20 percent over the last five years.

According to the Swedish Gas Association, more than 50 percent of the methane used to power Sweden’s natural gas vehicles now comes from biological sources, up from 45% last year. Natural gas vehicle sales in Sweden are increasing at the rate of 25% per annum.

Sweden was motivated to develop its Biomethane industry because it has no natural gas reserves, to more efficiently manage its waste, and to meet its obligations under the Kyoto Accord. Since Biomethane is developed from methane sources that would normally release into the atmosphere, it’s considered one of the most climate friendly fuels. Methane (and Biomethane) is 21 times more reactive as a greenhouse gas than carbon dioxide (CO2). Sweden is currently meetings its objectives and schedule as outlined in the Kyoto accord.

Biomethane is developed by heating up and breaking down biomaterials in an (Anaerobic Digesters) digester. Among other raw materials, Swedish operators feed their Anaerobic Digesters with slaughterhouse waste, swine manure, and even grassy crops. After the materials breakdown over a 20 day period, technology is then used to remove the impurities and produce Biomethane. Once cleaned-up, Biomethane is 98 percent methane and easily meets the Swedish and California pipeline standards.

The Memorandum of Understanding can be accessed on the California Resources Agency Web site: http://resources.ca.gov/press_documents/CaliforniaSwedenBiofuelsMOU.pdf

2. Anaerobic Digesters mitigate and reverse climate change and global warming by preventing Biomethane to escape into the atmosphere, which is one of the major causes of climate change and global warming.

3. Anaerobic Digesters are vital for renewable energy production and helping our country's drive for energy independence.

4. EVERY wastewater treatment plant as well as ALL Concentrated Animal Feeding Operations (CAFO's) - IN EVERY COUNTRY - will soon be installing Anaerobic Digesters to prevent Biomethane from entering the atmosphere and help reverse climate change as well as for use as a renewable fuel. Or, they will be replacing their existing inefficient and inferior mechanical wastewater treatment plants, with our "Natural Wastewater Treatment" plants!

5. The country of Sweden is the global leader in Biomethane production. Sweden has identified the Biomethane opportunities and is converting biowaste derived from agricultural material and residues into usable Biomethane. The Biomethane is used to generate clean, renewable electricity, residential heating, and also as a transportation fuel. Biomass sources make up 45% of Sweden’s Biomethane. Sweden's Biomethane industry has been growing at an annual rate of around 20% over the last five years. Biomethane powers more than 8,000 transit buses, garbage trucks, and 10 different models of passenger cars in Sweden. Sweden now has more than 25 Biomethane production facilities and 65 filling stations. The country believes that since Biomethane is developed from natural, organic sources that would have been released into the atmosphere, that Biomethane is considered one of the most climate-friendly fuels. Biomethane is 98% methane and easily meets the Swedish and California pipeline standards.

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.

The Renewable Energy Institute is the Publisher for the Leading Sites
for Anaerobic Digesters and Protecting Public Health, including;

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."

Biogas is the "crude methane" that is generated from landfills (landfill gas) or from anaerobic digesters (also called "methane digesters"). In both landfills and anaerobic digesters, the biogas is generated without oxygen, hence the name, "anaerobic."

It should be pointed out that the biogas or "crude methane" generated from anaerobic digesters has zero value and cannot be used as a fuel, or sold to a gas company. This is due to the fact that the biogas produced from the anaerobic digesters contains a large number of contaminants including H2S, siloxanes, carbon dioxide and nitrogen. If used as a fuel in an engine or turbine, the engine or turbine would quickly fail. So, the crude biogas, must be cleaned to "pipeline quality gas" through the use of "natural gas treating" equipment, also referred to as "biogas to biomethane" equipment, that upgrades the biogas into biomethane, which is then a useful product that can be sold as pipeline quality gas or used as a fuel in engines or turbines.

Biogas conditioning is the process of purifying "biogas to biomethane" and removes the impurities of raw biogas, such as; H2S, CO2, nitrogen, siloxanes, H20, and other impurities.

Methane Recovery (and Biogas Recovery) is the process of recovering methane, also referred to as natural gas or CH4.

Biogas, a "crude" form of methane, can be recovered from a number of facilities and locations, including; dairy farms, landfills wastewater treatment plants using Anaerobic Digesters and cleaned up to "pipeline quality gas" with "biogas to biomethane" equipment.

Natural Gas Processing plants separate the various hydrocarbons and natural gas liquids from the pure natural gas (methane or CH4) to produce what is known as 'pipeline quality' natural gas. Natural gas pipeline companies have requirements on natural gas they buy from producers which is why the natural gas processing plants are located where they are, and why they separate the ethane, propane, butane, and pentanes from the methane. Natural gas liquids or NGLs include ethane, propane, butane, iso-butane, and natural gasoline.

The synthesis gas (syngas) produced from biomass gasification and plasma gasification plants contains a wide and varying number of pollutants and contaminants before the synthesis gas can be used as a "fuel gas." These pollutants and contaminants include;

To meet environmental emission regulations, as well as to protect downstream processes, the owner/operator of biomass gasification and plasma gasification plants must insure these are removed in a "syngas cleanup" process.

Depending on the application, the synthesis gas may also require "conditioning" to adjust the hydrogen-to-carbon monoxide (H2-to-CO) ratio to meet downstream process requirements.

In applications where very low sulfur (<10 ppmv) synthesis gas is required, converting the carbonyl sulfide (COS) to hydrogen sulfide (H2S) before sulfur removal may also be required.

Fine Particulate Removal

The synthesis gas leaving today’s biomass gasification plants and tomorrow's plasma gasification plants is normally quenched and scrubbed with water in a trayed column for fine char and ash particulate removal prior to recycle to the slurry-fed biomass gasifiers.

For dry feed biomass gasification, cyclones and candle filters are used to recover most of the fine particulate for recycle to the biomass gasifiers before final cleanup with water quenching and scrubbing. In addition, fine particulates, chlorides, ammonia, some H2S, and other trace contaminants are also removed from the synthesis gas during the scrubbing process. The "scrubbed" synthesis gas is then either reheated for COS hydrolysis and/or a sour WGS when required, or cooled in the low temperature gas cooling (LTGC) system by generating low pressure steam, preheating boiler feed water, and heat exchanged with cooling water before further processing.

Spent water from the scrubber column is directed to the sour water treatment system, where it is depressurized and decanted in a gravity settler to remove fine particulates. Solid-concentrated underflows from the settler bottom are filtered to recover the fine particulate as the filter cake, which is then either discarded or recycled to the biomass gasifiers depending on its carbon content. Water from the settler is recycled for biomass gasification uses with the excess being sent to the wastewater treatment system for disposal.

COS Hydrolysis and Water-Gas-Shift

Most of the sulfur in the coal is converted to H2S during the biomass gasification process. Depending on the specific biomass gasification temperature and moisture content, approximately 3 to 10% of the sulfur is converted to COS. To generate low sulfur synthesis gas, the COS in the product gas needs to be converted to H2S before sulfur removal via current commercial AGR processes. This is done by passing the synthesis gas from the water scrubber through a catalytic hydrolysis reactor where over 99% of the COS is converted to H2S. The scrubbed synthesis gas feed is normally re-heated to 30 to 50 °F above saturation to avoid catalyst damage by liquid water.

In applications where a high synthesis gas H2-to-CO ratio is needed, synthesis gas from the water scrubber is passed through a multi-stage reactor containing sulfur-tolerant shift catalysts to convert CO and water into additional H2 and CO2. Normally, excess moisture is present in the scrubber synthesis gas from slurry-fed gasifiers to drive the shift reaction to achieve the required H2-to-CO ratio. For most slurry-fed biomass gasification systems, a portion of the synthesis gas feed may need to be bypassed around the sour shift reactor to avoid exceeding the required product H2-to-CO ratio. Depending on the gasification process and the required H2-to-CO ratio, additional steam injection before the sour shift may be needed for dry-fed biomass gasifiers. The scrubber synthesis gas feed is normally re-heated to 30 to 50 °F above saturation to avoid catalyst damage by liquid water. Shifted synthesis gas is cooled in the LTGC system by generating low pressure steam, preheating boiler feed water, and heat exchanging it against cooling water before going through the AGR system for sulfur removal.

Mercury and Trace Elements

Current commercial practice is to pass cooled synthesis gas from LTGC through sulfided, activated carbon beds to remove over 90% of the mercury and a significant amount of other heavy metal contaminants. Due to the sulfur in the activated carbon, these beds are normally placed ahead of the AGR system to minimize the possibility of sulfur slipping back into and contaminating the cleaned synthesis gas.

Acid Gas Removal (AGR)

Raw synthesis gas exiting the particulate removal and gas conditioning systems, typically near ambient temperature at 100°F, is routed to the AGR system where H2S removal and CO2 removal from the synthesis gas occurs using either physical or chemical solvent absorption. For chemical synthesis applications which require synthesis gas with less than 1 ppmv sulfur, physical solvent processes such as Rectisol and Selexol are normally used. For power generation applications, which allow higher sulfur levels (approximately 10 to 30 ppmv sulfur), chemical solvent processes such as Methyl diethanolamine (MDEA) and Sulfinol are normally used. The physical solvent absorption processes operate under cryogenic temperatures while the chemical solvent absorption processes operate slightly above ambient temperature.

In both physical and chemical absorption processes, the synthesis gas is washed with lean solvent in the absorber for H2S removal. Cleaned synthesis gas from the Acid Gas Removal process is then sent to downstream systems for further processing. Rich solvent leaving the bottom of the absorber is sent to the regenerator, where the solvent is stripped with steam under low pressure to remove the absorbed sulfur. The concentrated acid gas stream exits the top of the stripper and is sent to the Sulfur Recovery Unit (SRU) for sulfur recovery. The regenerated lean solvent from the bottom of the stripper is cooled by a heat exchanger against the rich solvent, followed by water cooling before being sent back to the absorber to start the absorption process again. The physical solvent processes tend to co-absorb more CO2 than MDEA. Multiple step depressurization of the rich solvent, supplemented with nitrogen stripping, is employed by the physical solvent processes to reject sufficient CO2 to concentrate the acid gas from the regenerator overhead to at least 15 to 25 Vol% H2S in order to feed the Claus SRU.

Because of the need for refrigeration, as well as more complex solution flashing arrangements, physical solvent processes are two to four times more costly than MDEA-based chemical solvent processes. While the physical solvent processes have higher power consumption than the chemical solvent processes, the chemical processes have higher steam consumption which translates to reduced power output from the power train. Thus overall net power output may be similar between the two types of AGR processes.

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.


	A natural gas to liquids, or "gas liquefaction" ultra clean fuels facility.



	America's demand for natural gas is expected to grow as much as 50% by 2025. Unconventional gas resources, much of which currently are not economically recoverable, are expected to bear much of the burden of meeting this demand.