H2 from Multiple Fuels & Polymeric Membrane Separation

So much is going on in hydrogen these days, but one still wonders whether truly novel developments will ultimately be the key to making H2 an economic and practical part of the energy system. H2fuel, a small technology development company in Chicago, has two important innovations that may be examples the kinds of breakthroughs that are needed.

1. Fuel Processor — Simpler cheaper integrated autothermal reformer system–sulfur tolerant

2. Polymeric Membrane — A unique new membrane that removes CO2 and H2S, by a chemical mass transport, not physical separation, while reducing CO.

H2fuel is jointly owned by Avista Labs(70%) and Unitel Fuel Technologies (30%). H2fuel is looking for investors. A business plan is available.

Lee Camara, Unitel, 847-297-2265
Mike Davis, Avista Labs, 509-228-6685

Here are some technical details, adapted from a 4-page summary the company has prepared, complete with color graphics. (download – password required):

Fuel Processor

A couple of years ago, H2fuel took over funding of work at Argonne on an autothermal reformer (ATR), and introduced new sulfur-tolerant catalysts. A key goal was to process any number of standard (sulfur bearing) fuels in the same device. The system now promises low cost, simple operation, ease of manufacture, rapid cycling (load following), and ease of manufacture.

Sulfur-tolerant water gas shift (WGS) catalysts have been qualified for both medium temperature and low temperature applications. One of the most significant breakthroughs is the elimination of the zinc oxide bed, thus allowing the H2S produced in this processor to go right through the reactor without any deleterious effects. The H2S is continuously removed by a new subsystem downstream (see below).

The CO produced in the fuel processor, ~1%, depending on the fuel, acts as a PEM fuel cell poison because it affects the anode electrocatalyst. H2fuel has developed a unique method for reducing the CO level to below 10 ppm, thus eliminating this problem.

H2fuel’s new hydrogen processor, with its sulfur-tolerant autothermal and water gas shift catalysts, and without the need for a zinc oxide bed, has been tested continuously for over 2500 hours with natural gas containing ~20 ppm sulfur compounds. During this period, it has successfully completed several load-following tests and maintained an output gas composition (dry basis) of 45% H2, 15% CO2, 1% CO, 0.4% CH4, balance N2. This reactor continues to be tested; however, the fuel is being changed to regular gasoline, and later to fuel grade ethanol.

Polymeric Membrane

On a separate front, under the auspices of a R&D program originally started at the University of Kentucky, and now being continued at Ohio State University, H2fuel has a controlling position in the IP developing polymeric membrane products and support devices to facilitate the removal of H2S and CO2 from the reformate product streams. The key component of this membrane separator is a surface layer that reacts with H2S and CO2, but not with H2 and CO. The membrane transports the reaction products from one side of the membrane to the other by mass transport. The H2S and CO2 desorb on the other side and are swept away. The H2 and CO don’t react with the membrane and are retained on the reformate side. A second membrane stage incorporates a catalyst to deplete the remaining CO in the reformate to less than 10 ppm.

This membrane technology can be used as well to clean up H2 from other production processes. Some major fuel cell companies have made clear their interest once higher temperature operation of the membrane is accomplished. — Intelligent fuel management.

A profitable existing company is going to a new stage of growth, with a new name and fully web-enabled extension of their business model. Acting directly on behalf of buyers of liquid petroleum fuels, they monitor (wireless/internet) the level of fuel in the customer’s tank, optimize fuel purchasing, and arrange delivery, taking a fixed fee per gallon delivered.

As a result, the customer:
– No longer has to manage their own fuel tank inventory
– Is assured that tanks will never run out of fuel
– No longer needs to negotiate decentralized contracts or daily pricing
– Can leverage their volume through TeamFuel purchasing power
– Is guaranteed the lowest possible price and optimal delivery of their fuel

They already have several major utilities as satisfied clients (APS, PSEG, SoCalEdison, ) and provide them with either fleet fuel or generation fuel.

The website will be up in another week or two. Dynamic Inventory Management actually occurs on password protected intranet sites, one for each client.

They are seeking equity investment in two rounds, one now and the second next year, to scale up their software/server capabilities and add sales and marketing staff.

An executive summary and business plan are available for possible investors. New customer contacts are also more than welcome. If you’d like more information, contact

Bill Green, CEO 415-381-2783

Here is a brief summary posted on (a new silicon valley company supporting startups by providing access to angel and venture investors

Each year U.S. commercial vehicle fleets, utilities, railroads, and airlines spend more than $100 billion on fuel. This fuel is stored in and distributed via a network of 200,000 tanks, which range in size from 10,000 gallons to over 100,000 gallons. The variable consumption patterns of these tanks – along with environmental compliance laws, interstate fuel tax calculations, and fluctuating fuel prices – make the procurement and management of fuel for these tanks a time consuming and expensive proposition for tank owners. TeamFuel provides an outsourced fuel management solution that acts as a intermediary between the thousands of local fuel suppliers and the tanks they service.

TeamFuel’s software and remote monitoring solutions optimize fuel purchases (via demand aggregation and market timing), resolve complex environmental and tax issues, and deliver guaranteed savings to fleets and tank owners. Unlike FuelQuest, which is a marketplace for suppliers, and FuelMan, which focuses on over-the-road fuel purchases by truck drivers, TeamFuel addresses the needs of fleets and tank owners.

TeamFuel’s dynamic inventory replenishment strategy is currently used by Walt Disney, Frito-Lay, Laidlaw, Southern California Edison, Toys “R” Us, Arizona Public Service, and 65 other companies. These customers have signed long-term management contracts, with a fixed fee per gallon, for TeamFuel’s services. The Company profitably generated revenues of $1.2 million in 1999. 2004 revenues are projected to be $88 million.

TeamFuel’s management team and 12-person staff have deep experience in the fuel and energy industry. The Company’s CEO previously founded a chemical exchange and has extensive experience in supply chain management. The founder and President of TeamFuel has been involved with fuel procurement outsourcing for more than 20 years.

Biomass Cofiring

A couple of UFTO utilities have expressed an interest in biomass cofiring, so I followed up with Sandia and also found some other resources also which you may find useful.


First, the new National Energy Technology Lab website for global climate change has a lot of information on the subject:


The 1995 UFTO report on Sandia had this brief summary on the Combustion Research Facility (CRF) that Sandia operates at its Livermore CA site…

“Over 1000 Sandia employees are located in facilities in Livermore California, and operate several special facilities, one of which is the Combustion Research Facility, the only one of its kind in DOE. Can handle industrial scale burners to 3 million BTU/hour. It is a “user facility” and outside visitors and users are encouraged. Partnerships with industry include GM, Cummins and Beckman Instruments and many others. Developed a number of specialized flame/combustion observational, measurement and diagnostic techniques. Provided fuel blending strategies to midwest utilities to meet SOx requirements. The Burner Engineering Research Laboratory is a user facility for industrial burner manufacturers.”


The CRF “Multifuel Combustor” website is currently under construction:


The CRF continues to be a significant contributor to combustion science, and in particular has amassed a major database of the combustion characteristics of over 50 different biomass fuels, most recently in the context of cofiring with coal. This work has been funded mostly by DOE, and includes information on emissions, carbon burnout, ash, and corrosion/deposition.

They’re also doing extensive computer modeling of coal, biomass and coal-biomass cofiring combustion. The coal modeling is under EPRI sponsorship, so that work is available to EPRI members. The dedicated biomass boiler modeling (stokers, etc.) is publicly available. The intellectual property issues associated with the coal-biomass cofiring are currently being sorted out, but it will be at least available to EPRI members and possibly to everyone.

For addition information, contact:

Larry Baxter 925-294-2862;
Sandia National Labs, Livermore, CA


Larry has generously supplied a copy of a brand new overview paper. Here are the first couple of pages. I have the complete 8 page overview as a (100k) Word document, which I can send on request. Larry has a more detailed article that he is willing to send to interested parties. Also, see below for some earlier reports, and a link to an upcoming American Chemical Society meeting session.



Larry Baxter, Allen Robinson, Steve Buckley and Marc Rumminger Sandia National Labs, Livermore CA

March 2000

This document presents guidelines for cofiring biomass with coal in coal-fired boilers. These guidelines are based on the results from pilot- and commercial-scale tests using a variety of biomass fuels and coals. Guidelines are offered in each of six general areas of major concern when cofiring biomass with coal: (1) fuel preparation and handling; (2) pollutant emissions; (3) ash deposition and deposit properties; (4) fuel burnout; (5) corrosion; and (6) fly ash utilization. For each of these areas, a brief statement of the issue and a brief guideline are summarized. More detailed information can be found at the cited website and in the references.

Summary of Cofiring Guidelines

We believe the following guidelines are generally valid, but there are specific instances where each of them is not valid. The discussions in the literature and web site provide the background to determine when such instances arise.

Fuel should generally be prepared and transported using equipment designed specifically for that purpose rather than mixed with coal and simultaneously processed.

Wood-coal blends generally reduce NOx emissions. This reduction is traced to lower fuel nitrogen content and higher volatile yields from biomass. SOx is nearly always reduced proportional to the reduction in total fuel sulfur associated with combining biomass with coal.

Deposition rates from blends of coal and biomass vary strongly with the type of biomass fired. Most wood-coal blends reduce both the rate of deposition and the difficulty managing the deposits. Some biomass-coal blends, in particular high alkali and high chlorine fuels, severely increase deposition problems.

Complete conversion of the carbon in biomass fuels requires that the fuel be processed to small particle sizes and be moderately dry. Particles generally need to be less than 3 mm (1/8 inch) to completely combust. Fuels that pass through a quarter-inch screen are generally dominated by particles less than 1/8 inch. High moisture contents (greater than 40%) and high particle density both significantly increase the time required to completely combust the particles.

Fuel chlorine and alkali concentrations should be limited to less than one fifth of the total fuel sulfur on a molar basis to avoid corrosion problems. This limit should be applied to the fuel composition as fired through any single burner except in the rare case of rapid and complete mixing of in the furnace.

Fly ash from wood-coal cofiring generally does not significantly degrade fly ash performance as a concrete additive. However, strict interpretation of current standards for inclusion of fly ash in concrete preclude mixed ashes, including biomass-coal ashes. Fly ash from many herbaceous fuels may negatively impact concrete properties.


Concerns regarding the potential global environmental impacts of fossil fuels used for power generation and other energy supplies are increasing in the U.S. and abroad. One means of mitigating these environmental impacts is increasing the fraction of renewable and sustainable energy in the national energy supply. Traditionally, renewable energy sources struggle to compete in open markets with fossil energy due to low efficiencies, high cost, and high technical risk.

Cofiring biomass with coal in traditional coal-fired boilers (subsequently referred to as cofiring) represents one combination of renewable and fossil energy utilization that derives the greatest benefit from both fuel types. Cofiring capitalizes on the large investment and infrastructure associated with the existing fossil-fuel-based power systems while requiring only a relatively modest investment to include a fraction of biomass in the fuel. When proper choices of biomass, coal, boiler design, and boiler operation are made, traditional pollutants (SOx, NOx, etc.) and net greenhouse gas (CO2, CH4, etc.) emissions decrease. Ancillary benefits include increased use of local resources for power, decreased demand for disposal of residues, and more effective use of resources. These advantages can be realized in the very near future with very low technical risk. However, improper choices of fuels, boiler design, or operating conditions could minimize or even negate many of the advantages of burning biomass with coal and may, in some cases, lead to significant damage to equipment. This document reviews the primary fireside issues and guidelines for implementing coal-biomass cofiring.

Fuel Characteristics

The biomass fuels considered here range from woody (ligneous) to grassy and straw-derived (herbaceous) materials and include both residues and energy crops. Woody residues are generally the fuels of choice for coal-fired boilers while energy crops and herbaceous residues represent future fuel resources and opportunity fuels, respectively. Biomass fuel properties differ significantly from than those of coal and also show significantly greater variation as a class of fuels than does coal. As examples (see Figure 1 and Figure 2), ash contents vary from less than 1% to over 20% and fuel nitrogen varies from around 0.1% to over 1%. Other notable properties of biomass relative to coal are a generally high moisture content (usually greater than 25% and sometimes greater than 50% as-fired, although there are exceptions), potentially high chlorine content (ranging from near 0 to 2.5 %), relatively low heating value (typically about half that of hv bituminous coal), and low bulk density (as low as one tenth that of coal per unit heating value). These properties each affect design, operation, and performance of cofiring systems.


Published papers available on cofiring:

Robinson, A., Baxter, L. L., Freeman, M., James, R. and Dayton, D. (1998) “Issues Associated with Coal-Biomass Cofiring,” In Bioenergy ’98Madison, Wisconsin.

Robinson, (1998) “Interactions between Coal and Biomass when Cofiring,” In Twenty-Seventh Symposium (International) on Combustion Combustion Institute, Boulder, CO, pp. 1351-1359.

Baxter and Robinson (1999) In Biomass: A Growth Opportunity for Green Energy and Value-added Products, Vol. 2 (Eds, Overend, R. P. and Chornet, E.) Elsevier Science, Ltd., Oxford, UK, pp. 1277-1284.

Baxter and Robinson (1999) “Key Issues When Cofiring Biomass with Coal in pc Boilers,” In Pittsburgh Coal Conference Pittsburgh, PA.

Baxter, Robinson, and Buckley (2000) “The Potential Role of Biomass in Power Generation,” In Biomass for Energy and Industry: 1st World Conference and Technology Exhibition Seville, Spain, to be presented.

Baxter, (1997) “Biomass-Coal Cofiring: Imperatives and Experimental Investigations,” In 3rd Biomass Conference of the Americas Montréal, Ontario, Canada.

Baxter, (2000) “Cofiring Biomass in Coal Boilers: Pilot- and Utility-scale Experiences,” In Biomass for Energy and Industry: 1st World Conference and Technology Exhibition Seville, Spain, to be presented.

Buckley, (1997) “Feasibility of Energetic Materials Combustion in Utility Boilers: Pilot-scale Study,” In 1997 Spring Meeting of the Western States Section of the Combustion Institute Sandia National Laboratories’ Combustion Research Facility, Livermore, CA.

Junker, (1997) “Cofiring Biomass and Coal: Plant Comparisons and Experimental Investigation of Deposit Formation,” In Engineering Foundation Conference on the Impact of Mineral Impurities on Solid Fuel Combustion Kona, HI. Robinson, A., Baxter, L. L., Freeman, M., James, R. and Dayton, D. (1998) “Issues Associated with Coal-Biomass Cofiring,” In Bioenergy ’98Madison, Wisconsin.

Robinson, (1997) “Fireside Considerations when Cofiring Biomass with Coal in PC Boilers,” In Engineering Foundation Conference on the Impact of Mineral Impurities on Solid Fuel Combustion Kona, HI.

Robinson, (1997) “Ash Deposition and Pollutant Formation when Cofiring Biomass with Coal in PC Boilers,” In EPRI Coal Quality Conference Kansas City, MO.

Robinson, (1997) “Pollutant Formation, Ash Deposition, and Fly Ash Properties When Cofiring Biomass and Coal,” In Engineering Foundation Conference on the Economic and Environmental Aspects of Coal Utilization Santa Barbara, CA.


1998 Tech Review — Sandia Combustion Research

-Coal and Biomass Combustion
-Cofiring Biomass and Coal to Reduce CO2 Emissions from
Coal-Fired Utility Boilers
-Thermal Conductivity of Ash Deposits Formed in Utility Boilers
-Mineral Matter Evolution during Coal Char Burnout


1997 Tech Review — Sandia Combustion Research

Scroll down to — “Coal and Biomass Combustion”

-Carbon Burnout Kinetic Model Developed for Pulverized Coal Combustion;
-Ash Deposit Property Analysis
-Pollutant Formation and Ash Deposition When Cofiring Biomass and Coal
-Formation of Ash Deposits in Biomass-Fired Boilers
-Combustion Properties of Biomass Pyrolysis Oils


AUGUST 20-24, 2000
Washington DC.

Division of Fuel Chemistry:

· 1990 Clean Air Act Amendments: A 10-Year Assessment
· Inorganics in Fossil Fuels, Waste Materials, and Biomass:
Characterization, Combustion
· Waste Material Recycling for Energy and Other Applications
· Fossil Fuels and Global Climate/CO2 Abatement
· Solid Fuel Chemistry
· Chemistry of Liquid and Gaseous Fuels

DOE Vision 21 Energy Plants of the Future Solicitation

Here’s a major opportunity to get DOE funding for good ideas. The website has additional materials, including a download link for the solicitation itself.

| Edward Beardsworth
| 951 Lincoln Ave. tel 650-328-5670
| Palo Alto CA 94301-3041 fax 650-328-5675
| *** UFTO ***

U.S. Department of Energy

Issued on October 1, 1999

Energy Department Opens First Major Competition For Vision 21 Energy Plants of the Future

The U.S. Department of Energy (DOE) has opened the competition for companies to begin designing a new type of energy facility that could change the way people think about fossil fuel power plants in the 21st century.

Called Vision 21, the new class of fossil fuel plants would produce electricity, chemicals, fuels or perhaps a combination of products in ways tailored to meet specific market needs.

Employing the latest in emission control systems, plus potentially revolutionary breakthroughs in such technologies as gas separation membranes, fuel cell-turbine hybrids, and carbon sequestration, Vision 21 energy facilities would have virtually no environmental impact outside the plant’s immediate “footprint.”

The plants would also be among the first to be developed and designed using advanced visualization and modeling software. Such “virtual demonstration” technology might eliminate the need for some of the expensive engineering and pilot facilities that have been necessary in other large scale development efforts.

The Energy Department will offer up to $30 million for winning projects, with each of the initial projects expected to receive from $1.5 million to $2.5 million. Private industry will be required to provide at least 20 percent of each project’s cost.

The initial set of projects would run for up to three years and would establish the design foundation and analytical capabilities for future development efforts.

The key to Vision 21 will be to integrate the ‘best-of-class’ technologies from across the fossil fuel spectrum – for example, the most fuel-flexible gasifiers and combustors, the most effective way to remove pollutant-forming impurities, the latest in fuel cell and turbine systems, and the most affordable ways to manufacture liquid fuels and chemicals.

Individually, none of these technologies are likely to achieve the increasingly stringent environmental and cost requirements that energy companies will confront in the 21st century. Integrated together, however, these advanced systems could provide consumers with affordable power and fuels along with unprecedented levels of environmental protection.

The Energy Department’s Federal Energy Technology Center is issuing the solicitation and plans to accept proposals throughout the coming year. Beginning around January 31, 2000, the department will announce project selections every four months. The due date for proposals for the first evaluation period is November 30, 1999. Proposals are being requested in three areas:

Technologies that will make up the “modules” of Vision 21 plants, for example, in such areas as advanced gas separation and purification, heat exchangers, fuel-flexible gasifers, advanced low-polluting combustion systems, turbines, fuel cells, and chemical and fuel synthesis processes.

Systems integration capabilities needed to combine two or more of the modules;

Advanced plant design and visualization software leading to a “virtual demonstration” of a Vision 21 plant.

The Energy Department has set a timetable to have Vision 21 technologies and designs ready for use by private industry in building commercial facilities by around 2015. Many experts forecast that the next major wave of U.S. power plant construction will begin around this time.

The Energy Department, however, expects the Vision 21 program to begin benefiting the energy industry well before 2015. The program is expected to produce spinoff technologies – possibly low-cost oxygen separation, better catalysts for the chemical industry, lower cost manufacturing processes, and improved pollution control systems — beginning as early as 2005.