HCE Logo

Home Page

About HCE

Links of
Interest


Documents of Interest

Contact HCE

FAQ's

Search

Site Map

The HCE Company
Frequently Asked Questions
  1. Siting. Could the IPFC process be installed on an existing powerplant or refinery site?

  2. IPFC Plant Capacities. What range of plant capacities do you anticipate for the IPFC process?

  3. Capital Costs. How do capital costs and plant efficiencies from the Integrated Plasma Fuel Cell compare to those from the Integrated Gasification Combined Cycle plants?

  4. Hydrogen. Doesn't the production of hydrogen with fossil fuels produce more pollution than simply consuming the fossil fuel directly?

  5. HPBR. What makes the Hydrogen Plasma Black Reactor so good when combined with the Direct Carbon Fuel Cell?

    5A. HPBR. Is the Hydrogen Plasma Black Reactor a nuclear reactor?

  6. Waste Heat. IGCC efficiencies are increased by using waste heat. Are IPFC efficiencies also calculated using waste heat?

  7. Electricity Consumption. The Hydrogen Plasma Black Reactor process operates at a very high temperature (~1500C) and uses an electricity powered plasma arc as the heat source. How much of the power produced by the Direct Carbon Fuel Cell does it consume?

  8. Hydrogen vs. Synfuels. What are the advantages in terms of the IPFC process of producing synfuels versus hydrogen?

  9. Catalysts. Catalysts are typically used to enhance the production of hydrogen. Does the IPFC use catalysts?

  10. Sulfur. The HCE flow diagram shows sulfur in the off-gas stream. How is the IPFC expected to handle sulfur, especially when there is variability in the feedstocks?

  11. Heavy Metals. How will the IPFC process handle heavy metals in the feedstock?

  12. Hydrogen, Carbon and Ash Separation. How does the Hydrogen Plasma Black Reactor separate hydrogen from carbon?

  13. DCFC Module. How long will it take to make a production module for the Direct Carbon Fuel Cell?

  14. Carbon Dioxide. Do profitability/cost calculations take into consideration the sale of carbon dioxide? The carbon dioxide market is a tough market.

  15. DCFC Waste Heat. Hydrogen fuel cells require thermal uniformity. Is this an issue with the Direct Carbon Fuel Cell?

  16. Karbomont HPBR Plant. What was the reason Karbomont Hydrogen Plasma Black Reactor plant closed?

  17. DCFC Current Distribution. High temperature hydrogen fuel cells have had problems controlling non-uniform current distribution due to the progressive contamination of the hydrogen fuel with stream reaction products, which decreases the chemical potential of the fuel and leads to non-uniform heat production and incomplete fuel utilization. How will the Direct Carbon Fuel Cell control this critical operating parameter?

  18. Hazard. Hydrogen fuel cells must be made air tight to prevent mixing hydrogen and oxygen, an explosive combination. Is there a similar explosion hazard in the Direct Carbon Fuel Cell?

  19. Anode Stability in Large-Scale Cells. Non-uniform current density in high temperature hydrogen fuel cells deleteriously affects anode stability and has been a significant barrier to high current density in large cells. Is this a limitation for the Direct Carbon Fuel Cell?

  20. Corrosion. Hydrogen fuel cells have suffered from corrosion. Is corrosion control in the Direct Carbon Fuel Cell a similar problem?

  21. Compare Power Production. Won't a hydrogen fuel cell produce three times the power of the Direct Carbon Fuel Cell of comparable size?

  22. DCFC Cost. How was the cost estimate for a large-scale Direct Carbon Fuel Cell determined?

  23. Purification DCFC Fuel. Sulfur entrains in the anode of hydrogen fuel cells and this poisons the platinum and nickel catalysts at concentrations as low as 0.5 parts per million. How is such poisoning avoided in the Direct Carbon Fuel Cell?

  24. Molten Salt. Has molten salt been used as a carrier fluid in the Direct Carbon Fuel Cell?

  25. Electric Utility Fuels. You state that the IPFC uses fossil fuels. What percentage of electricity is produced in the United States using fossil fuels?

  26. Electricity Sale Prices. HCE's cost charts accessed from the HCE home page indicate zero costs for hydrogen and gasoline when electricity is sold at 4 cents per kilowattt-hour and 5 cents per kilowatt-hour, respectively. What is the current selling price of electricity?

  27. Mercury. Mercury emissions from coal burning powerplants are being regulated by the Environmental Protection Agency and the States. Will the IPFC improve on mercury emissions?

  28. Sequestration. Department of Energy's FutureGen program is considering CO2 disposal in geologic formations. Does this produce income and how would the IPFC process manage CO2?

  29. Thermal Efficiency. What is thermal efficiency and how do you calculate it?

  30. IPFC Efficiency. Efficiency is high because the IPFC produces both hydrogen and electricity. What is the efficiency of the IPFC for all electricity production using coal?

  31. Gasification Efficiency. Gasification efficiencies for gasifiers are in the range of 75 to 92% (based on Lower Heating Values). So why is the IPFC process so different?

  32. IPFC Efficiency. How do you get 92% efficiency with the IPFC using coal?

  33. Water Usage. How much water is consumed in the gasification of the fuel in Integrated Plasma Fuel Cell process compared to the Integrated Gasification Combined Cycle?

  34. Fuel Choice and Hydrogen. What fuel source and process would produce the most economical hydrogen?

  35. Size. What is the smallest size you anticipate for an IPFC facility?

1. Question: Siting. Could the IPFC process be installed on an existing powerplant or refinery site?

Answer: Yes. As long as there were sufficient space on the site to build an IPFC plant, there is no reason why it couldn't be built at an existing powerplant or refinery site. Therefore, in utility applications, the IPFC is suitable for both repowering applications and new power plants.

Co-location at an existing power plant or refinery could have cost savings associated with sharing fuel preparation and delivery support infrastructure. It might also enhanceenvironmental credits for reducing site emissions per unit of production. Co-location at a refinery could ease delivery and utilization of hydrogen, which is important in petroleum refining. The flexibility of IPFC to using coal, oil or natural gas feedstocks enhances its compatibility with existing powerplant and refinery infrastructure.

2. Question: IPFC Plant Capacities. What range of plant capacities do you anticipate for the IPFC process?

Answer: The IPFC process is expected to be adaptable to a wide variety of potential market applications and plant capacities, from the kilowatt range to hundreds of megawatts. Small-scale applications are possible due to expected modularity of the design, flexibility in fuel, flexibility in products and superior environmental performance.

IPFC modules as small as 10 kilowatts are expected to be possible, although economics for this scale have not been analyzed. Small-scale applications, for example at a gas station or residence, would also probably require a natural gas or petroleum feedstock. The product for a household would probably be all electricity and the product for a gas station might be a combination of electricity and gasoline, diesel fuel or hydrogen. Since the IPFC process is highly efficient and extremely clean, expecially so using natural gas feedstock, environmental performance in this application would exceed anything practical utilizing combustion. This feature could be of overriding importance within cities and in high pollution areas.

Large-scale applications have been analyzed for return on investment and the larger the plant capacity, the higher the profit potential. Large-scale plants would probably utilize coal or biomass and produce electricity and gasoline, diesel fuel or hydrogen.

The IPFC is on an aggressive development schedule, which includes a pilot plant in 3 years and a demonstration plant in 6 years.

3. Question: Capital Costs. How do capital costs and plant efficiencies from the Integrated Plasma Fuel Cell compare to those from the Integrated Gasification Combined Cycle plants?

Answer: The calculated capital cost for an electricity and hydrogen plant using IPFC is about $700/KW, and it was compared to an IGCC electricity and hydrogen plant costing about $1,300/KW. The latter number is conservative in that the Energy Information Administration estimates IGCC capital costs at $1,367 per kilowatt in 2003. It is important to recognize that an IGCC plant needs oxygen and steam units and its efficiency is about 55%, whereas IPFC efficiency is estimated at 91%. For other types of electricity plants, capital costs vary from a low of $409 per kilowatt to a high of $3,915 per kilowatt. See the EIA's 2003 capital cost assumptions for 16 types of powerplants.

4. Question: Hydrogen. Doesn't the production of hydrogen with fossil fuels produce more pollution than simply consuming the fossil fuel directly?

Answer: No, not with the IPFC process.

MIT's Laboratory for Energy and Environment performed an assessment in 2000 and again in 2003, which is explained on their website as follows: "The hydrogen fuel-cell vehicle has low emissions and energy use on the road--but converting a hydrocarbon fuel such as natural gas or gasoline into hydrogen to fuel this vehicle uses substantial energy and emits greenhouse gases. . . . Ignoring the emissions and energy use involved in making and delivering the fuel and manufacturing the vehicle gives a misleading impression."

MIT assumes that the obvious solution is to produce hydrogen from a non-fossil fuel, which, of course, is one answer. MIT states, "The hydrogen must, of course, be produced without making greenhouse gas emissions, hence from a non-carbon source such as solar energy or from conventional fuels while sequestering the carbon emissions."

The obvious answer now has a non-obvious counterpart: the Integrated Plasma Fuel Cell process, which opens the door to the use of fossil fuels in the production of hydrogen without producing more emissions than directly consuming the fossil fuel.

A significant advantage of the IPFC process is that it is a noncombustion process, which is much more efficient and economical than existing conventional combustion processes for electricity and hydrogen production. High efficiency results in much less pollution emission of the main gaseous pollutants (sulfur, nitrogen and carbon dioxide).

But that is only part of the advantage. With the IPFC, the gaseous emissions are contained in a hydrogen stream that is cleaned of the pollutants by making solid or liquid products from them. That translates to very low gaseous emissions. Finally, the IPFC provides a potential for zero carbon dioxide release when sequestration is employed.

5. Question: HPBR. What makes the Hydrogen Plasma Black Reactor so good when combined with the Direct Carbon Fuel Cell?

Answer: The extraordinary compatibility of the Hydrogen Plasma Black Reactor and the Direct Carbon Fuel Cell is due in part to the fact that carbon material produced by the Hydrogen Plasma Black Reactor is "fully clean, highly reactive and pulverized." In other words, it is a perfect match with the requirements of the Direct Carbon Fuel Cell.

Complete cracking of the fuel in the Hydrogen Plasma Black Reactor will avoid the environmental problems of traditional gasification technology stemming from coal tar production. The fact that the Hydrogen Plasma Black Reactor operates using an electric arc in a hydrogen plasma makes it much more effective in terms of cost and efficiency and uniquely distinct from existing thermal pyrolysis devices.

As importantly, the Hydrogen Plasma Black Reactor is a simple and clean process that would remove pollutants from the coal, like sulfur, prior to feeding the pure carbon product to the Direct Carbon Fuel Cell. That, in turn, means that the gaseous emission from the Direct Carbon Fuel Cell will be pure carbon dioxide.

More information on the Hydrogen Plasma Black Reactor is available in a scientific paper by GAUDERNACK, et al., Hydrogen from Natural Gas without Release of CO2 to the Atmosphere, Proceedings of the 11th World Hydrogen Energy Conference, June 23-28, 1996, pp. 511 - 523, Stuttgart, Germany. For the quote source in the first paragraph above, see the Gaudernack paper at page 517.

In addition, the electrical energy requirement of Hydrogen Plasma Black Reactor is calculated to be less than 10% of that which would be produced by the highly efficient Direct Carbon Fuel Cell. Thus, the integrated system maximizes the electrical and hydrogen energy output.

5A. Question: HPBR. Is the Hydrogen Plasma Black Reactor a nuclear reactor?

Answer: No. Essentially, the Hydrogen Plasma Black Reactor is vessel wherein a thermally-induced chemical reaction takes place. The thermal energy is added by the use of an electric arc. This term "reactor" as used herein, is a commonly used in the chemical industry in a non-nuclear sense. The term "reactor" is also used in the nuclear industry to describe a device in which there is a controlled release of nuclear energy. However, the nuclear industry use of the term is not relevant to its use in respect to the Hydrogen Plasma Black Reactor.

6. Question: Waste Heat. IGCC efficiencies are increased by using waste heat. Are IPFC efficiencies also calculated using waste heat?

Answer: No. Using "waste heat" from the Direct Carbon Fuel Cell and an optional solid oxide fuel cell employed in one of the IPFC plant designs would add to the stated IPFC efficiencies. The IPFC includes options for a "back-end" steam Rankine cycle using this "waste heat" to maximize efficiency. However, it should be recognized that the energy or heat from the plasma cracking process is never wasted; rather it is recycled to the plasma and the feed processing system. Since it is not considered "waste heat," it is not used in a Rankine cycle. Three flow diagrams, including one using a back-end Rankine cycle, are available in the 7-page pdf document summarizing the IPFC.

7. Question: Electricity Consumption. The Hydrogen Plasma Black Reactor process operates at a very high temperature (~1500C) and uses an electricity powered plasma arc as the heat source. How much of the power produced by the Direct Carbon Fuel Cell does it consume?

Answer: Electric energy consumed by the IPFC process is expected to be less than 10% of that produced by the Direct Carbon Fuel Cell. The real benefit of high temperature with the plasma process is the very high efficiency of the operation without the need for catalysts, which can be costly. The Hydrogen Plasma Black Reactor has a proven efficiency of over 95%. More importantly, the overall thermal efficiency of the IPFC process for electricity and hydrogen is over 90% compared to about 55% for the best advanced technology, the Integrated Gasification Combined Cycle. The result is that the IPFC process extracts the maximum amount of energy available within any given feedstock. The very high thermal efficiency has a significant impact on minimizing power consumption, environmental pollution and costs.

8. Question: Hydrogen vs. Synfuels. What are the advantages in terms of the IPFC process of producing synfuels versus hydrogen?

Answer: Synfuels (gasoline and diesel fuels) can be used today in the economy without any changes to the marketing and consuming infrastructure. They constitute a product in high demand. Whereas, hydrogen for vehicles requires a change in infrastructure and hydrogen for use in oil refineries requires co-location at or near the refinery. The near-term hydrogen economy is limited, but the future demand for hydrogen is unlimited.

9. Question: Catalysts. Catalysts are typically used to enhance the production of hydrogen. Does the IPFC use catalysts?

Answer: No. The IPFC works best without catalysts in the production of hydrogen and electricity. Catalysts are an added cost and complicating factor eliminated by the IPFC process. The hydrogen plasma cracking process not only produces concentrated hydrogen, but also produces carbon in a form useful for highly efficient electricity generation in the Direct Carbon Fuel Cell.

10. Question: Sulfur. The HCE flow diagram shows sulfur in the off-gas stream. How is the IPFC expected to handle sulfur, especially when there is variability in the feedstocks?

Answer: The IPFC process is expected to enable use of domestically produced high sulfur coals. The Hydrogen Plasma Black Reactor produces a concentrated stream of hydrogen and carbon monoxide with a coal fuel. Sulfur emissions within this off-gas stream are expected to be in the form of hydrogen sulfide. Two well-known processes are available for recovering sulfur as hydrogen sulfide: It can be scrubbed out with a solvent or it can be precipitated out with zinc or zinc oxide. The Montreal hydrogen plasma plant removed it with a solvent.

11. Question: Heavy Metals. How will the IPFC process handle heavy metals in the feedstock?

Answer: The IPFC process will use two alternate approaches for feedstock processing. The first, and preferred method, is to directly feed the hydrocarbon to the Hydrogen Plasma Black Reactor, processed as to form only. For example, coal will be crushed to a suitable size. High temperature processing in the plasma black reactor permits direct feeding with little or no pre-treatment or chemical processing to remove contaminants. At the operating temperature of the plasma reactor, most contaminants will be volatilized and removed from the exhaust gases by well-known separations processes. Most of the ash and heavy metals will be a part of the molten vitreous frit material, similar to that in an Integrated Gasification Combined Cycle, which is removed at the bottom of the gasifier. Ash and heavy metals transported with the exhaust gases will be cleaned from the molten carbonate salt using known processes. The second method will involve de-ashing coal feedstocks before introduction in the HPBR. In addition to established de-ashing processes, HCE has a proprietary de-ashing process.

12. Question: Hydrogen, Carbon and Ash Separation. How does the Hydrogen Plasma Black Reactor separate hydrogen from carbon?

Answer: In the baseline design, fuel is introduced into the bottom of a vessel containing concentric graphite electrodes at the bottom and a molten salt carbon scrubber chamber at the top. At the operating temperature defined by the plasma within the electrodes (about 1,500C), the fuel is completely cracked into its constituent components. Hydrogen and lighter fluidized carbon particles exit out the annular space between the electrodes and rise to the molten salt carbon scrubber chamber. The molten salt scrubber captures the carbon using countercurrent contact of liquid molten salt downflow with fine carbon particle laden hydrogen gas upflow. The molten salt thereupon drains at the bottom of the scrubber chamber. The gases (carbon monoxide, hydrogen, hydrogen sulfide and ammonia) rise to the top and exit the scrubber chamber. The heavier solids and molten ash exiting the concentric graphite electrodes drop to the bottom of the vessel and flow out for disposal. The ash and other elements that are light enough to flow up with the carbon will be captured by the molten salt electrolyte. With an ash content of less than 0.1 wt% in the feed molten salt, electrolyte reprocessing cycle would be on a cycle of approximately 900 days.

13. Question: DCFC Module. How long will it take to make a production module for the Direct Carbon Fuel Cell?

Answer: The current plan is to have an operational Direct Carbon Fuel Cell module in 3 years. Multiple Direct Carbon Fuel Cell modules would be connected together to meet a broad range of electricity production requirements. The plan is to have each modular unit in a production plant capable of removal, without affecting plant operation.

14. Question: Carbon Dioxide. Do profitability/cost calculations take into consideration the sale of carbon dioxide? The carbon dioxide market is a tough market.

Answer: No. Sale of incidental products is not taken into consideration in cost calculations. The primary objective for the IPFC is profit from electricity, hydrogen and/or synfuels production. The sale price of electricity at going rates is what makes the IPFC process so profitable. Hydrogen or gasoline and diesel fuel can be zero cost products when subsidized by electricity sold from the process.

Carbon dioxide has a potential to enhance profits in the range of about 6 to 10%, more if a project is analyzed for sale of enhanced oil recovery or coal-bedded methane production. This extra profit potential could be enhanced by co-location at the wellhead or coal seam. Other incidental products (sulfur, steam, etc.) are expected to further enhance profits.

15. Question: Karbomont HPBR Plant. What was the reason Karbomont Hydrogen Plasma Black Reactor plant closed?

Answer: The Karbomont plant closure was related to the market for carbon black in the tire manufacturing business, which could not sustain profitable operation of the plant. Hydrogen from the Karbomont plant was sold to a nearby petroleum refinery. IPFC creates a new opportunity for the plasma black reactor, which is unrelated to its economics in the carbon black market.

16. Question: DCFC Waste Heat. Hydrogen fuel cells require thermal uniformity. Is this an issue with the Direct Carbon Fuel Cell?

Answer: No. At a fixed power rating, the hydrogen fuel cell stack has roughly 4 times as much waste heat to dissipate, which requires heat exchangers to offset thermal non-uniformities. The lower waste heat in the Direct Carbon Fuel Cell is an advantage.

17. Question: DCFC Current Distribution. High temperature hydrogen fuel cells have had problems controlling non-uniform current distribution due to the progressive contamination of the hydrogen fuel with stream reaction products, which decreases the chemical potential of the fuel and leads to non-uniform heat production and incomplete fuel utilization. How will the Direct Carbon Fuel Cell control this critical operating parameter?

Answer: The Direct Carbon Fuel Cell has a uniform current distribution and it is not subject to progressive contamination. In this sense, the Direct Carbon Fuel Cell is much less complex than the high temperature fuel cell.

18. Question: Hazard. Hydrogen fuel cells must be made air tight to prevent mixing hydrogen and oxygen, an explosive combination. Is there a similar explosion hazard in the Direct Carbon Fuel Cell?

Answer: No. Carbon fuel in the Direct Carbon Fuel Cell, wetted with salt, is not explosive even when exposed to air at 800 C. For process integrity, carbon cells need only be liquid tight.

19. Question: Anode Stability in Large-Scale Cells. Non-uniform current density in high temperature hydrogen fuel cells deleteriously affects anode stability and has been a significant barrier to high current density in large cells. Is this a limitation for the Direct Carbon Fuel Cell?

Answer: No. The carbon anode in the Direct Carbon Fuel Cell uses turbostratic carbons, which have already been scaled to 300,000 amp sizes--in the form of aluminum smelters. In the Direct Carbon Fuel Cell, the current density remains uniform, and there is no change in activity of carbon (unit activity) or carbon dioxide (1 atm fugacity) as you move from one part of the fuel cell to another. This is a significant difference because such large cells are considered impossible with hydrogen.

20. Question: Corrosion. Hydrogen fuel cells have suffered from corrosion. Is corrosion control in the Direct Carbon Fuel Cell a similar problem?

Answer: No. It is not an issue with the Direct Carbon Fuel Cell. It is true that a major problem in hydrogen fuel cells is steam-corrosion--most ferrous metals rust or corrode in the presence of steam, leading to a restricted list of materials of construction. However, in the Direct Carbon Fuel Cell, the anode is anhydrous, and no steam corrosion takes place.

Molten salt induced corrosion of metal structural components has been effectively limited by techniques well known in the industry, such as through a combination of spraying technologies and chemical vapor deposition. Alumina coatings have proved quite effective and are expected to be sutiable to the structural uses within the cell.

21. Question: Compare Power Production. Won't a hydrogen fuel cell produce three times the power of the Direct Carbon Fuel Cell of comparable size?

Answer: No. Production is about the same for both. Because of the way most hydrogen fuel cells are constructed (layers of orthogonal flow channels), only a fraction of the cross-sectional area of the expensive stack (about 1/3) is used to produce electric power, the balance is support and gas distribution. Because carbon fuel in the Direct Carbon Fuel Cell is fully utilized, the production capability is about the same.

22. Question: DCFC Cost. How was the cost estimate for a large-scale Direct Carbon Fuel Cell determined?

Answer: The current design of the Direct Carbon Fuel Cell was costed by the providers of the components, and the cost is about $500 per square meter. This price is based on components which are now in mass production.

23. Question: Purification DCFC Fuel. Sulfur entrains in the anode of hydrogen fuel cells and this poisons the platinum and nickel catalysts at concentrations as low as 0.5 parts per million. How is such poisoning avoided in the Direct Carbon Fuel Cell?

Answer: There are no catalysts to poison in the Direct Carbon Fuel Cell. The hydrogen fuel cell requires steam reforming, and then purification to prevent entrainment of sulfur into the anode. No steam reforming is required in the Direct Carbon Fuel Cell. In the IPFC, carbon, provided by the Hydrogen Plasma Black Reactor, is expected to be sulfur free, since the sulfur is volatilized as hydrogen sulfide and removed in the exhaust gas, serving as a minor marketable product.

24. Question: Molten Salt. Has molten salt been used as a carrier fluid in the Direct Carbon Fuel Cell?

Answer: Yes. Molten salt has been tested as a carrier medium and it works well in the Direct Carbon Fuel Cell.

25. Question: Electric Utility Fuels. You state that the IPFC uses fossil fuels. What percentage of electricity is produced in the United States using fossil fuels?

Answer: According to the Energy Information Administration, natural gas-fueled net electricity generation was 16.4 percent in 2002 and 15.0 percent in 2003. Petroleum and other sources, including solar, wind, and biomass, net generation was 4.0 percent in 2002 and 4.5 percent in 2003. Coal-based net electricity generation was 51.7 percent in 2002 and 52.6 percent in 2003. An EIA chart is available from the EIA web site.

26. Question: Electricity Sale Prices. HCE's cost charts accessed from the HCE home page indicate zero costs for hydrogen and gasoline when electricity is sold at 4 cents per kilowattt-hour and 5 cents per kilowatt-hour, respectively. What is the current selling price of electricity?

Answer: In the United States, residential electricity prices range from a low of 5.63 cents per kilowatt-hour in Kentucky to 17.13 cents per kilowatt-hour in Hawaii. The national average is 8.32 cents per kilowatt hour with New Yorkers paying 14.11 cents per kilowatt-hour. The Energy Information Agency publishes a Table , Table 5.6.A. Average Retail Price of Electricity to Ultimate Customers by End-Use Sector, by State, February 2004 and 2003 (Cents per kilowatthour).

27. Question: Mercury. Mercury emissions from coal burning powerplants are being regulated by the Environmental Protection Agency and the States. Will the IPFC improve on mercury emissions?

Answer: Yes. The IPFC does not utilize combustion of the fuel. It, therefore, is expected to produce very little in terms of non-carbon dioxide gaseous emissions, including mercury. Compared with combustion systems, IPFC has a major advantage when it comes to mercury control. Mercury is expected to be in a vapor phase due to its low boiling point (357C or 180F) and the high temperature of the plasma (1,500C). As in gasification systems, elemental mercury is expected to be the predominant chemical form. Essentially, all of the exhaust gas emissions from the Hydrogen Plasma Black Reactor are in the captured hydrogen stream. Carbon monoxide from oxygen contained in the coal is also in that stream and is a valuable component of the hydrogen/carbon monoxide "syngas." Because hydrogen is a valuable commodity, the hydrogen stream will be cooled and the gaseous emissions other than hydrogen and carbon monoxide will be either condensed out or otherwise captured as by-products. Under the current regulatory scheme on mercury, States will have until the end of 2007 to prepare State Implementation Plans (SIPs) identifying the steps they will take to bring nonattainment areas into compliance. The IPFC could play an important role in those nonattainment areas to reduce mercury emissions from electric powerplants.

In addition, the carbon dioxide from the Direct Carbon Fuel Cell is a concentrated stream of gas, which can be sold, sequestered or simply discharged as is the current practice. Because the volume of carbon dioxide would be about half that emitted from an equivalent capacity combustion plant, costs for sequestration would be proportionately lower than for sequestration from a combustion plant.

28. Question: Sequestration. Department of Energy's FutureGen program is considering CO2 disposal in geologic formations. Does this produce income and how would the IPFC process manage CO2?

Answer: Three types of reservoirs are candidates for geologic sequestration: depleted oil and gas fields, unmineable coal beds, and saline aquifers. Geologic sequestration is not intended to produce income, but rather to isolate and dispose of the carbon dioxide. However, carbon dioxide (CO2) may be injected into oil wells to enhance production of oil. Also injection into deep coalbeds produces methane. Sequestration by itself doesn't produce income. However, if oil or methane is produced using carbon dioxide injection, sequestration can become income producing, offsetting some of the cost of sequestration.

You can learn more about sequestration efforts at the National Energy Technology Laboratory's web site: http://www.netl.doe.gov/coalpower/sequestration/Resources/refshelf.html
An IPFC process facility would be a "zero-emissions" facility, as defined in the FutureGen program, when combined with sequestration. However, an IPFC process facility does not have to involve sequestration. If it does not, it would produce and emit about half the CO2 as an equivalant-capacity fossil burning plant, which is a significant improvement. This would save 50% of the CO2 production for the same amount of electricity generation. Such savings are expected to enable income from trading of the savings to other more significant emitters. A CO2 trading program is one of the Administration's pending proposals.

If sequestration is desired, the costs of sequestration of CO2 from the IPFC would be considerably lower than for a comparably-rated combustion facility. This is because the IPFC produces relatively pure CO2, which eliminates the need to separate and clean the gas prior to sequestration. Secondly, half the volume translates to a proportionate reduction in costs.

29. Question: Thermal Efficiency. What is thermal efficiency and how do you calculate it?

Answer: Thermal efficiency is applied to a particular product or products relative to the particular feedstock used in the particular process in question. One can use energy efficiency as the equivalent of thermal efficiency.

The input energy in the fuel feedstock is its Heating Value (BTUs) and that is always considered thermal energy. The product output, if it is electricity, is also considered as thermal energy because it can be converted all to heat in a resistor (I2R). A kilowatt-hour (kWh) of electricity is equal to 3,413 BTU and a BTU is thermal energy. When the product is hydrogen, then the energy value of hydrogen is counted, which is also in terms of its Heating Value (BTUs), because hydrogen is a fuel. Thus, the equations:

% Electrical Efficiency = [Electrical Energy (in terms of BTUs) / Heating Value of Fuel Feedstock (in terms of BTUs)] x 100. This also is the thermal efficiency for electricity production.

% Hydrogen Efficiency = [Heating Value of the hydrogen produced (BTUs) / Heating Value of the Fuel Feedstock (BTUs)] x 100. This is also the thermal efficiency for hydrogen production.

Electricity, hydrogen, fossil fuel and waste heat all have energy value and that can be expressed in themal units e.g., BTUs or kcals or Joules. Electrical energy is usually identified as kilowatt-hour-electrical (kWh(e)), but can be calculated in terms of kilowatt-hour-thermal (kWh(t)) using the proper conversion factor, 3,413 BTU/kWh, or its equivalent if calculating in other units.

30. Question: IPFC Efficiency. Efficiency is high because the IPFC produces both hydrogen and electricity. What is the efficiency of the IPFC for all electricity production using coal?

Answer: The calculated electrical enegy efficiency of an all electricity application of the IPFC using the range of U.S. coals is about 82% to 83%, which would be 2.2 times that of the standard coal Rankine steam cycle. The remaining energy in the fuel (18% to 17%), is in high temperature gases, which will be used to grind and dry the coal and keep the molten salt hot. The IPFC process would waste very little of the energy in the fuel.

31. Question: Gasification Efficiency. Gasification efficiencies for gasifiers are in the range of 75 to 92% (based on Lower Heating Values). So why is the IPFC process so different?

Answer: Gasification efficiencies do not reflect the thermal efficiency of producing the electricity and hydrogen products. The gasification efficiencies represent the efficiency for only one component in producing the final products: the gasification component. Said another way, the gasification efficiency only reflects the efficiency of the gasification process.

The gasification process converts the fuel feedstock to a gaseous material, which is subsequently used to produce the end products of electricity and hydrogen. Typical thermal efficiencies for producing electricity with the Integrated Gasification Combined Cycle are in the range of 42% to 50%, with a future expectation of improvement to 60%.

The 82 to 92% efficiencies calculated for the IPFC are for the final products, which includes the head end Plasma Black Reactor. These are calculated with the Higher Heating Value of the fuels, which results in a lower efficiency than when using the Lower Heating Values stated in the question. It is also noteworthy that the Hydrogen Plasma Black Reactor (the gasification component of the IPFC) typically achieved over 95% efficiency when it was in operation in the Karbomont plant.

32. Question: IPFC Efficiency. How do you get 92% efficiency with the IPFC using coal?

Answer: Efficiency for the IPFC applications is maximized by the co-production of electricity and hydrogen. For this co-product case, the electrical energy obtained is 52.8% of that available from the heating value of the feedstock North Dakota Lignite coal, which is 1.47 times the 38% efficiency of a conventional steam powerplant. The hydrogen that is produced from North Dakota Lignite adds 38.8% additional useful energy. Therefore, the total thermal efficiency increases to 92%.

Similarly, when Kentucky bituminous coal is the feedstock, the electrical energy obtained is 58.6% of that available from the heating value of the feedstock, which is 1.54 times the 38% efficiency of a conventional steam powerplant. The hydrogen that is produced from Kentucky bituminous coal adds 28% additional useful energy. Therefore, the total thermal efficiency increases to 86.6%.

For the North Dakota Lignite fuel, the remaining 8% of the energy in the fuel is in high temperature gases, which would be used to grind and dry the coal and keep the molten salt hot. However, unlike the case described in the previous question for only electricity production, it is possible that this residual thermal energy may be insufficient to grind and dry the coal and keep the molten salt hot. So, in that event, some of the hydrogen would be burned to provide the additional energy required. This would diminish the overall efficiency, but is not expected to be significant.

You can read about these calculated numbers in more detail in HCE's technical report HCEP-10-03, "A Highly Efficient Combined Cycle Fossil and Biomass Fuel Power Generation and Hydrogen Production Plant with Zero CO2 Emission."

33. Question: Water Usage. How much water is consumed in the gasification of the fuel in Integrated Plasma Fuel Cell process compared to the Integrated Gasification Combined Cycle?

Answer: The Hydrogen Plasma Black reactor does not utilize water in the gasification process. No water is used as a fuel transport medium and none is required for gasification. The gasification, more specifically decomposition (cracking) of the fuel, occurs in the absence of oxygen and water. The baseline IPFC process (electricity and hydrogen production) anticipates the use of water in the range of thousands of gallons per day in, for example, heat exchangers. Current plans call for circulating this water through cooling towers as a conservation measure, as is common in the industry.

Alternatives to the baseline IPFC process design, which for example would supplement hydrogen production, would consume additional water. In these alternatives, added components are a Water Gas Shift Reactor and a bottoming cycle to utilize waste heat. The Water Gas Shift Reactor consumes carbon monoxide and water and produces carbon dioxide and hydrogen gas. The bottoming cycle uses waste heat to create steam to drive a turbine-generator unit. This water would also be circulated through cooling towers, so that only make-up water is used. However, even for the most water intensive alternative IPFC process applications, water consumption is expected to be significantly lower than other equivalent-size steam gasification technologies. This is because, with the Integrated Plasma Fuel Cell process, the greatest economic return is delivered when the carbon in the fuel is used in elemental form to produce electricity with the Direct Carbon Fuel Cell, rather than being gasified with water as in steam gasification.

IPFC gasification without water is a significant environmental advantage both because it requires minimal water supplies and because it avoids process water contamination and waste water treatment and discharge issues. This is noticeably different from the other advanced gasification technology, the Integrated Gasification Combined Cycle. For example, the Environmental Impact Statement for the Kentucky Pioneer IGCC Demonstration Project facility reports that it would withdraw approximately 4.0 million gallons of water per day from the Kentucky River. That project uses a partial oxydation process in an enclosed pressurized reactor, and about 85% of the gaseous product is a mixture of carbon monoxide and hydrogen gas (called synthesis gas, syngas or fuel gas), which is then used as fuel in a gas-turbine combined cycle power plant.

Another important distinction is that the efficiency of a steam gasifier is lower than the Hydrogen Plasma Black Reactor because the steam-carbon reaction creating carbon monoxide and hydrogen is highly endothermic, requiring part of the coal to be burned to produce the energy to drive the steam gasification. In comparison, the Hydrogen Plasma Black Reactor consumes only a small fraction of the energy in the form of electricity from the Direct Carbon Fuel Cell to crack the coal. This is the reason the Hydrogen Plasma Black Reactor is highly thermally efficient and together with the Direct Carbon Fuel Cell makes the Integrated Plasma Fuel Cell process highly efficient.

34. Question: Fuel Choice and Hydrogen. What fuel source and process would produce the most economical hydrogen?

Answer: Coal and the Integrated Plasma Fuel Cell process is calculated to produce the most economical hydrogen in conjunction with electricity.

Natural gas has the richest hydrogen content, having a hydrogen to carbon ratio of 4. It is also the most expensive fuel for the energy it contains. Petroleum has a hydrogen to carbon ratio of 1.7, and is lower in energy cost than natural gas. Finally, coal has a hydrogen to carbon ratio of 0.8 and is the lowest in energy cost.

Another important point is that the carbon in all these fuels can be combined with water to make additional hydrogen. This means that both the Integrated Plasma Fuel Cell process and the Integrated Gasification Combined Cycle could be configured to utilize the carbon in the fuel to produce only hydrogen.

Fuel cost, energy content, electricity production, the need for steam and oxygen, and the use of water all influence the answer. However, they add up to one bottom line conclusion: The most economical production of hydrogen is obtained when hydrogen is produced as a co-product with electricity. So, for any given fuel, the Integrated Plasma Fuel Cell process is projected to be more economical than its only competitor, Integrated Gasification Combined Cycle, because the IPFC has a much higher overall energy efficiency, doesn't need an oxygen plant or a steam water supply, and the IGCC's gas-turbine combined cycle power plant is much lower in efficiency in producing electricity than the Direct Carbon Fuel Cell.

35. Question: Size. What is the smallest size you project for an IPFC facility?

Answer: There is no technical limitation on size. Rather this is a question of economy of scale. We really don't know yet what the economics are for small scale applications, e.g., in the range of 10 kilowatts or larger. The numbers we have generated in our economic reports are for large plants, e.g., 100 MW electrical. However, the long term market for small-scale applications could be quite large.

It is envisioned that smaller scale applications of the IPFC process could be located at gas stations and produce hydrogen, gasoline and electricity on a distributed basis. This would solve one of the more serious technical hurdles to the hydrogen economy: the means and cost of hydrogen distribution.

Science Magazine's August 13, 2004 edition in an article entitled "The Hydrogen Backlash," reports at page 960 "because of hydrogen’s low density, it would take 21 tanker trucks to haul the amount of energy a single gasoline truck delivers today, according to a study by Switzerland-based energy researchers Baldur Eliasson and Ulf Bossel. A hydrogen tanker traveling 500 kilometers would devour the equivalent of 40% of its cargo."



Last modified 10/11/04
Web Page Comments? E-mail: webmaster@hceco.com