Comparisons and Applications for O2/CO2 Combustion

Comparing the High-Efficiency O2/CO2 Combustion Technology of U.S. Patent No. 6,907,845 Issued June 21, 2005 with Air-Fired State-of-Art Rankine Cycle Thermoelectric Power Plants

  • Plant efficiency doubles to about 68% and potentially to 80% when fully optimized, compared to state-of-art plants at 34%.
  • Fuel savings--fuel cost reduced by half due to efficiency improvement.
  • Fuel flexibility--all non-nuclear fuels may be utilized including either biomass or refuse-derived fuel (RDF) up to about 20% of total fuel input.
  • Competitive capital costs--approximately $1,500 per kilowatt (KW) of plant capability depending on plant size, 50 to 300 megawatts (MW).   Cost-adjusted June 2008.
  • Reduced CO2 emissions and no carbon monoxide (CO) emissions.
  • No NOx emissions.   Nitrogen dioxide (NO2) is absorbed in the recovered exhaust gas condensate as dilute nitric acid (HNO3) and the condensate is chemically pH-adjusted for use as boiler feedwater.   Air-fired plants need high-cost catalytic converters to reduce NOx in the flue gas.
  • Virtually no SOx emissions with this O2/CO2 combustion method.   Liquid sulfur dioxide (SO2) is recovered.   Sulfur trioxide (SO3) is absorbed in the exhaust gas condensate as dilute sulfuric acid (H2SO4).   Air-fired plants require scrubbers to reduce SO2 and SO3 emissions.
  • Particulate in any final emission from high-efficiency O2/CO2 combustion should not exceed 0.2 microns and may not be detectable.   If uses are found for the CO2, the plant particulate emission will be zero.   State-of-art air-fired plants struggle to limit particulate to 10 microns with only electrostatic precipitators (ESP's).   The use of ESP's followed by baghouses can do better than 10 microns but at much greater plant capital and operating costs.
  • Net water producer, by recovering all exhaust gas condensate, versus state-of-art plants which are very large water users.   Plant cooling water needs are minimal because recovered liquid CO2 is available for cooling.
  • Carbon Capture.   Complete recovery of CO2 is embodied in our O2/CO2 combustion system.   See Carbon Capture.
  • Mercury (Hg) Capture.   Virtually all mercury oxide (HgO) and the many compounds of Hg are adsorbed on the particulate which is separated by our O2/CO2 combustion method.   Mercury (Hg) vapor is soluble in the dilute nitric and sulfuric acid condensate as it cools to about 35 degrees fahrenheit .   This condensate is then pH-adjusted to precipitate Hg and other heavy metals.   Air-fired plants require costly methods for mercury control as detailed in a May 2008 Topical Report #26 of the National Energy Technology Laboratory/U.S.D.O.E.   The report covers three mercury control demonstrations on operating coal-fueled power plants, each one complex and costly compared to Hg removal in our O2/CO2 combustion system.

Comparing High-Efficiency O2/CO2 Combustion with the General Electric (GE) Integrated Gasification Combined Cycle (IGCC) and Hitachi Ultra-Supercritical (SCPC) Rankine Cycle Technologies

General Electric contributed a table of data comparing its own IGCC technology with SCPC for an article published in Power Engineering, March 2005, pp. 30-40 (see Table 2).   GE shows its efficiency at 40% and equal to SCPC, which is only projected because a reliable commercial GE plant has yet to be built.   However, Hitachi (Japan) has already built at least one ultra-supercritical pulverized coal (SCPC) plant rated at 41% efficiency, which is in commercial operation and scaled to about 1,000 megawatts.   High-efficiency O2/CO2 combustion is expected to achieve 68% efficiency and, when fully optomized, up to 80% efficiency.   No separate costs for CO2 recovery are required because, unlike IGCC and SCPC, liquid CO2 recovery is built into the high-efficiency O2/CO2 combustion method, as explained in U.S. Patent No. 6,907,845.   It is a net water producer (from the exhaust gas condensate) rather than a large water user like the IGCC and SCPC technologies.   Capital costs should be equivalent to SCPC and less than IGCC.   Operating costs are less than either IGCC or SCPC.

Applications for High-Efficiency O2/CO2 Combustion

  • Large-scale base-load electric power production, initially 50 to 300 megawatts (MW).
  • Oilfield steam and electric production, especially in heavy oil reservoirs, where steam and recovered CO2 may be used in oil recovery.   Nitrogen, otherwise wasted from the required air separation unit (ASU), may also be used in oil recovery in certain mature fields.
  • Oil refinery use for steam and electric production, with the utilization of petroleum coke or residual fuel oil for boiler fuel.   Fuel sulfur is recovered as liquid sulfur dioxide (SO2) to feed a sulfuric acid (H2SO4) plant.   The acid feeds the refinery alkylation process.
  • Municipal use for electric power production where the CO2 recovered from fuel combustion is available without cost for sewage treatment and wastewater treatment.   Sewage is converted to biomass (a secondary boiler fuel) in the enhancement of the natural process of photosynthesis by algae requiring CO2 for growth, which process releases byproduct oxygen.   By the same process, wastewater may be purified to potable water.   See our October 27, 2005 proposal entitled "Combining Municipal Services".
  • Fuel drying.   Large amounts of oxygen are required for O2/CO2 combustion, 1,000 tons per 24 hours for a 100 megawatt plant at 68% efficiency.   Therefore a large amount of nitrogen, 3,000 tons per day, may be wasted from the air separation unit (ASU).   This bone-dry nitrogen, before wasting into the atmosphere, can be beneficially used to dry and then transport boiler fuels.   Fuel drying enhances boiler combustion efficiency.
  • Liquefied Natural Gas (LNG) processing.   In O2/CO2 combustion, the otherwise wasted nitrogen from the ASU can be liquefied for ocean transport to remote natural gas production sites for use in gas liquefication.   This method would replace the less efficient gas compression process for liquefying the gas for LNG shipment.   This makes possible full load round trips in state-of-art containment vessels, shipping liquid N2 to gas fields and then returning LNG to the point of use or distribution.   A 100 megawatt power plant ASU, separating 1,000 tons per day O2 for combustion, would recover 3,000 tons per day liquid N2 and could ship 90,000 tons per month of liquid nitrogen.   Liquid N2 ships at a temperature of -383.9 F (-195.5 C) for liquefaction of natural gas at -322.9 F (-161.6 C).   This concept is based on a recent municipal electric power proposal for the San Francisco Bay Area in California, USA.
  • Cement kiln efficiency improvement with CO2 capture and conversion to biomass in enhanced photosynthesis.
  • Gas turbine and a condensing heat recovery steam generator with no water losses.  The CO2 output is utilized either in enhanced oil recovery operations or converted to biomass in an enhanced photosynthesis process.    

Updated June 2009