We intend to deepen our analyses of gasification energy technologies with the aim of:

  1. Providing the analytical basis for gaining widespread US experience with and buying down the costs of major gasification energy and associated CO2 capture technologies during 2011-2016… even if a climate policy sufficiently stringent to motivate CCS for fossil energy via market forces is not then in place.
  2. Using this CO2 capture activity to facilitate the conduct of a large number of scientific investigations of CO2 storage at commercial CO2-EOR sites (a la Weyburn) and at aquifer/other storage demonstration sites.

These goals are motivated by considering that:

  1. Gasification energy plants with CO2 capture provide very low cost CO2. 
  2. The new consensus that future oil prices are not likely to fall below $35 per barrel implies that CO2 provided by gasification energy plants (that make electricity and/or synfuels) can be sold for CO2-EOR at a price1 that makes both gasification energy and CO2–EOR profitable if there are CO2-EOR opportunities not too far from gasification energy plants;
  3. New Department of Energy studies carried out for 10 regions/basins indicate a huge US CO2-EOR potential (covering most of the regions where new coal conversion plants are being planned) that could be supported by a large number of gasification energy projects.2

The Capture Group analyses will aim to help catalyze promising commercial and demonstration gasification energy projects with CO2 capture that might be brought on line during 2011-2016.

To provide a basis for prioritizing projects that might come on line 2011-2016, Capture Group analyses will explore a wide range of gasification energy options for making electricity and/or fuels with CCS and will attempt to rank them with regard to economic prospects, climate mitigation potential, and other benefits and drawbacks—along with articulation of the major challenges that must be overcome.

These analyses would involve a range of feedstocks—coals of various ranks [including sub-bituminous (Powder River Basin) and lignite (North Dakota and Texas), as well as high-ash coals (India)], petroleum residues, and biomass—and would consider systems producing both electricity and synfuels. Both separate processing and co-processing (including co-gasification) of feedstocks would be considered. Plants producing electricity and synfuels separately and in combination would be considered.

  • Some of the very first gasification energy projects to be brought on line during 2011-2016 are likely to be based on use of petroleum residues. We shall carry out techno-economic analyses of various such gasification energy systems as a benchmark against which other gasification energy options can be compared. Kreutz, Larson, and Williams would collectively lead this effort.
  • To date, all our systems analyses for coal gasification energy have been carried out for bituminous coals using one commercial entrained flow gasifier type. But if coal energy is to play a large role in a climate-constrained world, lower rank coals will also be used—for which gasifiers other than the one we have modeled might be better suited. Detailed techno-economic systems analyses will be carried out for alternative feedstock/gasifier combinations based on currently commercial gasifiers—giving attention to feedstock drying and other processing (e.g., de-ashing) requirements for alternative feedstocks and to alternative gasifier feed mechanisms [water slurry feed, dry feed, and alternative advanced feed mechanisms (e.g., CO2/coal slurry) that might be relevant for CCS system]—expanding on work recently begun, led by Kreutz. Aspen and cost models will be developed for handling alternative feedstock/gasifier combinations for alternative entrained flow gasifiers for use in different regions. Particular attention will be given to co-cogasification of coal and biomass using entrained flow gasifiers—an effort that will be led by Larson and Williams, possibly in collaboration with Stefano Consonni at the Politecnico di Milano. Regional effects on system economics include constraints such as water resource availability for process needs (see below) and the altitude effect on power output for gasification systems that include electricity as a product (e.g., important consideration in high altitude regions such as Powder River Basin). These models will be used as “plug in” modules by Larson, Williams, and Kreutz for use in new analyses of gasification energy systems that make electricity, synfuels, or synfuels plus electricity.
  • Besides commercial gasifiers there are several possible “game-changing” gasifiers that are not yet commercial that we hope to be able to investigate. For these we will carry out technical analyses with much less detailed economic calculations (because of our expectation that these gasifiers are not yet sufficiently close to commercial readiness that reliable cost data will be available). However, our intention is to carry the economic analysis sufficiently far to make preliminary judgments as to whether any of these gasifiers offers the potential for significantly changing the outlook for gasification energy beyond what can be realized with variants of commercially established gasifiers. Kreutz and Larson would lead these analyses. Three options we are considering giving attention to are:
    • The transport gasifier (under development at Wilsonville by the Southern Company): a fast circulating fluidized bed gasifier that offers potential advantages over entrained flow gasifiers when operated on lower rank coals, biomass, and other feedstocks characterized by high reactivity.
    • The Choren gasifier (under development in Germany): a two-stage biomass gasifier intended to avoid the tar management problem posed by conventional low-temperature biomass gasifiers. The first stage is a low-temperature gasifier that produces a tar-rich gas and char; the second stage is a high-temperature gasifier for which the feed is the output of the first gasifier.
    • The steam pyrolysis/hydogasification gasifier (under development at the University of California at Riverside): a modestly pressurized gasifier using H2 + steam (the latter to enhance reactivity). Advantages: no need for O2 plant or to dry fuels—candidate for use with biomass and low-rank coals.
  • An entirely new area we intend to investigate is the gasification energy production/process water requirements/CO2 storage nexus. ANL work indicates water availability is likely to become a constraining factor for energy projects in many US regions; such constraints might be especially important in arid regions such as the PRB. The extent of the constraint will be explored for alternative conversion technologies/feedstocks/regions. Prospective water supplies to be investigated include water recovery from F-T process in synfuels manufacture, water recovery from drying of feedstocks (low-rank coals and biomass), and fossil water that might be withdrawn from geological reservoirs targeted for CO2 storage and desalinated3. Kreutz and Williams will lead this analysis. For the final option we will work with the Storage Group to investigate the implications for CO2 storage of the saline water removal strategy.
  • Conventional wisdom is that the optimal use of biomass in climate mitigation is in providing fluid fuels characterized by low GHG emissions. We agree with this judgment but our analyses show that this does not necessarily mean that biomass should be used to make liquid fuels. Our analysis shows that gasification systems that make electricity and/or liquid fuels with CCS from biomass or biomass/coal are the most promising in mitigating climate change for fluid fuels4 and also in terms of economics. We have shown that such systems are far more promising than cellulosic ethanol systems that vent CO2. We intend to extend this comparison to include cellulosic ethanol systems that involve CCS, for which we will develop plant designs based on cellulosic ethanol already designed by Lynd and his collaborators at Dartmouth.
    The fermenter in an ethanol production system generates CO2 in a pure stream at a rate of 1 kmol for each kmol of C2H5OH produced—which is one possible source of CO2 for CCS at an ethanol plant. But this stream would account for only ~ 1/6 of the C in the feedstock, so that CCS would be very costly. However, the lignin fraction of biomass (~ 1/3 of C in feedstock for corn stover) cannot be used for ethanol production and might be gasified along with other biowastes from the ethanol production unit, and the resulting syngas might be shifted to make mainly H2 (e.g., for B-IGCC-C power generation) + CO2 for CO2 storage. Back-of-envelope calculations indicate 50-60% of C in feedstock might be recovered for storage in this manner. Larson and Williams will lead this analysis.
  • We expect little in the way of commercial biomass or biomass/coal gasification energy systems being launched in the market during 2011-2016. Instead we hope with our analyses to catalyze demonstration projects for such technologies in this period. In all likelihood such demo projects would be based on use of forest-product-industry or agricultural residues. We intend to find collaborators who are “culturally close” to the major bioenergy stakeholders in these area, with whom we might work to help provide the analytical basis for bioenergy gasification projects with CCS.
    During the past year Larson has led a cost/benefit analysis of a forest-product-industry-based “biorefining” for the co-production of liquid fuels (or liquid fuels plus electricity) along with pulp and paper. This analysis was carried out under a DOE contract with cost-sharing by a private-sector group led by the American Forest and Paper Association. Motivated in part by the work of Larson and colleagues, the forest products industry is aiming to implement a commercial-scale demonstration of the forest products/biorefinery concept. Larson, probably in collaboration with Consonni, with whom Larson collaborated in the just-completed cost/benefit analysis, intends to extend the plant designs already considered to include CCS and the prospective cost/benefit implications of this additional feature. The goal of is to bring the CCS option to the attention of this important set of bioenergy stakeholders and get this option into forest product industry biorefinery projects (e.g., projects subsequent to the planned demo project).


  1. Equal to (incremental cost of energy production with CO2 capture plus cost of CO2 transport to EOR site)/(CO2 capture rate).
  2. The estimate of the US economic potential with current CO2-EOR technology (47 billion barrels) is sufficient to support a 4.3 MMB/D crude oil production rate for 30 years. If this level of CO2-EOR could be realized by 2025 and if all the CO2 were to be provided by C-IGCC-C plants (which won’t be the case because some coal synfuels are also being planned), the coal C-IGCC-C capacity needed to support CO2-EOR is ~46 GWe (127 plants)-equivalent to ~3/5 of US new coal capacity expected to be built 2011-2025.
  3. Back-of-envelope calculations indicate that the volumes of water required for synfuel plants are comparable to the volumes needed for storing supercritical CO2 and that desalination costs would add only modestly to synfuel production costs.
  4. The negative CO2 of B-IGCC-C systems can be used to offset GHG emissions from fossils fluid fuels.