The results of the Capture Group’s studies on coal synfuels and biomass have prompted the researchers to examine strategies that combine the strengths of both in hybrid fossil fuel-biomass schemes.
Liquid Fuels from Coal and Biomass with Low GHG Emissions
Although the manufacture of coal synfuels with CCS can reduce the fuel-cycle-wide GHG emission rate to approximately the rate for hydrocarbon fuels derived from crude oil, a much larger reduction in the emission rate would be required if coal synfuels are to play a major role in providing liquid fuels in a climate-constrained world. Deep reductions in emissions might be realized by exploiting the negative emissions potential of biomass energy systems with CCS as discussed above.
In 2004, Williams led the exploration of one strategy that involves offsetting GHG emissions from production and use of DME from coal with CCS with negative emissions from separate biomass energy systems with CCS. The analysis showed that the most cost-effective emissions offset strategy would involve deploying biomass gasification power plants with CCS (the B-IGCC-CCS option in Figure 3). Making CCS costs attractive with this strategy requires large-scale biomass energy conversion systems and probably dedicated energy crops.
During 2005 this analysis was extended by Williams, Larson, and Haiming Jin to explore the coprocessing of coal and biomass to make F-T liquids in polygeneration plants. This strategy would make it feasible to exploit the negative energy potential of bioenergy production with CCS even with biomass waste resources that are widely distributed on the landscape (such as various crop and forest product industry residues), by exploiting the scale economies of coal energy conversion.
The basic idea is to make H2 from the biomass via gasification to blend with H2-deficient coal-derived syngas to help realize the H2/CO ratio needed in making F-T liquids. The negative CO2 emissions that arise when the CO2 coproduct of biomass-derived H2 is stored underground (along with CO2 from gasified coal) can offset the CO2 emissions that arise when the synfuel is eventually burned. The GHG emissions associated with the production and use of synfuels are thus reduced to near zero. When GHG emissions are valued at $100/tC this option is likely to be the least-costly way of making synfuels using coal with aquifer storage, with a plant-gate production cost of about $1.5 per gallon of gasoline equivalent. This cost is significantly less than both the current refinery-gate cost of making gasoline from imported oil and the cost of conventional biofuels such as biodiesel or cellulosic ethanol.
To make a given amount of low GHG-emitting synfuels from coal plus biomass in this manner would require less than half as much biomass input as is required in making conventional biofuels. The same conclusion holds for the B-IGCC-CCS and B-FT-CCS options discussed in the previous section (see Figure 3, top and middle). Thus CCS pursued for both coal/biomass hybrids and biomass-only systems makes it feasible for bioenergy to play a much larger role in climate change mitigation than is feasible with conventional biofuels.
Pairing gasification energy systems with CO2 enhanced oil recovery (CO2-EOR) could provide a market-based mechanism for motivating early CCS action. If new gasification energy facilities are built near sites where crude oil production could be increased via CO2-EOR, the captured CO2 could be injected into mature oil reservoir to increase oil production and thus enhance plant economics for gasification energy. At the same time, this strategy would make CO2-EOR more profitable by exploiting the low cost CO2 that can be provided by gasification systems.
Figure 4 shows that CO2 capture with the sale of CO2 for EOR would be quite profitable without subsidy for both coal IGCC plants and coal F-T liquids polygeneration plants at oil prices of $35-$40 a barrel or more and with a $0/tC value for GHG emissions. For the synfuels options, the profitability would be comparable for coal and coal/biomass polygeneration plants (compare the coal FT-EOR option for $50 a barrel oil in Figure 4 with the C/B-FT-EOR option in Figure 3). For all options the rate of return on equity is positive even for very low oil prices, so that there is essentially zero risk of bankruptcy as a result of inability to service debt.
How big an opportunity is this? Current oil production techniques recover on average 34% of the original oil in place in a U.S. oil field. Recent studies carried out for the U.S. Department of Energy show that it is economically feasible to increase this percentage to 42% with current CO2-EOR technology. Today CO2–EOR amounts to 0.21 million barrels/day (MMB/D), and most CO2 supplies come from natural CO2 wells. In many regions what limits additional projects is the availability of low-cost CO2. If copious quantities of low-cost CO2 were available, CO2-EOR based on current technology could support a production rate of 4.3 MMB/D over a 30-year period—about 4/5 of the current level of total US crude oil production.
Much of the needed low-cost CO2 could be provided by gasification energy plants. To illustrate the possibilities, suppose, as a thought experiment, that aggressive effort leads, by 2025, to a CO2 -EOR production rate of 4.3 MMB/D of oil. Suppose that initially the CO2 is provided by a 50/50 mix of coal IGCC plants and coal plants that make F-T liquids + electricity, and that after 2015 all the required CO2 is provided by synfuels + electricity plants fueled with coal and biomass. In this thought experiment each barrel of synfuels produced via polygeneration would support the production of 4 barrels crude oil via CO2-EOR. For all synfuels plants built after 2015 the GHG emission rate for the synfuels would be only 1/5 the rate for crude oil-derived hydrocarbon fuels (see Figure 2, bottom). The GHG emission rate for the electricity produced in all the deployed plants would be only 1/10 of that for average coal power plants.
The total amount of gasoline and diesel produced from CO2–EOR and synfuels would be sufficient to supply more than 2/5 of the fuel consumed by all US light-duty vehicles in 2025. The coproduct “decarbonized” electric generating capacity is equivalent to 2/5 of total new coal generating capacity expected to be built by 2025. The amount of biomass required under this thought experiment is sufficiently modest that “waste” resources alone are adequate—the biomass required by 2025 amounts to less than 2/5 of the biomass currently available in urban wood wastes and residues of the forest product and agricultural industries.
The CO2-EOR option represents a “niche” opportunity, to be sure, but it is sufficiently large that exploitation of this option could lead to significant “buy-down” of costs for gasification and CCS technologies. As a result of field experience (learning by doing), costs might be significantly less than at present by the time it becomes necessary to pursue widely aquifer storage of CO2 .
*For all options the assumed debt/equity ratio is 55/45, and the feedstock prices are $1.35 and $3.0 per GJ (HHV) for coal and biomass, respectively. For the CO2–EOR cases it is assumed that the CO2 price (in $ per thousand standard cubic feet) is 3% of the oil price (in $ per barrel). The reference $50/barrel oil price is the levelized oil price during 2010-2040 based on the Energy Information Administration’s Annual Energy Outlook 2006 forecast. The reference 14% real rate of return on equity is for Base Case financing, so that greater returns are regarded as especially attractive.