Carbon Mitigation Initiative
CMI

Eighth Year Report 2009
Carbon Capture: Systems Analyses for Synthetic Fuels Production

The Williams Group carried out systems analyses for synthetic fuels production include both generic systems studies and a case study of hypothetical coal/biomass polygeneration systems that might be deployed in Illinois.

Generic Systems Studies

A major analytical activity during 2008 was a systematic investigation of mass, energy and carbon balances, fuel-cycle-wide GHG emissions, prospective capital and production costs, and economic outlook as a function of GHG emissions price and oil price, for 16 alternative plant configurations for making Fischer-Tropsch (F-T) liquids in gasification systems from coal or biomass alone, and from coprocessing coal and biomass. The work, the first results published from which appear in the Proceedings of the 2008 Pittsburgh Coal Conference, analyzed both RC (recycle) systems that maximize the production of liquid fuels by recycling unconverted syngas and OT (once-through or "polygeneration") systems that burn unconverted syngas to generate electricity. Energy and cost adders for CO2 capture and storage (CCS) relative to systems that vent CO2 (V) were estimated.

A major impetus for this work was a request from the National Research Council (NRC) to develop a detailed spreadsheet model to help the Alternative Fuels Panel and other Panels of the NRC's 18- month study entitled America's Energy Future: Technology Opportunities, Risks, and Tradeoffs being carried out to help guide the Obama Administration on energy policy. The PEI analysis was intended to help the authors of that study understand, on a self-consistent basis, how alternative synfuel and power technologies relate to one another in terms of mass, energy and carbon balances, fuel-cyclewide GHG emissions, and economic prospects. Previous Capture Group experience with synfuels production analysis and the timely addition to the group in March 2008 of Dr. Guangjian Liu, an experienced Aspen Plus modeler from the BP Clean Energy Center of Tsinghua University enabled the Capture Group to take on this effort to respond to the NRC request.

For the NRC spreadsheet, the researchers created Aspen Plus models for more than 30 different plants that convert bituminous coal and/or biomass via gasification to electricity and/or liquid transportation fuels (primarily F-T liquids) with and without CCS. Rather than investigate the promise of novel technologies, this study focused on potential gains to be found in new combinations of technologies that are proven at commercial scales or are near commercial. Detailed mass, energy and carbon balance simulation results were imported into a common framework (Microsoft Excel) used for calculating capital costs, fuel-cycle-wide GHG emissions, internal rates of return, and breakeven oil prices (for liquid fuels), as functions of GHG emissions price, crude oil price, and financing costs. This dual Aspen/Excel methodology has proved to be a powerful tool for carrying out a detailed, self-consistent evaluation of many disparate plant configurations.

The findings of this study were summarized in a paper prepared for 9th Biennial GHG Control Technologies meeting (November 2008) and presented there by Williams. The main findings are:

  • For the same coal input levels, an OT synthesis plant can provide F-T liquids at a much lower production cost (and therefore a lower breakeven crude oil price) than can a RC synthesis plant. This advantage (illustrated in Figure 1 for coal-only systems) arises largely because OT plants can generate electricity at far higher efficiencies than stand-alone coal power plants by harnessing waste heat from F-T synthesis, leading to a relatively high credit for the electricity co-product.
  • Polygeneration systems can provide decarbonized electricity at a cost of GHG emissions avoided that is ? to ½ of that for stand-alone power plants. This avoided cost difference arises because F-T systems generate a pure CO2 stream (accounting for ~ ½ of feedstock carbon) as an inherent aspect of the synthesis process, so that CO2 capture costs are very low (Figure 2). (Capture costs for the RC configuration, also shown in Figure 2, are lower than for the OT system, but economics for the RC design are not as favorable for the conditions analyzed.)
  • Biomass/coal co-processing in polygeneration plants with CCS can lead to significant reductions in F-T liquids GHG emission rates very cost-effectively under a serious carbon mitigation policy (Figure 3). This benefit, arising largely because of the negative carbon emissions from biomass deployed in CCS systems, makes it feasible to realize near-zero GHG emissions for liquid fuels with much less biomass input than with biofuels such as cellulosic ethanol.
  • Because polygeneration plants have two revenue streams (from liquid fuels and electricity) they can be very powerfully competitive in economic dispatch competition (Figure 4). As long as oil prices are not too low, polygeneration plant operators can bid to sell electricity in dispatch markets down to prices far less than what existing coal power plants can bid—offering thereby a market approach for replacing carbon-intensive coal power with decarbonized power. To illustrate, Figure 4 shows that, at a GHG emissions price of $80 a tonne of CO2eq, the minimum dispatch cost for CBTL-OT-CCs is ¼ of that for existing coal power plants when the oil price is $20 per barrel, and zero when the oil price is $40 per barrel.
Figure 1
F-T System Outputs GHGI
CTL-RC-V 50,000 B/D + 427 MWe 2.2
CTL-RC-CCS 50,000 B/D + 317 MWe 1.0
CTL-OT-V 36,700 B/D + 1279 MWe 2.8
CTL-OT-CCS 36,700 B/D + 1075 MWe 1.3
CTL = coal to F-T liquids
RC = recycle configuration
OT = once-through configuration
V = CO2 venting
CCS = CO2 capture and storage
GHGI = GHG emission rate relative
to the rate for crude oil products displaced when electricity is assigned the rate for a coal IGCC power plant with 90% CO2 capture.

Figure 1. Breakeven Crude Oil Price vs. GHG Emissions Price for Alternative F-T Liquids Systems Fueled with Coal
All systems shown assume the same level of coal input and produce F-T liquids in the form of finished diesel (61%) and finished gasoline (39%). For the CCS, cases, the CO2 is stored 2 km underground in a deep saline formation located 100 km from the conversion plant. In this figure, as well as in Figures 3 and 7, the selling price for the electricity coproduct is assumed to be $60/MWh (US average grid price in 2007) + a GHG emissions charge at the 2007 U.S. grid-average GHG emissions rate (636 kg CO2eq/MWh).

Figure 2

Figure 2. CO2 Capture Costs for Alternative Energy Conversion Systems
The capture cost is the difference between the 20-year levelized production cost ($ per GJ) in the CTL cases and $ per MWh in the electricity cases) with CO2 captured and that with CO2 vented for the same plant type divided by the CO2 capture rate (in tonnes of CO2 per GJ and MWh, respectively). The capture cost includes the cost of compression to 150 bar but not costs for CO2 transport and storage. The 4th and 5th bars involve post-combustion capture for a supercritical pulverized coal steamelectric plant (PC) and for a natural gas combined cycle power plant (NGCC), respectively.

Figure 3
F-T system Bio % (HHV) Outputs GHGI
CTL-OT-CCS 0 36,700 B/D + 1075 MWe 1.3
CBTL2-OT-CCS 8.6 36,700 B/D + 1113 MWe 1.0
CBTL-OT-V 38.1 8,100 B/D + 315 MWe 1.7
CBTL-OT-CCS 38.1 8,100 B/D + 276 MWe 0.0
BTL-RC-V 100 4,400 B/D + 34 MWe - 0.1
BTL-RC-CCS 100 4.400 B/D + 24 MWe - 1.4

Figure 3. Breakeven Crude Oil Price vs. GHG Emissions Price for Alternative F-T Liquids Systems.
The four coal F-T options shown are the same as in Figure 1. The five additional systems involve biomass, assumed in all cases to be delivered at a rate of 1 million dry tonnes per year. Two of these involve only biomass (BTL options) and 3 involve coal/biomass co-processing (CBTL options). Notably, a zero net GHG emission rate is realized for the CBTL-OT-CCS option, which is fueled with 38% biomass.

Figure 4

Figure 4. Minimum Dispatch Cost at Two GHG Emissions Prices for Existing Coal Power Plants (left) and for CBTL-OT-CCS Plants (right).
The market determination of when a plant connected to the power grid gets dispatched and thus a plant's capacity factor depends only on the short run marginal cost (SRMC)…the capital cost is a sunk cost that does not come into play. Power plant operators will bid to provide power in economic dispatch at power prices down to the minimum dispatch cost (MDC), determined by the condition that revenues = SRMC. For existing coal power plants the only revenue stream is from electric power sales, so that the MDC for coal power (MDC CP) = SRMC. For OT F-T liquids systems there are two revenue streams (one from power and one from F-T liquids), so that the MDC can be less than SRMC as long as oil is above a certain minimum price.

If CCS is pursued for biomass, system economics would be more favorable if biomass is co-processed with coal than if it is used in biomass-only systems—because of coal energy conversion scale economies and the low cost of coal relative to biomass. The negative emissions arising from photosynthetic CO2 storage can offset positive emissions from coal.

To summarize, coal/biomass polygeneration with CCS systems offer an economically attractive way to decarbonize simultaneously both liquid fuels and electricity under a serious carbon mitigation policy.

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