The Williams Group uses Aspen Plus simulations and economic models to analyze energy and carbon balances and the economics of new systems for producing synthetic fuels and electricity. During 2009, major foci of the synfuels analytical activity were: (i) a comparison of alternative low-carbon transportation fuels, (ii) a study of coal/biomass coproduction with CCS systems as repowering options for existing coal power plant sites, and (iii) analyses of methanol to gasoline systems based on coal, biomass, and coal + biomass without and with CCS. A good context for this analysis is a 2009 Science paper discussing sustainability issues for biomass energy.
Context: Sustainable biomass for energy
In June of 2008, 11 academic analysts (including Bob Williams and Eric Larson in the Carbon Capture Group) with a wide range of expertise and perspective met in Princeton for two days to exchange views about the sustainability of biofuels, food, and the environment. The meeting, convened by Prof. David Tilman of the University of Minnesota and CMI Co-Director Robert Socolow, was motivated by simultaneous consideration of the importance of biomass in providing low-carbon liquid fuels and growing concerns about food/biofuel conflicts and land-use impacts (direct and indirect) of growing biomass for fuels on cropland. After considerable subsequent back-and-forth, a consensus emerged that was published as a Science commentary in 2009 (Tilman et al., 2009 – see Publications). The co-authors’ hope is that those charged with making biofuels policies will benefit from the synthesis of the deliberations.
The commentary stresses that realization of substantial net societal benefits from biomass use for energy probably requires avoiding the growing of dedicated energy crops on cropland, so that the primary biomass supplies available for energy are likely to be various crop and forest residues and dedicated crops grown on abandoned cropland and degraded lands. The significance of this perspective for the U.S. is that prospective biomass supplies for energy are likely to be only about ½ of what was thought feasible just a few years ago, demanding new collaborations to identify acceptable ways forward for bioenergy—involving environmentalists, economists, technologists, the agricultural community, engaged citizens, and governments worldwide.
This Science commentary provides a helpful context for understanding the merits of the Capture Group’s approach to biomass for energy—which emphasizes three strategies: (i) thermochemical conversion (via gasification) rather than biochemical conversion (which presently dominates biofuels production); (ii) CCS for biomass (most analyses of CCS technologies and strategies have focused on CCS for fossil fuels but not for biomass), and (iii) the production of low-C synthetic liquid fuels via co-processing of biomass with coal (the conventional approach to low carbon liquid fuels is via biofuels). Combining all three of these strategies has led the Williams Group to an approach to low-C transportation fuels that requires less than half as much biomass per unit of low-C fuel as would be required with next-generation biofuels such as cellulosic ethanol—an advantage if biomass will be much scarcer than was previously thought. Moreover, as will become clear from the discussion below, the path to low-C fuels that combines these three strategies is likely to enable a transition from food biomass to lignocellulosic feedstocks more quickly than is feasible via biochemical conversion approaches because: (i) the technologies are probably closer to being ready for widespread deployment (if CCS proves to be viable as a major carbon mitigation option), (ii) the liquid fuels produced can be provided to consumers without changes in infrastructure and end-use vehicles, and (iii) the fuels produced are likely to be much more competitive with crude oil-derived fuels than fuels derived via biochemical means.
Low-carbon transportation fuels from coal and biomass with CCS
Drawing on the Princeton Energy Group’s 2008 Pittsburgh Coal Conference Report that analyzed 16 alternative synfuel options, a systematic comparison of alternative low-carbon liquid transportation fuels has been launched. A greenhouse gas emission index (GHGI) is being used to characterize carbon mitigation performance: (total system-wide GHG emissions for energy production and consumption)/(emissions for the displaced fossil energy). So far, the technologies being compared include the three Fischer-Tropsch liquids (FTL) systems and the two cellulosic ethanol systems listed at the top of Table 2 (acronyms are defined in Table 1).
The two biomass-only FTL options included are recycle designs that make mainly liquid fuels, without and with CCS (BTL-RC-V and BTL-RC-CCS). Also included is a coal/biomass oncethrough coproduction option that makes electricity as a major coproduct (accounting for about 1/3 of the energy output); this option (CBTL-OT-CCS-38% BIO, or coal-biomass-CCS, see Figure 1) is fueled with just enough biomass (38% on an energy basis) to reduce emissions to 10% of those for the fossil energy displaced (GHGI = 0.1).
The key parameters assumed for understanding the economics of cellulosic ethanol plants that vent CO2 are from the assessment made by the Alternative Liquid Transportation Fuels Panel of the National Research Council’s America’s Energy Future study. Another cellulosic ethanol option, in which fermentation CO2 is captured and stored, is included in the comparison.
One finding is that, although biomass inputs are comparable for FTL via BTL-RC and via cellulosic ethanol, FTL produced via CBTL-OT-CCS-38% BIO requires only about ½ as much biomass as does cellulosic ethanol (for which GHGI is 1.7 X as large, see Table 2)
For the economic analysis presented in Figure 2, the estimated capital intensity of BTL options ($ per barrel per day of gasoline equivalent) is about twice that for cellulosic ethanol. This implies that, at zero GHG emissions price, the levelized fuel production cost for FTL via BTL-RC-CCS is about 1.2 X that for EthOH-V. But for GHG emissions prices > $28/t CO2eq the FTL so produced is less costly. Figure 2 shows that results wouldn’t be much different if ethanol were produced via EthOH-CCS, because of the much lower GHGI for BTL-RC-CCS (- 1.08) compared to EthOHCCS (- 0.21)—see Table 2. The GHGI is much lower for BTL-RC-CCS because of its higher CO2 storage rate (> 50% of the feedstock C, compared to 15% for EthOH-CCS).
The most striking result is that the FTL cost via the coal-biomass-CCS strategy is much less than that for cellulosic ethanol. One measure of economic performance is the GHG emissions price required to compete with crude oil-derived products. At $75/barrel, the needed GHG emissions price is ~ $40/t CO2eq for CBTL-OT-CCS-38% BIO and ~ $100/t for EthOH-V.
Repowering coal plants with coal-biomass-CCS vs. CCS retrofits
Decarbonizing coal power (which accounts for ½ of U.S. electricity and ⅓ of total U.S. CO2 emissions from fossil fuel burning) must be a major focus of U.S. efforts to reach a goal of reducing economy-wide GHG emissions 83% by 2050 relative to 2005 (as proposed currently by the U.S. Congress). Most attention should be directed to existing coal power plants because, under a carbon mitigation policy, pursuit of the low-hanging fruit for carbon mitigation (energy efficiency improvements in buildings) is likely to lead to hardly any electricity demand growth.
The Williams Group is analyzing and comparing several decarbonization options with regard to energy and water penalties and costs: CCS retrofits and four repowering options (CIGCC-CCS, NGCC-V, NGCC-CCS, and CBTL-OT-CCS-38% BIO)—see Table 2. For the six systems compared, generation costs vs. GHG emissions price are shown in Figure 3. There are no capital charges for the reference plant—assumed to be an aged written-off unit. (The average age of U.S. coal plants is 37 years.) The retrofit considered involves recovering CO2 from the dilute stack gases (postcombustion CO2 capture) of an existing coal fired power plant without boiler modification—the least costly retrofit option. The CCS energy penalty (increased coal use per MWh) for capturing 90% of the carbon in the coal as CO2 is 36%, and the water required for power generation at the site increases 33%. Until the GHG emissions price exceeds $76/t CO2eq, a profit-oriented plant manager would choose to pay the emissions fine rather than invest in a CCS retrofit. At that GHG emissions price, the levelized generation cost would be 3.4 X the generation cost for the writtenoff plant when the GHG emissions price is $0/t CO2eq.
The next option considered is repowering the site with a CIGCC-CCS plant. Here repowering is defined as “bulldozing” the site (saving only the infrastructure) and building a completely new plant at the “brownfield” site. With this option CO2 is captured pre-combustion at relatively high concentration and partial pressure from the shifted synthesis gas (mostly H2 + CO2), and the remaining H2–rich synthesis gas is burned in the combustor of a gas turbine/steam turbine combined cycle to make power. In this case the energy penalty is much less (19%) and the water required for the site actually declines by 7% (largely because evaporative cooling water is not needed for the gas turbine part of the power plant). Electricity generated via this CIGCC-CCS will be more costly than for the PC-CCS retrofit for all displayed GHG prices (see Figure 3)— largely because the capital cost is about 3 times that for the retrofit (see Table 2).
The new bullishness about shale gas—potentially abundant and ubiquitous—has created much interest in repowering sites having aged coal plants with NGCC-V systems, for which the required capital investment is ~ ¼ less than for the PC-CCS retrofit strategy, and the site water requirement would decline more than 60%. Moreover, even with the assumed natural gas price ($6.0 per GJ—some 3.5 X the assumed coal price), the levelized generation cost is less than that for the PC retrofit (1/3 less @ $0/t CO2eq, and the GHG emissions price needed to be more costeffective than the written-off coal plant is only $49/t (see Figure 3). However, a shift to NGCC-V, for which GHGI = 0.51, would be an inadequate response to the carbon mitigation challenge for power—CCS is also needed, either initially or as a retrofit at some point during this half century.
The energy penalty for a new NGCC-CCS system with post-combustion capture would be 16%— some 55% less than for the PC-CCS retrofit. This might seem surprising because the flue gas concentration of CO2 is only ~ 6%, so that the energy penalty per tonne of CO2 removed is more than for the CCS retrofit case. However, the H/C ratio = 4 for natural gas vs. 0.8 for coal, so that much less CO2 has to be recovered—0.4 tonnes/MWh vs. 1.2/MWh for the CCS retrofit. Although a NGCC-CCS repowering plant would require 1.4 X the capital investment of a PC-CCS retrofit, its generation cost would be less. However, a very high GHG emissions price (> $89/t) would be required to induce CCS. At lower GHG emissions prices a profit-maximizing NGCC plant manager would instead pay the emissions fine (see Figure 3).
Finally consider repowering with a CBTL-OT-CCS-38% BIO plant consuming 1 million tonnes of biomass per year and whose total energy input is about the same as for the existing coal power plant (see Table 2). Because 2/3 of energy output is synfuels, the production of which requires removal of a stream of pure CO2 even in the absence of carbon mitigation policy, this system is characterized by a much smaller energy penalty (7%) for CCS than for the other options, and water requirements for the site would be reduced 19%. Although the coal-biomass-CCS option requires about 3X the capital investment of the PC-CCS retrofit (see Table 2), co-production of electricity and fuel enables attractive generation economics for prospective oil prices. Assuming that FTL co-products are sold at the refinery gate prices of the displaced crude oil-derived products (including charges for fuel-cycle-wide GHG emissions). Figure 3 shows generation costs for three crude oil prices. Generation costs decline sharply with GHG emissions price because the value of crude oil-derived products displaced increases with GHG emissions price. At the minimum GHG emissions price needed to induce CCS for the retrofit case ($76/t), the electricity generation cost via the coal-biomass-CCS option is 91%, 62%, and 32% of the generation cost for the PC-CCS retrofit for crude oil prices of $50, $75, and $100 a barrel, respectively. The GHG emissions price needed to induce a shift from the existing written-off coal plant to coal-biomass- CCS is $69, $48, and $27/t of CO2eq for crude oil prices of $50, $75, and $100 a barrel, respectively.
Consider, in light of its superior economics, widespread use of the coal-biomass-CCS option for repowering. Deployment is limited by prospective sustainable biomass supplies, estimated for the US to be 0.5 billion tonnes per year (see Sustainable Biomass for Energy above). Imagine (as a “thought experiment”) that all of this biomass is ultimately (e.g., by 2040-2050) used for repowering in this manner. There would be enough biomass generate decarbonized electricity equivalent to 60% of generation by the displaced coal plants while coproducing 3.9 million barrels per day (gasoline equivalent) of low-carbon FTL. If CIGCC-CCS makeup power generated at greenfield sites were to provide the other 40% of displaced generation, annual GHG emissions avoided and CO2 storage rates would amount to 2.2 Gt CO2eq and 1.7 Gt CO2, respectively (see Figure 4). Some 39% of total avoided emissions are due to having biomass in the system—the other 61% would have been realized even if CTL-OT-CCS (see Table 2) instead of CBTL-OTCCS- 38% BIO had been used for repowering.
If instead the same amount of existing coal capacity were decarbonized via a PC-CCS retrofit strategy, low-carbon electricity generated in retrofit plants would be equivalent to 85% of the displaced electricity. If in this case also 100% of makeup power is via CIGCC-CCS plants, the total GHG emissions avoided and CO2 stored would be, respectively, 0.66 X and 1.18 X the rates for the repowering strategy (see Figure 4).
The higher CO2 storage rate for the PC-CCS retrofit strategy is perhaps surprising because the repowering strategy decarbonizes the same amount of electricity as the PC-CCS retrofit strategy plus a large amount of liquid fuels as well; the higher storage requirement arises because of the high efficiency of making electricity via coproduction and the very low efficiency of making electricity via PC-CCS retrofits. These efficiency differences as well as the biomass co-processing aspect of the repowering strategy account for the additional fact that the total coal use for the CCS retrofit strategy is 9% more than for the repowering strategy even though the retrofit strategy involves no synthetic fuel production.
Synthetic gasoline production from coal and/or biomass
During 2009, the Williams Group extended its CBTL analyses to include the production of synthetic gasoline from coal and/or biomass-derived syngas via gasification and intermediate production of methanol. Unlike the better known Fischer-Tropsch (F-T) process, which produces a broad spectrum of straight chain olefins and paraffins that require upgrading to produce finished diesel fuel, gasoline, and lubricants, the so-called methanol-to-gasoline (MTG) process produces primarily a finished-grade gasoline, with a small propane/butane co-product.
Far fewer studies have been published on coal or biomass based MTG processes than for F-T processes, and none have examined MTG processes with CCS. Moreover, there have been no studies that compare F-T and MTG processes using a self-consistent analytical framework. The objectives of the MTG work were to carry out detailed steady-state process design, simulation, and cost analyses for MTG systems using coal and/or biomass feedstocks and compare these results with prior results for F-T systems developed using the same analytical framework.
Exxon-Mobil and Halder Topsoe both offer commercial MTG synthesis technologies. The Exxon- Mobil process begins with methanol production from syngas followed by partial conversion of methanol to DME in a separate reactor, followed by conversion of the DME/methanol mixture into gasoline in a third reactor. The Haldor Topsoe process utilizes an initial single-step conversion of syngas into DME/methanol, followed by conversion to gasoline in a separate reactor. Williams and colleagues have chosen to base their simulations on the Exxon Mobil process because it has the most commercial-scale operating experience, and because more details of the process needed for simulation are available in the literature.
The group presented preliminary performance and cost results for coal-to-gasoline, biomass-to-gasoline, and coal/biomass-to-gasoline systems in May 2009 at the annual NETL CCS Conference.