In 2010, the primary focus of the Williams Group was on technological options for simultaneously producing decarbonized electricity and hydrocarbon transportation fuels by coprocessing biomass with coal or natural gas in systems with CCS. The Capture Group’s work in 2010 was led by its core members, Robert Williams (group head), Tom Kreutz, and Eric Larson, and involved a number of others:
- Guangjian LIU, a post-doctoral fellow, who returned to a faculty position at the North China Electric Power University (Beijing) in September 2010 after 2.5 years with the Williams Group.
- Three Chinese visitors (in-residence at Princeton for 10 to 12 months each):
- Dr. Xiangbo GUO from the Sinopec Research Institute on Petroleum Processing,
- Prof. Haiping CHEN from the North China Electric Power University,
- Mr. Zhe ZHOU, a PhD student of our long-time collaborator Prof. LI at Tsinghua University.
- Andrea Lanzini, a Fulbright scholar from Politecnico di Torino.
- Long-distance collaborations with:
- Prof. Zheng LI at Tsinghua University,
- Prof. Stefano Consonni at Politecnico di Milano,
- Dr. Emanuele Martelli, a former PhD student of Consonni, now a researcher at Politecnico di Milano,
- Michiel Carbo and Dan Jansen at the Energy Research Centre of the Netherlands (ECN).
Fischer-Tropsch fuels and electricity from coal and biomass with CCS
In 2010 the Williams Group refined and finalized its research on the co-production of low carbon electricity and Fischer-Tropsch liquid (FTL) transportation fuels from gasified bituminous coal and biomass with and without CCS, publishing a comprehensive summary of this work. Detailed process simulations, lifecycle greenhouse gas emissions analyses, and cost analyses carried out in a comprehensive analytical framework were presented for 16 alternative plant configurations. Cost estimates developed for Nth-of-a-kind plants on a component-by-component basis were the foundation for a self-consistent comparison of relative costs among a wide range of alternative energy systems. Systematic comparisons were made to cellulosic ethanol as an alternative low GHG-emitting liquid fuel and to alternative options for decarbonizing stand-alone fossil-fuel power plants.
The analysis found that FTL fuels are typically less costly to produce when electricity is generated as a major co-product than when producing mainly liquid fuel. Co-production systems that coprocess biomass along with coal and employ CCS offer attractive opportunities for decarbonizing liquid fuels and power generation simultaneously. These co-production systems can provide decarbonized electricity at lower costs than is feasible with stand-alone fossil-fuel power plant options under a wide range of economic conditions (i.e. crude oil and GHG emissions prices).
The advantages of co-producing electricity and FTL fuels from coal and biomass with CCS are impressive under a carbon mitigation policy. For example, the group simulated a plant coprocessing 29% biomass with coal and providing 70% of its output in the form of FTL (10,880 barrels per day) and 30% as electricity (287 MWe) while storing 65% of the feedstock carbon underground as CO2 (referred to as CBTL-OTA-CCS-29%). By making use of the net “negative emissions” of stored CO2 from biomass, at a plausible future GHG emissions price of $50/tonne CO2eq, this system could provide low GHG-emitting synthetic fuels at the same levelized cost of fuel (LCOF) as for a coal-to-liquids plants with CCS having nearly four times the FTL output capacity, but a GHG gas emission rate ten times higher. At the same time, when the crude oil price is $90 a barrel, this co-production plant would provide electricity at only ¾ of the levelized cost of electricity (LCOE) as for its closest stand-alone power plant competitor in terms of LCOE—a natural gas combined cycle plant that vents CO2.
Overview analyses of the coal and biomass to fuels and power with CCS concept were carried out during 2010 via invited papers prepared for the Annual Review of Chemical and Biomolecular Engineering and for an international conference convened by the East-West Center and the Korea Energy Economics Institute.
Synthetic gasoline and electricity from coal and biomass
Synthetic gasoline and electricity from coal and biomass The most widely known commercial route for converting solids into transportation fuels is the coupling of gasification to synthesis of FTL fuels. Building on the extensive FTL analytical effort and on a preliminary analysis of methanol to gasoline (MTG) carried out in 2009 as part of contributions to the National Research Council’s America’s Energy Future study, Williams and colleagues began a systematic analysis of manufacturing synthetic gasoline, an especially relevant fuel for the gasoline-intensive transportation sector of the U.S. The MTG process produces primarily a finished-grade gasoline, with at most a minor LPG-like co-product. Exxon-Mobil and Haldor Topsoe offer MTG technology.
In 2010, the Williams Group modeled coal to gasoline (CTG), biomass to gasoline (BTG), and coal/biomass to gasoline (CBTG) systems, without and with CCS, using the same analytic framework as for the FTL analysis, and began a systematic comparison of FTL and MTG systems. Their findings indicate that, at similar plant scales and with comparable inputs, FTL and MTG systems have comparable GHG emissions characteristics and production costs. Moreover, the levelized cost of fuel (LCOF) for the MTG system is 6% higher than for the coal-based FTL system described in the last section if the GHG emissions price is $50/tCO2e. If at the same time the crude oil price is $90/barrel, the LCOE would be 9% less than for the coal-based FTL system. Preliminary findings for the MTG analysis are presented in the final draft of the Knowledge Module 12: Fossil Energy Systems of the forthcoming Global Energy Assessment (the GEA is discussed below).
Synthetic liquid fuels and electricity from natural gas and biomass with CCS
During 2010 the Williams Group began exploring the co-production of FTL transportation fuels and electricity from natural gas and biomass with CCS (Figure 1 – next page). Emphasis was given to an economic evaluation of such systems as power generators to find out:
- if it makes strategic and economic sense to make transportation fuels as well as electricity from natural gas in light of the new bullishness about shale gas and other unconventional gas supplies,
- if this approach can enable a transition to CCS and thus deep reductions in emissions for electricity based on natural gas at a lower GHG emissions price than for natural gas combined cycle (NGCC) power plants (which require GHG emissions prices above $80/t of CO2eq to induce CCS via market forces), and
- how this approach to low-carbon fuels compares to both biofuels and to systems with CCS that co-process coal and biomass to make low-carbon liquid fuels and electricity—which our previous research found to be an especially attractive approach for making liquid fuels.
The findings of this study were presented by Williams at GHGT-10 in the context of a comparison between a natural gas-based system (GBTL-OT-CCS-34%, for which biomass accounts for 34% of the feedstock energy—see Figure 1) and its coal counterpart (CBTL-OTACCS-29% – described above). Each consumes 1 million tonnes per year of biomass and in each case has a fuel-cycle-wide GHG emission rate that is at least 90% less than that for the fossil energy displaced [assumed to be crude derived diesel and gasoline and electricity from a new supercritical pulverized coal plant that vents CO2 (Sup PC-V)].
The most notable differences between the natural gas-based and coal-based co-production systems are that:
- the natural gas-based system converts 34.5% of the feedstock C to FTL compared to 24.2% for the coal-based systems—a consequence of the much lower H/C ratio for coal compared to natural gas (0.8 vs. 4.0);
- the FTL output amounts to 34.4% of input energy for natural gas-based system compared to 32.5% for the coal-based system—showing that the energy penalty for the hydrogen-poor coal feedstock is much less than is suggested by the carbon conversion to final products;
- the CO2 storage rate for the natural gas-based system is only half that for the coal-based system, reflecting both the lower H/C ratio for coal and the fact that the latter option vents as CO2 only 6.6% of the C in the feedstock compared to 12.4% for GBTL-OT-CCS-34%;
- the natural gas-based option is much less capital intensive than the coal-based option.
Figure 1. A gas to FTL system ( GBTL‐OT‐CCS‐34% ) that provides F‐T liquids (via use of a cobalt catalyst) and electricity from natural gas and biomass. Natural gas is converted to syngas in an autothermal reformer. Syngas is generated from biomass in a fluidized bed gasifier. The autothermal reformer is also used to crack (i.e., eliminate) the tars from the biomass‐derived syngas. 52% of C in the feedstocks is captured, compressed to 150 bar, and sent via pipeline to a geological storage site. The system was designed with enough biomass co‐processing (34% on an energy basis) to realize a 90% reduction in system‐wide GHG emissions relative to the fossil energy displaced. Such a system consuming 1 million tonnes per year of biomass would provide 9,750 barrels/day of FTL + 300 MWe of net electricity at an overall net energy efficiency of 50%. It is assumed that the captured CO2 is pressurized to 150 atmospheres, transported via pipeline 100 km, and stored in a deep saline formation 2 km below ground—as in the case of the CBTL‐OTA‐CCS‐29% system, to which it is compared in the main text.
Figure 2. Levelized cost of electricity (LCOE) vs. GHG emissions price for a crude oil price of $90/barrel. Assumed coal and natural gas prices are $2.0 and $5.1 per GJ, respectively—levelized prices over 2016‐2035 based on projected US average prices to electricity generators in the Reference Scenario of the Energy Information Administration’s Annual Energy Outlook 2011. The assumed biomass price is $5.0 per GJ.
NGCC = natural gas combined cycle; CCS = carbon capture and storage; Sup PC = supercritical pulverized coal; CIGCC = coal integrated gasifier combined cycle; GBTL = natural gas to liquid fuel; CBTL = coal/biomass to liquid fuel; OT = once‐ through with mild CO2 capture; OTA = once‐through processing with aggressive CO2 capture; V = vent; CCS = carbon capture and storage; percentages indicate portion of feedstock energy that comes from biomass.
Figure 2 presents the LCOE vs. GHG emissions price for these two options along with the CO2 vented versions, as well as for four stand-alone power plant technologies (assuming that the crude oil price is $90/barrel, the price at the time of this writing). The important results from this set of curves are:
- even at $0/t GHG emissions price, the natural gas-based system offers a lower LCOE than does a coal integrated gasifier combined cycle power plant with 88% capture;
- it provides less costly electricity than a natural gas combined cycle plant venting CO2 for GHG emissions prices greater than $46/t—thereby enabling natural gas to provide low carbon power at a much lower GHG emissions price than is needed to induce CCS at a natural gas combined cycle plant.
The LCOE for these systems depends sensitively on crude oil price (as in the case of coal-based co-production systems). The LCOE increases (decreases) for natural-gas based systems by $13.5/MWh for each $10 a barrel decrease (increase) in the crude oil price, independent of the GHG emissions price.
Since future oil prices are highly uncertain, how would governments interested in promoting transportation fuel supply security protect investors in these co-production technologies against the risk of oil price collapse? Figure 3 suggests a powerful approach: a strong carbon mitigation policy + widespread deployment of co-production technologies with CCS and a high degree (~ 30%) of biomass co-processing—whether the feedstock is natural gas or coal. Figure 3 shows, for example, that if the carbon mitigation policy in place is equivalent to a GHG emissions price of $60/t of CO2eq, investors in the natural gas-based and coal-based systems described above would profit down to crude oil prices of $65/barrel and $58/barrel, respectively—i.e., there would be no need for a (potentially very-costly-to-government) guaranteed floor price for oil: a strong carbon mitigation policy could powerfully protect investors against the risk of oil price collapse for modest-scale (~ 10,000 barrels per day) co-production facilities that offer low GHG-emitting liquid fuels.
This finding is in sharp contrast to the present approach by synfuel project developers who seek to build huge plants so as to protect their investors against the oil price collapse risk by exploiting economies of scale. The Qatar Pearl natural gas-based FTL project involves constructing a 140,000 barrels/day project that is likely to end up costing ~ $20 billion to build. Much less capital would be at risk for natural gas-based or coal-based co-production systems, for which Nth of a kind (NOAK) plants would cost perhaps $1.3 to $1.8 billion and 1st of a kind (FOAK) plants would cost perhaps twice that much.
It is worth noting that these relatively small distributed co-production systems co-processing about 30% biomass (based on either natural gas or coal) would require < 40% as much biomass to Figure 3. Breakeven crude oil price (BECOP) vs. GHG emissions price for alternative co‐production options. CTL = coal‐to‐liquid fuel; OT= once‐through processing with mild CO2 capture; OTA = once‐through processing with aggressive CO2 capture; V = vent; CCS = carbon capture and storage; GBTL = natural gas‐to‐liquid fuel; CBTL = coal/biomass to liquid fuel; percentages represent portion of feedstock that is biomass. 21 make a given quantity of synthetic liquid fuel as would conventional next generation biofuels such as cellulosic ethanol (see Figure 4)—which is very important in light of growing concerns about conflicts with food production, indirect land use effects, and biodiversity loss associated with the growing of biomass for energy on croplands. The co-production systems described here could make major contributions to both carbon mitigation and energy security enhancement in the U.S. and worldwide using only lignocellulosic biomass in the forms of crop residues and forest residues and biomass grown as dedicated energy crops on abandoned croplands.
Figure 5 shows, in addition, that the levelized cost of fuel (LCOF) for co-production systems providing low C fuels is likely to be much less than for either biochemically derived cellulosic ethanol (the historical focus of U.S. biofuels development) or pure biofuels technologies based on thermochemical conversion—both sets of technologies that can also use lignocellulosic biomass that does not require good cropland for its production.
Finally, it should be noted that the economic analyses presented in these figures are based on the assumed feedstock prices indicated in the caption for Figure 2. The results are very sensitive to relative prices, and a modest change in the relative prices could bring natural gas- and coal-based FTL systems into dead heat competition.
Williams will present a paper comparing natural gas/ biomass co-production of fuels and power to coal/biomass co-production of fuels and power at the Annual Meeting of the American Chemical Society in Anaheim, California in March 2011.
Prospects for using captured CO2 to make transportation fuels
“Recycle/Reuse” is a seemingly virtuous approach to natural resource management. For example, it is well known that recycling/reuse is indeed both resource-conserving and cost-effective for aluminum cans. But the concept is not always “virtuous.” For example, while plutonium recycle/reuse leads to more efficient use of uranium in nuclear power plants, doing so won’t be cost-effective for at least many decades and introduces a significant risk that the plutonium separated from spent nuclear fuel will be used to make nuclear weapons. What about “recycle/reuse” of the fossil fuel carbon in the form of CO2 in the flue gases of coal power plants?
Capturing CO2 at fossil energy conversion plants and using it for enhanced oil recovery, with eventual permanent storage of the captured CO2, is widely recognized as an important market-based strategy for launching CO2 capture technologies, but there is wide interest (e.g., in China) in using fossil fuel power plant CO2 to make other useful products. In the United States, the US Department of Energy recently dedicated $107 million to twelve “Innovative Concepts for Beneficial Reuse of Carbon Dioxide”, of which the most numerous and globally significant are systems that use microalgae to capture CO2 from power plant flue gas and convert it (via sunlight, water, and nutrients) into natural oils that are readily processed into liquid transportation fuels such as biodiesel.
The Intergovernmental Panel on Climate Change in its 2005 Special Report on CCS pointed out that CO2 use to make industrial products represents, at best, a marginal carbon mitigation opportunity: “The scale of the use of captured CO2 in industrial processes is too small, the storage times too short and the energy balance too unfavorable for industrial uses of CO2 to become significant as a means of mitigating climate change.” But the algal oil idea cannot be dismissed as Figure 5. Levelized cost of fuel (LCOF) in $ per gallon of gasoline equivalent (gge) vs. GHG emissions price for alternative low‐carbon fuels derived from switchgrass. In all cases, the assumed annual biomass input rate is 0.5 million dry tonnes per year. 23 a niche opportunity, when one considers, as an example, that the US in 2008 consumed fossil fuel carbon in the amounts of 500 million tonnes in the form of transportation fuels while simultaneously emitting 540 million tonnes from pulverized coal steam electric power plants. So, in principle, if the CO2 in flue gases of these power plants were captured and used by being converted into carbonaceous liquid fuels using solar energy or another carbon-free energy source to provide the needed process energy, enormous quantities of transportation fuels could be provided without increasing GHG emissions.
However, this example also highlights the essence of the shortcomings of reuse to make transportation fuels: If, hypothetically, 100% of the CO2 from flue gases of US coal power plants were converted via carbon-free energy sources into transportation fuels that were to displace crude oil-derived transportation fuels, the carbon emissions for the system of making both transportation fuels and electricity from coal would be reduced by only 50% from the level of the current system that makes electricity from coal with CO2 venting and transportation fuels from crude oil. Thus, deep reductions in GHG emissions for transportation fuels + electricity generation are not feasible, even in principle, for coal-power emissions derived transportation fuels production.
In a paper presented at GHGT-10, Kreutz estimated the potential for GHG emissions reduction via use of coal power plant CO2 to make synthetic liquid transportation fuels for two sets of novel technologies: i) growing algae in algal ponds to make biodiesel and ii) using concentrated sunlight to reduce CO2 to CO and O2 and/or H2O to H2 and O2 and then make liquid fuels via FischerTropsch synthesis. For these two technologies Kreutz estimated the potential for system-wide GHG emissions reduction (for energy consumption as well as production) for two different economic conditions: 1) for a GHG emissions price P less than the GHG emissions price PD needed to induce widespread decarbonization of the electric power sector (e.g. by CCS), and 2) for P > PD. Emissions reduction was measured relative to the GHG emissions of displaced crude oil-derived products + electricity from a supercritical pulverized coal plant (both synfuels production processes produce small amounts of electricity as a byproduct).
When P < PD , using flue gas CO2 to make biofuels is equivalent to extracting CO2 from the atmosphere, because a profit-motivated power generator would vent CO2 to the atmosphere and pay the emissions fine rather than invest in CCS. In this case, Kreutz estimated that the potential fuel cycle-wide GHG emissions reduction is 65% for making biodiesel from algae and 90% for making FTL via high temperature solar heat.
For P > PD, when CCS is assumed to be widespread, CO2 for fuel would come mainly from pipelines that carry CO2 to underground storage sites. In this case, CO2 diversion to the manufacture of liquid fuels would be equivalent to extracting CO2 from underground. For P > PD, Kreutz estimated that making FTL via high temperature solar heat would reduce GHG emissions by only 40%, and algal biofuels would increase emissions by 8%. Thus, at high carbon prices, the carbon mitigation potential of CO2 use strategies to make synthetic transportation fuels is, at best, modest. According to Kreutz: “Using the carbon twice fails to meet the objective of deep GHG emission reductions across the entire energy economy; only one sector (either power or transportation) – but not both – can claim the benefit of carbon neutrality.” Thus, unless they are coupled with (at present, only nascent) technologies that enable the direct capture of CO2 from the air, processes that use CO2 to make synthetic fuels would not enable the deep (80+%) reductions in GHG emissions that leaders of industrialized countries are targeting for the energy economies of their countries by mid-century.