The goal of the capture group, in collaboration with researchers at Tsinghua University (see Box 1) and the Politecnico di Milano (see Box 2), is to assess the feasibility of and potential technology costs for bringing about a low-carbon energy economy.
Production of Hydrogen and Electricity with CO2 Capture
A major focus of the capture group, in collaboration with colleagues at the Politecnico di Milano, has been to examine how fossil fuels – primarily coal and natural gas – can be converted to hydrogen and electricity (both carbon-free energy carriers) with CO2 capture and storage (CCS). This involves chemical conversion of the fuel into a synthesis gas (or “syngas”), followed by a separation process in which CO2 and hydrogen are selectively removed from the syngas. Typically, the remaining components of the syngas are burned in a combined cycle to produce electric power, increasing the overall efficiency of the process.
Tom Kreutz led a series of detailed investigations comparing the thermodynamic and economic performance of various systems that convert fossil fuels into hydrogen and electricity. In one set of studies, coal-to-H2 systems composed of “commercial-ready” components were compared with novel, membrane-based gas separation technologies. The novel plants were found to yield only modest reductions in the cost of hydrogen. In another study, the cost of coal-based hydrogen and electricity production – both with and without CCS – was compared with the cost of production from natural gas as a way of ascertaining which economic conditions (carbon tax and price of natural gas) might lead to large scale capture and storage of CO2. Producing hydrogen from coal was found to offer the lowest cost barriers to large scale CCS, because the incremental CO2 capture costs are quite modest. The CO2 co-product of H2 manufacture from coal is available as a relatively pure stream, so that the capture cost, consisting mainly of CO2 compression costs to make the CO2 disposal-ready, adds only about 10% to the production cost. Co-capture and co-storage of sulfur-bearing species – either H2S or SO2, depending on the system – along with the CO2 has the potential to lower system costs.
H2 and CO2 Infrastructures
Joan Ogden, who recently moved to U.C. Davis, led initiatives to model the logistics of transitioning to a low-carbon economy while with CMI.
Dr. Ogden and colleagues have carried out both generic studies modeling H2 and CO2 pipeline infrastructures and regionally specific studies using GIS data for Ohio.
A major finding of the generic studies is that the cost of CO2 storage in deep aquifers (including the cost of CO2 pipeline transport) is likely to be modest if CO2 transport distances are not too large. For a 100 km transport distance, storage for CO2 from coal adds less than 10% to the cost of H2 with capture. However, this estimate does not include monitoring costs or other post-injection (e.g., remediation) costs.
After analyzing the spatial relationships of population, energy plants, and possible pipeline paths in Ohio, the researchers determined that delivery of hydrogen will likely be economical for urban centers, where the majority of the population lives.
In contrast, distributing hydrogen to rural areas with low population densities is unlikely to be cost-effective. The high costs of transporting hydrogen gas through pipelines or liquid hydrogen by truck, coupled with low demand, will likely hinder market penetration into rural areas and present significant obstacles to making hydrogen fuels as convenient as gasoline without breakthroughs in hydrogen storage technology.
CO2 Capture and Storage in Manufacturing Synthetic Liquid Fuels
There are likely to be some fuels markets even in the long term that cannot easily be served by either H2 [e.g., in low energy use density (rural) regions] or electricity. Some mix of biofuels, liquid fuels derived from natural gas, and liquid fuels derived from synthesis gas via gasification of carbon-rich fossil fuel feedstocks would be needed. In a climate-constrained world carbon-neutral biofuels would be the most desirable, but the extent to which they can meet this need is uncertain because of land-use constraints. Fossil fuel-based liquid fuels might also thus be needed.
As part of the CMI collaboration with Tsinghua University (see Box 1), Bob Williams is leading a research effort that is exploring the production of liquid fuels from gasification-derived synthesis gas under a climate constraint. Because coal is the main fossil fuel resource in China, this effort is focusing initially on coal as the gasification feedstock, but the findings for coal are broadly applicable to other carbon-rich feedstocks (tar sands, petroleum residuals, heavy oils) as well.
The basis approach involves making high H/C liquid fuels (H/C ~ 2-4) from coal, for which H/C ~ 0.8. As in the case of making H2 from coal, the CO2 coproduct of liquid fuel manufacture is typically available as a relatively pure stream, so that CO2 capture costs are modest. Under a climate constraint, nearly all of the carbon originally in the coal feedstock that is not contained in the liquid fuel itself can be recovered and disposed of underground as CO2. With full CCS, there are still CO2 emissions associated with the combustion of these liquid fuels, but on a fuel cycle-wide basis, greenhouse-gas (GHG) emissions per unit of synthetic fuel energy might typically be ~ 0.8 times the GHG emissions liquid fuels derived from natural gas or crude oil.
The research is showing that the most cost effective configurations often involve “once-through” synthesis, which obviates the need for costly synthesis gas recycle equipment. In these systems the synthesis gas passes only once through the synthesis reactor (in which the synthetic fuel is made) and the gas not converted in a single pass is used either to make co-product electricity in a combined cycle power plant or to make a mix of H2 and electricity (see figure above). The latter option is an especially promising way to introduce H2, because the CMI/Milan collaborative research shows that there is no “preferred” H2/electricity output ratio from production cost and thermodynamic perspectives, so the ratio of H2 to electricity output can be adjusted to match demand.
Such “polygeneration” systems are already established in many countries at refineries and chemical process plants that coproduce electricity and chemicals—mainly via gasification of petroleum residuals. It is straightforward to extend the technology to co-production of liquid fuels and to coal as a feedstock. The extension is probably easier in China than in most other regions because China’s chemical process industry is to a considerable extent already based on use of modern coal gasification technology.
An important finding is the possibility of gaining experience with CCS in polygeneration systems even before a market value is put on CO2 emissions—in conjunction with an innovative approach to “acid gas management” for such systems. The possibility arises because maximizing synthesis gas conversion to liquid fuel in a single pass through the synthesis reactor requires partial shifting of the synthesis gas upstream of the synthesis reactor and removal of the CO2 produced as a relatively pure stream. H2S must also be removed from the synthesis gas ahead of the synthesis reactor to protect synthesis catalysts. There are two alternative possibilities for managing these acid gases. They might be removed separately, with H2S reduced to elemental sulfur and CO2 vented, or they might be removed together and stored underground. The CMI/Tsinghua analyses suggest that in some instances the latter would be the less costly option. The amounts of CO2 involved depend on the synthetic fuel produced but can be significant—typically involving CO2 quantities equivalent to 30% or more of the carbon in the coal, Disposal rates at a typical facility would be 1-2 million tonnes of CO2 per year. However, it is uncertain whether underground CO2/H2S co-storage is a viable option at such large scales in widespread applications. Successful experience with 39 small acid gas disposal projects in Western Canada in conjunction with the production of sour natural gas resources is promising. More research and “megascale” demonstration projects are needed to ascertain the viability of this option.
Costs of Fuel Cell Vehicles
Analysis by Dr.’s Ogden, Williams, and Larson shows that future hydrogen fuel cell cars would not be competitive if taxes on conventional fuels account only for their contribution to climate damages, even under relatively optimistic assumptions about future costs for fuel cell cars. However, when air pollution and energy security externalities are also included in the lifetime-cost calculations, it appears that hydrogen fuel-cell cars might be competitive. The researchers observe that there are large uncertainties in the valuation of these externalities, and that it not yet known how to bring fuel cell car costs down to the levels assumed in their analysis.
Eric Larson leads an effort to assess advanced technologies for using biomass for energy—exploring prospective performance, costs, GHG and air pollutant emissions, and other impacts.
Black Liquor Gasification
One research area has been gasification of “black liquor.” Currently, black liquor, the lignin-rich byproduct of kraft pulp making, is burned in boilers to provide steam and power for the pulp mill. Gasification technologies are being developed that could be used to provide electricity and heat for a mill much more efficiently and cleanly than today’s technologies, enabling substantial electricity exports to the grid where they could displace fossil fuel electricity. Analysis by Larson and colleagues indicates that black liquor gasification would be cost competitive with conventional technology if scaledup for commercial use, even in the absence of financial incentives for low-emissions technologies.
Box 1: CMI/Tsinghua Collaboration
The group’s collaboration with the bp-sponsored “Clean Energy Facing the Future” program at Tsinghua University, begun in 2001, has expanded its capacity to model clean and climate-friendly energy systems. The collaboration has focused on study of polygeneration systems for making electricity, chemicals, fuels, and heat from fossil fuels.
Prof. Ren Tingjin from Tsinghua visited Princeton for a one-year period during 2002-2003 to collaborate on modeling production of liquid fuels (dimethyl ether and methanol) via coal gasification.
CMI and Tsinghua researchers were major participants in an August 2003 workshop in Beijing organized by the Task Force on Energy Strategies and Technologies (TFEST) of the China Council for International Cooperation on Environment and Development (CCICED) to review coal gasification-based energy strategies for China that are being developed in the CMI/Tsinghua collaboration. CMI/Tsinghua research provided the key technical analysis supporting the broad findings and recommendations of the TFEST report to the CCICED. This TFEST report has recently been presented to the highest levels of the Chinese government. A special issue of the journal, Energy for Sustainable Development, guest-edited by Eric Larson and Li Zheng (Tsinghua) and published in December 2003, is an edited and peer-reviewed collection of dedicated to papers from the TFEST workshop.
If gasification-based energy strategies are adopted in China, it will be possible to reduce air pollution from coal use and decrease dependence on imported oil, while putting in place a key enabling technology (gasification) for carbon capture and storage.
Box 2: CMI/Politecnico di Milano Collaboration
The CMI Capture group began a formal research collaboration with the Energy Department at Politecnico di Milano in the fall of 2001, tapping into their expertise in designing and modeling innovative power cycles. The group, headed by Ennio Macchi and including Giovanni Lozza, Stefano Consonni, and Paolo Chiesa, is known worldwide for its research in advanced energy systems. The CMI collaboration strengthened a longstanding, less formal partnership between the two groups which has been active since Stefano Consonni received his Ph.D. (modeling advanced gas and steam turbine cycles) at Princeton in 1992.
Prof. Chiesa spent six months visiting Princeton in 2001, collaborating on zero CO2 emission coal-to-H2 systems that employ hydrogen separation membrane reactors. More recently, Prof. Consonni and a graduate student, Federico Vigano, spent the 2002-2003 academic year at Princeton, collaborating on a number of studies examining the production of H2 and electricity from both coal and natural gas using “commercially ready” technologies.
The collaboration has led to a number of joint papers and on-going projects.
Economics of Biomass Refineries
Dr. Larson is playing a leading role in a new 2-year, multi-institution project assessing possible future roles for biomass in the US energy economy. His team is analyzing alternative thermochemical (gasification-based) conversion technologies and costs for large-scale electricity and transportation fuels production from plantation-grown biomass (switchgrass). A goal is to find paths to large-scale biomass energy production that ultimately will be sustainable without government subsidies. This study will help provide a better understanding of the competition between liquid biofuels and H2 in transportation, as well as the competition between liquid biofuels and fossil fuels used directly in markets not easily served by H2 and electricity.
Combustion of Alternative Fuels
Proponents of a hydrogen economy envision that cars and trucks would be ultimately be powered by fuel cells that use hydrogen as an energy source and produce only water vapor as exhaust. Before this advanced technology becomes available, substantial emissions reductions could be achieved by adapting conventional internal combustion engines (ICE’s) to burn hydrogen fuel.
Because hydrogen gas has a low power density, hydrogen ICE’s are supercharged to boost performance. Supercharging, however, promotes other combustion problems, especially the propensity for pre-ignition and engine knock which limit fuel efficiency. Adoption of hydrogen as a fuel is also hampered by the potential for explosion from slow-leaking or punctured hydrogen tanks.
Chung K. Law and colleagues are carrying out simulations and experiments to find solutions for hydrogen combustion and safety problems. The team has determined the conditions for hydrogen ignition, and shown that mixing propane with hydrogen moderates the burning intensity of hydrogen flames such that the tendency to knock could be correspondingly reduced. In addition, combining propane with hydrogen lowers the potential for explosion in storage.
In a related project, Yiguang Ju is leading an effort to study the combustion of dimethyl ether (DME), a synthetic liquid fuel. This research has demonstrated that DME combustion is very unstable under high pressure, and that flame speeds are inconsistent with current kinetic models. The group therefore intends to compile measurements of chemical kinetics for DME-air combustion to improve the accuracy of numerical modeling for industrial application. The group’s numerical simulations also demonstrate that a lean DME-air mixture behaves much differently than mixtures of other large hydrocarbon fuels. Dilution of the DME fuel mixture with CO2 in air will lift the DME-air flame and significantly reduce the soot emission. This result is contrary to current theory, and provides important fundamental data and information for DME combustor design.