Bibliography - Thomas Kreutz

1. Liu, Guangjian, Eric Larson, Robert H. Williams, Thomas Kreutz, and Xiangbo Guo, 2011: Making Fischer-Tropsch Fuels and Electricity from Coal and Biomass: Performance and Cost Analysis. Energy Fuels, Published on Web 12/06/2010, (25), doi:10.1021/ef101184e 415-437
   [ Abstract ]

   Major challenges posed by crude-oil-derived transportation fuels are high current and prospective oil prices, insecurity of liquid fuel supplies, and climate change risks from the accumulation of fossil fuel CO₂ and other greenhouse gases in the atmosphere. One option for addressing these challenges simultaneously involves producing ultraclean synthetic fuels from coal and lignocellulosic biomass with CO₂ capture and storage. Detailed process simulations, lifecycle greenhouse gas emissions analyses, and cost analyses carried out in a comprehensive analytical framework are presented for 16 alternative system configurations that involve gasification-based coproduction of Fischer-Tropsch liquid (FTL) fuels and electricity from coal and/or biomass, with and without capture and storage of byproduct CO₂. Systematic comparisons are 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 indicates that FTL fuels are typically less costly to produce when electricity is generated as a major coproduct than when producing mainly liquid fuel. Coproduction systems that utilize a cofeed of biomass and coal and incorporate CO₂ capture and storage in the design offer attractive opportunities for decarbonizing liquid fuels and power generation simultaneously. Such coproduction systems considered as power generators can provide decarbonized electricity at lower costs than is feasible with stand-alone fossil-fuel power plant options under a wide range of conditions. At a plausible GHG emissions price under a future U.S. carbon mitigation policy ($50/t CO_2eq), such a coproduction system built at a scale suitable for competing as a power generator would be able to provide low-GHG-emitting synthetic fuels at the same estimated unit cost as for coal synfuels characterized by ten times the GHG gas emission rate that are produced in a plant with CO₂ capture and storage that does not provide electricity as a major coproduct having three times the synfuel output capacity and requiring twice the total capital investment. Moreover, the low GHG-emitting synfuels produced by such systems would be less costly to produce than cellulosic ethanol and require only half as much lignocellulosic biomass.

2. Martelli, E., Thomas Kreutz, Michiel Carbo, S. Consonni, and D. Jansen, 2011: Shell coal IGCCS with carbon capture: Conventional gas quench vs. innovative configurations. Applied Energy, Elsevier, 88, doi:10.1016/j.apenergy.2011.04.046
   [ Abstract ]

   The Shell coal integrated gasification combined cycle (IGCC) based on the gas quench system is one of the most fuel flexible and energy efficient gasification processes because is dry feed and employs high temperature syngas coolers capable of rising high pressure steam. Indeed the efficiency of a Shell IGCC with the best available technologies is calculated to be 47-48%. However the system looses many percentage points of efficiency (up to 10) when introducing carbon capture. To overcome this penalty, two approaches have been proposed. In the first, the expensive syngas coolers are replaced by a "partial water quench" where the raw syngas stream is cooled and humidified via direct injection of hot water. This design is less costly, but also less efficient. The second approach retains syngas coolers but instead employs novel water-gas shift (WGS) configurations that requires substantially less steam to obtain the same degree of CO conversion to CO₂, and thus increases the overall plant efficiency. We simulate and optimize these novel configurations, provide a detailed thermodynamic and economic analysis and investigate how these innovations alter the plant's efficiency, cost and complexity.

3. Williams, Robert H., Guangjian Liu, Thomas Kreutz, and Eric Larson, 2011: Coal and Biomass to Fuels and Power. Annual Review of Chemical and Biomolecular Engineering, 2, doi:10.1146/annurev-chembioeng-061010-114126 529-553
   [ Abstract ]

   Systems with CO₂ capture and storage (CCS) that coproduce transportation fuels and electricity from coal plus biomass can address simultaneously challenges of climate change from fossil energy and dependence on imported oil. Under a strong carbon policy, such systems can provide competitively clean low-carbon energy from secure domestic feedstocks by exploiting the negative emissions benefit of underground storage of biomass-derived CO₂, the low cost of coal, the scale economies of coal energy conversion, the inherently low cost of CO₂ capture, the thermodynamic advantages of coproduction, and expected high oil prices. Such systems requiremuch less biomass to make low-carbon fuels than do biofuels processes. The economics are especially attractive when these coproduction systems are deployed as alternatives to CCS for stand-alone fossil fuel power plants. If CCS proves to be viable as a major carbon mitigation option, the main obstacles to deployment of coproduction systems as power generators would be institutional.

4. Kreutz, Thomas, 2010: Prospects for producing low carbon transportation fuels from captured CO₂ in a climate constrained world. ScienceDirect, http://www.princeton.edu/pei/energy/publications/texts/Kreutz-GHGT10-final-%2810-29-10%29.pdf
   [ Abstract ]

   The climate implications of technologies that capture CO₂ to produce transportation fuels (CCTF) are investigated by study-ing two examples: biodiesel from microalgae and Sandia National Laboratory’s S2P process. Simple performance and economic models for each technology are examined in the context of a bifurcated – “pre-CCS” vs. “post-CCS” – climate regime in which CCTF uses CO₂ that is, respectively, captured from power plant flue gases or taken from CCS pipelines. CCTF promises to im-prove domestic energy security by converting sunlight and waste CO₂ into transportation fuels; in addition, these fuels are roughly climate neutral when CO₂ is captured from either flue gases or directly from the atmosphere. However, after the power sector becomes largely decarbonized under a stringent climate policy, large point sources of concentrated CO₂ are likely to be relatively rare, and unfortunately, fuels made from pipeline CO₂ destined for storage do not have markedly reduced net GHG emissions. Thus, absent the development of economical CO₂ capture from air, it’s difficult to see how CCTF can play a signifi-cant long term role in decarbonizing the US transportation sector (and thus reaching US climate goals).

5. Liu, Guangjian, Robert H. Williams, Eric Larson, and Thomas Kreutz, 2010: Design Economics of Low-Carbon Power Generation from Natural Gas and Biomass with Synthetic Fuels Co-Production. International Conference on Greenhouse Gas Technologies (GHGT 10), Elsevier/Energy Procedia,
   [ Abstract ]

   There is growing optimism about the prospects for large natural gas reserves in shale formations. This paper explores the feasibility vis-à-vis coal power generation of a new approach for decarbonized natural gas power generation. Key features of process designs examined here are coproduction of synthetic transportation fuels with electricity and co-feeding of some biomass with natural gas in such co-production systems. Key questions addressed in the analysis of these systems are: 1) can the competitiveness of natural gas in economic dispatch be improved vis-à-vis a natural gas combined cycle, and 2) can the GHG emissions price needed to induce CCS for natural gas power generation be reduced from that required to induce CCS for NGCC. We find that gas/biomass co-production systems with CCS will be able to defend high capacity factors in economic dispatch at projected oil prices with only modest GHG emission prices. We also find that the breakeven GHG emission price needed to induce CCS for natural gas power generation is reduced considerably vis-à-vis NGCC-CCS.

6. Williams, Robert H., Guangjian Liu, Thomas Kreutz, and Eric Larson, 2010: Alternatives for Decarbonizing Existing USA Coal Power Plant Sites. International Conference on Greenhouse Gas Technologies (GHGT 10), Elsevier/Energy Procedia,
   [ Abstract ]

   A CO₂ capture and storage (CCS) retrofit strategy is compared to several repowering strategies for decarbonising existing coal power plant sites. The more promising repowering approaches analyzed seem to be a shift to natural gas via natural gas combined cycles and deployment of systems that coproduce synthetic liquid fuels plus electricity from coal and biomass with CCS. Under a wide range of plausible conditions, the latter option seems to the most promising approach for decarbonising these plant sites—exploiting simultaneously the carbon mitigation benefit of coprocessing biomass in CCS energy systems and the more general benefits offered by coproduction systems with CCS of: (i) a low CO₂ capture cost, (ii) a high efficiency of power generation, and (iii) large credit for the sale of the synfuel coproducts at current or higher oil prices.

7. Larson, Eric, G. Fiorese, Guangjian Liu, Robert H. Williams, Thomas Kreutz, and S. Consonni, 2009: Co-production of decarbonized synfuels and electricity from coal + biomass with CO₂ capture and storage: an Illinois case study. Energy and Environmental Science,
   [ Abstract ]

   Energy, carbon, and economic performance are estimated for facilities co-producing Fischer- Tropsch Liquid (FTL) fuels and electricity from a co-feed of biomass and coal in Illinois, with capture and storage of by-product CO₂. The estimates include detailed models of supply systems for corn stover or mixed prairie grasses (MPG) and of feedstock conversion facilities. Biomass feedstock costs in Illinois (delivered at a rate of one million tonnes per year, dry basis) are $3.8 GJ_HHV for corn stover and $7.2/GJ_HHV for MPG. Using a strong carbon mitigation policy, the economics of co-producing low-carbon fuels and electricity from a co-feed of biomass and coal in Illinois are promising. An exploration to the United States of the results for Illinois suggests that nationally significant amounts of low-carbon fuels and electricity could be produced this way.

8. Martelli, E., Thomas Kreutz, and S. Consonni, 2009: Comparison of coal IGCC with and without CO₂ capture and storage: Shell gasification with standard vs. partial water. Energy Procedia, Washington, DC, 1(1), doi:10.1016/j.egypro.2009.01.080 607-614
   [ Abstract ]

   This work provides a techno-economic assessment of Shell coal gasification -based IGCC, with and without CO₂ capture and storage (CCS), focusing on the comparison between the standard Shell configuration with dry gas quench and syngas coolers versus partial water quench cooling.

9. Williams, Robert H., Eric Larson, Guangjian Liu, and Thomas Kreutz, 2009: Fischer-Tropsch Fuels from Coal and Biomass: Strategic Advantages of Once-Through (‘Polygeneration’) Configurations. Energy Procedia, 1(1), doi:10.1016/j.egypro.2009.02.252 4379-4386
   [ Abstract ]

   Systems that produce synthetic liquid fuels and electricity from coal and biomass with carbon capture and storage offer an attractive cost-competitive approach for decarbonising liquid fuels and electricity simultaneously.

10. De Lorenzo, L., Thomas Kreutz, P. Chiesa, and Robert H. Williams, 2008: Carbon-free Hydrogen and Electricity from Coal: Options for Syngas Cooling in Systems Using a Hydrogen Separation Membrane Reactor. Proceedings of ASME Turbo Expo 2005, Reno, NV, June 6-9, 2005, 130(3), doi:10.1115/1.2795763
    [ Abstract ]

    Conversion of coal to carbon-free energy carriers, H₂ and electricity, with CO₂ capture and storage may have the potential to satisfy at a comparatively low cost much of the energy requirements in a carbon-constrained world. In a set of recent studies, we have assessed the thermodynamic and economic performance of numerous coal-to-H₂ plants that employ O₂-blown, entrained-flow gasification and sour water-gas shift (WGS) reactors, examining the effects of system pressure, syngas cooling via quench versus heat exchangers, “conventional” H₂ separation via pressure swing adsorption versus novel membrane-based approaches, and various gas turbine technologies for generating coproduct electricity. This study focuses on the synergy between H₂ separation membrane reactors (HSMRs) and syngas cooling with radiant and convective heat exchangers; such “syngas coolers” invariably boost system efficiency over that obtained with quenchcooled gasification. Conventional H₂ separation requires a relatively high steam-tocarbon ratio (S/C) to achieve a high level of H₂ production, and thus is well matched to relatively inefficient quench cooling. In contrast, HSMRs shift the WGS equilibrium by continuously extracting reaction product H₂, thereby allowing a much lower S/C ratio and consequently a higher degree of heat recovery and (potentially) system efficiency. We first present a parametric analysis illuminating the interaction between the syngas coolers, high temperature WGS reactor, and HSMR. We then compare the performance and cost of six different plant configurations, highlighting (1) the relative merits of the two syngas cooling methods in membrane-based systems, and (2) the comparative performance of conventional versus HSMR-based H₂ separation in plants with syngas coolers.

11. Kreutz, Thomas, Eric Larson, Guangjian Liu, and Robert H. Williams, 2008: Fischer-Tropsch Fuels from Coal and Biomass. Proceedings of the 25th Annual International Pittsburgh Coal Conference,
    [ Abstract ]

    The prospect of sustained high oil prices, the heavy dependence of the US on imports for meeting its oil needs, and Middle East turmoil have together catalyzed intense interest in secure domestic alternatives to oil for satisfying US transportation energy needs. Also, it is now highly likely that the US will soon put into place a serious carbon mitigation policy—in which the transportation sector, accounting for 1/3 of US GHG emissions from fossil fuel burning, is likely to get focused attention. The two most significant domestic supplies that might be mobilized to address these challenges are biomass and coal.
    Spurred by farm policy, biomass has long been a focus of development efforts that have focused on using food crops for making biofuels (primarily corn-based ethanol but also biodiesel derived from soybeans and canola). However, concerns about food price impacts [1] and indirect land use impacts of growing biomass for energy on croplands [2,3] have led to growing recognition that emphasis should be shifted instead to exploiting for energy mainly lignocellulosic feedstocks that don’t require use of food biomass for providing energy—such as various crop and forest residues and energy crops that can be grown on degraded lands. These options include cellulosic ethanol produced biochemically and synthetic fuels derived thermochemically via biomass gasification—so-called biomass to liquids (BTL) technologies. Renewable lignocellulosic biomass provided using modest fossil fuel inputs can be considered a nearly “carbon neutral” feedstock, since CO₂ released to the atmosphere is recycled via photosynthesis.
    Among BTL options the production of Fischer-Tropsch liquids (FTL) from biomass has been given considerable attention [4,5,6,7,8]. FTL offers as advantages over cellulosic ethanol the prospects that: (i) no significant transportation fuel infrastructure changes would be required for widespread use, (ii) the technology could plausibly come into widespread use more quickly than cellulosic ethanol, which needs considerably more development before it can be widely deployed, (iii) it can probably accommodate more easily the wide range of biomass feedstocks that are likely to characterize the lignocellulosic biomass supply - because gasification-based processes tend to more tolerant of feedstock heterogeneity than biochemical processes.
    Recent oil price increases have led to considerable interest in making synthetic fuels from coal—so called coal-to-liquid (CTL) fuels—in light of coal’s relatively low prices and the abundance of coal both in the US and in other world regions that are not politically volatile. Much of this attention has been focused on FTL [9,10,11,12]. Coal can do much to improve energy security if it is used to make FTL. Moreover, the synfuels provided would be cleaner than the crude oil products displaced (having essentially zero sulfur and other contaminants and ultralow aromatic content). Also, for FTL production via modern entrained flow gasifiers, the air pollutant emissions from the plant are extremely low. But synthetic fuels made from coal without capture and storage of by-product CO₂ result in net GHG emissions about double those from petroleum fuels. And even with CO₂ capture and storage (CCS), the net GHG emission rate would be no less than for the crude oil products displaced. This would not be an auspicious feature of CTL with CCS technology if society decides to pursue an energy future that avoids dangerous anthropogenic interference with climate—as is required by the UN Framework Convention on Climate Change; there is now near scientific consensus that this will require by mid-century deep reductions in GHG emissions worldwide relative to the current global GHG emission rate [13].
    One approach to this challenge is to identify negative GHG emissions opportunities that might offset the CTL emissions and emissions from other difficult-to-decarbonize energy sources. Among these are opportunities to provide FTL from biomass at strong negative GHG emission rates. A striking feature of FTL technology is that a natural part of the process is the production of a stream of pure CO₂, accounting for about ½ of the carbon in the feedstock. If this CO₂ were captured and stored via CCS for FTL derived from biomass, the biofuels produced would be characterized by strong negative GHG emissions, because of the geological storage of photosynthetic CO₂ [14]. However, sustainably-recovered biomass is expensive, and the size of the BTL facilities will be limited by the quantities of biomass that can be gathered in a single location—which implies high specific capital costs ($ per barrel/day).
    These challenges posed by the BTL-with-CCS option could be mitigated by co-processing biomass with coal in the same facility. The economies of scale inherent in coal conversion could thereby be exploited, the average feedstock cost would be lower than for a pure BTL plant, and if CCS were carried out at the facility, the negative CO₂ emissions associated with the biomass could offset the unavoidable positive emissions with coal, leading to FTLs with low, zero, or negative net emissions [15]. Since this CBTL-with-CCS idea was first introduced, there has been much government and industrial interest in the concept: (i) in 2007 an Air Force/National Energy Technology Laboratory study was released exploring the prospects that its 2016 goal for 16 alternative jet fuel supplies1 might be met via CBTL with CCS to the extent of reducing the GHG emission rate for the FTL so produced to 0.8 times the rate for the crude oil products displaced [17]; (ii) the CBTL with CCS concept got focused attention in a recent Western Governors’ Association Report on future transportation fuels [18]; (iii) the National Energy Technology Laboratory is carrying out a major study comparing a wide range of CTL, BTL, and CBTL options with and without CCS [19], and (iv) some synfuel project developers are pursing plans to incorporate biomass as a feedstock along with coal in future FTL projects—including an FTL plant with CCS being planned by Baard Energy on the Ohio River at Wellsville, Ohio, that would eventually produce 50,000 barrels per day of FTL with up to up to 30% biomass by weight [20].
    Despite the growing interest in using CCS and biomass along with coal in addressing simultaneously the energy insecurity and climate change challenges posed by fuels for transportation, there is not yet available a comprehensive analytical framework for deciding the most promising ways forward—including a systematic way of assessing: (i) BTL vs CBTL vs CTL options, (ii) the amounts of biomass that might be accommodated in CBTL systems, (iii) the appropriate scales for BTL and CBTL systems, (iv) the extent to which CO₂ capture might plausibly be pursued for all FTL systems derived from coal and/or biomass, and (v) prospective carbon policy impacts on FTL projects.
    This paper can be considered a first step toward addressing these issues. We present here a comprehensive analytical framework suitable for addressing these challenges and early results of applying this framework by making comparisons in a self-consistent manner of designs for 16 alternative CTL, BTL, and CBTL plants, with and without CCS, with regard to mass/energy/carbon balances and economics.

12. Chiesa, P., Thomas Kreutz, and G. G. Lozza, 2007: CO₂ Sequestration from IGCC Power Plants by Means of Metallic Membranes. Journal of Engineering for Gas Turbines and Power, 129, doi:10.1115/1.2181184 123-134
    [ Abstract ]

    This paper investigates novel IGCC plants that employ hydrogen separation membranes in order to capture carbon dioxide for long-term storage. The thermodynamic performance of these membrane-based plants are compared with similar IGCCs that capture CO₂ using conventional (i.e., solvent absorption) technology. The basic plant configuration employs an entrained-flow, oxygen-blown coal gasifier with quench cooling, followed by an adiabatic water gas shift (WGS) reactor that converts most of CO contained in the syngas into CO₂ and H₂. The syngas then enters a WGS membrane reactor where the syngas undergoes further shifting; simultaneously, H₂ in the syngas permeates through the hydrogen-selective, dense metal membrane into a counter-current nitrogen “sweep” flow. The permeated H₂, diluted by N₂, constitutes a decarbonized fuel for the combined cycle power plant whose exhaust is CO₂ free. Exiting the membrane reactor is a hot, high pressure “raffinate” stream composed primarily of CO₂ and steam, but also containing “fuel species” such as H₂S, unconverted CO, and unpermeated H₂. Two different schemes (oxygen catalytic combustion and cryogenic separation) have been investigated to both exploit the heating value of the fuel species and produce a CO₂-rich stream for long term storage. Our calculations indicate that, when 85 vol % of the H₂+CO in the original syngas is extracted as H2 by the membrane reactor, the membrane-based IGCC systems are more efficient by ~1.7 percentage points than the reference IGCC with CO₂ capture based on commercially ready technology.

13. Chiesa, P., S. Consonni, Thomas Kreutz, and Robert H. Williams, 2005: Co-production of Hydrogen, Electricity, and CO₂ from Coal with Commercially Ready Technology. Part A: Performance and Emissions. International Journal of Hydrogen Energy, 30(7), doi:10.1016/j.ijhydene.2004.08.002 747-767
    [ Abstract ]

    This two-part paper investigates performances, costs and prospects of using commercially ready technology to convert coal to H₂ and electricity, with CO₂ capture and storage. Part A focuses on plant configuration and the evaluation of performances and CO₂ emissions. Part B focuses on economics, establishing benchmarks for the assessment of novel technologies and guidelines for technological development. In the co-production plants considered in the paper, coal is gasified to synthesis gas in an entrained flow gasifier. The syngas is cooled, cleaned of particulate matter, and shifted (to primarily H₂ and CO₂ in sour water–gas shift reactors. After further cooling, H₂S is removed from the syngas using a physical solvent (Selexol); CO₂ is then removed from the syngas, again using Selexol; after being stripped from the solvent, the CO₂ is dried and compressed to 150 bar for pipeline transport and underground storage. High purity H₂ (99.999%) is extracted from the H₂-rich syngas via a pressure swing adsorption (PSA) unit and delivered at 60 bar. The PSA purge gas is compressed and burned in a conventional gas turbine combined cycle, generating co-product electricity. The H₂/electricity ratio can be varied by lowering the steam-to-carbon ratio in the syngas or by letting part of the de-carbonized syngas by-pass the PSA unit. Performances and emissions of H₂/electricity co-production with CO₂ capture are compared with those of a system that vents the CO₂. We examine different methods of syngas heat recovery (quench versus radiant cooling) and explore the effects of changing the electricity/H₂ ratio, gasifier pressure and hydrogen purity. Results show that state-of-the-art commercial technology allows transferring to de-carbonized hydrogen 57–58% of coal LHV, while exporting to the grid decarbonized electricity amounting to 2–6% of coal LHV. In contrast to decarbonizing coal IGCC electricity, which entails a loss of 6–8 percentage points of electricity conversion when capturing CO₂ as an alternative to venting it, CO₂ capture for H₂ production gives a minor energy penalty (∼ 2 percentage points of export electricity). For H2 production, the efficiency gain achievable by hot syngas cooling vs. quench is a modest 2 percentage point increase in electricity for export, compared to 2–4 percentage points in the electricity case. Reducing H2 purity or increasing gasification pressure has minor effects on performance.

14. Kreutz, Thomas, May 2005: A Potential Role for “Slipstream” H₂ from Coal IGCC with CO₂ Capture and Storage in an Emerging H₂ Economy for Transportation. Proceedings of the Fourth Annual Conference on Carbon Sequestration, Alexandria, VA,
    [ Abstract ]

    Large capital-intensive energy conversion facilities generally require high load factors to achieve favorable economic performance; this typically implies high and relatively constant demand profiles. For this reason, large centralized H₂ production plants are not well matched to the decentralized and variable H₂ demand characteristic of a nascent “H₂ economy” in the transportation sector. It is widely believed that small scale distributed H₂ production technologies such as natural gas steam reforming (SMR), located at H₂ refueling terminals, will be the most economical method of providing H₂ to vehicles. Unfortunately, this model fails to satisfy two key drivers for the H₂2 economy: low CO₂ emissions and increased energy supply security. We describe an alternative model of H₂ production and distribution based on relatively large, centralized sources of decarbonized H₂ from slipstreams of synthesis gas generated in coal integrated gasification combined cycle (IGCC) power plants with CO₂ capture and storage (CCS). We have investigated the design and economics of integrated systems that include syngas production, H₂ purification, compression, buffer storage, compressed gas distribution (via pipeline or truck), and delivery at refueling stations. The delivered cost of “slipstream” H₂ is found to be quite competitive with that of H₂ from distributed SMR. Furthermore, the cost is fairly insensitive to the amount produced (when the fraction of extracted syngas is relatively small, <5-10%), making it a good match for an evolving H₂ demand. At ~10% syngas extraction, IGCC+CCS can provide enough H₂ to fuel most of the light duty vehicles in U.S. cities. The results suggest that, in a climate-constrained future that involves widespread deployment of IGCC+CCS near urban areas, the H₂ economy may be fueled by coal-based decarbonized “slipstream” H₂ rather than large dedicated H₂ plants or small scale distributed H₂ production technologies.

15. Kreutz, Thomas, Robert H. Williams, S. Consonni, and P. Chiesa, 2005: Co-production of Hydrogen, Electricity, and CO₂ from Coal with Commercially Ready Technology. Part B: Economic Analysis. International Journal of Hydrogen Energy, 30(7), doi:10.1016/j.ijhydene.2004.08.001 769-784
    [ Abstract ]

    This two-part paper investigates performances, costs and prospects of using commercially ready technology to convert coal to H₂ and electricity, with CO₂ capture and storage. Part A focuses on plant configuration, performance, and CO₂ emissions. Part B focuses on the cost of producing H₂ and electricity, with and without reduced CO₂ emissions. Our estimates show that the costs for ∼ 91% decarbonized energy (via quench gasification at 70 bar) are about 6.2 ¢/kWh for electricity and about $ 1.0/kg (8.5 $/GJ, LHV) for hydrogen; these are, respectively, 35% and 19% higher than the corresponding energy costs with CO₂ venting. Referenced to these analogous CO₂ venting plants, the costs of CO₂ emissions avoided are ∼ 24 $/tonne for electricity and 11 $/tonne for H₂.

16. Kreutz, Thomas, and Robert H. Williams, September 2004: Competition Between Coal and Natural Gas in Producing H₂ and Electricity under CO₂ Emission Constraints. Proceedings of the 7th International Conference on Greenhouse Gas Control Technologies, (GHGT-7), http://www.princeton.edu/~cmi/research/Vancouver04/Kreutz%20-%20Williams%20,
    [ Abstract ]

    This study explores the competition between coal and natural gas in the large scale production of electricity and H₂ in a world with severe constraints on greenhouse gas emissions. We examine the economic conditions that fa-vor: 1) CO₂ capture vs. CO₂ venting, and 2) coal versus natural gas as the primary energy source, by varying the magnitude of an assumed carbon tax, the price of natural gas, and capacity factor of natural gas combined cycle (NGCC) plants. Coal-based conversion focuses on gasification: electricity from integrated gasifier combined cycle (IGCC) plants, and H₂ + electricity from gasification-based plants; both pure CO₂ capture and storage (CCS) and (the potentially less costly) co-capture and co-storage of H₂S+CO₂ are considered. We also examine the effect of 3 Party Covenant financing, a public subsidy for encouraging the commercial adoption of IGCC. The natural gas (NG) systems considered are NGCC for electricity and steam methane reforming for H₂ production.

17. Kreutz, Thomas, Robert H. Williams, Robert H. Socolow, P. Chiesa, and G. G. Lozza, September 2002: Production of Hydrogen and Electricity from Coal with CO₂ Capture. Proceedings of the 6th International Conference on Greenhouse Gas Control Technologies (GHGT-6), http://www.princeton.edu/pei/energy/publications/texts/Kreutz_Kyoto_02.pdf,
    [ Abstract ]

    This paper summarizes a series of studies examining the prospective performance and cost of facilities that convert coal to H₂, co-product electricity and a stream of concentrated CO₂ (for sequestration). Synthe-sis gas is produced via oxygen-blown, entrained flow coal gasification, quench cooled and shifted to (pri-marily) H₂ and CO₂ via sulfur-tolerant water-gas shift (WGS) reactors. Our focus is on separating H₂ from the syngas and processing the carbon-bearing raffinate/purge gas to produce electricity and CO₂. We explore the use of novel inorganic membrane reactors for H₂ separation and compare their performance and cost with conventional gas separation technologies: CO₂ capture via solvent absorption followed by H₂ purification using pressure swing adsorption (PSA). This work highlights potential economic benefits of high system pressure, low H₂ purity, and co-sequestering CO₂ with sulfur-bearing waste gases, H₂S and SO₂.

18. Zheng, X. L., J. D. Blouch, D. L. Zhu, Thomas Kreutz, and Chung K Law, 2002: Ignition of Premixed Hydrogen/Air in Heated Counterflow. Proceedings of the Combustion Institute, 29(2), doi:10.1016/S1540-7489(02)80201-2 1637-1644
    [ Abstract ]

    The inert temperature required to ignite a lean premixed hydrogen/air mixture in a counterflow was determined experimentally and numerically using detailed chemistry and transport. It was found that above Φ = 0.2, the ignition temperatures increased with increasing equivalence ratio. This effect is due to the fact that the ignition kernel is located on the hot, inert side of the flow and preferential diffusion of hydrogen makes the flow self-stratifying, resulting in a rich mixture in the ignition kernel even for a very lean freestream mixture. The dearth of O₂ in the kernel reduces the reaction rates to the point where diffusive loss becomes significant relative to the rates of kinetic production and consumption. In the presence of this significant transport loss mechanism, premixed ignition temperatures are much higher than non-premixed ignition temperatures and the influence of the strain rate is likewise increased. Adding a few percent of O₂ to the hot inert side of the flow lowers the kernel equivalence ratio and increases the reaction rates to the point where diffusive effects are no longer of the same order as kinetic effects. In these cases, the ignition temperatures drop significantly to values close to those of non-premixed ignition even though the free-stream flow is still predominantly premixed.

19. Ogden, J. M., Thomas Kreutz, and M. M. Steinbugler, 2000: Fuels For Fuel Cell Vehicles. Fuel Cells Bulletin, 3(16), doi:10.1016/S1464-2859(00)86613-4 5-13
    [ Abstract ]

    The issue of fuel choice impacts both fuel cell vehicle design and infrastructure development. In general, there is a trade-off between simpler vehicle design (hydrogen vehicles are inherently simpler than those with onboard fuel processors) and simpler infrastructure issues (liquid fuels such as gasoline or methanol are easier to store and handle, and are more compatible with the existing refueling infrastructure). In this article we compare fuel cell vehicle characteristics and infrastructure requirements for four possible fuel options: compressed hydrogen gas, methanol, gasoline and synthetic liquids derived from natural gas. The advantages and disadvantages of various fuels are discussed, and possible fuel strategies leading towards the commercialisation of fuel cell vehicles are explored.

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