Understanding fossil-fuel based polygeneration strategies was one of the primary foci at the beginning of the Initiative, and continues to be a core strength of the program.


Hydrogen and electricity production from fossil fuels

Research early in the grant focused on electricity and hydrogen (H2) production at large centralized plants, using performance and cost models to investigate the potential of various plant designs and operations. Early studies of H2 and electricity generation from coal with carbon capture and storage (CCS) using novel H2 separation membrane reactors gave way to research on similar plants that employ “commercially ready” gas separation technologies, as it was found that membrane reactors did not yield substantial economic benefits relative to conventional technologies.

Another early focus was the competition between coal and natural gas in producing low-carbon H2 and electricity, both with and without CCS. The researchers found that electricity from coal-based power plants with CCS is generally more expensive than power from natural gas combined cycle (NGCC) plants that vent CO2, requiring a carbon price of the order of $100 per tonne of carbon (tC) for coal to be competitive with natural gas. (The exact value depends upon the price of natural gas and the load factor of the NGCC unit.) For H2 production, though, coal was competitive with natural gas at a significantly lower carbon price, because much of the hardware needed for carbon capture already exists in hydrogen plants.  The group also found that 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 the cost of H2 and/or electricity by 3-4%, further improving the relative economics of coal-based plants with CCS. The cost of avoided CO2 emissions from these plants is significantly smaller than that estimated for NGCC with CCS.

The capture group also studied how H2 produced at large,centralized facilities could be distributed to users. Tom Kreutz and Joan Ogden (formerly of CMI, now at U.C. Davis) determined that delivery of H2 will likely be economical for urban centers, where the majority of the population lives, but not for rural areas with low population densities. Their study found that the high costs of transporting H2 gas through pipelines or liquid H2 by truck, coupled with low demand, will likely hinder market penetration into rural areas and present significant obstacles to making H2 fuel as convenient as gasoline without breakthroughs in H2 storage technology.

Because large facilities dedicated to H2 production would not be practical in the early stages of the evolution to a “hydrogen economy,” capture group researchers have recently shifted focus to study the cost-effectiveness of alternative routes. Conventional wisdom holds that early H2 production would occur through small-scale steam reforming of natural gas at many decentralized stations, avoiding the large costs associated with transporting H2. A drawback of this scheme is that CCS is not economically viable in small scale, distributed systems, so this transitional technology would provide only modest reductions in carbon emissions.

Alternatively, small amounts of H2 fuel could be produced at large H2-powered central electric power plants where CCS is economical, then provided to nearby fleets of H2 vehicles.  This year, Tom Kreutz has shown it would be practical and cost-effective to provide virtually carbon-free H2 in small amounts from domestic coal resources—by producing small “slipstreams” of H2 at large coal integrated gasification combined cycle (IGCC) plants equipped with CO2 capture and storage. He showed that pressurized H2 bled off in variable amounts at these plants, purified in pressure swing adsorption units, and transported by truck (or pipeline) to refueling stations is economically competitive with locally generated H2 from reformed natural gas. With this strategy, H2 can be produced from coal – an inexpensive, abundant, and indigenous resource – with near zero GHG emissions for transportation even in the early phases of a H2 economy (see Figure 1). However, the option does require incentives to make coal IGCC plants with CCS economically viable.


Figure 1. Comparing H2 costs for alternative production options for the transition to a hydrogen economy

The cost to consumers at refueling stations is presented for a coal H2 case involving the production of 1 tonne per day of slipstream hydrogen (99.999% purity) at a central facility (that also produces 362 MWe of power) and delivery of this H2 to a refueling station 24 miles away as a compressed gas that is transported by truck.

Assuming natural gas and coal prices of $8.0 and $1.34 per GJ (HHV), respectively and a carbon price of $100/tC, the figure shows that the cost of H2 to consumers via this approach is much less than H2 provided via current steam methane reforming (SMR) technology and comparable to the cost of H2 produced via hoped-for future SMR technology.


Minimizing the Emissions of Coal-based Synfuels

There is growing interest in coal synfuels as a result of rising global demand for liquid fuels, high oil prices, oil supply security concerns, the abundance of low cost coal, and the commercial availability of technologies for making synfuels. Coal liquids would be simultaneously economically attractive for investors and disastrous for society from a climate perspective—because the GHG emission rate for coal synfuels produced with CO2 vented is about twice as large as for crude-oil-derived hydrocarbon fuels. Capture researchers in partnership with colleagues at Tsinghua University are carrying out research aimed at understanding better the performance, costs, and emissions characteristics of alternative synfuels technologies and opportunities for climate change mitigation via CCS.

Initially the Tsinghua/Princeton collaboration focused on producing methanol and dimethyl ether (DME) via coal gasification. Methanol is widely used as a chemical and in some parts of China there is interest in its use a transportation fuel. There is considerable interest in China in DME as a cooking fuel and also, for the longer term, as a super-clean fuel for use in compression-ignition (diesel) engines for motor vehicles.

Our initial research showed that “polygeneration” systems that make liquid fuels plus electricity are often more cost-effective than systems that make liquid fuels alone. The research also showed that some of the carbon in the coal feedstock will often be removed as relatively pure CO2 from the syngas as a standard part of the synthetic fuel production process. Costs both with CO2 vented and with CCS were estimated. It was found that, as an “acid gas management strategy,” co-capture and co-storage underground of H2S and CO2 to the extent of about 30% of the carbon in coal might be less costly than the alternative of capturing H2S and CO2 separately, then converting the H2S to elemental sulfur and venting the CO2 to the atmosphere.

During 2004, the research on making DME from coal via polygeneration was extended, in an effort led by Larson and Williams, to an analysis of systems that involve full as well as partial capture of CO2 for underground storage. This research showed that although the GHG emission rate for DME when the CO2 is vented would be about twice that for the crude oil-derived fuel displaced, with CCS the GHG emission rate could be reduced to a level comparable to that for the crude-oil-derived fuels.

During 2005 the group’s coal synfuels production modeling was extended to an analysis of the production of Fischer-Tropsch (F-T) liquids (synthetic gasoline and diesel) from bituminous coals—without and with CO2 capture and storage (CCS). This activity was led by Williams and Larson in collaboration with Haiming Jin of Dartmouth College.

F-T liquids offer the advantage over both H2 and DME that F-T liquids deployment requires little or no change in transportation refueling infrastructure. As in the case of prior research on DME, the group’s focus has been on “polygeneration” systems that make electricity as a major co-product. Their work shows that, as for DME, the GHG emission rate for F-T liquids with CO2 vented is much higher than for hydrocarbon fuels derived from crude oil (Figure 2, top) but with CCS the GHG emission rate can be reduced to about the rate for crude oil-derived fuels (Figure 2, middle).

Our economic analysis shows that, in the absence of a strong climate mitigation policy, CCS could still be attractive economically if the CO2 captured in synfuel projects were used for CO2 enhanced oil recovery. Further discussion is provided in “Toward Early Experience with CCS” on page 17.


Figure 2. Carbon and energy balances for making and using Fischer-Tropsch liquids + electricity with alternative systems, along with fuel-cycle-wide greenhouse gas emission rates

The mine-to-wheels greenhouse gas (GHG) emission rates are in CO2 equivalent units. (The small emissions arising in transporting F-T liquids to final consumers and in refueling are not included.) For comparison, the well-to-wheels GHG emission rates associated with making and using gasoline and diesel from crude oil in the US are estimated to be 25.6 and 26.1 kgCequiv/GJ by the GREET model of Argonne National Laboratory.

For the coal + biomass option the biomass input fraction was chosen such that the mine-to-wheels GHG emission rate allocated to F-T liquids would be the same as for H2 made from coal with CO2 capture and storage.


Toward Early Experience with CCS

Because motivating CCS with aquifer storage for coal-based energy systems currently requires a market valuation of GHG emissions of about ~ $100/tC, a large amount of GHG emissions might get “locked in” before a carbon policy is in place that makes CCS economically attractive to investors. For example, if the 1400 GWe projected to be built worldwide, 2003-2030, were built without CCS, the lifetime CO2 emissions of these new coal plants would be more than a 40% increment over the cumulative CO2 emissions from burning all fossil fuels from the beginning of the industrial era in 1750 through the year 2000. Finding strategies to advance and buy down the price of carbon capture and storage is one new focus of the capture group’s work.

Previously, the Capture Group helped William Rosenberg of Harvard develop his 3-Party Covenant (3 PC) scheme to facilitate construction of the first few IGCC plants, which are a critical step in moving toward coal power with carbon capture and storage. The 3 PC scheme involves a low-cost subsidy in the form of a government loan guarantee that reduces financing costs, so that electricity generation costs are less than for conventionally financed coal steam-electric power plants, even for the very first IGCC units built. This incentive scheme became a key element in the new national energy policy that resulted from the passage of the Energy Policy Act of 2005 (EPACT 2005). It appears that gasification technology will start to be deployed for power coal power generation as a result of this and other incentives in EPACT 2005 and the growing recognition that gasification is key to low cost CCS for coal power.

Much of ongoing industrial activity relating to coal IGCC plants that are expected to be built during the next few years is aimed at designing the plants to be CO2 “capture ready.” Concerned that this represents an inadequate near-term response to the climate change challenge, Williams and David Hawkins of the Natural Resources Defense Council have been developing a policy proposal for an early CCS action strategy that is not dependent on having a climate mitigation policy in place that values CO2 emissions at a price of the order of $100/tC. Specifically they have proposed introducing a national coal low-carbon generation obligation for U.S. coal electricity modeled after the familiar Renewable Portfolio Standard. Under the proposed low-carbon generation obligation, each retail power supplier would be required to provide a growing fraction of coal power generation with CCS in its electricity supply portfolio every year.

Under this scheme, each retail electricity provider would either generate low-carbon coal power, purchase such power from independent electricity suppliers, or purchase credits in a tradeable credit market. The credit value would reflect the cost increment for coal power with CCS, and selling these credits would make it profitable for coal power generators to pursue CCS. The incremental cost for CCS would increase generation costs at low-carbon coal power plants, but the low-carbon generation obligation would spread these costs over all ratepayers.

Williams and Hawkins proposed that the obligation be a growing percentage of total coal power generation. They showed that if the obligation is large enough to cover all new coal generating capacity expected to be built during 2012-2020 (increasing from 0.3% of total coal power generation in 2012 to 9.3% by 2020), the maximum increase in the retail electricity price under the proposed obligation during this period would be quite modest—comparable to the annual fluctuation in the national average retail electricity price.