FutureGen Switches Tracks

The standard knock on carbon capture and sequestration (CCS) is that it hasn't been tested and proven on an industrial scale. That's really only true in the narrow sense in which you start with coal, produce electricity, and then collect and bury the CO2 that comes out the stack--which I imagine is what CCS evokes for most people who have even heard of the technology. Some years back, the US government set out to close that gap by building a large-scale test facility to demonstrate the coal-to-CCS cycle, with help from a consortium of industry partners. The program was called FutureGen. It died in 2008 after reported cost overruns but was revived in a different format last year. Now the reoriented effort has spawned a new project at a different location--though still in Illinois--to replace the ill-fated Mattoon project. Its basic concept differs significantly from the original FutureGen, and in ways that might improve the odds that coal could continue to contribute a substantial share of the US energy mix for many decades.

The CO2 produced by power plants is much harder to capture and dispose of than the traditional pollutants we associate with them, not least because it is the primary chemical result of the combustion of hydrocarbons, along with water vapor, rather than a byproduct resulting from a fuel impurity or imperfect combustion. That requires dealing with emissions that exceed the mass of fuel being consumed, rather than an order of magnitude or two smaller. And when fossil fuels are burned in air, the CO2 produced must be separated from all that nitrogen, which is the largest constituent of flue gas, before it can be sequestered. All this is expensive, in both energy and financial terms. The original FutureGen was designed to finesse this problem by converting coal into a hydrogen-rich gas that could be burned efficiently in a combined-cycle gas turbine (IGCC), producing emissions consisting mainly of water vapor, plus a sequestration-ready CO2 stream from the hydrogen-production process. Unfortunately, the hardware necessary to do that isn't cheap, either.

FutureGen 2.0, as announced, would take a different tack. It aims to convert an existing power plant owned by Ameren Corporation into an "oxy-coal" plant, in which pure oxygen replaces air in the boiler for combustion, resulting in flue gas consisting mainly of CO2. This approach has pluses and minuses, compared to IGCC. It requires a bigger air separation plant to support full combustion, but it eliminates all the hardware associated with hydrogen. That should entail somewhat lower capital costs, but not necessarily lower operating costs, particularly when you consider that the efficiency of IGCC exceeds that of most existing US coal power plants, though not necessarily supercritical or ultra-supercritical pulverized coal plants. (I couldn't tell how much the basic power block of Unit 4 of Ameren's Meredosia, IL plant, which formerly burned fuel oil, will be modified.) As in FutureGen 1.0, the resulting compressed CO2 would then be pipelined to a disposal site elsewhere in the state.

Although it would take some doing to convince me that oxy-coal with CCS is a better technology than IGCC with CCS, the revised approach to FutureGen looks like a good call on the part of the government. That's because the context in which FutureGen is being pursued has altered significantly since it was first devised. Instead of a scenario of continuing to build many new coal-fired power plants every year to meet steadily-growing electricity demand, the future--at least in the US--looks quite different. An article in yesterday's Washington Post pointed out that a number of new coal plants are still under development, but the rate of new construction has slowed dramatically, due to regulatory pressures, weaker electricity demand, competition from cheaper natural gas, and the growth of renewables. If we want to have an impact on the emissions from the US coal-fired power plant fleet--which accounts for 31% of total US emissions and 91% of the emissions from the electricity sector--then our best strategy probably doesn't involve building hundreds of gleaming new IGCC plants, but rather retrofitting hundreds of existing units built with older technology, for which conversion to IGCC would likely be cost-prohibitive. If FutureGen 2.0 succeeds--technically, if not economically--it would validate that retro-fitting potential.

The world hasn't stood still while the Department of Energy wrestled with all the political and technical challenges that FutureGen faced. The original siting competition between Texas and Illinois looked like a textbook case of logrolling, and FutureGen 1.0 exhibited the hallmarks of a classic government boondoggle. Meanwhile, commercial projects such as Duke Energy's Edwardsport IGCC (without CCS, but in effect CCS-ready) and the Good Spring IGCC project of Future Fuels LLC have emerged and appear to be making progress. The latter is based on technology from the Thermal Power Research Institute of China, which is a good bet to beat all of these projects to the punch with its GreenGen power plant in Tianjin. If FutureGen 2.0 is going to matter, it must be built smartly, quickly and cost-effectively. Yet technical success still won't guarantee that this technology will be taken up and deployed widely. In a market economy, rather than a centrally-planned one, it's hard to see any of this going beyond a demonstration plant or two without a substantial price on CO2 emissions to offset the inherently higher costs of generating power this way.

Read More

Zombie Project?

A year ago, the FutureGen partnership to build a prototype low-emissions coal power plant incorporating gasification and carbon capture and sequestration (CCS) technology looked dead in the water. Now, according to Technology Review, it may be on the verge of revival. A cynic would point out that a project sited in the home state of the new President might be a little harder to kill than most. It also can't hurt that Illinois's senior Senator stands high in the leadership of the majority party. However, there may be objective reasons to carry on with the project, particularly if the cost assessments that led to its "restructuring" were flawed, as suggested in a report issued recently by the General Accounting Office. Moreover, although major R&D projects ought to be carried out as efficiently as possible, I'm not sure that project costs should be the primary criterion for evaluating a one-off proof of concept, especially for such a crucial technology.

At its estimated cost of $1.8 billion for a 275 MW power plant, FutureGen must be the most expensive coal-fired power plant project in the world, for its size. That equates to $6500/kW of capacity, roughly triple the cost of a conventional coal plant and six times the cost of the combined-cycle gas-turbine unit that its core power block resembles. In normal utility service it could never compete with the cost of power from other technologies. If the project is successful, it should produce reliable power for many years, but as a byproduct of its principal purpose, which is to demonstrate a fully-integrated process for reducing the greenhouse gases and criteria pollutants from fossil-fuel power plants to the maximum extent possible. While all of the elements of this system, involving the gasification of coal to produce hydrogen, combustion of hydrogen in a gas turbine, and the capture and sequestration of CO2 from flue gas have all been demonstrated separately, with some of these elements in routine industrial and oil-industry service, integrating them at scale and running them together to determine the suitability of such a system for wider deployment has not.

As I described recently, CCS is a key technology for addressing climate change and for holding down the cost of large-scale reductions of emissions, once we've harvested the low-hanging fruit of energy efficiency and methane destruction. That doesn't mean FutureGen should be given a blank check, unless the new management at the Department of Energy can convince themselves that, particularly in light of all the work already done on this project, it represents the quickest and most effective next step in proving the technology. In particular, they should assess whether FutureGen includes outcomes beyond a proven prototype CCS power plant, such as opportunities to transfer technology elements to improve the efficiency or cost of other new and existing facilities. For example, could it improve existing integrated gasification combined cycle (IGCC) designs to increase their efficiency advantage over supercritical pulverized coal and other conventional coal technology, and thus reduce emissions even without full CCS? Could it advance our knowledge concerning the retro-fitting of CCS to existing power plants? If the answers to these questions look promising, then FutureGen deserves reviving, even if that creates the appearance of home-state favoritism.

Note: Energy Outlook will be on vacation for a few days. New postings should resume next Wednesday or Thursday.

Read More

Conference Highlights

I spent the last three days at the annual energy investment conference held by the sponsor of this blog, John S. Herold, Inc. Many of the panels I attended were overshadowed by the enormous uncertainty about the US financial system and pending bailout proposals, along with the Presidential election, the dynamics of which appear to have shifted again. However, the sessions provided some very interesting insights into an important unfolding natural resource play, along with showcasing some nifty applications of existing technology that could help to narrow the gap between growing global energy demand and the stagnating supply of conventional oil.

The two words that I heard most frequently this week were “shale gas”, the development of which just might facilitate achieving some of Mr. Pickens’s ideas about energy security. This is not the kind of shale that has been touted as a nearly unlimited source of unconventional oil, but rather a layer of natural gas-bearing rock that until recently was very difficult to tap. But as several panelists explained, companies have “cracked the code” for drilling into these deposits and producing flows that compete favorably with conventional gas fields in both output and cost. The result could be a modest gas bubble—a period of relatively abundant US natural gas supplies—though it comes with an inherent price floor not far below current levels. So while it is unlikely to rejuvenate struggling gas-based industries such as fertilizer production, for which $7/MMBTU is still quite dear, it could support expanded natural gas use in both transportation and power generation, where it could yield significant environmental and cost benefits.

One of the two technologies that impressed me was featured on the Alternative Energy panel I moderated. One of the founders of DKRW Advanced Fuels described a clever application of off-the-shelf technology that turns Wyoming coal into unleaded gasoline without releasing the vast quantities of CO2 that have made coal liquefaction look unpalatable. This trick is accomplished by marrying GE’s gasification technology (the old Texaco Coal Gasification Process on which I worked briefly as a young engineer) with ExxonMobil’s methanol-to-gasoline process that operated for 10 years in New Zealand, until the natural gas field feeding it was depleted. The output is 87 Octane unleaded gasoline and a pure CO2 stream that will supply the region’s extensive enhanced oil recovery projects, which will effectively sequester it. This scheme creates a double energy benefit: mainstream liquid fuel from America’s most abundant energy resource, and increased output at some of our aging oil fields. Even better, it looks like this can be accomplished with lifecycle greenhouse gas emissions no worse than from conventional oil.

The other technology that caught my attention was presented by an old friend and former Texaco colleague, who is now the CEO of Compact GTL. Instead of using proven gas-to-liquids technology to unlock “stranded” natural gas reserves—non-associated gas deposits far from infrastructure or markets—he aims to apply it to the problem of “distressed gas.” He defines that as natural gas produced in conjunction with oil in projects for which the cost and logistics of traditional methods for handling the gas have become an obstacle to developing the oil field. Previously, such gas would be flared, but that practice is being phased out on environmental grounds. Turning it into synthetic oil could prove cheaper than re-injecting it into the ground, while also shortening the development cycle of some large oil fields. Another double win, if it proves practical.

With the country still debating the merits of expanded oil drilling and looking to renewable energy sources that have not yet achieved the scale necessary to wean us off imported oil and slash our greenhouse gas emissions, the approaches described above can provide a valuable bridge. They could also be real money-spinners, at a time when other parts of the economy are looking pretty sick.

Read More

Alternative Energy for Shipping

Last Sunday's New York Times carried an interesting article on the implications of high energy prices for the sustained globalization of supply chains. The reporter described how rising shipping costs were forcing manufacturers and retailers to rethink fundamental aspects of their business models, ultimately threatening the continuing expansion of world trade. Higher oil prices are responsible for much of the rise in freight rates, particularly for products carried by sea and air. Marine and aviation fuels are taxed very lightly, so they are more sensitive to changes in oil prices than motor fuels. But while airlines are hoping--perhaps in vain--for long-term fuel price relief from biofuels, cargo ship operators are likely to experience more competition from other uses for bunker fuel, and may need to seek solutions involving more exotic energy sources.

Earlier this year, I mentioned an idea for deploying small, high-tech sails to reduce the fuel consumption of cargo ships. But if world oil supplies fall seriously short of meeting potential demand in the years ahead--an easy prospect to imagine, given the rate at which Chinese and Indian consumers are buying automobiles--ocean freight lines may need to look elsewhere for their primary energy source, not just for ways to supplement it. In 2004, the residual fuel burned by ships and power plants accounted for 1 out of every 8 barrels of global oil demand. If competition for crude oil increases, refiners may be more interested in turning the long, complex molecules in fuel oil into higher-value products such as diesel and jet fuel, rather than selling them as-is. Thanks to heavy investment in upgrading hardware, US refineries produce less than a quarter of the "resid" volumes they did in the late 1970s, and their scope for further "resid destruction" is limited. Globally, however, upgrading 10 million barrels per day of resid output could ultimately prove more attractive than producing the same quantity of hydrocarbons from oil sands, shale, or coal-to-liquids. Where would that leave the shipping industry?

Two large-scale alternatives come to mind, assuming that biofuels will remain focused on the highest-value fuels segments, substituting for gasoline, diesel and jet fuel. Between the late 1970s and early 1990s, nuclear power and coal displaced most petroleum liquids from the US power generation sector. Either could provide a long-term substitute for residual fuel in ocean-going vessels. Nuclear power has obvious advantages in terms of its low emissions and extensive experience in naval fleets, plus a few civilian icebreakers. Unfortunately, the disadvantages will appear equally obvious to nuclear critics, in terms of the risks of proliferation and terrorism, which at sea may be less manageable than onshore. However, if it proved cost-effective, this is one way that nuclear power could directly displace more oil, and it might be achieved faster than we could build a new generation of land-based nuclear power plants.

A return to coal for ships' fuel might seem an odd and untimely suggestion, in light of concerns about greenhouse gases and the other emissions from burning coal. However, if this were done using small onboard gasification units fueling efficient gas turbines, rather than coal-fired boilers, the CO2 output from such a system might be no worse than from today's ships. And with the right equipment, sulfate and nitrate emissions that contribute significantly to urban air pollution in busy ports could also be scrubbed, at least for limited durations. The practicality of such an approach would have to be demonstrated, but the underlying driving force is clear. Despite the recent spike in coal prices, the BTUs in thermal coal still cost less than half as much as those in bunker fuel, at current prices.

A global retrenchment in trade due to the impact of high energy costs on freight rates would affect shipowners as much as their customers. A generation ago, the world's cargo fleets converted from steam turbines burning the lowest-quality bunker fuel available to the powerful, reliable marine diesel engines that dominate today's commercial shipping. The cost of operating these engines--and thus global shipping rates--depends on the price of the heavy fuel oils they consume. Although shipping firms lack a practical alternative fuel today, there's no reason the next generation of ships couldn't be built around entirely different energy sources. That would be on a par with the shift from coal to oil early last century, and far less dramatic than the switch from sail to steam.

Read More