By John Kemp
LONDON, Nov 12 (Reuters) - New funding for research into lower-cost ways of capturing carbon dioxide is meant to emphasise the Obama administration’s commitment to a future for cleaner coal-fired power generation.
But it underlines the continuing cost problems with carbon capture technology that make it hard to deploy on a commercial basis.
On Nov. 7, the U.S. Department of Energy announced that it was awarding a total of $84 million to 18 research projects intended to find a lower cost way of capturing carbon dioxide (CO2) emissions from power plants.
The projects will test new solvents and sorbents to separate CO2 from other gases in power plant exhaust streams.
The aim is “improve the efficiency and drive down the costs of carbon capture processes for new and existing coal-fired plants,” according to officials.
The announcement is designed to underline the administration’s commitment to developing carbon capture and storage (CCS) technology and refute suggestions it is waging a “war on coal.”
But all the projects are for basic science and very early stage technologies, underscoring the fact CCS is not yet a mature technology.
Nonetheless, draft emissions rules published by the U.S. Environmental Protection Agency in September would require any new coal-fired power plants built in the United States to be equipped with CCS.
The agency is now developing rules for existing coal-fired plants, though officials caution that these will probably be different from those governing new plants.
Coal producers and the owners of coal-fired power stations complain that the administration is mandating the use of a technology which has not yet proven cost effective at commercial scale, effectively prohibiting new coal-fired generation.
For supporters, the new rules will force the power industry to devote all its inventiveness to making CCS a reality, using the regulatory process to spur technological change.
For opponents, the rules are an arbitrary backdoor ban that puts an important source of fossil energy off limits and makes the power sector dangerously dependent on natural gas.
The relative immaturity of the capture stage of the CCS process suggests there is some validity to that criticism.
CCS is a promising technology, which is indispensable to meeting future energy requirements and ensuring a future for the coal industry while limiting emissions of greenhouse gases. But to mandate its use for new power plants, let alone existing ones, seems premature.
Transporting carbon dioxide over long distances by pipeline and storing it underground in depleted oil and gas fields are fairly mature technologies, which have already been implemented many times over the last 40 years.
Capturing CO2 in the first place is more commercially challenging. CO2 has been successfully separated from other gases in industrial processes for nearly a century.
But most of the CO2 separation has occurred at natural gas processing plants and facilities producing ammonia, where the volume of gas is comparatively small and the CO2 is found in fairly high concentrations.
The exhaust stream of a major power plant involves a much larger volume of gases, perhaps 20-50 times higher, and the carbon dioxide is much more dilute. CO2 accounts for as little as 15 percent of the exhaust gases from a power plant. The rest is mostly nitrogen (N2) as well as small quantities of pollutants like nitrogen oxides (NOx) and sulphur dioxide (SO2).
Most existing capture systems pass the mixed waste gases through an absorber, where the CO2 comes into contact with a solvent and becomes bound to it; the other gases pass through unaltered. The CO2-rich solvent is then passed through a stripper, where it is heated to 100-140 degrees Celsius, releasing the concentrated CO2 and regenerating the solvent so it can be re-used in the absorber.
The need to heat the solvent to regenerate it and the enormous quantities of material involved impose a considerable cost and energy penalty on the process.
Scaling the process up to deal with the much larger volume of dilute CO2 in the exhaust gases of a major power station would involve enormous expenditure and impose a severe energy penalty on the efficiency and competitiveness of the power plant.
So the hunt is on for a more efficient way to capture CO2.
Until now, the most promising routes to reducing the energy penalty have focused on raising the concentration of CO2 in power plant exhausts.
One option involves burning coal in nearly pure oxygen (O2) rather than ordinary air, most of which is nitrogen, which would produce a stream that is 80-98 percent pure CO2.
The problem with this “oxy-combustion” process is that oxygen has to be produced from air in the first place in an oxygen plant, which itself involves large amounts of energy. The energy penalty is changed rather than eliminated.
A second option is to convert coal into synthesis gas (a mixture of hydrogen and carbon monoxide) by partially oxidising it in a gasifier rather than burning it. The carbon monoxide (CO) is then reacted with steam (H2O) to produce even more hydrogen and a fairly concentrated stream of CO2.
In an integrated gasification and combined cycle (IGCC) power plant, the produced hydrogen is first burned in a jet turbine, then the hot exhaust gases are used to raise steam which powers a secondary steam turbine.
IGCC plants are extremely efficient and produce concentrated CO2 streams which are easy to capture. But they are formidably expensive to build. For the plant to operate efficiently, all the processes (gasifier, jet turbine and steam turbine) must operate smoothly together, which poses a severe engineering challenge.
In the United States, Southern Company is building an IGCC power plant with some CCS capability in Kemper County, Mississippi, which will use local supplies of lignite in the gasifier. But Kemper has already gone wildly over-budget and it is not yet in service so its operating efficiency remains unproven.
The Dakota Gasification Company has operated 14 enormous gasifiers at the Great Plains Synfuels Plant in North Dakota for nearly two decades, producing pipeline natural gas, as well as ammonia and other specialty products, using lignite as a feedstock. It also produces CO2, which is captured and sold to oil producers in Canada for enhanced oil recovery (EOR) operations.
But the Great Plains Synfuels Plant was only built with an enormous amount of financial assistance from the federal government, and had to be bailed out by the Department of Energy when it became insolvent in the mid-1980s, so it is hardly a model for gasification on a commercial basis.
Policymakers and engineers are now working on a so-called “second generation” of separation technologies which could be fitted to new and existing power plants, which would be cheaper and require much less energy to strip the CO2 from exhaust gases.
Combined membrane-absorbent systems use sophisticated membranes to make the solvent/absorption process faster and more efficient.
Most of the projects for which the Department of Energy announced funding involve membrane technologies.
Fifteen projects with total funding of just under $70 million are trialling membranes and solvents that could be employed for post-combustion CO2 capture, so they could be retrofitted to existing power plants.
The remaining projects focus on pre-combustion CO2 capture and would support a new generation of IGCC plants, if they are ever built.
All the projects are either pilot-scale or bench-scale. They are the sort of advanced science and technology funding that the department has successfully sponsored in the past. Even if they achieve a breakthrough, however, it will be years before they could be deployed commercially.