By Siân Green

Worldwide concern over greenhouse gas emissions is driving research into reducing emissions of carbon dioxide. Alstom is just one company working with the US Department of Energy (DOE) to find ways of capturing and sequestering carbon emissions from power plants.

Emissions of carbon dioxide (CO2) from OECD countries stood at 23.2 Gt in 1999, of which emissions from fossil fuel combustion accounted for 60 per cent. Worldwide, electricity and heat production accounts for one-third of CO2 emissions, and there is a growing awareness in the power sector of the need to control carbon emissions.

Figure 1. 1999 total CO2 emissions from fuel combustion (23.2 Gt in 1999) by source and fuel type
Click here to enlarge image

Emissions of CO2 are thought to make a significant contribution to the global enhanced greenhouse effect. Some 94 countries have now ratified the Kyoto Protocol on greenhouse gas emissions and as countries look at ways of meeting their commitments, the introduction of carbon legislation looks increasingly likely in Kyoto-compliant countries.

The USA is taking its own approach to climate change policy, however, having decided not to sign Kyoto. In February 2002, President Bush announced the Global Climate Change Initiative (GCCI) aimed at reducing the greenhouse gas intensity of the USA over the next ten years, while sustaining economic growth. The GCCI calls for increased research and development to provide an improved basis for future decision-making, increased emphasis on carbon sequestration, and for reductions in non-CO2 greenhouse gas emissions such as methane. It also calls for a progress review relative to the goals of the initiative in 2012, at which time decisions will be made about additional implementation measures for mitigating greenhouse gas emissions.

The US Department of Energy (DOE) Carbon Sequestration Program, administered by the Office of Fossil Energy’s National Energy Technology Laboratory, directly implements the GCCI, as well as several other National Energy Policy goals targeting the reduction of greenhouse gas emissions. It is recognised that the development of carbon capture and sequestration technologies must play a key role if the USA is to set a path to slow the growth of greenhouse gas emissions, and to stop and reverse that growth. The Carbon Sequestration Program is developing a portfolio of technologies that hold great potential to reduce greenhouse gas emissions.

Relative to greenhouse gas emissions from power generation, the Carbon Sequestration Program is developing the technological capability to eliminate 90 per cent of carbon emissions from existing and new energy facilities at less than a ten per cent increase in the cost of energy services. Research is focused on developing technologies that dramatically lower the energy penalty and cost of capturing CO2 from flue gas combustion streams. The Program is exploring research on a range of approaches which include: advanced integrated plant designs; membranes; oxy-fuel systems; solid sorbents; CO2 hydrates; and advanced gas/liquid scrubbing technologies.

Another key part of research is aimed at increasing the efficiency of existing coal fired plants to reduce emissions of CO2. Replacing existing plants with ultrasupercritical coal technology would reduce per-MWh CO2 emissions by 25 per cent.

DOE initiatives

In September 2002, the DOE announced that power equipment manufacturer Alstom is to participate in its sequestration programme by developing and testing new ways to capture, store and use CO2 produced by coal-fired power plants.

This is not the first time that Alstom has worked with the DOE on carbon sequestration. “We have worked with the DOE on a prior initiative together with American Electric Power in Ohio to look at CO2 capture from existing coal fired power plants,” said John Marion, Alstom’s manager of Contract R&D for Power Plant Laboratories. “We looked at technologies that were feasible today and the purpose of the analysis was to determine what would be the implications of imposing [CO2 controls] as policy.”

This work finished in June 2001, and Alstom and the DOE recognised the long term nature of this topic and the need to look at new and future power plants where greater innovation could be deployed. “So we discussed a project in which we would look specifically at combustion-based approaches for carbon capture in new plants,” added Marion.

According to Alstom, studies have shown that integrated gasification combined cycle (IGCC) technology offers the lowest cost incrementally for capturing carbon because the coal fuel is turned into a syngas from which carbon can be removed. However, IGCC is today not an economic option for the power generation industry, even though it is used widely in the petrochemical industry. “All of the IGCC plants that have been built around the world have a relatively high cost of electricity because the capital cost of that technology is high.”

Thus in its work with the DOE, Alstom will take the benchmark work done on carbon capture using IGCC, and compare with it a number of other possible carbon capture approaches. “We are looking at a range of technologies and there are a number of novel technologies. We have a total of ten cases to examine, each of which uses a combination of oxygen firing, a chemical looping process, a carbonate cycle process as well as other technologies,” says Marion. “These cases will be analysed and compared with a commercial-reference IGCC plant as well as a future IGCC concept.”

The cases will also be compared with a commercial-reference circulating fluidized bed (CFB) power plant, with cost, performance and efficiency being evaluated. This first phase of the project will run until the end of March 2003, at which point Alstom and the DOE will evaluate the results and implement the second phase. Phase two of the scheme will involve the construction of a 3 MWth pilot-scale plant based on one of the cases evaluated in phase one. Phase two is cheduled to be completed by November 2004.

Oxygen firing

Many of the case studies being evaluated in phase one involve the use of oxygen firing technology. The idea behind this is that if you fire a fuel in pure oxygen, you avoid the creation of nitrogen oxides and so the products of combustion are just water vapour and CO2. The water vapour can be easily removed from the exhaust stream, leaving a concentrated stream of CO2.

Oxygen firing presents a number of challenges, however. If oxygen is simply introduced with the fuel into a boiler, the flame temperature would be far too high for the equipment to tolerate. This can be overcome by recirculating up to 90 per cent of the flue gas to control the flame temperature. “This is a hugely complicated and costly design to achieve,” notes Marion, “but with a CFB boiler, this complication can be easily avoided because an inherent feature of CFB technology is that there are solids, such as limestone or sand, that are circulated within the combustor. These can be passed to a heat exchanger and back into the combustor and thereby help to control flame temperatures.

“So with CFB technology, we don’t have to recirculate any of the flue gas in order to control flame temperature. This means that the application of oxygen firing will be less expensive in a CFB boiler than other boiler types.”

Nevertheless, oxygen firing is an expensive option compared to conventional firing due to the need for an air separation plant on-site. “The penalty is estimated to be as high as 20 per cent,” says Dr. Nsakala Nsakala, project leader with Alstom. “But this penalty can be overcome and we are looking at two approaches under the DOE study.”

One approach is to deploy a new class of oxygen production technology which uses electrochemical membranes to reduce by one-third the costs associated with producing oxygen.

Chemical looping

The second approach involves the use of metal oxide oxygen carriers such as iron. Marion explains: “Once iron is oxidised it can be introduced into a chemical process under which it releases its oxygen which is then used to combust a fuel. The iron, now in a reduced state, can be returned to a regenerator where it would be oxidized again.” He adds: “This is classified as a chemical looping process.”

“The other issue we have with [carbon capture] technology is that the industry convention is to compress the CO2 for transport by pipeline as a liquid,” says Marion. “The energy penalty for compressing the gas is around ten per cent of the power plant’s output. And it’s hard to overcome this penalty.”

Overcoming cost is one of the greatest challenges of the programme. According to the DOE, the largest expense and technical challenge remains with the capture of carbon, rather than with sequestration.

Helping to drive the commercialization of carbon capture technology is the market for CO2 gas in the chemical industry and also its use in enhanced oil recovery (EOR) applications, where gas is injected underground into oil fields to increase the level of oil recovered. According to Marion, using CO2 and also nitrogen for EOR is an emerging technology in the oil and gas industry, but is growing rapidly.

“It is Alstom’s opinion that applications like EOR are the sites for early adoption of CO2 from power plants,” notes Marion. “Today, EOR applications use naturally-occuring CO2 , whose cost of delivery is less than current costs to capture CO2 from power plants.”

In addition, the implementation of a government policy on carbon would add an economic value to mitigating CO2, which would enhance the economics of capturing carbon.

Alstom study cases (all nominally 210 MWe gross equivalent)

Case 1. Base case circulating fluid bed (CFB) boiler (210 MW): Conventional operating air-fired CFB without CO2 capture, compression, and liquefaction. This provides a reference point for performance and economic analyses of other cases (particularly cases 2-7).
Case 2. New compact O2-fired CFB with CO2 purification, compression, and liquefaction: Same thermal input but smaller boiler island than Case 1. A conventional cryogenic air separation unit supplies oxygen. Concept provides concentrated CO2 flue gas.
Case 3. Same as Case 2, but without CO2 purification steps (‘dirty’ flue gas is sequestered).
Cases 4 – 7. New O2-fired CFB-type plants utilising advanced boiler design concepts. These plants use oxygen from a conventional cryogenic air separation unit, an oxygen transport membrane (OTM), or a metal oxygen carrier (such as Calcium). CO2 is purified (where appropriate), compressed, and liquefied.
Case 8. Present day integrated gasification combined cycle (IGCC): Conventional operating IGCC (Single Train F-Class Gas Turbine) without CO2 capture, compression, and liquefaction. Provides a reference point for performance and economic analyses of Cases 9 and 10.
Case 9. Same as Case 8, but with scrubbing equipment for CO2 capture, compression, and liquefaction
Case 10. Future (2015) IGCC. Same as Case 9, but applying the most advanced thinking of technology breakthroughs that might reduce the cost and increase the performance of an IGCC power plant (e.g., H-Class Gas Turbine, OTM for oxygen production, and direct quench cooling of the syngas).