Clean coal : green and lean

With the economic benefits of emissions offsets, clean coal is poised to move from a government-subsidised to a commercially viable industry, as Catherine Lacoursière reports

The place of coal in a low-carbon world is still being debated. With 1,000 billion tons of global coal reserves and hundreds of coal-powered plants being developed around the globe, "King Coal" is not expected to be knocked off its perch as the world's lowest-cost power supply in the coming decades.

Yet clean coal technology – coal with low or zero pollutant emissions – has not proven to be cost-effective on a standalone basis. All six of the world's high-efficiency integrated gasification combined cycle (IGCC) plants receive government subsidies. But with the help of emissions offsets, clean coal is ready to move beyond concept technologies and high subsidisation to become a commercially viable industry.

Clean coal encompasses a wide variety of technologies, with those with the greatest emission reduction potential at the far end of the commercialisation timeline. Although often overlooked as part of the "clean coal" family, in the US flue gas desulphurisation units (or scrubbers) have been required at coal plants to reduce the sulphur that causes acid rain since 1978. Other pre-combustion clean coal technologies are now becoming commercially viable with the help of advances in technology and high natural gas prices. These include KFx's K-Fuel and Coaltek's "designer coal". Both technologies – which are in the early commercialisation and trial stages respectively – remove the moisture while increasing the Btu content of low-grade coal to provide a higher-grade coal with lower emissions. The K-Fuel technology reduces mercury emissions by 70%, and sulphur dioxide and nitrogen oxide emissions by 30%.

But it is the post-combustion zero or near-zero emissions clean coal technologies that are receiving most of the press attention – coal gasification, and carbon capture and storage (CCS) technology. The US's Futuregen is the model zero emissions plant, a $1.5 billion coal-fired IGCC plant. "Polygen" plants like Futuregen produce multiple products at the same time, including synfuel (liquid fuel obtained from coal), carbon, hydrogen and other chemicals.

Carbon credits

Despite the cheap and abundant feedstock, the costs of building an IGCC plant are still high. The Electric Power Research Institute (EPRI) has estimated capital costs for an IGCC plant at 1,490–1,610 $/kw versus 1,430 $/kw for a pulverised coal plant. With carbon capture and storage technology installed, it has been estimated that an IGCC plant's costs could run as much as 40% higher than that of a pulverised coal (PC) plant. It is a high price tag, but carbon capture and storage (CCS) is an important economic component in clean coal plants. The carbon can be stored or sold for use in other applications, while any carbon emission reductions can be monetised through the carbon credit market.

In fact, under a CO₂ capture scenario, carbon credits have the potential to make clean coal more economical than not only the lower-cost incumbent coal technologies – PC and fluidised bed coal combustion – but also the world's most advanced natural gas plants. "When taking into consideration carbon capture, many studies indicate that the economic advantage then shifts to IGCC, says Tom Sarkus, division director for advanced energy initiatives at the National Energy Technology Laboratory (NETL).

The main difference is the amount of CO₂ captured by post-combustion PC and FBD technologies versus pre-combustion IGCC technology. In a PC or FBD plant, CO₂ is captured from the flue gases after the fuel is burned with air/oxygen, resulting in higher nitrogen and other constituents versus CO₂, whereas an IGCC plant gasifies the coal and runs it through a sift reactor, resulting in higher hydrogen and carbon dioxide streams with a smaller gas stream.

Capturing and monetising this higher concentration of CO₂ in the synfuel through the carbon market can help offset the higher overall costs of IGCC plants.

There is still a considerable difference between the cost of carbon capture and storage, at upwards of $200 per ton of carbon captured and sequestered, and the cost of carbon credits, trading around $3.50 to $4.00 a ton on the Chicago Climate Exchange (CCX).

Methane markets

One of the fastest growing clean coal sectors in the world today is coalbed methane (CBM) projects, which turn methane – a greenhouse gas found in coal mines – into natural gas. Coalbed methane projects capture coalbed methane and convert it into pipeline gas or electricity.

For decades this clean-burning hydrocarbon remained untapped in abandoned coal mines, until the CCX's coalbed methane emissions offsets created a traded market for coalbed methane reductions, providing the economic impetus to extract methane. The CCX certifies methane offsets from a wide variety of projects in addition to CBD, including agricultural, forestry, landfill and waste. With a global warming potential 23 times that of carbon dioxide, high to medium concentration methane (CH) projects provide the opportunity for attractive carbon and methane emissions offset streams.

"The methane credits have allowed projects that were not able to get financing from banks to become economical," says Derek Six, controller of State College, Pennsylvania-based Environmental Credit Corp. "They are probably the tipping point in terms of revenue lines, particularly in making abandoned projects viable. The value of the environmental benefits is that they turn economically unfeasible or marginal projects into viable projects. These projects are not financable without these credits."

Since the CCX certificate's launch in 2003, the Chicago Climate Exchange has issued 2.1 million tons in coalbed methane offsets. The projects that have been registered with the CCX are all in Germany, but a big uptick in North American projects is expected over the next six to 12 months, says Six, whose company is working on a number of CBD projects.

International banks – primarily European and Asian – that have been active investors in carbon credit projects in Europe, Asia and elsewhere have had the highest risk appetite for coalbed methane projects. With the exception of a North American carbon market, US domestic banks appear to have a lower comfort level with project loans involving carbon credits.

Nevertheless, more financing is becoming available for coalbed methane projects, which are typically small in size, and therefore lower-risk. IGCC plants, on the other hand, have much higher overall costs.

In China, hundreds of coalbed methane projects are being evaluated for financing under the clean development mechanism (CDM). In August, the Jincheng Anthracite Mining Group opened its 120,000 methane power plant at its Sihe coalmine in Shanxi province, financed with $150 million from various investors in exchange for certified emission reductions (CERs). A significant development in clean coal research was the formation in August of the Clean Energy Commercialisation Centre (CECC) by BP and the Chinese Academy of Sciences (CAS). The centre will consolidate clean coal research throughout China with a focus on IGCC and CSS technologies.

Oil recovery premium

An important factor in bringing down the cost of IGCC plants with carbon capture and storage is the creation of revenue streams from the captured carbon. While there are many byproducts of IGCC production, including hydrogen and chemicals, the greatest economic benefit – and the focus of many IGCC projects – is finding markets for the captured carbon.

A number of projects are assessing the economic feasibility of selling carbon into the enhanced oil recovery (EOR) market, calculating that the EOR premium will make it economical to use even low-grade coals in gasification plants. The model for EOR is the Wabash River project. The CO₂ pipeline flows 200 kilometers from North Dakota to the Weyburn oilfield in Saskatchewan where it pumps CO₂ into oil wells. The Wabash-Weyburn project, which has benefited from large government subsidies, was also a testbed for carbon storage.

The Canadian oil recovery markets are becoming a hotbed for CO₂ projects. Alberta utility EPCOR is evaluating the feasibility of an IGCC plant that would create revenue streams by selling CO₂ to oil operations for enhanced oil recovery to offset the extra refining expenses involved in burning Alberta's low-grade coal in an IGCC plant. EPCOR is situated within 80 kilometers of the Pembina oilfields. In Saskatchewan, SaskPower is exploring an alternative clean coal technology to gasification called oxyfuel to process its low-grade lignite coal.

"It is a real paradigm shift. We are used to pulverised coal combustion," says David Lewin, EPCOR's senior vice president of IGCC development and chair of the Canadian Clean Power Coalition (CCCP), who notes that an IGCC plant involves running a petrochemical plant requiring chemical engineers to extract hydrogen, carbon and chemicals in addition to the synfuel. First, EPCOR is focused on evaluating whether EOR can close the gap between high IGCC costs and the added expense of processing lower-grade coal. Initially it will be looking to the federal and provincial governments for assistance in filling the gap. With upgraders going into Alberta and Saskatchewan oil and oil sands projects, Lewin also sees a local market for hydrogen. He estimates that the high initial capital costs can be factored out of the project within 10 to 15 years.

EPCOR and SaskPower can expect a lot of competition. Great Point Energy, a venture capital-backed startup with a pre-combustion clean coal technology, views the Alberta EOR market as a prime market. Great Point's Bluegas technology extracts moisture from coal. Daniel Goldman, GreatPoint's CFO, says Bluegas has a number of advantages over IGCC. It is a more efficient process, requiring only three steps to produce pipeline grade gas – gasification, water gas shift, and methanation. In contrast, the technology used by Shell, Siemens, GE, Conoco Phillips and others uses partial oxidisation gasification, requiring an oxygen plant operating at high temperatures to produce hydrogen and oxygen.

Great Point's simpler process introduces a catalyst to the feedstock, which could be coal, pet coke or biomass, producing pure streams of methane and carbon dioxide which it plans to pipe to places like Alberta for use in EOR projects. Great Point says it is commercialising a low-risk technology, developed in the 1980s and abandoned when natural gas fell below a dollar, that can produce power at a lower cost than IGCC or conventional coal plants.

A study recently conducted by Nexen Bechtel estimates that Great Point's technology can produce energy at $4/Btu. Another important market is at the mine mouth of lower-grade coal sources, which Great Point can economically process into higher-grade coal. Great Point expects to have its first plant up and running by 2012. The first plant will be on a smaller scale – in the range of 2,000 to 4,000 tons per day producing 30 to 60 mm cubic feet a day of gas.

As a venture-backed company, Great Point has a greater incentive to get its clean coal technology to market early. "We are trying to develop a technology that is not dependent on any state or federal incentives. We are looking to develop a commercially viable technology that does not require loan guarantees," says Goldman.

All of the major manufacturers of IGCC technology, including Siemens and GE, are exploring opportunities in Canada's oil sands sector, which consumes vast amounts of natural gas. The amount of gas used in oil sands projects, close to 1 billion cubic feet today, is expected to double to 2.1 billion cubic feet by 2015. Shell-based technology is being used at the Long Lake Alberta SAGD operations of Nexen and to convert asphaltene to synthetic gas. The hydrogen and carbon byproducts can then be used in heavy oil upgrading. The use of such opportunistic fuel – or no-cost, onsite fuel derived from the oil extraction process – can significantly lower the costs of producing synfuel.

Carbon streams

If Canada's clean coal future is realised as envisioned, carbon streams will be flowing generously throughout Alberta's oil recovery projects from both pre-combustion and post-combustion clean coal technology in the 2012 to 2015 timeframe.

First, CO₂ pipelines need to be built. "Before anyone invests in an IGCC plant, there needs to be a commitment to a CO₂ infrastructure, otherwise it will be difficult to convince investors that it is viable," says EPCOR's Dr Lewin. Canada plans to build an integrated CO₂ pipeline network. The first phase will be in Alberta's Pembina and Swan Hills areas, with plans to expand to the oil sands projects in Fort McMurray, Saskatchewan.

Fuel-flexible IGCC plants are proving to be the most cost-effective. Tampa Electric's IGCC plant is the top dispatch unit – lowest-cost producer of power – in the Tampa Electric's power system due to its use of pet coke rather than coal as a feedstock. Pet coke, a byproduct of oil refining, can be purchased for as little as the cost of transportation. The Tampa IGCC plant is now expanding from 250MW to 600MW. Despite the more attractive economics, the future of IGCC is still clean coal. The US produces about 50 million tons of pet coke a year but 1.1 billion tons of coal.

Byproducts from polygen IGCC plants and CO₂ pipelines may still not be enough to make clean coal commercially viable, particularly in areas with low-grade coal. Carbon finance will also be necessary. Emission offsets and the financing that carbon revenue streams help secure will also be a necessary component of the clean coal cost structure. To ensure the clean coal plants are operational by 2012, Canada and the US may want to hasten the development of carbon trading markets.