Tag Archives: gasification

Carbon Energy Delivers Innovations in Underground Coal Gasification

By Morné Engelbrecht
Managing Director and CEO, Carbon Energy Limited

After decades on the fringes of world energy production, advancements in underground coal gasification (UCG) are proving the process can deliver high-quality syngas on a commercial scale with limited impact on the surrounding environment, at a lower cost than current coal-to-gas production in Australia.

Carbon Energy Limited, based in Australia, has built on many years of work by that country’s leading research organization, the Commonwealth Scientific and Industrial Research Organisation (CSIRO), to further develop and demonstrate a UCG technology that has satisfied stringent technical and environmental assessments by a panel of government-appointed independent scientists. Decommissioning and rehabilitation processes have also been assessed by the state environmental protection authority.

Today UCG is poised to become a valuable option to help meet future domestic and global energy demand because it offers an environmentally responsible and economically attractive means of extracting energy from otherwise unmineable coal.


One of the stumbling blocks that has held UCG back from becoming a fully commercial industry has been the inability to extract a consistent-quality syngas required for continuous feed into the selected downstream industrial process (whether for fuel or fertilizer production, electricity generation, or other uses that require syngas as a raw feedstock).

UCG requires ignition (heating of the underground coal seam to high temperatures between 1200 and 1600°C) to initiate the gasification process, and the subsequent injection of an oxidant (e.g., air or oxygen and steam) to maintain the syngas production. Traditional UCG approaches have employed a “batch process” using vertical wells and requiring manual intervention and reignition approximately every 30 days. This causes fluctuations in temperature and syngas quality.

Carbon Energy’s process, developed over more than 16 years of research and in-field trials, has been proven to address this issue by using a unique design that provides continuous automated gasification in a panel of coal to produce a high-quality syngas for up to 10 years (see Figure 1). This innovation, called the Controlled Retraction Injection Point (CRIP), was extremely important in achieving the consistently high-quality syngas that was produced continuously over many months during Carbon Energy’s demonstration at Bloodwood Creek in Queensland.

FIGURE 1. Carbon Energy’s approach to UCG

FIGURE 1. Carbon Energy’s approach to UCG

With horizontal in-seam injection and production wells, and an oxidant injection point that retracts as the coal face is gasified, the gasification process is maintained at a consistent temperature, which in turn produces consistent quality syngas. Moreover, a significant proportion of the potentially contaminating by-products produced with the syngas are destroyed in the path of the gasification face, contributing to the now-proven environmental credentials of the technology.


Global primary energy demand is expected to rise 37% by 2040, according to the International Energy Agency’s “World Energy Outlook 2014”.1 With the world’s hunger for energy growing, unlocking new energy sources that are commercially sustainable and are amenable to carbon capture techniques is a priority. Coal is predicted to remain a significant source of energy for the world given its widespread availability and low cost. UCG is a technology that is able to maximize the energy extracted from coal, while ensuring a small environmental impact and footprint.

Carbon Energy’s technology has improved on previous UCG methods and been shown to extract 60 times more energy than coalbed methane extraction on the same area of coal. It is also able to produce syngas from coal seams previously considered too deep and uneconomical for traditional coal extraction technologies. Carbon Energy’s recently completed demonstration at Bloodwood Creek was operated at depths of more than 200 meters below the surface; however, operation at far greater depths is also possible and commercially viable.

Rigorous scientific assessments and independent review have shown that potential environmental issues around waste and impacts on groundwater have also been overcome. With site selection methodology developed by CSIRO, refined engineering design to geothermal standards, and demonstrated operating protocols, it has been demonstrated that environmental impacts are kept to a minimum. With the physical footprint of the UCG operations contained to 50 hectares of land while recovering a significant volume of energy, good relationships are maintained with landholders. Together with the proven environmental credentials, this should assist Carbon Energy to achieve a social license to operate its unique technology.


Carbon Energy’s proposed Blue Gum Gas Project neighbors the existing demonstration site in the Surat Basin at Bloodwood Creek, about 200 km west of Brisbane, Queensland, Australia. Once government approvals are received, Carbon Energy will build and operate a commercial-scale UCG plant that will produce syngas which will be processed above ground to deliver pipeline-quality synthetic natural gas (SNG). The plant will produce 25 PJ of natural gas per annum, which is approximately 0.687 billion Nm3/yr natural gas equivalent, suitable for use by existing connected homes and domestic industries. SNG production is expected to commence within three years of the start of construction.

Carbon Energy’s proposed commercial Blue Gum Gas project will be located near the existing demonstration site.

Carbon Energy’s proposed commercial Blue Gum Gas project will be located near the existing demonstration site.

Carbon Energy’s focus on developing SNG over power or ammonia production has been driven by commercial demand. The domestic natural gas market on the east coast of Australia will see a significant increase in natural gas prices as the export of coal seam gas commences. East coast manufacturers are eager to find a low-cost natural gas feedstock. The Blue Gum Gas Project will be located near existing infrastructure enabling ready transport of natural gas to customers.

Carbon Energy operated a demonstration (pilot) project at Bloodwood Creek in Queensland from 2008 to 2012 in order to fine-tune the application of their unique technology, and to collect necessary data to submit to the state government for approval to operate the technology in Queensland. Although most of the syngas over the demonstration period was flared, the syngas was used to power generators, with power used on site and also exported to the local electricity grid.

The pilot-scale demonstration project involved operating two underground gasifiers. The “panels” of coal where the gasifiers operated were constructed at a depth of about 200 meters, are 500 meters long, and 30 meters wide, with an average thickness of 8–9 meters. A panel of this size has sufficient coal to produce syngas continuously for five years. However, as proof of concept of the technology was achieved after almost two years of continuous production of high-quality syngas from the second gasifier, further expenditure on the pilot was unwarranted and the demonstration project was decommissioned.

The commercial-scale project will simply replicate the panel module at the scale required for the project. In the case of the proposed Blue Gum Gas Project, around 40 of these panels will be required to generate 25 PJ of syngas per annum.

Environmental Review

An Independent Scientific Panel (ISP) was appointed by the Queensland government in 2009 to review and report on the pilot projects being conducted in the state at that time, focusing on the technical and environmental aspects of UCG technology. Technology developers were required to prepare a comprehensive report on their pilot projects and submit these reports to the ISP for review.

The final peer-reviewed ISP report on the pilot projects was released in July 2013. The government gave in-principle support to the ISP’s conclusions that the capability to commission and operate a UCG gasifier had been demonstrated, and that “the technology could, in principle, be operated in a manner that is socially acceptable and environmentally safe when compared to a wide range of other existing resource-using activities”. However, the government required that the technology developers demonstrate successful decommissioning prior to any approval being granted for a commercial-scale project.

Essentially, this meant that Carbon Energy needed to provide evidence that gasification had ceased at the pilot project site and that any of the relevant environmental values affected by the underground coal gasification process (excluding surface facilities and landform, which would be addressed under normal processes) could be restored to a condition agreed to with the Department of Environment and Heritage Protection (DEHP). There was a particular focus on groundwater quality, which could potentially be impacted adversely by UCG by-products.

Carbon Energy’s UCG pilot site

Carbon Energy’s UCG pilot site

To meet the government’s requirement, Carbon Energy prepared a comprehensive Decommissioning Report and Rehabilitation Plan and submitted these documents on 29 August 2014 and 1 October 2014, respectively. Preparation of these documents involved a full site investigation by an independent Suitably Qualified Person for contaminated land assessment (as authorized under the Environmental Protection Act 1994), which in turn involved a drilling program for collection and laboratory analysis of decommissioned gasifier cavity water and core samples, core samples from new near-cavity boreholes, and baseline core samples. Analysis of the data from these new wells was in addition to analysis of results from the ongoing monitoring of groundwater quality from 24 monitoring wells surrounding the gasifier cavity and located in the target coal seam and overlying and underlying rock formations.

The Queensland DEHP has advised Carbon Energy that its expert consultants have completed the review of Carbon Energy’s Decommissioning Report and Rehabilitation Plan. This review will be referred to the Department of Natural Resources and Mines (DNRM), which is the lead agency in the matter of UCG policy, for a government decision on commercialization of the technology in Queensland.

Decommissioning Plan

  • The Decommissioning Plan was required to include:
  • Evidence that gasification had ceased
  • Quantification of any contaminant load
  • Delineation of the zone of impact of any contamination
  • Evidence that any contaminants were not increasing or moving outside of the lower-pressure zone maintained by Carbon Energy around the gasifier cavities.

The process data clearly showed that gasification stopped within 48 hours of initiating the shutdown procedure (see Figure 2). This was evidenced by changes in the composition of vented gas, which quickly returned to high percentages of natural methane gas with a sharp decline in the concentrations of hydrogen and carbon dioxide, and declining syngas flow rate and temperature.

FIGURE 2. Carbon Energy’s pilot-scale demonstration

FIGURE 2. Carbon Energy’s pilot-scale demonstration

Once gasification stops, it cannot start again naturally, due to the absence of oxygen 200 meters underground beneath a tightly sealed formation, with the UCG panel surrounded by groundwater.

The results of the groundwater quality investigation showed that:

  • The majority of remaining UCG by-product was within the cavity.
  • More than 90% of by-products were eliminated by steam venting during the shutdown procedure.
  • Concentrations of remaining by-products are decreasing.

Both during operation and after decommissioning, pressure in the gasifier is maintained at a level below the regional groundwater pressure so that groundwater continuously flows toward and into the gasifier cavity. The pressure is controlled by Carbon Energy from the surface. This approach successfully contains UCG by-products within the small area of low pressure.

Environmental testing was completed to ensure that the pilot operations had been concluded safely.

Environmental testing was completed to ensure that the pilot operations had been concluded safely.

Rehabilitation Plan

As previously indicated, the purpose of the Rehabilitation Plan was to demonstrate Carbon Energy’s ability to restore the relevant environmental values of the site, those essentially being groundwater quality. Given the baseline quality of the groundwater (which is not fit for human consumption), the applicable environmental values for the Bloodwood Creek site were identified as stock watering and human health.

Based on the results of the site investigation, a risk assessment and highly conservative fate and transport modeling based on the applicable environmental values, it was concluded that the current groundwater conditions within the cavity do not pose harm to human health or the environment.

The independent Suitably Qualified Person under the Environ-mental Protection Act 1994 signed off on the Rehabilitation Plan, which concluded that:

  • The low levels of remaining by-products will rapidly and naturally reduce to baseline levels.
  • No environmental receptors are likely to be impacted.
  • No active remediation is required.

Parameters have been proposed for a range of chemicals against which groundwater analysis will be assessed on a regular basis and reported to the government. Monthly reporting of groundwater results from the groundwater monitoring network will also continue.


Carbon Energy has demonstrated its technology is a significant advance in UCG, in producing consistently high-quality syngas that can support commercially viable downstream use. More than 100 years since the first suggestion of gasifying coal underground, Carbon Energy’s approach is an attractive, environmentally responsible, and economically viable means of utilizing the energy potential of coal considered too deep for viable conventional mining.


  1. International Energy Agency. (2014, 12 November). World energy outlook 2014, press release, www.worldenergyoutlook.org/

For more information, please email askus@carbonenergy.com.au


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Underground Coal Gasification: An Overview of an Emerging Coal Conversion Technology

By Cliff Mallett
Chairman,A Underground Coal Gasification Association
Technical Director, Carbon Energy Limited

Fossil fuels undeniably remain the world’s principal source of energy. They have underpinned the growth of industry and standards of living for the last 300 years. However, finding ways to continue to utilize fossil fuels in a low-carbon and otherwise environmentally-friendly manner is a global priority.

Underground coal gasification (UCG) is one approach to energy production that may allow for emissions and other environmental impacts to be effectively managed. Decarbonization could be achieved by gasifying coal and reforming the syngas product to hydrogen (H2, a clean energy carrier) and safely store the carbon dioxide (CO2).

UCG demonstration rig

UCG demonstration rig

Coal gasification has been carried out for centuries. During the 19th and early 20th centuries numerous towns had their own gas works, responsible for making coal gas (i.e., syngas) from mined coal. The gas was piped to homes and industry. Coal gas, or town gas, is now referred to as syngas and is a mixture of energy gases such as H2, carbon monoxide (CO), as well as methane (CH4).

The development of carrying out gasification underground, UCG, can be attributed to researchers and innovators from around the world. The earliest recorded idea of producing energy by gasifying coal underground came from Sir William Siemens in the late 1800s.1 Working with his brothers, a coal gasifier was invented, which Siemens suggested be placed underground.

The subsequent major step in the development of UCG was in 1910 when patents were granted to an American engineer for UCG methods that closely resemble modern approaches. Then, in 1912, a British chemist, Sir William Ramsay, proposed gasifying coal underground as a way to avoid emissions from burning coal, which were resulting in air quality issues in cities at the time. He believed that this coal-derived syngas would be the fuel of the future.

Ramsay began preparations to trial UCG, but the outbreak of World War I derailed his plans. Interest in UCG was rekindled in the 1930s with the USSR conducting extensive experiments. However, the program was scaled back in the 1960s when the USSR discovered huge natural gas and oil reserves. More recently, momentum has grown yet again as countries including China, the U.S., Canada, Argentina, and Chile have commenced UCG projects.


Most coal-derived energy is obtained when the contained carbon reacts with oxygen (O2), yielding CO2 and releasing energy in the form of heat. If excess O2 is present, combustion occurs with nearly all the carbon converted to CO2. When coal is gasified in an O2-deficient environment, some coal is converted to heat and CO2 and this heat drives the conversion of the remaining coal to syngas. Syngas generated from UCG contains about 80% of the energy that was in the original coal.

To gasify coal underground, O2 or air is pumped down a borehole into a coal seam, the coal is gasified in a cavity created by the conversion of coal to syngas, and the sygnas is extracted through a different (i.e., production) borehole. A number of underground gasifier designs have been demonstrated, the latest being from Australia-based Carbon Energy. In a demonstration project its technology provided consistently high-energy syngas over 20 months and demonstrated the same could be achieved from a single panel of coal for up to 10 years (see article on page 61 for further details).


The primary reason to gasify coal underground is the low cost of energy production. Estimates from UCG companies on the cost of producing UCG syngas range from US$1–3/GJ depending on the coal deposit and on whether air or oxygen is used as the oxidant.2,3 Additional UCG benefits include:

  • It is applicable to very large, deep resources that can consist of low-quality coal not suited for conventional mining (normally conventional mining occurs above 1000 m). The estimated amount of usable coal at such depths could equal or exceed all current mineable coal resources and be a game changer for global energy supply.
  • The energy is produced as syngas, which is readily cleaned using existing processes and transported via pipelines.
  • Multiple uses exist for syngas, such as a fuel for power station gas engines to produce electricity, or chemical feedstock for the production of fertilizers, diesel and gasoline, and methanol derivatives such as olefins and plastics. Syngas can also be readily processed into natural gas.
  • Compared to coalbed methane extraction from the same coal seam, UCG generates over 60 times more energy.
  • UCG offers a small environmental footprint with little surface impact and minimal waste generation.
  • The health and safety issues associated with people working underground can be avoided.
One important benefit of UCG is the small footprint.

One important benefit of UCG is the small footprint.


Early 20th-century UCG trials resulted in significant lessons learned that allowed researchers and technology providers to improve the efficiency and environmental credentials of UCG. One of the major concerns related to UCG has been the ability to avoid affecting groundwater quality. Modern UCG technologies have evolved to ensure destruction of potential contaminants as part of the gasification and decommissioning processes, as well as managing operating pressures to protect groundwater.

A particular observation that evolved from early trials and subsequent research was the “Clean Cavern” concept. This is the process whereby the gasifier is self-cleaned via the steam produced during operation and following decommissioning (during decommissioning while the ground retains heat steam continues to be generated). Another important practice is ensuring that the pressure of the gas in the gasifier is always kept below that of the groundwater surrounding the gasifier cavity. Thus, groundwater is continuously flowing into the gasifier and liquids which could potentially contain chemicals will not be pushed out into the surrounding strata (see Figure 1). The pressure is controlled by the operator using pressure valves at the surface.

FIGURE 1. Operating UCG with a pressure lower than the surrounding area draws groundwater toward the gasifier.

FIGURE 1. Operating UCG with a pressure lower than the surrounding area draws groundwater toward the gasifier.

In addition, the high temperature in the cavity during gasification destroys many of the potentially contaminating organic by-products produced during the process. When operation of a gasifier is stopped, the groundwater pressure in the cavity is reduced to near atmospheric pressure (much lower than the surrounding pressure) to increase the volume of groundwater flowing into the cavity, which increases steam production. A significant percentage of remaining by-products are carried to the surface as vapor via the production well and combusted. This overall approach to UCG has now been successfully implemented at sites in the U.S., Spain, Australia, and South Africa.

Another historic concern related to UCG has been the ability to understand and predict ground subsidence. The UCG process creates a cavity similar to those found at conventional underground coal mines. These cavities are well understood thanks to conventional mining, and thus their behavior can be predicted accurately with modern 3D computer models. Similar to conventional underground coal mining, ground subsidence is predicted before UCG operations commence; if surface subsidence is predicted to significantly affect current or future land use or infrastructure, UCG will not proceed at that particular site.

One of the most rigorous long-term environmental evaluations of UCG pilot sites was carried out by the Queensland Government in Australia from 2008 to 2014. An Independent Scientific Panel appointed by the state government reviewed four years of UCG Pilot Project operations and concluded in the “Independent Scientific Panel Report on the Underground Coal Gasification Pilot Trials” (June 2013) that UCG “could be conducted in a manner that is socially acceptable and environmentally safe when compared to a wide range of resource using activities”.

Decommissioning and rehabilitation of an underground UCG gasifier cavity had not been attempted in the Queensland trials at the time of the ISP evaluations, but in late 2014, independent experts advised the government that Carbon Energy had successfully decommissioned its gasifier, and steam cleaning of the cavity resulted in the cavity posing no environmental or health risks. Groundwater quality will rapidly and naturally be restored to pre-project conditions and no active remediation is required.


Industrial processes require specific, controlled conditions for optimal and safe operation and UCG is no exception. The conditions required for operation of the underground gasifer are established through exploration, prior to construction or operation of a UCG panel. For example, proper UCG site selection is critical—several hydrogeological conditions must be satisfied before proceeding with construction.

First, the coal seam being gasified must be overlain by impermeable strata. The buoyancy of the gas forces it to move upward; thus, the gas will be lost unless the coal seam is capped by strata through which the gas cannot pass, such as shale or clay beds. Second, as coal seams always have some permeability and gas is able to move laterally through coal, the groundwater in the surrounding coal seam must be at a higher pressure than the pressure in the gasifier to prevent the flow of gas away from the gasifier cavity. These primary criteria are illustrated in Figure 2. Other characteristics also must exist at a suitable UCG site—for example adequate groundwater pressure for gasification to occur, coal seams of adequate thickness to maintain gasification temperatures, and appropriate separation from overlying and underlying water-bearing formations.

FIGURE 2. Primary criteria required for a suitable UCG site.

FIGURE 2. Primary criteria required for a suitable UCG site.

Field tests and digital modeling facilitate the development of hydrological models that can be used to predict risks to water supplies. Just as with subsidence modeling, if harmful effects are predicted in the exploration stage, UCG will not proceed.

Similar to other resource production industries, UCG requires appropriate pre-development exploration and investigations to ensure that hydrogeological conditions suit the technology being applied.


Until recently, there have been few new developments in UCG. A commercial UCG plant has been running for many years in Uzbekistan; however detailed information on the operation or output of that plant has not been made public. Developed countries with accessible resources have chosen to access shallower coal deposits using traditional mining methods. Additionally, projects based on traditional approaches to UCG have struggled to produce a consistent, high-quality syngas.

Looking at almost a hundred historical UCG sites worldwide,5 the main difficulties can be categorized as follows:

  • Insufficient knowledge of the site geology
  • Inability to drill boreholes with necessary precision
  • Operating with inappropriate gasification parameters
  • Lack of understanding of the impact of the gasification process on the surrounds of the underground cavity.

More recently, however, there have been major technological innovations which have addressed the issues encountered in previous UCG projects (see Table 2).


These advances facilitate proper site investigation, UCG design performance modeling, and identification of issues with respect to product gas or environmental impacts which demand specification or exclude the site as a UCG prospect. In addition, UCG operators now have access to real-time control of underground processes. This allows interpretation of changes in UCG performance and the design of appropriate responses.

The UCG ignition panel is used to carefully control the process underground.

The UCG ignition panel is used to carefully control the process underground.

Since 2000, long-term UCG pilots in Australia, China, and South Africa utilizing the technologies shown in Table 2 have successfully demonstrated that deep UCG can be low cost and environmentally benign. Results from these trials continue to demonstrate that UCG’s major challenges have been resolved and has led China to incorporate this technology into its Five-Year Plan process for resources and energy.

Recent progress and innovation have made it possible that UCG will be an important technology in the future energy mix. However, progress in nontechnical areas must be made with respect to the interrelated areas of government regulation, community understanding and engagement, and project financing.

Given that the production cost of UCG syngas can be significantly lower than that for production of energy by other means, and its demonstrated environmental credentials, UCG presents an opportunity for high-potential growth investors looking for approaches to generate low-emissions power, synthetic natural gas and other fuels, and chemicals from coal.


Energy demands continue to grow globally, particularly in emerging economies in Asia and Africa. At the same time, there is pressure to minimize the cost and maximize the availability of energy supplies as well as the social imperative to reduce the environmental impact associated with energy.

The adaption and application of new petroleum and mining techniques have demonstrated that consistent supplies of high-quality syngas can be safely produced in commercial-scale UCG projects. Further progress and innovation in the field of UCG has been seen recently and several new commercial UCG projects are nearing commencement. Once the first commercial project is successfully established, I believe there will be an avalanche of follow-on projects, and the industry will become a valuable contributor to global energy production.

The syngas created underground is collected and processed above ground.

The syngas created underground is collected and processed above ground.

A. Dr. Cliff Mallett served as Chairman of the Underground Coal Gasification Association from 2013 to 2015. His tenure at that position concluded near the time of article preparation. Dr. Mallett is also Technical Director at Carbon Energy. Thus, some of the technical innovation discussed in the article is based on his direct involvement with Carbon Energy.


  1. Klimenko, A.Y. (2009). Early ideas in underground coal gasification and their evolution. Energies, 2(2), www.mdpi.com/1996-1073/2/2/456
  2. Carbon Energy. (2012, 26 June). Carbon Energy UCG syngas – low cost source of natural gas. ASX/Media Announcement, www.carbonenergy.com.au/IRM/Company/ShowPage.aspx/PDFs/1561-83497961/LowCostSourceofNaturalGas
  3. Pricewaterhouse Coopers. (2008, May). Industry review and an assessment of the potential of UCG and UCG value added products, www.lincenergy.com/data/media_news_articles/relatedreport-02.pdf
  4. Moran, C., da Costa, J., & Cuff, C. (2013, June). Independent Scientific Panel report on underground coal gasification pilot trials, Independent Scientific Panel to the Queensland Government, www.fraw.org.uk/files/extreme/derm_2013.pdf
  5. UCG Association. (2015). Worldwide UCG projects and developments, www.ucgassociation.org/index.php/ucg-technology/worldwide-ucg-projects-developments (accessed April 2015)

The author can be reached at Cliff@carbonenergy.com.au


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Ashworth Gasifier-Combustor for Emissions Control From Coal-Fired Power Plants

By Robert Ashworth
Senior Vice President, ClearStack Power, LLC
By Mark Becker
Senior Process Engineer, ClearStack Power, LLC

The growing role of coal is especially prominent in many emerging economies where rapid urbanization and industrialization are driving the growth in energy demand.1 In fact, the equivalent of one 500-MW coal-fired power plant has come online every three days since 2010.2 The president of the World Bank has said that coal will be essential to helping Africa meet its demand for power and alleviate “energy apartheid”.3 Several nations leading the world in economic growth as well as some developed countries are relying heavily on coal-fueled electricity.4

As coal-fired power generation around the world increases, the necessity of limiting the emissions becomes increasingly vital. A range of emissions control technologies for all major emissions is currently commercially available. However, especially when power plants are retrofitted, these large pieces of equipment are often piecemealed together, resulting in marginal increases in both the cost of power and the amount of auxiliary power required. In emerging economies these technologies can be cost-prohibitive. Even in the U.S., where inexpensive natural gas has increased competition in the power market, some power plant operators have chosen to shut down coal-fired plants rather than retrofit them with emissions controls. Thus, having options for reducing the costs associated with comprehensive emissions control from coal-fired power plants is globally important to providing affordable, reliable, and low-emissions electricity.

The Ashworth Gasifier-Combustor, under development by ClearStack Power, LLC, is a low-cost air-blown coal gasification technique that dramatically reduces the major criteria emissions [e.g., NOx, SO2, Hg, air metal toxics, and particulate matter (PM)] from a coal-fired power plant when paired with an electrostatic precipitator (ESP). The technology also offers a smaller footprint and draws far less auxiliary power than traditional emissions controls.

ClearStack’s approach to emissions control is based on a three-stage gasification-combustion technology (see Figure 1), which can be applied to new or existing power plants. In the first stage, pulverized coal is gasified in air in an entrained-flow gasifier to form a mixture primarily of carbon monoxide (CO), hydrogen (H2), water vapor (H2O), and nitrogen (N2, from the injected air). In the first stage limestone is added, which reacts with potential contaminants in the molten ash (i.e., slag) produced. The coal and limestone are fired downward into a molten slag bath, which results in the formation of PM in which the individual particles are larger than what would be created during combustion. When this technology is retrofit to existing power plants the first-stage gasifier takes the place of the burners and is thus fully integrated with the plant. Then, complete combustion occurs in the second and third stages.

FIGURE 1. Ashworth Gasifier-Combustor retrofit schematic

FIGURE 1. Ashworth Gasifier-Combustor retrofit schematic

The amount of air relative to the coal used in the first-stage gasifier is specifically selected to minimize emissions. For example, an oxygen-deficient environment minimizes NOx production from the nitrogen in the coal and also provides the optimal conditions to reduce emissions of sulfur (captured through reaction with the limestone), mercury, and other air metal toxics.

More oxygen is available for reaction in the second stage, the lower boiler furnace, to preclude NOx formation in that stage. Excess oxygen is used for combustion in the third stage of the technology, in the upper boiler, as the gases have cooled to a point that minimizes thermal NOx production. Using less excess air throughout the gasification and combustion processes also increases the overall plant efficiency.


Reducing Criteria Emissions

The principal objective of the Ashworth Gasifier-Combustor technology is to reduce emissions from coal-fired power plants in a cost-effective manner. Environmental benefits are listed in Table 1.


The approach of gasifying prior to combustion produces nonhazardous, salable inert slag and fly ash. Since selective catalytic reduction is not required (because NOx formation is avoided during combustion), chemicals like ammonia are not required. Similarly, since no water is sprayed into the flue gas as is the case with wet desulfurization scrubbers, no visible water vapor is observed at the power plant stack.

In addition to comprehensively reducing emissions, the technology also offers several co-benefits. Approximately 75% of the fly ash, or PM, is captured and removed with the molten slag produced in the gasifier. Because the PM generated is larger than what is created during combustion, the PM that is not removed with the slag is less harmful and also is more efficiently captured by an ESP, since larger particles are easier to capture. Thus, a combined gasification-combustion approach would reduce plant emissions using the same ESP (in the case of a retrofit). For example, with a particular ESP using a voltage of 94 kV,5 employing the gasifier-combustion operation would yield an overall PM removal of 99.32 wt% compared to removal from flue gas from a conventional coal-fired unit of 94.96 wt% (see Table 2).


Another benefit is that the ash is more alkaline because limestone is mixed with the coal. Research has shown that the alkali and alkaline earth metal concentrations are important factors in reducing the resistivity of the fly ash (to improve the ease of capture).6

Carbon Emissions

In addition to criteria emissions, the technology can reduce carbon dioxide (CO2) emissions. First, it can be applied to biomass/coal mixtures, thus reducing carbon emissions. Up to 15% of the coal could be replaced with biomass. While conventional boilers can cofire some 10% biomass, the reactive alkalis, such as sodium and potassium, can decrease boiler tube life. In the gasification-combustion system under development, these compounds are mostly tied up with other minerals in the slag and thus not as much of a concern.

In addition, the required auxiliary power is far less than traditional emissions control options. When using the traditional emissions controls combination of low-NOx burners, selective catalytic reduction, and a wet FGD system, a 580-MW power plant might have 15 MW of parasitic energy consumption (meaning that the plant can only sell 565 MW), not including the ESP and other auxiliary power draws required by both systems. However, the only parasitic energy used by the Ashworth Gasifier-Combustor process is that for treatment and injection of the limestone. Thus, the parasitic energy for a similarly sized plant would be 0.5 MW instead of 15 MW and a 580-MW power plant could sell 579.5 MW of electricity. In addition, certain coals with high-calcium ash, such as some Powder River Basin coals, would not require limestone addition. In that case the auxiliary power for emissions controls could be negligible. With each improvement in efficiency the CO2 emissions are decreased.

In the long term, if the technology is applied to new ultra-supercritical boilers that currently achieve 45–46% overall thermal efficiency,7 a power plant built with the Ashworth Gasifier-Combustor would be more efficient than a coal-based integrated gasifier combined-cycle (IGCC) power plant. It would also require less space and would be less expensive to install and operate.

Saleable By-Products

Since the advent of low-NOx burners and activated carbon injection for mercury capture, many coal-fired power plants that once sold their fly ash to the cement industry are no longer able to do so due to increased carbon content. As the Ashworth Gasifier-Combustor results in fly ash with 5 wt% carbon or less, it is suitable for sale to the construction industry. The slag from the first-stage gasifier could also be saleable since coal-fired cyclone boiler slag is currently used as a wear-resistant component in surface coatings of asphalt for road paving. Finer-sized slag could also be used as blasting grit and is commonly used for coating roofing shingles.


Preliminary economics have been calculated for the Ashworth Gasifier-Combustor. For a retrofit, the costs are compared with a FGD scrubber to remove SO2 and Hg plus selective catalytic reduction (SCR) for NOx control (see Table 3). The comparison assumes the same environmental performance for the two emissions control options. A 200-MWe T-fired coal boiler firing run of mine bituminous coal was used as the basis for the retrofits. For calculation of operating costs, an 80% capacity factor was used.A The capital and operating costs are based on 2015 U.S. dollars.


The Ashworth Gasifier-Combustor was calculated to be ~38% of the capital cost and 36% of the operating cost compared to the conventional emissions control technologies. Also, this analysis does not include any credit for other air metal toxics (80–100%) that are removed by the gasifier and/or greater ESP performance. In addition, because the ash and slag are saleable, the economics could actually improve further.


The Ashworth Gasifier-Combustor was demonstrated at a 4-MWe scale at the Lincoln Developmental Center, in Lincoln, IL, U.S., on a coal-fired stoker (see Figure 2).8 The gasifier was incorporated into boiler operation. The gasifier design modifications were successful in increasing sulfur capture and reducing NOx emissions compared to the original two-stage Florida Power Corporation “CAIRE” gasifier-combustor to which ClearStack owns the rights and completed testing at the Foster Wheeler Development Center.9

FIGURE 2. Ashworth Gasifier-Combustion system (40 million Btu/hr)

FIGURE 2. Ashworth Gasifier-Combustion system (40 million Btu/hr)


Today this gasification-combustion technology remains under development. Currently, ClearStack is seeking a project partner in the U.S. to demonstrate the technology on an existing 20–75-MWe coal-fired power plant. The objective of the collaboration would be to retrofit the technology in order to meet the U.S. EPA Mercury and Air Toxics Standards. Depending on the environmental permit requirements, it will take 18 to 24 months to retrofit the technology onto an existing coal-fired plant in the U.S. Pending a successful demonstration, ClearStack will look to deploy the technology at power plants needing emissions control both in the U.S. and abroad.


A. The Ashworth Gasifier-Combustor is applicable to coal-fired power plants of any size. A     200-MWe plant was chosen for the economic analysis because this represents the most likely near-term customers in the U.S.


  1. Advanced Energy for Life. (2015). The world is counting on coal to power growing needs, www.advancedenergyforlife.com/article/world-counting-coal-power-growing-needs (accessed April 2015)
  2. BP. (2014). Energy outlook 2035, www.bp.com/en/global/corporate/about-bp/energy-economics/energy-outlook.html
  3. Kim, J.Y. (2014, 1 April). Speech by World Bank Group President Jim Yong Kim at the Council on Foreign Relations, www.worldbank.org/en/news/speech/2014/04/01/speech-world-bank-group-president-jim-yong-kim-council-on-foreign-relations
  4. Watanabe, C. (2015, 9 April). Japan’s new coal plants threaten emission cuts, group says. Bloomberg Business, www.bloomberg.com/news/articles/2015-04-09/japan-s-new-coal-plants-threaten-emission-cuts-group-says
  5. Haque, S., & Rasul, M.G. (2009). Thermal power plant: Performance improvement of electrostatic precipitator, www.knovelblogs.com/2009/12/03/ecthermal-power-plant-performance-improvement-of-electrostatic-precipitator/
  6. Wheland, B., Devire, G., Pohl, J.H., & Creelman, R.A. (2000). The effect of blending coals on electrostatic precipitator performance American Chemistry Society, Energy & Fuels (preprint), web.anl.gov/PCS/acsfuel/preprint%20archive/Files/45_1_SAN%20FRANCISCO_03-00_0024.pdf
  7. Power-Technology.org. (2007). Yuhuan 1,000MW ultra-supercritical pressure boilers, www.power-technology.com/projects/yuhuancoal/
  8. Ashworth Combustor Demonstration Final Report. (2003, 15 May). ClearStack Combustion Corporation for the Illinois Department of Commerce and Community Affairs and the Illinois Clean Coal Review Board.
  9. Ashworth, R.A., & Padilla, A.A. (1992). “CAIRE” Advanced Combustor Development. Presented at the Ninth Annual International Pittsburgh Coal Conference, Pittsburgh, PA, www.clearstack.com/wp-content/uploads/CAIRE-Advanced-Combustor-Development.pdf

The authors can be reached at rashworth@clearstack.com and mbecker@clearstack.com

The content in Cornerstone does not necessarily reflect the views of the World Coal Association or its members.
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Distributed Power With Advanced Clean Coal Gasification Technology

By Carrie Lalou
Vice President of Business Development, Synthesis Energy Systems, Inc.

One major barrier for clean coal gasification technologies being implemented into conventional energy sectors has been the perception that a large capital investment is required to move away from a natural gas or oil feedstock to a solid feedstock such as coal or biomass, and the conversion thereof. Historically, this has marginally been the case in some places where gasification projects have been implemented to “fuel” chemical, power, fertilizer, and other energy projects. However, projects that can take advantage of the optimal “integration” of gasification and downstream processing technologies and maximize capital effectiveness and efficiency can reap great benefits from gasification technologies. In cases where the lowest cost feedstocks can be used and feedstock flexibility is maximized, again without overspending capital, the projects’ return on investment can be further enhanced.

SES’ Zao Zhuang New Gas Company Joint Venture Plant that produces methanol from coal—Shandong Province, China (SES ~98% ownership)

SES’ Zao Zhuang New Gas Company Joint Venture Plant that produces methanol from coal—Shandong Province, China (SES ~98% ownership)

During the last few decades, many well-established gasification companies have attempted to improve integration with downstream technologies, yielding mixed results. In some instances, the optimized plant configuration resulted in significant cost savings—giving the project a reduced cost of production for its end product. In other instances, the integration was so complex that significant additional capital was required to realize such optimization and the technical difficulties encountered during startup and operation had a negative impact on the project and its economic performance.

Synthesis Energy Systems (SES) has developed, demonstrated, and deployed its advanced fluidized bed SES Gasification Technology, which is able to cleanly convert low-grade, low-cost coal, coal wastes, and biomass into multiple high-value end products without the same level of capital investment required for most gasification projects. Based on the fuel flexibility and lower upfront costs, SES’ fluidized bed gasification technology has been breaking barriers to enter markets previously not considered feasible for smaller-scale gasification projects. The products at such facilities include direct reduced iron steel, transportation fuels, chemicals, fertilizers, coal-derived synthetic natural gas, and power generation—the one market segment where it has been most difficult for gasification to succeed economically.

Historical IGCC Implementation

The first integrated gasification combined-cycle (IGCC) facility using coal as feedstock was constructed in the early 1980s in California using General Electric (formerly Texaco) gasification technology in combination with GE’s heavy-duty gas turbines. It was funded partially by the U.S. Department of Energy as a proof-of-concept. At the time of project initiation, the 1970s oil crisis was in full swing, and there was a mandate from the U.S. government to develop homegrown technologies to replace dependence on imported energy sources, especially oil, in an environmentally friendly manner.

Under the Cool Water Coal Gasification Program, an IGCC plant was constructed in Southern California and operated from 1984 to 1989 on four types of bituminous coals using high-purity oxygen.1 The plant released just a fraction of the permitted air-quality-related emissions at the time and achieved about 90% reliability—exceeding the benchmark set by conventional coal power generation technologies. According to the final report issued by the Electric Power Research Institute (EPRI),2 a participant in the program, the project accomplished the demonstration of low SO2, NOx, and particulate emissions. No solid waste was generated due to sulfur removal, the capital and electricity costs were competitive, and feedstock flexibility was achieved. Actual installed costs for the 93-MW plant were $315.2MM ($3387/kW).2 EPRI found that the installation cost of a “mature technology” Cool Water plant could be as low as $1567/kW,2 which became the target for future IGCC plants in the U.S. Although the project was deemed to be fuel flexible, the coals gasified at the plant were within 4% of the plant’s designed coal heat content of 11,300 BTU/kWh,2 which was actually a very narrow feedstock window.

During the next two decades, several more commercial-scale IGCC plants were constructed, including3:

  • Wabash River Coal Gasification Repower Project (1995), Indiana – CB&I
  • Polk Power Station IGCC Plant (1996), Florida – GE
  • Willem-Alexander IGCC Plant (1998), Buggenum, Netherlands – Shell
  • ELCOGAS IGCC Plant (1998), Puertollano, Spain – Uhde (PRENFLOTM)
  • Duke Edwardsport IGCC Plant (2013), Indiana – GE

Common to all of the plants listed above, and most of the other commercially operating IGCC plants, is the use of entrained flow gasification technologies, which require the use of expensive, high-quality bituminous and sub-bituminous coals, have a narrow feedstock quality capability, and allow limited deviation from the intended “design” feedstock. Additionally, all of the subsequent IGCC plants were constructed as one-of-a-kind designs, which does not lead to further cost reductions in implementation from design repeat practices. Lastly, the most recently developed large utility-scale plants (>400 MWnet), based on a “bigger is better” mentality, generally require such large capital investments that the multibillion dollar projects have been difficult to develop and finance.

The previously listed large-scale power-producing gasification projects highlight that there is progress being made and sufficient market drivers to advance the deployment of IGCC. However, in some less affluent areas, multi-billion dollar capital investments and reliable access to low-ash coal may not be practical or feasible. Therefore, we believe that smaller, less capital intensive, and more fuel-flexible gasification facilities can serve an important role, often in places where gasification is needed most—developing countries with access to low-rank coal or other solid feedstocks, but limited financial resources.

Transformative Technology

SES licenses its proprietary fluidized bed gasification technology into markets where high-value products, conventionally produced from natural gas and oil, can be produced from synthesis gas (syngas) via coal, coal wastes, biomass, and other waste materials. In regions where solid feedstocks are available, and gas and oil resources are scarce and expensive, syngas generated from solid fuel gasification can enable the economical production of chemical and energy products such as methanol and its derivatives, fertilizers, electricity, hydrogen for refining, transportation fuels such as gasoline and diesel, substitute natural gas (SNG), reducing gas for metals refining, and fuel gases. SES’ gasification technology, which has over 40 years of development behind it, is well suited for a wide range of carbonaceous feedstocks, including the lowest cost, lowest quality options available. Over the last decade, SES has implemented and enhanced the gasification system design from the original U-GAS® technology, developed by the Gas Technology Institute in Chicago, Illinois.

The SES Gasification Technology includes a dry-feed system with multiple feed ports, using oxygen, enriched air, or air as the oxidant, into a single reactor that operates under a bubbling-bed fluidization regime. A bubbling bed reactor has a forgiving operating envelope; the large volume of feedstock in the gasifier as compared to the feed rate allows the operation of the gasifier to have reduced sensitivity to feedstock fluctuations and other operating parameter changes. The gasifier operates with uniform bulk reactor temperatures, which prevents the formation of tars and oils. The syngas leaves the top of the gasifier through a series of cyclones, which remove the particulate matter and return it to the gasifier for additional conversion. The ash is removed through the bottom of the gasifier where it is cooled and depressurized for ease of handling. After the first set of cyclones, the hot syngas is used to raise superheated medium-pressure steam, which is then used as a primary fluidizing media in the gasifier along with the oxidant. The syngas is then further scrubbed to remove any remaining particulate matter before it is ready for additional downstream processing into a multitude of potential energy and chemical products (see Figure 1).

Figure 1. SES Gasification Technology based on a fluidized bed gasifier

Figure 1. SES Gasification Technology based on a fluidized bed gasifier

Fluidized beds are cost effective to build and operate reliably, which is why the SES Gasification Technology leads to lower capital investment, lower operating costs, and higher plant availability (compared to other commercialized gasification technologies). Fluidized bed gasification systems have simpler equipment designs, reduced oxidant usage, and increased fuel and operational flexibility that include on-stream fuel switching and gasifier turndown capabilities to 30% of the designed syngas production rates. Additionally, the SES Gasification Technology offers minimal wastewater discharge as compared to many other gasification technologies through the use of dry solids handling processes, and no generation of tars and oils from coal gasification, which can be extremely costly to clean from syngas.

Perhaps one of the most important attributes of the SES Gasification Technology is that it is fuel-flexible—capable of gasifying all ranks of coal, coal wastes, and other solid fuels, thus allowing its end users to secure the lowest cost feedstock for their operations, and further lower the cost of production of the valuable chemical and energy products (see Table 1).

Table 1. Range of fuel characteristics tested with SES Gasification Technology

Table 1. Range of fuel characteristics tested with SES Gasification Technology

Pairing SES Gasification Technology with GE’S Power Generation Technology

In early 2013, SES and GE’s aero-derivative gas turbine group began co-marketing a small- to medium- scale, standardized design, cleaner coal gasification plant for the distributed power market (<300 MW). This plant design is intended to have numerous economic, environmental, and societal advantages.

Chief among the benefits is that the plant enables customers to use the lowest quality, and thereby lowest cost, coals and has the ability to switch coal feedstocks with no plant modifications. It optimizes “reuse” of plant design through use of fuel-flexible gasification technology: The wider the fuel envelope for the gasifiers with little to no impact on the equipment design, the greater the reuse of plant design will be. The plant’s modular design standardizes on 90% of the plant, allowing for modifications only in packaged process units (like air separation) or in coal handling units to accommodate different ash content requirements. Staying smaller and standardizing on a nonutility-scale basis widens the market to distributed power and captive power users like mining operations and stand-alone chemical or refinery applications. The plant also implements World Bank environmental standards into the base design with allowances for modifications to improve on the environmental performance if local permitting mandates it.

Additionally, the new plant design limits the complexity of integration and avoids the temptation to over-optimize and thus drive up project costs; the simple design also allows for utilization of regional partners. Partnering with local EPC contractors and power project developers also improves the likelihood of project success. Today, SES and GE are marketing to regions where large utility-scale plants are not feasible due to lack of grid infrastructure, natural gas is nonexistent or prohibitively expensive, low-quality local coal is unusable in conventional boilers, and/or power is generated from expensive imported LNG or fuel oil/diesel.

Integration with a Little “I”

Whereas previously designed and constructed IGCC plants placed significant focus on maximizing integration with the intent to maximize plant efficiency, SES and GE have taken a different approach on a small- to medium-scale SES Gasification Technology-based power plant design. By limiting and prioritizing the integration of the gasification and power production technologies, the design lends itself to lower capital costs and simplicity with a greater ease of operation including startup sequencing. The ability for the power plant to maximize the use of prepackaged process units (such as air separation, water treatment, acid gas removal, and sulfur recovery units) and reduce the complexity of startup will allow the plant to benefit from simpler operations and process controls. Although the installed cost on a per unit of power basis may be higher than conventional coal-based power generation technologies of the same scale, the reduced complexity does not exacerbate this issue, and still allows the cleaner coal plant to surpass CFB boiler and PC boiler technologies in emissions profile and overall plant efficiency. In other words, at this small scale, the reduced integration does not have the negative impact that would be expected when competing against larger, base-load utility coal facilities. Additionally, as gasification plants produce a high-purity CO2 stream, they are essentially carbon-capture ready.4

The integration with a little “i” includes sending syngas to the GE turbines (see Figure 2). Exhaust from the turbines as well as superheated steam is sent to the heat recovery steam generator (HRSG), which is also integrated with a steam turbine.

Figure 2. Schematic of the proposed integration of SES Gasification Technology with power generation

Figure 2. Schematic of the proposed integration of SES Gasification Technology with power generation

SES’ Distributed Power Plant Concept: the First Pass

In January 2014, the first potential customer for launch of this small- to medium-scale gasification distributed power plant was identified and preliminary engineering efforts were undertaken. The early work performed by SES, with support from GE and their regional partners Tuten and IstroEnergo Group, yielded the following design components regarding the combined technologies:

  1. System Design:
    1. Single SES gasifier system, operating at nominally 50 bar(g), on high-purity oxygen, and consuming 1100–1700 tonnes/day of coal (depending on coal quality) to produce clean syngas that is suitable for GE’s LM-2500 series aero-derivative gas turbines.
    2. Two GE LM-2500+G4 gas turbines in combined cycle with a single steam turbine and HRSG.
    3. SES gasifier system sends excess superheated medium pressure steam to the power plant.
  2. Net power output is nominally 80 MW, with projected improvement based on minor modifications to the gas turbine fuel nozzle.
  3. Feedstock capability includes lignite, sub-bituminous, and bituminous coals with heat contents as low as 3000 kcal/kg (as received, LHV).
  4. Reuse of process units from the SES Gasification Technology system through syngas cooling, fines removal, acid gas removal, sulfur recovery unit, and the gas turbines. The “flex” packaged units would include air separation unit, coal handling and preparation, ash handling,A and the bottoming cycle in the power plant.
  5. Initial budgetary estimates start as low as $1800/kW installed costs for a China construction basis and are projected to run $2000–2500/kW for a significant portion of the market; these prices can be achieved through maximizing fabrication of packaged units and major process equipment via qualified and internationally accredited Chinese fabricators.
  6. The estimated net LHV plant efficiency is 34–38% depending on coal quality, plant site conditions, and elevation.
  7. Operating and maintenance costs, excluding coal costs, are estimated to be 2–3% of the total installed cost basis annually.4

A sample of the projected plant economics is provided in Table 2.

Table 2. Example indicative plant economic factors based on Indonesian lignite

Table 2. Example indicative plant economic factors based on Indonesian lignite

Deploying Distributed Gasification Power One Plant at a Time

Tackling the major barriers to implementing coal gasification projects is SES’ main focus and the SES Gasification Technology’s capability of converting a wide range of low-cost, low-quality coals is the largest factor in achieving good project economics. In addition, SES has developed equipment manufacturing capabilities in China that help it reduce the capital costs required to build projects.

SES has partnered with Zhangjiagang Chemical Machinery Co., Ltd. (ZCM) for its China and select Asia regional business, forming Jiangsu Tianwo-SES Clean Energy Technologies Ltd. (T-SEC), which is intended to enable global-scale implementation of projects using SES Gasification Technology via the lowest cost supplier of process equipment. This partnership is designed to enable SES to pass on savings to its customers, thereby reducing the overall capital expenditure for historically capital-intensive gasification projects.

SES secured the global exclusive rights to this technology more than a decade ago, and has since constructed five of its low-quality coal gasification systems in two methanol-producing plants in China: the Zao Zhuang New Gas Company Joint Venture Plant (ZZ) in Shandong Province and the Yima Joint Venture Plant (Yima) in Henan Province. Both plants convert low-grade coals and coal wastes, with very high ash content regularly exceeding 40 wt%, into syngas which is then converted into refined methanol. The ZZ plant, constructed in 2007 with commercial operation initiated in 2008, housed the largest U-GAS® based gasifiers ever installed at the time: two SES gasifiers, each with a capacity to produce 14,000 Nm3/hr of syngas.

At the Yima plant, which had its first methanol production in 2012, SES scaled up from the ZZ gasifier capacity and pressure threefold, installing three 1200-tpd SES gasifiers that operate at 10 bar(g), each with the capability to produce 45,000 Nm3/hr of syngas. During the first years of operation at ZZ, SES devised and implemented multiple improvements to the U-GAS® technology, many of which were included in the design of the Yima plant. These improvements increased carbon conversion, overall gasifier efficiency, operability, and heat recovery. These enhancements, along with additional optimizations that are being devised from the larger scale Yima gasifiers, are included in SES’ high-pressure gasification system design—optimized for chemicals and energy production where downstream processes benefit or require high-pressure syngas for end-product manufacturing.

Yima Joint Venture Plant—Henan Province, China (SES 25% ownership)

Yima Joint Venture Plant—Henan Province, China (SES 25% ownership)


Gasification is a global solution for the utilization of the world’s most abundant natural resource—coal—to produce chemical and energy products cleanly and efficiently. The challenge to do this economically and in markets that are not likely to support a large capital investment has been a historic challenge for gasification, and SES is making headway on knocking down the two major barriers to cost effectiveness: large capital investment and required access to expensive, high-quality coals. Through the implementation of a low-cost source for process equipment and the ability to use the lowest cost fuels available, SES believes it can enable projects to proceed in even the most challenging market: distributed power generation from coal gasification. SES is excited to move forward with its project partners to implement its clean coal gasification technology into the distributed power market for the production of clean, efficient, and economic electricity production.


  1. Only as a cost savings measure for plants which will have known maximum ash contents for their fuel sources.



  1. U.S. Department of Energy. (2014, June). IGCC project examples, www.netl.doe.gov/research/coal/energy-systems/gasification/gasifipedia/project-examples
  2. Electric Power Research Institute. (1990, December). Cool Water Coal Gasification Program: Final report, EPRI GS-6806, www.epri.com/search/Pages/results.aspx?k=Cool%20Water%20Coal%20Gasification%20Program:%20Final%20Report
  3. Electric Power Research Institute. (2007, March). Integrated gasification combined cycle (IGCC) design considerations for high availability, Volume 1: Lessons from existing operations. Report 1012226.
  4. National Energy Technology Laboratory. (2011, May). Cost and performance baseline for fossil energy plants. Volume 3a: Low rank coal to electricity: IGCC cases, DOE/NETL-2010/1399, www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Coal/LR_IGCC_FR_20110511.pdf


For more information regarding SES and its technology, please visit www.synthesisenergy.com.

The content in Cornerstone does not necessarily reflect the views of the World Coal Association or its members.

The Shell Coal Gasification Process for Reliable Chemicals, Power, and Liquids Production

By Rob van den Berg
General Manager Gasification Technology, Shell (China) Projects & Technology Ltd
Zhong-Xin Chen
General Manager, China Technical Service Centre, Shell (China) Projects & Technology Ltd
Sze-Hong Chua
Gasification Licensing Sales Manager, Shell Global Solutions

Embracing Clean Coal Technology

Environmentally responsible gasification technologies are helping to unlock the world’s coal reserves with increasing efficiency. The synthesis gas (syngas) produced is being used in chemical and integrated gasification combined-cycle (IGCC) plants worldwide. China, in particular, has embraced coal gasification technology as a way of using its abundant, indigenous coal reserves efficiently and with low environmental impact to manufacture methanol, ammonia, hydrogen, and synthetic liquid hydrocarbons. In other countries syngas, which burns as cleanly as natural gas, is generating power in IGCC plants.

The Shell Coal Gasification Process (SCGP), examples of its use, and a description of the continuous improvement culture that is pushing reliability and performance to new levels are the focus of this article.

South Korea is investing in its first IGCC plant, full site as of 31 May 2014 shown above (photo courtesy of Korea Western Power Co. Ltd).

South Korea is investing in its first IGCC plant, full site as of 31 May 2014 shown above (photo courtesy of Korea Western Power Co. Ltd).

Shell Coal Gasification Technologies for Different Needs

With 28 licenses sold worldwide, Shell is one of the main global suppliers of coal gasification technology and is unusual in being both the technology developer and a licensor with hands-on operational experience through an equity investment in a commercial gasification plant. This provides the company valuable operational insights, and a vested interest, in achieving ever-higher operational reliability and performance standards.

Shell began gasification research in the 1950s and built coal gasification demonstration plants in the 1970s and 1980s in the Netherlands, Germany, and the U.S. Two technologies have emerged from this pioneering work: The Shell Gasification Process (SGP) converts refinery residues to syngas and the SCGP uses solid feeds, including petroleum coke (petcoke), anthracite, bituminous coal, lignite (brown coal), and biomass, to produce syngas. There are two SCGP-related lineups for users with different needs.

Proven High-Efficiency Technology

SCGP syngas cooler technology (Figure 1) has been used commercially for more than 20 years. It can help achieve carbon conversion rates of over 99% and cold coal gas efficiency (the amount of energy in the coal converted to the energy in the combustible syngas) of 80–83%. A syngas cooler recovers most of the sensible heat in the syngas to produce high- or medium-pressure steam, which can reduce the operating costs within a facility.

Figure 1. SCGP syngas cooler technology

Figure 1. SCGP syngas cooler technology

An entrained-flow process uses an inert carrier gas to transport dry coal feedstock to the gasifier, where it contacts oxygen and steam. The gasifier has unique features, such as specially designed multiple burners and a membrane wall of high-pressure tubes designed to enable the safe and low-maintenance separation of syngas and slag.

The molten slag flows down into a water bath from where it can be extracted as a solid, thereby reducing wastewater pollution. Dry-filtered and wet-washed syngas quenches the syngas to about 900°C before it leaves the top of the gasifier. The syngas is cooled further in an external cooler to generate high- and medium-pressure steam as valuable by-products. The use of multiple burners provides the potential for easy scaling up and, more importantly, efficient slag removal with only a small amount of a fine fly ash, which is removed downstream to less than 1 ppmv.

In China alone, 23 SCGP gasifiers have come onstream since 2006 and six more are due to start up in the near future. Of these 23 gasifiers, 17 have dry pulverized coal intake capacities of over 2000 t/d. SCGP units are also running or planned in South Korea and Vietnam.

Proven Low-Capital-Costs Technology

For operators that need to lower their capital expenditure and are looking for wider feedstock flexibility while retaining good efficiency levels, Shell has developed a bottom-quench technology (Figure 2). This simplified lineup can reduce capital costs by up to 30% while satisfying the country’s basic, and some advanced, efficiency and environmental requirements.

Figure 2. Bottom-quench technology

Figure 2. Bottom-quench technology

The bottom-quench lineup retains the membrane wall and burner technology of the first lineup but has proven water-quench technology to replace the syngas cooler. This means less steel, less equipment, and a shorter manufacturing time, which substantially reduces capital costs. SCGP bottom-quench technology also helps to eliminate fouling risks to offer wider coal suitability.

In 2013, Shell and Wison Engineering successfully started a 1000-t/d SCGP bottom-quench technology demonstration plant in the Nanjing industrial park, which had 99% carbon conversion. In January 2014, Hulunbeier Jinxin, a subsidiary of the Yuntianhua Group, signed a licensing agreement for a bottom-quench gasifier to process lignite feedstock.

A Broad Range of Applications


In China, SCGP gasifiers are delivering syngas for methanol, ammonia, and hydrogen production. For example, the Yueyang Sinopec and Shell Coal Gasification Co. Ltd. (Dongting) joint venture has been successfully supplying syngas and steam to the associated Baling fertilizer plant since 2006. This has given Shell eight years of first-hand, local operational experience. The facility processes 2000 tonnes of pulverized coal a day and produces syngas for urea/fertilizer and caprolactam (nylon) manufacture.

In 2012, the first of two plants in Vietnam operated by Vietnam National Chemical Group began commercial operations.

Gasification unit under construction at South Korean IGCC power plant (photo courtesy of Korea Western Power Co. Ltd)

Gasification unit under construction at South Korean IGCC power plant (photo courtesy of Korea Western Power Co. Ltd)

Coal for IGCC Power

SCGP licenses for IGCC plants have been sold in Europe and Asia. Importantly for a power plant, the SCGP unit gives operational flexibility with the ability to follow load changes quickly.

In the Netherlands, the 2000 t/d Willem-Alexander (formerly Nuon) power plant operated from 1993–2013. Commissioned as a demonstration plant, it has proven SCGP technology’s reliability and low maintenance costs, which result from the robustness of the gasifier membrane wall and the long-life burners. The IGCC plant also demonstrated feedstock flexibility by processing more than 20 different coal types and blends, and running successfully with up to 30 wt% biomass.

South Korea is building its first IGCC plant, Taean IGCC No. 1. Here, Korea Western Power Co. Ltd will be using SCGP and gas-treating technologies for efficient generation of clean power for the country. SCGP technology was chosen for its good economic value, and high reliability and efficiency. Knowledge transfer and training were also key factors in the selection decision.

The 300-MW (net) IGCC plant aims to have a design target of over 42% efficiency (net).

The plant, which will process 2670 t/d bituminous and sub-bituminous coal, is designed to have emissions of less than 30-ppm nitrogen oxides and 15-ppm sulfur oxides. It also opens the possibility of carbon capture and storage for reduced greenhouse gas emissions through a readily available stream of concentrated high-pressure carbon dioxide.


In China, Shanxi Lu’an Coal Mine Group is constructing a coal-to-liquids plant with four SCGP gasifiers that will each have a 3200-t/d dry coal intake capacity.

Reaching New Performance Standards

Since its introduction in the early 1970s, SCGP syngas cooler technology has been continuously improved to enhance performance, extend equipment life, and widen the range of usable feedstocks.

Efficiency and Environment

SCGP syngas cooler technology is efficient and has a low environmental footprint. For example, independent assessments have shown that SCGP gasifiers have the highest exergetic efficiency of all coal gasification technologies.1 Typical ranges for oxygen and coal consumption are also low: 310–350 Nm3 oxygen per kNm3 syngas and 510–615 kg standard coal per kNm3 syngas, respectively. Indeed, SCGP gasifiers exceed China’s National Development and Reform Commission’s (NDRC) basic requirements for energy, coal, and water consumption, and meet many of its advanced requirements (Figure 3). Note that the requirements are for overall projects and therefore a plant’s performance depends partly on the downstream process employed.

Figure 3. SCGP syngas cooler technology performance compared with NDRC requirements (Shell analysis)

Figure 3. SCGP syngas cooler technology performance compared with NDRC requirements (Shell analysis)

Feed Flexibility, Selection, and Management

A wide variety of coal has been processed across the world, including feeds with 6–36% ash, up to 35% moisture content, and ash-melting points (fluid temperatures) from 1140°C to well over 1500°C. Low-quality coal types, including lignite, have been successfully gasified in commercial operations. Several SCGP technology users, including four in China, have implemented an effective strategy of blending high-ash coal with petcoke to promote stable gasification operations and high syngas output. These plants have shown the longest continuous runs and greatest uptime of all the SCGP plants. The ability to gasify low-quality coal with petcoke is likely to become increasingly advantageous as more coal-to-chemical facilities come online and coal quality generally deteriorates as high-grade reserves become exhausted.

Gasifying petcoke may be an attractive power-generation option in the Middle East, where petcoke could be a widely available, low-cost feed. Some recycled ash/slag or a locally sourced fresh ash would need to be added, as the SCGP design principle requires sufficient ash in the feed to form a protection layer in the gasifier.

Shell is capturing the extensive and growing knowledge of the behavior of different coal types in the SCGP in a database and has established a basic theory about the effects of coal quality on gasification, which it has verified using the experience database. The result is a powerful and practical modeling tool that is helping users to select and evaluate coal types without conducting expensive trial runs and to make day-to-day production decisions.

Continuous Improvement

Substantial value can be captured early in coal gasification investments through good project definition and smart configuration (developing the best plan). A project’s value can be enhanced further by correct project execution and continuous improvement (optimizing the completed facilities).

Shell gives SCGP users intensive operational training and dedicated support for start-up and early runs. In addition, they help users to establish a plant management system to improve reliability, manage risk, and plan equipment maintenance. This structured process ensures that users learn about the plant and become familiar with it as quickly as possible, thereby increasing equipment reliability and establishing a solid foundation for high-load operation over extended cycles of use.

Shell also recognizes the importance of creating opportunities to learn from operational experiences in the pursuit of continuous improvement. To this end, all technical information relating to improvements is collected and used to build a database of lessons learned, to the benefit of its licensees. Shell has also facilitated eight global coal gasification technology users’ conferences in the past six years. These forums, hosted at different operating sites, provide a platform for licensees to discuss and improve their operations.

In addition, lead users strongly committed to improving the operation and design of this technology are working together on a reliability board to discuss specific experiences and capture the means for achieving good performance. The reliability board meets more frequently than the larger user conference to work on particular issues and implement the lessons learned.

Thus, the experience of solving problems and improving plant performance has become part of the process of continuous improvement. Any issues identified are fed to a team of people at Shell who develop solutions. This team includes process, mechanical, and control engineers. Using their understanding of the technology and their ability to communicate effectively and rapidly with clients, they can help to resolve the issues and, most importantly, feed improvements back to the master design to benefit future customers.

The benefits of this feedback process range from minor improvements and changes in the type of valve used to major developments such as dealing with blockage of the inlet of the syngas cooler or candle filter breakages. Some solutions apply to a range of situations, others just to a single plant. The change process is strictly managed; this combination of actions has resulted in positive feedback from clients.

Effect on Reliability

SCGP users are employing a structured improvement process to achieve high levels of reliability. In China, for example, users typically accumulate more than 300 days per year of normal operation. One chemical plant has achieved over 328 running days in each of the last five years, with a highest yearly total of 341 days (Figure 4). It is important to note that SCGP lineups do not require spare gasifiers, although multiple units are used for large-capacity projects. Some alternative lineups claim higher reliability levels, but use spare gasifiers, which add significantly to a project’s capital costs.

Figure 4. Cumulative running days for a Chinese coal-to-chemicals plant employing SCGP technology

Figure 4. Cumulative running days for a Chinese coal-to-chemicals plant employing SCGP technology

Burner lifetimes typically exceed 8000 hours, and the filter candles typically have lifetimes of two to three years.

To ensure that each SCGP lineup offers improved reliability and performance, Shell captures lessons learned from all the technology users in a database and applies them to improving the master design.

Ever-Increasing Performance

SCGP technology is proven to offer high-efficiency coal gasification, excellent environmental performance, and good feedstock flexibility. It has been applied worldwide to a broad range of successful chemical and IGCC applications, and a coal-to-liquids plant under construction. Due to the structured learning procedure and a culture of continuous improvement culture adopted by users worldwide, SCGP technology operates with ever-increasing levels of reliability and performance.



  1. Gräbner, M., & Meyer, B. (2014). Performance and exergy analysis of the current developments in coal gasification technology. Fuel, 116, 910–920.


The authors can be reached at Rob.Vandenberg@shell.com, Zhongxin.Z.Chen@shell.com, and Sze-Hong.Chua@shell.com


The content in Cornerstone does not necessarily reflect the views of the World Coal Association or its members.

Improving the Case for Gasification

By Harry Morehead
Director, Gasification and IGCC Sales and Marketing, Siemens Energy, Inc.
Juergen Battke
Manager, Business Development, Siemens Fuel Gasification Technology GmbH & Co. KG

Gasification is a technology with a long and checkered history. It was widely used to produce “town gas” for lighting and cooking in the 1800s before it was replaced by electricity and natural gas. Yet its commercial deployment for industrial applications and power generation has been limited, despite several attempts to kick-start the industry.

Historically, interest in coal gasification has tended to peak when access to other fossil fuels was limited or their prices were high. For example, gasification received a great deal of attention in the 1970s during the oil crisis, and at various periods in recent years as a response to high natural gas prices.

Shenhua Ningxia Coal Group’s coal-to-polypropylene project, Ningxia Provence, PRC

Shenhua Ningxia Coal Group’s coal-to-polypropylene project, Ningxia Provence, PRC

A major factor behind gasification’s stuttering commercialization has been the upfront cost. Coal gasification plants typically require capital investments of hundreds of millions of dollars, and in some cases billions. With the effects of the recent global financial crisis still being felt, bringing down the capital cost is essential if coal gasification is ever to truly take off.

Companies such as Siemens have been able to make progress through technology advances as well as a growing number of references, which in itself will reduce costs and build confidence in the feasibility of the technology.

The development of the Siemens gasification process—a pulverized fuel, pressurized, entrained-flow gasification technology—was begun in 1975 by Deutsches Brennstoffinstitut Freiberg/Sa. (DBI, German Fuel Research Institute). The main objective was to create a conversion technology that would allow the use of locally abundant lower-rank coals, including lignite, to partially replace the demand for crude oil and natural gas. Many countries are now taking advantage of their local energy resources and converting those resources into low-carbon electricity, chemical feedstocks, and clean transportation fuels. Heading into China’s 13th Five-Year Plan, the China National Coal Association recommends to “shift from viewing coal as a fuel to considering it a raw material to produce a wide array of products. Based on the initial results of coal conversion demonstration projects in China, such as coal-to-liquids, coal-to-olefins, and coal-to gas, China’s coal industry should accelerate the construction of large-scale, clean, and efficient coal-conversion projects, which could effectively replace some oil and gas.”1

The government of the former German Democratic Republic intended to build several gasification plants around central Germany to supply major chemical companies through long-distance pipelines with syngas produced from coal. Due to the low rank of this lignite and its high salt content, the gasification process developed had to address special requirements for the feeding system and the gasifier itself. The first test facility, built in 1979 with a thermal capacity of 3 MW, was used to examine the technical concept and to test the targeted saliferous lignite for the construction of a large-scale demonstration facility in 1984 at the Gaskombinat Schwarze Pumpe site. Between 1994 and 1998 further test facilities were erected at a Siemens site in Freiberg, among them a 5-MWth cooling screen reactor. Up to now these facilities have been used to gasify more than 90 candidate gasification feedstocks—including different ranks of coal, municipal- or industrial-provenance sewage sludge, petroleum coke, waste oils, bio-oils, bio-slurries, and several liquid residues—in order to investigate their gasification behavior and to analyze the quality and characteristics of the gasification products.

Through this systematic research and development, the range of application of the Siemens Fuel Gasification (SFG®) technology was extended from conventional fuels, such as coals and oils, to also include residual and waste materials and biomass. Over the years since its privatization in 1991, the technology has been owned by several companies. Since its purchase by Siemens in 2006, the Siemens gasification group has been organized under Siemens Fuel Gasification Technology (SFGT) GmbH & Co. KG and has extended its footprint to China, South Korea, and the Americas.


Essentially there are several basic gasifier designs, differentiated by whether they use pure oxygen or air, wet or dry coal feed, the reactor’s flow direction, and the syngas cooling process. Oxygen-blown and entrained-flow gasifiers, such as those designed by Siemens (see Figure 1), are likely to be the most popular going forward.

Figure 1. Siemens SFG® gasification island with dry feeding system; oxygen-blown, entrained-flow gasifier; full water quench

Figure 1. Siemens SFG® gasification island with dry feeding system; oxygen-blown, entrained-flow gasifier; full water quench

Oxygen-blown gasifiers have the advantage of being a compact, cost-effective design and they produce a very clean syngas that can be directly processed after dust removal. These gasifiers operate under high pressure in the range of 40–46 bar, which allows a high syngas output per single gasifier, resulting in fewer trains and subsequently lower CAPEX per ton of final product.

Entrained-flow gasifiers operate at temperatures higher than the ash-melting temperature. Typical operation temperatures are in the 1300–1800°C range. At these high temperatures, the gasifier produces only the components hydrogen, carbon monoxide, and carbon dioxide—no hydrocarbons such as phenols or tar, as is the case for fixed-bed gasifiers. The fuel flexibility ranges from biomass, petroleum coke, oils, tar, and liquid chemical residues to all kinds of coals such as lignite, sub-bituminous and bituminous coal, or even anthracite. For most feedstock, the carbon conversion rate is in the range of 96–99.5%.

Today, gasification processes around the world must limit the production of gas, solid, and liquid wastes. Siemens believes the oxygen-blown, entrained-flow gasifiers represent the environmentally best available technology due to a lack of waste production. There are no gaseous emissions. Solids emissions are in the form of vitrified slag, which is inorganic and nonleaching, and can be sold as construction material. Solids entrained in the gas, process fines, are extracted as filter cake. Liquid-phase waste is becoming an increasingly important issue for gasification plants because water consumption must be reduced; almost certainly, zero liquid discharge systems will be a future requirement in many parts of the world. A quench system can be supplied with a variety of process waters, such as gas condensates from the CO shift or condensate from a methanation unit. The combination of an entrained-flow gasifier and a dry-feed system has the lowest freshwater consumption of all available industrial-scale gasification technologies, typically in the range of 0.35–0.45 ton freshwater/ton coal despite having a full water quench, which is usually fed by recirculating the gas condensate. Eventually, water is discharged from the quench system to limit the salt concentration based on the material and fouling constraints. The typical entrained flow gasifier blow-down rate is lower than other industrial-scope gasification technologies, in the range of 0.1–0.15 ton water/ton coal.

The performance of such entrained-flow gasifiers has already surpassed the older fixed-bed gasifiers, such as those used in the past in South Africa.

Siemens Developments

Prior to 2007-08, the number of Siemens gasification references was very limited and some had been built 30–40 years ago or were no longer in operation. Today, however, there are seven projects operating, in construction or under development with Siemens gasifiers, mostly in China where there are extensive coal reserves. Siemens’ current focus is on “design-to-cost” for the gasification island, taking into account the associated subsystems, in order to simplify the entire process and thus reduce costs.

Generally, larger gasifiers are more efficient and require less pipework and other components. Work has therefore centered on developing a gasifier that offers the optimum size in terms of efficiency and cost.

Much of the SFG development work has been carried out at the Siemens Fuel Gasification Test Center in Freiberg, Germany, which is one of the most comprehensive gasification test facilities in the world (see Figure 2). The centerpiece of the test center is a 5-MWth gasification reactor equipped with Siemens’ innovative cooling screen design. This design allows the reactor to gasify a broad range of coals with ash contents up to 30–35% and high ash-melting temperatures. This reduces start-up and shutdown times at the commercial scale from two to three days (compared to refractory-lined gasifiers) to approximately two hours. The cooling screen has a lifetime of at least 10 years and eliminates the need for the annual or bi-annual shutdowns customary with refractory-lined reactors, resulting in a significantly higher availability.

Figure 2. Siemens Fuel Gasification Test Center, 5-MWth gasifier

Figure 2. Siemens Fuel Gasification Test Center, 5-MWth gasifier

This Siemens-owned test center has been instrumental in developing and testing the SFG-200 and later the larger SFG-500 (2000 t/day coal capacity). Six of these units are now successfully operating at plants around the world.

As part of the continuing effort to reduce costs, Siemens has now developed the SFG-850 gasifier, introduced to the market at the end of March 2014 (see Figure 3). The reactor with this system is sized for larger gasification plants producing chemical feedstocks, synthetic natural gas, or clean transportation fuels, as well as IGCC applications using the most advanced gas turbines.

Figure 3. Siemens’ new SFG-850 gasifier

Figure 3. Siemens’ new SFG-850 gasifier

The SFG-850 is designed to enhance the profitability of future gasification plants by reducing specific plant costs, along with the associated production costs of synthesis gas. An SFG-850 gasifier can convert around 3000 t/day of coal into more than five million standard cubic meters (Nm3) of high-quality synthesis gas.

The SFG-850 gasifier is based on the same technical design as the SFG-200 and SFG-500; however, the proven central burner design and dry coal feed system have now been optimized further in the SFG-850. As with its predecessors, the new gasifier has a high degree of fuel flexibility. All of the proven advantages of Siemens gasifier technology, including its short start-up and shutdown times and the tried-and-tested serviceability of its water-cooled design, contribute to its ability to maintain a high level of availability.

The SFG-850, however, is bigger than its predecessor: Its outer diameter is 0.5 m larger than the SFG-500. Although not a huge increase, this offers a 33% increase in coal throughput capacity. With a length of 22 m, an outer diameter of 4.8 m, and weighing 380 tonnes, the SFG-850 gasifier is one the world’s largest. The new model can be completely fabricated and tested at the factory. Despite its size and weight, the unit can be transported to its installation location in one piece, eliminating the time and expense of field fabrication.

Gasification Has a Bright Future Based on Today’s Hard Work

As noted before, the cost of gasification-based plants is the major challenge for the gasification industry. Companies across the industry are working to reduce the cost of gasification and all of the upstream and downstream processes that will allow gasification plants to operate economically. At Siemens, we believe that the introduction of the SFG-850 makes a significant step forward in reducing the cost of the gasification island. In addition to the economy of scale compared to a standard Siemens SGF-500 reference plant in China, Siemens has achieved further reduction in capital investment cost by optimizing the selection of equipment, valves, and instruments—incorporating lessons learned from today’s operating plants to select better construction materials and developing a more compact gasification island layout.

Beyond the gasification island, Siemens is partnering with industry leaders in coal milling and drying and CO shift catalysts; improvements in these areas will further increase the efficiency of tomorrow’s gasification plants. For example, Clariant, a world leader in specialty chemicals, and Siemens have introduced a new jointly developed sour gas CO shift technology specifically designed for coal gasification. This advanced “low steam” shift technology with Clariant’s ShiftMax® 821 catalyst reduces capital expenditure for the shift unit by up to 20% and optimizes operating costs with up to 30% lower catalyst volume and significantly less steam consumption. This will make gasification plants more economically appealing and, hence, more competitive than what is currently offered.

Ongoing cost reductions will enable greater use of gasification, especially in the industrial sector where countries worldwide are looking to leverage their domestic, low-cost energy resources, such as coal, to produce high-value products including low-carbon power, chemical feedstocks, and clean transportation fuels. The ability to use low-rank coals will make the gasifier particularly attractive to markets such as Indonesia, which currently has no real use for such coal. Gasification would unlock this resource. The same is also true for countries such as Australia, Mongolia, Vietnam, and even Thailand where gasification projects are being considered. There could even be possibilities in the U.S. as natural gas prices rise.

Gasification may also be used as a strategic tool in some countries to reduce dependence on imported fossil fuels. Turkey, which has coal but is heavily dependent on gas imports, is one such country. Ukraine is another prime example; the recent conflict with Russia highlights why gasification might be an attractive option to the purchase of Russian natural gas. As gasification technologies continue to demonstrate better performance, better reliability, and lower costs, more countries will be able to economically justify the use of this innovative clean energy conversion technology to produce the power, chemical feedstocks, and clean transportation fuels they need.



  1. Wang, X. Z. (2014). Advancing China’s coal industry. Cornerstone, 2(1), 15–18.


The authors can be reached at harry.morehead@siemens.com and juergen.battke@siemens.com.


The content in Cornerstone does not necessarily reflect the views of the World Coal Association or its members.

Gasification Can Help Meet the World’s Growing Demand for Cleaner Energy and Products

By Alison Kerester
Executive Diraector
Gasification Technologies Council

Energy is fundamental to economic growth. Economies cannot grow and people cannot raise their standard of living without adequate supplies of affordable energy. The global demand for energy is projected to rise by 56% between 2010 and 2040, with the greatest increase in the developing world.1 This growing energy demand is a direct result of improving individual prosperity, national economies, and infrastructure, and thus living conditions. With this demand in energy also comes a demand for products to support development.

“Increased flexibility, vastly increased scale, and new applications are driving gasification technologies to gain greater prominence  than ever before.”

“Increased flexibility, vastly increased scale, and new applications are driving gasification technologies to gain greater prominence than ever before.”

Gasification, which can provide cleaner energy and products, is not new. Its origin dates back to the late 1700s when an early form of gasification was used in the UK to create “town gas” from local coal reserves. More modern gasification technologies began to evolve prior to and during World War II as Germany needed to create its own transportation fuels after being cut off from oil supplies. Later, Sasol in South Africa made the first strides in transitioning toward large-scale production of commercial, economically competitive gasification-derived products and was instrumental in developing the foundations of the modern gasification industry.

Today’s advanced gasification technologies incorporate significant improvements over those early versions; increased flexibility, vastly increased scale, and new applications are driving gasification technologies to gain greater prominence than ever before. The wide deployment of gasification technologies can be largely attributed to socioeconomic, energy security, and environmental issues. In addition, there is more variation in gasification technologies, with some developers focused on reducing costs through integration while others focus on smaller, modular gasifiers. Greater deployment of gasification still faces challenges, but the recent upswing, especially in China, clearly demonstrates the advantages of this technology for utilizing domestic energy sources to produce commercial products.

Gasification Basics

Gasification is a thermochemical process that converts carbon-based materials—including coal, petroleum coke, refinery residuals, biomass, municipal solid waste, and blends of these feedstocks—into simple molecules, primarily carbon monoxide and hydrogen (i.e., CO + H2) called “synthesis gas” or “syngas”. It’s quite different from combustion, where large amounts of air are blown in so that the material actually burns, forming carbon dioxide (CO2). There are several basic gasifier designs and a wide array of operating conditions. The core of the gasification process is the gasifier, a vessel in which the feedstock(s) reacts with air or oxygen at high temperatures. The CO:H2 ratio depends, in part, on the hydrogen and carbon content of the feedstock and the type of gasifier. This ratio can be adjusted or “shifted” downstream of the gasifier through the use of catalysts.

A key advantage of gasification systems is that they can be designed to have a reduced environmental footprint compared to combustion technologies. For instance, over 95% of the mercury present in the feedstock can be captured using commercial activated carbon beds. Capturing nearly all the feedstock sulfur is necessary because downstream catalysts are generally intolerant of sulfur. This sulfur can be collected in its elemental form or as sulfuric acid, both of which are saleable products. Slag created from the ash, unreacted carbon, and metals in the feedstock are also captured directly from the gasifier, requiring less equipment than what would be required for post-combustion removal of those same materials in the flue gas of combustion-based systems.

Slag captured from the gasification process (photo provided by Westinghouse Plasma Corp., a division of Alter NRG)

Slag captured from the gasification process (photo provided by Westinghouse Plasma Corp., a division of Alter NRG)

CO2 emissions can also be captured from the syngas in gasification plants. Greater than 90% of the carbon in the syngas stream can be captured as CO2 and processed for utilization and/or storage. Some studies have shown that transportation fuels can be produced with near-zero carbon footprints using gasification of coal and biomass with CO2 capture and storage.2

Gasification typically takes place in an above-ground gasification plant; however, the gasification reaction can also take place below ground in coal seams. With underground coal gasification (UCG), the actual gasification process takes place underground, generally below 1200 feet below the surface in coal seams that are considered not economically mineable. Recent advances in well-drilling technologies are now enabling UCG development of coal seams in the 4000–6000-ft depth range, with increased environmental protection and process efficiency benefits at these depths. The underground setting provides both the feedstock source (the coal) as well as pressure comparable to that of an above-ground gasifier. With most UCG facilities, wells are drilled on two opposite sides of an underground coal seam. One well is used to inject air or oxygen (and sometimes steam) and the other is used to collect the syngas that is produced. The ash and other contaminants are left behind. A pair of wells can last as long as 15 years. Under its New Energy Policies scenario, the International Energy Agency has estimated that emerging economies will account for over 90% of the projected increase in global energy demand.3 UCG could play a unique role in helping meet this rising energy demand by utilizing deep coal seams that would otherwise be unobtainable economically.

Additional information on the technical fundamentals behind gasification is provided at the end of this article.

Today’s Gasification Market

Key Benefits

Finding a path to energy security is a chief concern of nearly every sovereign nation. In the past, fast changing markets have rocked economies that were overly dependent on a single fuel source, such as the oil shocks experienced by the U.S. in the 1970s. Today, perhaps the clearest example is the fact that even as European countries pass sanctions against Russia, they are still highly dependent on Russian natural gas. This dependence could be reduced, or even eliminated, through the use of gasification.

Even within borders, diversification of energy sources is crucial. Although the U.S. has access to inexpensive and seemingly abundant natural gas, the extreme cold resulting from the polar vortex in the winter of 2014 saw rapid spikes in natural gas prices. Around the world, oil and natural gas prices continue to fluctuate dramatically. In addition to avoiding price uncertainty, many nations have a strong strategic desire to use their indigenous energy resources to produce the energy and products needed for economic growth. Gasification facilities can be designed to use the carbon-based feedstock that is most appropriate for a given region.

Environmental concerns are also receiving increased attention globally. For reasons explained previously, gasification can offer environmental benefits in terms of reduction of a wide range of emissions. In addition, CO2 emissions can be significantly reduced if carbon capture, utilization, and/or storage are employed. Although environmental concerns may not be the principal driver for the deployment of gasification today, the advantages are undeniable. For instance, gasification can be employed to create low-sulfur transportation fuels, thus reducing one of the major contributors to urban air pollution.

Modern gasification technologies are extremely diverse in their feedstocks, operational configuration, and products. Gasification converts virtually any carbon-containing feedstock into syngas, which can be used to produce electricity and/or other valuable products, such as fertilizers, transportation fuels, substitute natural gas, chemicals, and hydrogen (see Figure 1 for examples of products from gasification). Polygeneration facilities can produce multiple products, one of which can be electricity, from the same initial stream of syngas; the integration of the different components of polygeneration plants can also increase efficiency and provide an overall reduction in the environmental footprint.

Figure 1. Gasification can yield a tremendous variety of products; the examples shown include only the most common (figure courtesy of Eastman Chemical Company).

Figure 1. Gasification can yield a tremendous variety of products; the examples shown include only the most common (figure courtesy of Eastman Chemical Company).

Gasification processes can be designed to operate using coal, petroleum, petroleum coke, natural gas, biomass, wastes, and blends of these feedstocks; this diversity is the fundamental reason that gasification can be used to address energy security concerns. Coal is by far the most common source of the carbon feedstock for gasification today—a fact that is likely to remain true into the foreseeable future as countries look for a way to utilize their vast coal reserves. China has clearly seized on this fact and is now leading the way on building new gasification projects.

Market Drivers

Gasification is not a stagnant technology, nor is it a one-size-fits-all technology. Its use is growing globally and the regional growth is far from uniform. Generally, industrial gasification facilities are becoming larger by increasing the number of gasifiers as well as the gasifier size. The economies of scale, and sharing key equipment such as the air separation unit among multiple gasifiers, are bringing down the cost of the final products. However, these large facilities also come with a billion-dollar-plus price tag, so even though the end products may be competitive, in some instances the upfront costs are prohibitive. In such cases there are other options; project developers can turn to smaller, more nimble gasification facilities that are also able to produce power and products. These smaller projects could bring reliable power to a mini-grid. For instance, SES’ fluidized bed gasifier can be used to gasify a wide range of feedstocks without changing the gasifier design, making it a contender for distributed power generation.

Today’s gasification technologies are able to meet market needs throughout the world. To track projects, the Gasification Technologies Council maintains the Worldwide Gasification Database.4 This database is being updated annually, with the next update due in late 2014. The database lists 747 projects, consisting of 1741 gasifiers (excluding spares). Of the 747 facilities, 234 of them, with 618 gasifiers, are active commercially operating projects. As of August 2013, 61 new facilities with 202 gasifiers were under construction with an additional 98 facilities incorporating 550 gasifiers in the planning phase.5 The cumulative global gasification capacity projected through 2018 is shown in Figure 2.

Figure 2. Cumulative worldwide gasification capacity and projected growth

Figure 2. Cumulative worldwide gasification capacity and projected growth4

Preferred Products

Chemical production is the most common application of gasification worldwide (see Figure 3). Synthetic fuels (both liquid and gaseous) are also becoming increasingly important. The second most common application is liquid fuels, although there is also a large amount of planned production of gaseous fuels. About 25% of the world’s ammonia and over 30% of the world’s methanol is produced through gasification.5


Figure 3. Gasification by application

Figure 3. Gasification by application4

In contrast, gasification for power has declined sharply, with many of the planned projects in the U.S. no longer proceeding.6 The emergence of abundant and cheap natural gas has been a game changer, making coal gasification less economically competitive in North America. In addition, environmental regulations in the U.S. have resulted in few new coal-based gasification projects being planned. Those projects that are proceeding have been reconfigured to capture CO2 and/or to produce multiple product streams—generally, power generation and/or urea for fertilizer production, and CO2 for enhanced oil recovery, such as is the case with the Texas Clean Energy Project. In the U.S. today, a primary interest is in waste gasification, as cities and towns seek to reduce the cost of disposing of municipal solid waste, reduce the environmental impacts of landfilling, and recover the energy contained in the waste. Although North America has generally turned away from new IGCC projects, IGCC projects are moving forward elsewhere; China’s 265-MW GreenGen project and the massive (2.6 GW available for export) Saudi Aramco Jazan refinery project are prominent examples.

Regional markets dictate which products will be most favorable in specific areas. Figure 4 provides an overview of regional market drivers and the products with the most potential to be economically desirable in the near term. Common traits mostly shared throughout India, China, and most of Southeast Asia are high natural gas prices and vast reserves of low-rank coal, which create a strong market for coal-derived substitute natural gas (SNG) facilities.

Figure 4. Gasification market drivers and products by region (figure courtesy of GE)

Figure 4. Gasification market drivers and products by region (figure courtesy of GE)

Although Figure 4 is based on the common belief that in the EU the potential for the expansion of gasification is limited, it actually could play a major role in reducing the reliance on imported natural gas.

Unquestionably, Asia is experiencing the strongest growth in coal and petroleum coke gasification (see Figure 5), with China leading the way. There are now a number of Chinese gasification technology companies that did not exist a decade ago. The high price of natural gas and LNG, coupled with LNG import restrictions in some countries in Asia (primarily China, India, Mongolia, and South Korea), are prompting those countries to utilize their domestic coal and petroleum coke to produce the chemicals, fertilizers, fuels, and power needed for their economies.

Figure 5. Gasification capacity by geographic region

Figure 5. Gasification capacity by geographic region4

Coal Is the Dominant Feedstock

Coal is the primary feedstock for gasification and will continue to be the dominant feedstock for the foreseeable future (see Figure 6). The current growth of coal as a gasification feedstock is largely a result of new Chinese coal-to-chemicals plants.

Figure 6. Gasification capacity based on primary feedstock

Figure 6. Gasification capacity based on primary feedstock4

Although there are many options for the feedstocks for gasification, coal is far and away the choice most often employed, for several reasons. Of course, energy security plays a role considering that coal is distributed globally. In addition, the price fluctuations in natural gas and LNG are another major concern. Figure 7 shows the price, in US$/MMBtu, of several fuel sources, including global oil, natural gas at two sites, and fuel oil, coal, and LNG in Asia over the decade from 2003 to 2013.

Figure 7. Recent prices for gasification fuel options (figure courtesy of GE)

Figure 7. Recent prices for gasification fuel options (figure courtesy of GE)

Fuel price volatility has affected industrial production of chemicals and other products for many decades. In the 1980s, volatile natural gas prices prompted Eastman Chemical Company to switch from natural gas to coal as a feedstock at their Kingsport, Tennessee, chemicals plant. Today, gasification project developers in Asia and elsewhere find themselves facing feedstock choices and fuel pricing options that can dictate project economics. Considering prices in Asia specifically (where most new large-scale gasification is taking place), oil, coal, natural gas, and LNG prices must be compared when considering new projects. In Asia, coal is by far the least expensive option. In addition, the price fluctuations for coal are relatively small compared to those observed in other fuel options.

Increasingly Larger Scale Plants

With a few exceptions, coal and petroleum coke gasification plants are becoming larger in scale to produce enough product(s) to meet market demand as well as to drive down the product price. Although the sizes of the gasifiers are not increasing substantially, the number of gasifiers per project is increasing. The increasing size of projects is resulting in the scale-up of the supporting equipment, such as the air separation units. Large gasification projects currently under construction or operating include:

  • Reliance Jamnagar Refinery (India): The world’s largest refinery and petrochemical complex will be gasifying petroleum coke and coal for the production of power, hydrogen, SNG, and chemicals. The project will have over 12 gasifiers and is currently under construction. The first gasification train is expected to be completed by mid-2015 and the overall project by early 2016.
  • Saudi Aramco Jazen Refinery (Saudi Arabia): This will be the world’s largest gasification-based IGCC power facility to convert vacuum residues to electricity for use both in the refinery and for export. This project is now selecting vendors and is expected to be completed in 2017.
  • Shell’s Pearl Facility (Qatar): The world’s largest natural gas-to-liquids facility using Shell’s gasification technology is now operational.
  • Tees Valley (England): The world’s largest advanced plasma gasifiers are being installed in the Tees Valley to gasify municipal solid waste, construction and demolition debris, and coal to produce power for an estimated 100,000 homes. This project is due to start up in 2016.

Remaining Challenges

Although the momentum behind the application of gasification has increased, a number of challenges remain to increasing deployment. One of the most important is a lack of regulatory certainty in some developing countries. For instance, some gasification projects in India are having trouble gaining a foothold amid concerns about feedstock availability and timely project approvals. Restrictions also are being created by some governments demanding that all technologies be domestically derived, slowing the advancement of deployment in the near term.

The upfront costs associated with large-scale gasification projects remain a hurdle today. Although alternatives to the capital-intensive projects exist, they are unlikely to become a suitable replacement for large gasification projects that offer a lower-cost end product and produce the large quantities of products necessary to meet market demand, such as the chemicals and fertilizer sectors. Bringing down capital costs or finding ways to obtain the required investment will remain a challenge.

Although the capital costs for gasification projects receive more attention, the industry is also working to find ways to reduce operating costs, often through efficiency improvements. For instance, the ability to remove contaminants from hot or warm syngas instead of first cooling the gas (for use with today’s commercially available processes) has the potential to yield significant energy savings. One promising project is RTI International’s warm syngas cleanup project.6 Research is also being undertaken on the development of sulfur-tolerant catalysts, which would allow the sulfur in the syngas to be removed at a later stage in the process, which may be more cost effective.

UCG is a promising technology that today remains relatively undeveloped. There are still technical challenges to UCG that must be overcome, but the major hurdles are actually institutional and a lack of public understanding. Successful demonstration projects could deter misconceptions that UCG is unproven and damages the environment. Linc Energy’s new UCG project in Poland will help demonstrate the viability of UCG to the world.

A great deal of innovative work is underway on new gasification technologies. In addition to UCG, a number of nontraditional approaches to gasification are emerging. For instance, KBR’s new TRIG™ gasification technology, the Free Radical Gasification (FRG™) technology developed by Responsible Energy, and the lower emissions gasification technology developed by ClearStack Power, LLC are all examples of the innovative work currently being conducted that will yield tomorrow’s gasification systems.


The gasification market has evolved significantly over the last five years. Coal gasification, and particularly coal gasification for power generation, has declined significantly in the U.S., although there is a growing interest in waste-to-energy gasification in North America.

Coal-based gasification (and coal gasification for chemicals) is dominant in Asia and will likely continue to be so for the foreseeable future. There is a growing market for petcoke gasification in Asia as well, as Asian refineries strive to remain competitive in the Asian market. High natural gas and LNG prices in Asia, the growing demand for energy and products in the developing world, and the need for energy security will all continue to drive the demand for coal and petroleum coke gasification.

These new plants are moving the deployment of gasification forward in a way that may not have seemed possible just 10 years ago. The tremendous amount of RD&D occurring globally promises that tomorrow’s technologies will be more advanced, less expensive, and more flexible than those in the market today. New experience, technical advancements, and the potential to integrate gasification with CO2 capture, combined with greater needs for energy security, may mean the coming years will fully unlock the potential for gasification that we’ve known has existed for decades.



  1. U.S. Energy Information Administration. (2013, 25 July). International energy outlook 2013: World energy demand and economic outlook, www.eia.gov/forecasts/ieo/world.cfm
  2. Williams, R. (2013). Coal/biomass coprocessing strategy to enable a thriving coal industry in a carbon-constrained world. Cornerstone, 1(1), 51–59.
  3. International Energy Agency. (2013, 12 November). World energy outlook 2013, www.worldenergyoutlook.org/publications/weo-2013/
  4. Gasification Technologies Council. (2014). Database and library, www.gasification.org/page_1.asp?a=103 (accessed July 2014).
  5. Higman Consultancy, GmbH. (2013). State of the gasification industry—The updated Worldwide Gasification Database. Presented at the 2013 International Pittsburgh Coal Conference, 1619 September 2013, Beijing, China.
  6. Research Triangle International. (2014). Warm syngas-cleanup technology, www.rti.org/page.cfm?obj=278DDE67-5056-B100-31A62FC32B088667 (accessed July 2014).


The author can be reached at akerester@gasification.org


Gasification Fundamentals

Gasification is a thermal process that converts any carbon-based material, including coal, petroleum coke, refinery residuals, biomass, and municipal solid waste, into energy without burning it. The carbon-containing feedstock is reacted with either air or oxygen which breaks down the mixture into simple molecules, primarily carbon monoxide and hydrogen (CO+H2), called “synthesis gas” or “syngas”. The undesirable emissions from gasification can be much more easily captured because of the higher pressure and (often) concentration compared to conventional pulverized coal-fired power plants.


Gasifiers capture the energy value from coal, petroleum coke, refinery wastes, biomass, municipal solid waste, waste-water treatment biosolids, and/or blends of these materials. Examples of potential feedstocks that can be gasified and their phases include

  • Solids: All types of coal, petcoke, and biomass, such as wood waste, agricultural waste, household waste, and hazardous waste
  • Liquids: Liquid refinery residuals (including asphalts, bitumen, and oil sands residues) and liquid wastes from chemical plants and refineries
  • Gases: Natural gas or refinery/chemical off-gas

Gasifying Fluid

Gasifiers utilize either oxygen or air during gasification. Most gasifiers that run coal, petroleum coke, or refinery or chemical residuals use almost pure oxygen (95–99% purity). The oxygen is fed into the gasifier simultaneously with the feedstock, ensuring that the chemical reaction is contained in the gasifier vessel. Generally, gasifiers that employ oxygen are not cost effective at the smaller scales that characterize most waste gasification plants.


The core of the gasification process is the gasifier, a vessel where the feedstock(s) reacts with the gasification media at high temperatures. There are several basic gasifier designs, distinguished by the use of wet or dry feed, the use of air or oxygen, the reactor’s flow direction (up-flow, down-flow, or circulating), and the syngas cooling process. There are also gasifiers designed to handle specific types of coal (e.g., high-ash coal) or petcoke.

Prior to gasification, solid feedstock must be ground into small particles, while liquids and gases are fed directly. The amount of air or oxygen that is injected is closely controlled. The temperatures in a gasifier for coal or petcoke typically range from 1400° to 2800°F (760–1538°C). The temperature for municipal solid waste typically ranges from 1100° to 1800°F (593–982°C).

Currently, large-scale gasifiers are capable of processing up to 3000 tons of feedstock per day and converting 70–85% of the carbon in the feedstock to syngas.


Although syngas primarily consists of CO+H2, depending up on the specific gasification technology, smaller quantities of methane, carbon dioxide (CO2), hydrogen sulfide, and water vapor could also be present. The CO:H2 ratio depends, in part, on the hydrogen and carbon content of the feedstock and the type of gasifier. This ratio can be adjusted or “shifted” downstream of the gasifier through the use of catalysts. Ensuring the optimal ratio is necessary for each potential product. For example, refineries that produce transportation fuels require syngas that contains significantly greater H2 content. Conversely, a chemicals production plant uses syngas with roughly equal proportions of CO and H2. This inherent flex-ibility of the gasification process means that it can produce one or more products from the same process.

Some downstream processes require that the trace impurities be removed from the syngas. Trace minerals, particulates, sulfur, mercury, and unconverted carbon can be removed to very low levels using processes common to the chemical and refining industries.



Most solid and liquid feed gasifiers produce a glass-like byproduct called slag, composed primarily of sand, rock, and minerals contained in the gasifier feedstock. This slag is nonhazardous and can be used in roadbed construction, cement manufacturing, and in roofing materials.

Underground Coal Gasification

With underground coal gasification (UCG), the actual gasification process takes place underground, generally below 1200 feet in depth, although recent advances in well-drilling technologies now make UCG possible at much deeper conditions (i.e., 4000–6000-ft depth range).

The UCG reactions are managed by controlling the rate of oxygen or air that is injected into the coal seam through the injection well. The process is halted by stopping this injection. After the coal is converted to syngas in a particular location, the remaining cavity (which will contain the leftover ash or slag from the coal, as well as other rock material) may be flooded with saline water and the wells are capped. However, there is a growing interest in using these cavities to store CO2 that could be captured from the above-ground syngas processing or even nearby combustion facilities. Syngas from UCG can also be treated to remove trace contaminants; once CO2 storage is added, UCG offers another opportunity to achieve a coal-based, low-carbon source of energy and carbon-based products. Once a particular coal seam is exhausted (after up to 15 years), new wells are drilled to initiate the gasification reaction in a different section of the coal seam.

UCG operates at pressures below that of the natural coal seam pressure, thus ensuring that materials are not pushed out into the surrounding formations. This is in contrast to hydraulic fracturing operations in oil and gas production, where pressures significantly above natural formation pressure are used to force injectants into the formation.


As explained, gasification can be used to yield a number of carbon-containing products, including several simultaneous products at polyproduction facilities.

Gasification is a complex process with decades of development behind it. The future of gasification technologies promise to improve on the work that has already been done.

For more information on gasification, visit the Gasification Technologies Council website: www.gasification.org/

The content in Cornerstone does not necessarily reflect the views of the World Coal Association or its members.

The Global Need for Clean Coal Technologies and J-COAL’s Roadmap to Get There

By Uichiro Yoshimura
Former Director, Japan Coal Energy Center
Toshiro Matsuda
Director, Japan Coal Energy Center

Global coal use has rapidly expanded in recent decades—from 2.2 billion tonnes of oil equivalent (toe) in 1990 to 3.7 billion toe in 2011.1 Much of the increase in coal utilization was from the construction of new coal-fired power plants; global coal-based electricity generation increased from just over 4400 TWh in 1990 to approximately 9100 TWh in 2011. Under the International Energy Agency’s (IEA’s) New Policies Scenario, in 2035 there will be more than 12,300 TWh of global coal-based electricity, an increase by a factor of approximately 1.4.1 Coal’s role in globally supplying primary energy can be largely attributed to the fact that there are long-term, widely distributed coal reserves and the cost of coal-based energy is affordable. As a result of these factors, coal’s role in the global energy mix is not expected to change for the foreseeable future.

Coal’s energy-security-related advantages, such as the stability associated with long-term supplies, lack of price fluctuations, and reliability as a base electricity source, are especially important in Japan, where nearly all energy is imported; coal has historically provided approximately 20% of Japan’s primary energy. Taking into account the very low capacity factor of Japan’s nuclear power plants since the Great East Japan Earthquake in 2011 and also concerns about the desire to reduce CO2 emissions the Japanese government had been reviewing its national Basic Energy Plan, which was approved by the cabinet recently. Because coal use is projected to continue, reducing the associated environmental impacts is an important aspect of the plan.

Japan’s coal-fired power plants are some of the most efficient in the world. The steam turbine at J-Power’s ultra-supercritical Isogo plant is shown above.

Japan’s coal-fired power plants are some of the most efficient in the world. The steam turbine at J-Power’s ultra-supercritical Isogo plant is shown above.

Driven by our own energy challenges and the strong need to rely on all available energy options to ensure energy security, Japan must continue to aggressively support research, development, and deployment of clean coal technologies (CCTs), which are critical to addressing the environmental impacts associated with coal utilization. In addition, because coal will continue to be increasingly deployed around the world, there is a major opportunity for the CCTs developed in Japan to be deployed globally. The Japan Coal Energy Center (J-COAL) has examined the CCT needs for Japan and the world and has recently updated our CCT roadmap to facilitate the research, development, and deployment of such technologies.

Understanding the Need for Clean Coal Technologies

The need for CCTs is global and is largely driven by various regulations and the desire to reduce environmental impacts associated with coal-based power production and coal utilization. The needs are not universal; in emerging economies there may be an opportunity to employ CCTs to newly built plants. However, in developed countries, where electricity growth is slow, and for the existing fleet of plants in emerging economies, technologies that can be retrofit will be necessary to meet various national and international goals and regulations.

Reducing Criteria Emissions

Globally, regulations are being proposed and deployed to reduce criteria emissions, such as SOx, NOx, particulate matter, and mercury. Advanced technologies for the capture of such criteria emissions are widely employed at Japanese coal-fired power plants, and emissions in Japan are some of the lowest in the world.

Taking mercury as an example, in Japan the emissions standards for mercury are 0.00004 mg/m3 in gases and 0.0005 mg/L in liquids. Many other countries have their own mercury emission regulations as well, such as the Mercury Air Toxics Standards in the U.S. At the international level, the Minamata Convention had been signed by 97 countries as of March 2014. Under the Convention, the emissions, use, and transportation of mercury will be restricted comprehensively and internationally. The parties that ratify the convention will be required to control, and reduce where feasible, mercury emissions from coal-fired power plants or other sources. There are many commercial CCTs for mercury control, several of which were developed in Japan. At many power plants, the vast majority of mercury can be captured by existing particulate control and desulfurization facilities. Mercury control through dry desulfurization technologies, combined with mercury sorbent injection, can also contribute to further reductions in mercury emissions.

Reducing CO2 Emissions

There has been an increase in the number of national-level CO2 regulations in recent years, with limits in place in the U.S., the EU, Canada, China, and other countries. For example, in the U.S., it has been proposed that new power plants have a CO2 intensity no greater than 454 g-CO2/kWh (1000 lb-CO2/MWh), a level only obtainable with carbon capture and storage (CCS) for coal-fired power plants. In addition, regulations for existing power plants were recently proposed.

The EU has also committed to cutting its 2020 emissions to 20% below 1990 levels. Some EU member countries and regions are considering their own goals as well. In the UK, for example, setting a new standard, 450 g-CO2/kWh, again, achievable only with CCS, was legislated in December 2013. As a result, it is projected that from the period from 2015 to 2020, consumption of coal in the EU could decrease.

At the international level, an IEA roadmap has proposed emission targets for coal-fired power plants from the current worldwide average of 1400 to 743 g-CO2/kWh by applying the most advanced available technologies, such as ultra-supercritical (USC) and integrated gasification combined cycle (IGCC).2 Note that some such high-efficiency, low-emissions (HELE) plants, with at least 45% efficiency, can offer a 40% decrease in CO2 intensity compared to plants operating at the current global average efficiency of 33%. The IEA roadmap also recommends further decreasing CO2 intensities to 669 g-CO2 g/kWh by 2030 through further HELE technology development and deployment.3 Through 2030, high-efficiency technology development and deployment can play a major role in reducing CO2 emissions; for deeper cuts, CCS will be necessary. Those plants that are built or upgraded with higher efficiencies will be the best options for implementation of CCS.

Since Japan imports nearly all the coal it uses, it is focused on using high-efficiency coal-fired power plants. For this reason, some of the most efficient plants in the world are operating in Japan, such as the 600-MW USC Isogo plant, which can operate at an efficiency as high as 45%.

Utilizing Low-Rank Coal

Although there are no regulations to encourage the use of low-rank coal, it is a field where technology development and deployment could be critical, especially for Japan. Globally, approximately half of mineable coal reserves, ~400 billion tonnes, are sub-bituminous or lignite, which are usually utilized near the mine; such coal is not yet commonly imported and used in Japan because of unfavorable economics and some environmental concerns.4 In the interest of being able to import such fuels, Japan has been investing in the development and optimization of technologies, such as drying, conversion, gasification, and liquefaction of low-rank coal.

Japan’s Race to Develop Clean Coal Technologies

The Japanese government had been revising its national basic plan for energy; the plan was approved by Japan’s cabinet in April 2014 and has been published. The main priorities in the plan are 1) energy security, 2) economic feasibility, 3) the environment, and 4) safety. In addition, it has been recommended that any changes in energy policy take into consideration projections around Japan’s economic growth and other geopolitical conditions.

The plan has outlined that based on its lower geopolitical risk and low-cost per unit energy, coal will continue to play a major role in providing energy in Japan, but because of greenhouse gas emissions there must be changes to Japan’s coal-based energy. Coal-fired power plants will continue to be used to supply base electricity, although such plants must improve their environmental impact through further application of CCTs; in addition, there will be a continued focus on high-efficiency coal-fired power generation.

Introduction of state-of-art technologies available today to new power plants and replacement of older coal-fired power plants was another focus. According to Japan’s Energy Plan, HELE technologies should be introduced both domestically and internationally so that coal can be used to improve global energy security with the least possible environmental impact.

Japan’s policies related to CCT development can be categorized into two main aspects: 1) environmental policy and 2) industrial policy. See Figure 1 for an overview.

Figure 1. Criteria for formulation of Japan’s CCT-related policies

Figure 1. Criteria for formulation of Japan’s CCT-related policies

J-COAL’S Clean Coal Technology Roadmap

J-COAL supports Japan’s government in its policy development and implementation and also supports Japan’s energy industry to find the most efficient ways to use coal. Recognizing the need for CCTs to achieve HELE coal-based energy, J-COAL has recently revised its CCT roadmap, which was originally prepared in 2010 based on the following objectives:

  1. Provide a CCT roadmap for research and development (R&D) through 2050 that takes into account the future outlook around coal utilization, including where secure coal supplies exist and environmental stewardship that will be required; this roadmap should be easily understandable to the public.
  2. Support the sustainable development of the coal utilization industry, which contributes to Japan’s energy security, through joint government and industry R&D.
  3. Propose the future direction for CCT-related R&D by recognizing the progress achieved to date and challenges that remain.
  4. Identify promising CCT projects and propose them as candidates for government support.
  5. Propose and organize government-led and -sponsored R&D projects.
  6. Identify emerging CCTs, which can help the government implement its policies and meet its goals related to energy, environment, industry, and international trade.

Formulation of Targets for Research, Development, and Demonstrations

Since global coal-based energy faces challenges, such as reducing the cost of CO2 emissions controls, increasing fuel diversity by utilizing low-rank coals, and reducing the overall environmental impact, research, development, and demonstration (RD&D) of CCTs must be encouraged (see Figure 2).

Figure 2. Criteria for the formulation of J-COAL’s CCT R&D roadmap

Figure 2. Criteria for the formulation of J-COAL’s CCT R&D roadmap

In December 2013, J-COAL completed revisions to its CCT roadmap; the outline was released to the public in January 2014. The technologies being pursued under the roadmap are shown in Figures 3–5; 28 individual technologies were selected from our previously published roadmap and other reports, such as “Technological Roadmap in the Area of Coal Usage” (March 2012) developed by the New Energy and Industrial Technology Development Organization (NEDO). The latest information on CCT technologies, including their targets, size, and RD&D stage, are provided in the roadmap to make clear the current progress of CCT RD&D in Japan.

After compiling information on individual technologies, they were categorized into three groups based on their respective objectives and level of development (from basic research to commercialization). The three groups are as follows:

  1. Mid- and long-term R&D: technologies with technical issues to be solved (see Figure 3)
  2. Economic improvements: technologies with no major technical challenges, but that require further development to improve overall economics (see Figure 4)
  3. Formulation of supply chain: technologies necessary to build a comprehensive clean energy supply chain, which includes production, processing, transportation, and distribution (see Figure 5)
Figure 3. CCTs with technical issues under mid- and long-term R&D Notes: *1 IGFC = integrated gasification fuel cell combined cycle; *2 A-IGCC = advanced IGCC; *3 ABC = advanced biomass and coal utilization technologies; *4 Ferro Coke = coke made from low-rank coal and iron ore; *5 COURSE50 = CO2 reductions in the steelmaking process through innovative technology for Cool Earth 50; *6 Hyper Coal = nonash coal produced using solvent extraction; *7 TIGAR = twin circulating fluidized bed gasification technology; *8 ECOPRO = Coal flash partial hydropyrolysis technology

Figure 3. CCTs with technical issues under mid- and long-term R&D
Notes: *1 IGFC = integrated gasification fuel cell combined cycle; *2 A-IGCC = advanced IGCC; *3 ABC = advanced biomass and coal utilization technologies; *4 Ferro Coke = coke made from low-rank coal and iron ore; *5 COURSE50 = CO2 reductions in the steelmaking process through innovative technology for Cool Earth 50; *6 Hyper Coal = nonash coal produced using solvent extraction; *7 TIGAR = twin circulating fluidized bed gasification technology; *8 ECOPRO = Coal flash partial hydropyrolysis technology

For the first two categories (Figures 3 and 4), three subcategories were included to further categorize the technologies: 1) high-efficiency, low-carbon generation; 2) utilization of low-rank coal; and 3) reducing environmental impact. Details about these three subcategories are described in the next three sections.

High-Efficiency, Low-Carbon Coal-Fired Power Plants

The efficiency of coal-fired power plants in Japan has been demonstrated as high as 43% HHV (once it reaches the grid) based on USC technology with a steam temperature of 600°C. Technologies are currently under development that will lead to advanced USC (A-USC) plants with steam temperatures of 700°C and efficiencies of approximately 46%, which will reduce coal consumption and CO2 emissions by an additional 10%. The main technical hurdles to the widespread deployment of such plants are materials and equipment that can withstand the higher temperatures, which are a major focus of development efforts.

IGCC (integrated gasification and combined cycle) and IGFC (integrated coal gasification fuel cell combined cycle) are power plants based on gasification that are under development; these plants could dramatically reduce CO2 emissions and achieve higher efficiencies than conventional coal-fired power plants. The IGCC demonstration plant in Nakoso, Fukushima, has operated at an efficiency of 40.5% based on the utilization of a Japanese air-blown entrained flow gasifier and 1200°C GT (gas turbine). An IGCC plant with 1500°C GT could offer an efficiency of 46%.

Figure 4. CCTs focused on economic improvements Notes: *9 UBC = upgraded brown coal; *10 JCF·HWT (high-temperature water treatment) coal water slurry made from brown coal

Figure 4. CCTs focused on economic improvements
Notes: *9 UBC = upgraded brown coal; *10 JCF·HWT (high-temperature water treatment) coal water slurry made from brown coal

IGFC power plants incorporate both IGCC and fuel cell technology and are expected to exceed 55% efficiency and therefore dramatically reduce CO2 emissions. The Osaki CoolGen demonstration project is currently underway in Osaki, Hiroshima; this project is based on a Japanese oxygen-blown entrained-type gasifier. The first phase of this project includes only the IGCC plant, the second phase will include CCS, and the third phase will incorporate fuel cells so that the full IGFC technology is implemented with CCS.

As has been highlighted by the IEA, though high-efficiency technologies can greatly reduce CO2 emissions if deployed globally, CCS will eventually be needed to drastically cut emissions. To achieve the ultimate target of near-zero CO2 emissions by 2050,5 J-COAL proposes that an integrated demonstration plant of a commercial coal-fired power plant with CCS should commence operation by 2025.

Utilization of Low-Rank Coal

Due to the general characteristics of higher moisture, lower calorific value, and spontaneous combustion, lignite and sub-bituminous coal have not been widely used in Japan. However, to broaden fuel options in Japan, R&D is underway to develop cost-effective conversion processes to produce upgraded brown coal and JGC Coal Fuel, for example, and liquefaction.

Lignite consists of a greater fraction of volatile components, which facilitates its gasification more than bituminous coal, but is still of limited usage because of limitations around costs for transportation. R&D about gasification, conversion to liquid fuels, and chemicals is underway. We also believe there may be a possibility for coal-derived products and fuels to displace some oil and gas in the Japanese market.

In addition, based on the important goal of securing resources for Japan’s iron industry, conversion technologies that could create coking coal from low-rank coal, including pyrolysis and hydrogenation, are also being developed.

Reducing Environmental Impact

On the topic of reducing the environmental impact of coal, J-COAL’s roadmap is focused on three main areas:

  • Technologies for coal-based electricity: complete RD&D to reduce CO2
  • Technologies for coal usage in general industry: develop and deploy air pollution reduction technologies for criteria emissions (e.g., SOx, NOx, particulate matter, etc.)
  • Technologies to reduce environmental impact: RD&D to reduce toxic materials in flue gas and ash.

J-COAL is compiling individual tables for the 28 technologies listed in Figures 3–5; the tables will include 1) outlines for R&D, 2) current status of R&D activity, and 3) challenges for acceleration of R&D and technology advancement. These tables will be released to the public in the near future.

Figure 5. CCTs focused on supply chain development

Figure 5. CCTs focused on supply chain development


As a result of Japan’s unique energy situation, especially in the supply side, maintaining energy security hinges on an appropriate diversity in energy supply, including coal, which is regarded as a principal source of energy. For this reason, Japan has been researching and developing technologies to facilitate the deployment of CCTs in order to meet energy needs, such as high efficiency, low environmental impact, and cost feasibility. J-COAL’s roadmap provides a timeline to move these technologies to the Japanese and global markets.



  1. International Energy Agency (IEA). (2013). World energy outlook 2013, www.worldenergyoutlook.org
  2. IEA. (2012). Technology roadmap: high-efficiency, low-emissions coal-fired power generation, www.iea.org/publications/freepublications/publication/name,32869,en.html
  3. IEA Clean Coal Center. (2012). Global coal developments and climate change policy in 2012. London: IEA Clean Coal Center.
  4. J-COAL. (2008). Coal note 2008. Tokyo: Japan Coal Energy Center.
  5. Japan’s Government. (2007). Cool Earth 50 Plan.

The second author can be reached at tmatsuda@jcoal.or.jp.

The content in Cornerstone does not necessarily reflect the views of the World Coal Association or its members.