Tag Archives: carbon capture and storage

Cryogenic Carbon Capture™ as a Holistic Approach to a Low-Emissions Energy System

By Larry Baxter
Cofounder, Sustainable Energy Solutions (SES)
Professor, Chemical Engineering, Brigham Young University

Reducing global carbon emissions requires a a diverse portfolio of low-emissions technologies, including renewable energy and carbon capture and storage (i.e., CCS and CCUS).1,2 Without using the full portfolio of low-emission options, the costs for reducing global emissions will be higher and the probability of successful climate change mitigation decreases. Each technology, however, faces its own set of challenges. For example, although the deployment of renewables has accelerated in recent years, the issue of intermittency remains a major challenge. Similarly, CCS is lagging behind the projected amount of demonstration projects needed. Sustainable Energy Solutions (SES) has developed a low-cost, integrated energy storage and CO2 capture technology, called Cryogenic Carbon CaptureTM (CCC), that can help address the major challenges faced by renewables and CCS.


The foundation of the CCC process relies on refrigeration to cryogenic temperatures, rather than a chemical reaction, to separate CO2 from flue gas from a power plant or industrial source. Typically, refrigeration cycles consume large amounts of energy, but this is only true if the final products are at lower temperature than the incoming streams, e.g., air conditioning. While the CCC process relies on refrigeration process principles, the products are at nominally the same temperature as the incoming flue gas, and thus the energy efficiency is much higher than for typical refrigeration processes. For comparison, the energy efficiency of an air conditioner could be similarly high if it delivered air at the same temperature as the outdoor air, which, of course, defeats the purpose for that application. However, since the purpose of the CCC process is to separate CO2 from the other constituents in flue gas, with cooling as only an intermediate step, recuperative heat exchange drives most of the temperature change.

There are two possible implementations of the CCC process. Figure 1 illustrates the major process steps of the external cooling loop (CCC-ECLTM) version, which is the implementation that enables large-scale energy storage. Alternatively, the compressed flue gas (CCC-CFGTM) version of the process differs from the ECL version in that it does not include an external refrigeration loop but rather uses the flue gas as its own refrigerant. This article focuses on the ECL process to highlight the opportunity to meet the dual challenge of CCS deployment and energy storage; more information on the CFG process is provided elsewhere.3–5

FIGURE 1. Simplified flow diagram of the CCC-ECL™ process

FIGURE 1. Simplified flow diagram of the CCC-ECL™ process

CO2 Capture

The flue gas enters the capture system and cools in a series of heat exchangers until it reaches a temperature at which the CO2 freezes to form a nearly pure solid that separates easily from the remaining gases. The process pressurizes the solid CO2 to force out all the gases from between the solid particles. Two separate streams exist at this point in the process: the pressurized solid CO2 stream and the CO2-lean flue gas stream at ambient pressure. Both streams warm to ambient temperature by cooling the incoming gases in recuperative heat exchangers. These recuperative heat exchangers are important because they accomplish most of the sensible cooling in the process. As the solid CO2 warms, it melts to form a liquid. The process delivers a liquid stream of nearly pure CO2 at 150 bar and a gas stream at atmospheric pressure, with both streams near ambient temperature. This process can capture more than 99% of CO2 from a large-point source emitter. One substantial advantage of this approach is the ease with which emission sources can be retrofit. Although the process uses electricity, it does not require the extraction of steam or any upstream modifications.

Simultaneous Emissions Control

As the flue gas cools in a series of heat exchangers (for sim-plicity, only one is shown in Figure 1), most gases other than N2 and O2 condense at component-specific temperatures. Thus, as part of the CO2 capture process, the CCC process also captures SOx, NOx, Hg, HCl, particulate, VOCs, etc. In fact, the CCC process removes all gas constituents less volatile than carbon monoxide (CO), which includes nearly all other currently and foreseeably regulated emissions.

Energy Storage

The CCC-ECLTM process stores energy in the form of cold, condensed refrigerant. If there is excess power from renewables on the grid, the extra electricity generates and stores excess refrigerant. The CO2 capture process recovers this energy in periods of high power demand by increasing the net power plant input, using the stored refrigerant, rather than compressor power, to drive the carbon capture and reduce parasitic losses. Refrigerant generation represents over 80% of the energy required in the CCC-ECLTM process (see Table 1). The same approach allows dispatchable power plants to follow dynamic load without changing steam generation rates or temperatures.

Baxter Table 1

SES has completed detailed transient analyses of the energy storage and recovery processes.7 For example, an 800-MWe power plant can stabilize up to a ±400-MWe swing in power demand on a typical U.S. grid with intermittent wind and dispatchable gas and coal power. The estimated economic benefit of the energy storage exceeds $20/MWh, because the system can utilize energy which would otherwise be curtailed or is generated using low-cost baseload resources during off-peak times.1 The process also largely decreases the need for spinning reserve and other high-cost backup systems. The value of the energy storage nearly equals the carbon capture cost in many markets.


Economic analysis completed by SES, based on application of the technology in the U.S., indicates that, even without considering the economic advantages of energy storage, the CCC process is more efficient and cost effective than leading alternative approaches to CO2 capture.

SES has completed quantitative estimates for the energy consumed by its CCC processes and compared them to that of a post-combustion liquid amine CO2 capture system. The results based on the CFG and ECL systems appear in two forms: a bolt-on version and implementation with some integration. The bolt-on versions consume about 0.71 GJe/tonne of CO2 captured. An integrated system (1) uses a portion of the heat collected in the first condensing heat exchanger to preheat boiler feedwater and (2) reduces the energy demand associated with the control of other emissions (e.g., SOx, NOx, etc.) by capturing them as part of the CCC process. These integration steps reduce the effective energy demand to a little less than 0.6 GJe/tonne of CO2. In both the bolt-on and integrated configurations, CCC is predicted to consume significantly less energy than post-combustion liquid amine-based CO2 capture (see Figure 2).

FIGURE 2. Estimated parasitic load for amine6 and CCC capture processes

FIGURE 2. Estimated parasitic load for amine6 and CCC capture processes

The primary sources of energy savings compared to liquid amine systems come from two factors: (1) the CCC process does not require large thermal swings or recycling materials (e.g., water and amine in the liquid amine CO2 capture process, distillation reflux in oxyfuel systems, etc.) and (2) the CCC process pressurizes the CO2 in a condensed phase, rather than as a gas. Condensed-phase compression requires far less expensive equipment and far less energy than gas compression.

While the parasitic energy is a major component of costs, the economics of all CO2 capture processes also depend strongly on financing and capital costs. To provide some means of comparison with other technology options, SES obtained vendor quotes for major equipment and otherwise made stride-for-stride identical assumptions and used the same software (to the greatest extent possible) as used in detailed cost estimates provided by the U.S. Department of Energy (DOE) National Energy Technology Laboratory (NETL) (see Figure 3).6

FIGURE 3. Incremental increases in the cost of electricity relative to a non-capture supercritical (SC) plant for an amine system6 and for CCC with varying degrees of integration. The bars represent estimated cost of electricity for a new SC coal plant with no carbon capture, a new SC plant with 90% capture via aqueous amines, a new SC plant with 90% capture by CCC, the cost of power for an existing plant with paid-off capital (i.e., most existing plants in the U.S.), and cost of power from an existing SC plant retrofitted with CCC. The first two of these bars are based on results published by NETL6 and the others are SES results using the same assumptions.

FIGURE 3. Incremental increases in the cost of electricity relative to a non-capture supercritical (SC) plant for an amine system6 and for CCC with varying degrees of integration. The bars represent estimated cost of electricity for a new SC coal plant with no carbon capture, a new SC plant with 90% capture via aqueous amines, a new SC plant with 90% capture by CCC, the cost of power for an existing plant with paid-off capital (i.e., most existing plants in the U.S.), and cost of power from an existing SC plant retrofitted with CCC. The first two of these bars are based on results published by NETL6 and the others are SES results using the same assumptions.

In all configurations, the CCC CO2 capture cost estimates per unit of electricity fall well below those of leading alternatives. The CCC processes are predicted to increase electricity costs by about 2.5 ¢/kWh, possibly much less if the processes are fully integrated and/or the energy storage option is used.4 The energy storage, as previously discussed, might provide up to 2 ¢/kWh of additional savings, which is close to the total CO2 capture cost for the fully integrated systems.8 For context, the average U.S. residential retail electricity price is about
13 ¢/kWh.


SES has built and successfully tested the CCC-CFGTM and CCC-ECLTM versions of the process at lab, bench, and skid scales up to 7–8 tonnes of flue gas/day (1 tonne of CO2 per day). The largest of these test systems occupies two shipping containers and is mobile. Field tests have included flue gas slipstreams from subbituminous coal, bituminous coal, biomass, natural gas, municipal waste, tires, and blends of these fuels. These field tests occurred at utility-scale power plants, industrial heat plants, cement kilns, and pilot-scale reactors. SES is actively seeking technology partners capable of constructing the equipment for the next two phases of the project: a 5-MWe equivalent (100 tonnes/day of CO2) pilot plant and ultimately a 150–200-MWe demonstration plant.

CCC-ECLTM process test skid

CCC-ECLTM process test skid

Several of the essential components of the CCC processes are in commercial use in the power and other industries. Examples include the condensing heat exchanger, many of the intermediate heat exchangers, slurry and cryogenic liquid pumps, dryers, and water treatment facilities. The primary equipment that is not currently available commercially, and thus the focus of current and future technology development efforts, includes cryogenic solid-fluid separations equipment and desublimating heat exchangers that continuously process solids-forming streams without fouling or plugging.

The remaining challenges in the scale-up of the CCC technology include assessing potential long-term issues with construction materials and engineering details related to solids handling at large scale. Water purification, multi-pollutant handling, and other process steps also still require demonstration, but should be manageable using currently available commercial technologies.


The CCC-ECL™ process affordably reduces emissions from fossil-fueled power plants while enabling more and better use of renewables on the grid. The CCC process offers major advantages over alternative capture technologies, including lower energy consumption, lower costs, optional energy storage, easier retrofit, lower water use, and optional criteria emission control. Based on its multiple advantages, the CCC process could become one of the most strategically important components of a low-carbon power industry.


  1. International Energy Agency. (2013). Technology roadmap: Carbon capture and storage 2013, www.iea.org/publications/freepublications/publication/technology-roadmap-carbon-capture-and-storage-2013.html
  2. Intergovernmental Panel on Climate Change. (2014). Climate change 2014: Mitigation of climate change. Contribution of Working Group III to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change. Available at: www.ipcc.ch/report/ar5/wg3/
  3. Safdarnejad, S.M., Hedengren, J.D., & Baxter, L.L. (2015). Plant-level dynamic optimization of Cryogenic Carbon Capture with conventional and renewable power sources. Applied Energy, 149, 354–366.
  4. Jensen, M.J., Russell, C.S., Bergeson, D., Hoeger, C.D., Frankman, D.J., Bence, C.S., & Baxter, L.L. (2015). Prediction and validation of external cooling loop cryogenic carbon capture (CCC-ECL) for full-scale coal-fired power plant retrofit. International Journal of Greenhouse Gas Control, 42, 200–212.
  5. Sustainable Energy Solutions. (2015). Our technology, www.sesinnovation.com
  6. U.S. Department of Energy, National Energy Technology Laboratory. (2013). Cost and performance baseline for fossil energy plants, volume 1: Bituminous coal and natural gas to electricity, www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/OE/BitBase_FinRep_Rev2a-3_20130919_1.pdf
  7. Fazlollahi, F., Bown, A., Ebrahimzadeh, E., & Baxter, L.L. (2015). Design and analysis of the natural gas liquefaction optimization process-CCC-ES (energy storage of cryogenic carbon capture). Energy, 90, 244–257.
  8. Safdarnejad, S.M., Hedengren, J.D., & Baxter, L.L. (2015). Plant-level dynamic optimization of Cryogenic Carbon Capture with conventional and renewable power sources. Applied Energy. 149, 354–366.

The author can be reached at l.baxter@sesinnovation.com and additional technology details can be found at www.sesinnovation.com


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Learning From Positive Outcomes on Land Reclamation

By Holly Krutka
Executive Editor, Cornerstone

As this issue of Cornerstone goes to press, world leaders are meeting in Paris, France, for the COP21 negotiations under the United Nations Framework Convention on Climate Change. Momentum for the meetings has long been building, and future issues of Cornerstone will cover the outcomes, as they pertain to the coal industry and the broader energy community. As we have done in the past, we will continue to focus on policy approaches and technologies—including high-efficiency, low-emissions (HELE) coal-fired power plants and carbon capture, utilization, and storage—which enable coal utilization in a carbon-constrained world.

Krutka Headshot

While the significance of reducing emissions is not easily overstated, the environmental footprint of energy production and utilization is far from limited to greenhouse gases. For example, working with local communities and governments to ensure mined land is successfully reclaimed is a process that may not garner the same amount of attention as climate change mitigation, but to those living near mines it can cut at the heart of sustainable energy. Thus, in this issue of Cornerstone, we are highlighting lessons learned and international best practices in reclamation projects—principally from opencast mines. For countries currently growing their coal production, the decades of experience gained in reclamation efforts around the world could help leapfrog standard learning cycle time requirements to enhance reclamation practices.

Reclamation often begins while coal is being actively mined elsewhere at the same site. Such an approach minimizes the footprint of an opencast mine at any given time. Prior to the first excavation shovel, successful reclamation requires soliciting input from local stakeholders and ecology experts. Identifying any plant or animal species at risk, planning for drainage, and defining the optimal end use for the land are key first steps that are site specific. For example, as highlighted in this issue, while the western U.S. may use reclaimed land for livestock grazing, in the Czech Republic, which has recently announced that it is increasing limits on lignite production, nature preserves are a good fit. In cases such as the Czech Republic, spontaneous reclamation—allowing nature to do the work—has demonstrated ecological value.

Positive reclamation projects require an understanding of the local ecology and the risks posed by mining and other associated activities. Protection of the sage grouse in the western U.S. is an important success story of how mining companies have worked with local governments and environmental experts to minimize impact. As this issue of Cornerstone was being prepared, the U.S. Fish and Wildlife Service announced that the sage grouse would not be added to the endangered species list—a positive result for the bird and also the stakeholder groups that have been working to operate mines without affecting it unduly.

As global leaders negotiate on climate change mitigation, there may well be lessons on collaboration and commitment to the environment that can be gleamed by considering decades-long reclamation efforts. On behalf of the editorial team, I hope you enjoy this issue of Cornerstone.


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What Will It Take for CCS to Have a Future in the European Union?

By Samuela Bassi
Policy Analyst, Grantham Research Institute
on Climate Change and the Environment,
London School of Economics and Political Science

Carbon capture and storage (CCS) can play a considerable role in tackling global climate change. By capturing CO2 and storing it underground, CCS allows coal- and gas-fired power stations to produce low-emissions electricity. Furthermore, it is the only technology that can reduce carbon emissions from large industrial installations, such as steel and cement plants. If successfully applied to bio-energy generators, CCS technology could also result in “negative emissions”, that is, it could actually remove CO2 from the atmosphere.

For these reasons CCS is included in a wide range of authoritative energy models forecasting future low-carbon energy portfolios, including models developed by the International Energy Agency (IEA)1 and those included in the Fifth Assessment Report of the Intergovernmental Panel on Climate Change (IPCC).2 Most analysts agree that it may be much more expensive, if not infeasible, to limit warming to 2°C without CCS.

The case for CCS is also strong in the European Union. All the scenarios developed in the EU’s Energy Roadmap 2050, which aims to reduce emissions by 80–95% below 1990 levels by 2050, involve using CCS.3 According to these scenarios, CCS should be applied to between 7 and 32% of electricity generation in the EU by 2050.

To achieve the emission reductions outlined in the Energy Roadmap 2050 scenarios, CCS must be deployed in Europe from 2020 onward. However, momentum for CCS on the continent appears to have dwindled, and progress has been painfully slow.

A recently published study by the Grantham Research Institute at the London School of Economics and Political Science and the Grantham Institute at Imperial College investigates the barriers to CCS development in the European Union and recommends a European-wide strategy to speed up investment.4 This article shares key findings from that study.

The full report by the Grantham Institute on Climate Change and the Environment investigates barriers to CCS in the EU.

The full report by the Grantham Institute on Climate Change and the Environment investigates barriers to CCS in the EU.


Although no explicit target has ever been enforced, the European Council did once aspire to have up to 12 CCS demonstration projects operating by 2015.5 Despite this, the pace of CCS development in the European Union has been very slow. Not a single CCS plant is even in construction in the EU. By comparison, North America already has 13 CCS installations in operation and six under construction (see Figure 1).

FIGURE 1. CCS installations in operation by sector and country, 20144,6,7

FIGURE 1. CCS installations in operation by sector and country, 20144,6,7

This does not mean that efforts have not been made by some EU member states. Six CCS plants are now at various stages of planning, five of which are in the UK with the other one being in the Netherlands. It remains unclear how many of these projects will secure enough financing to be fully realized. At the moment only two of them—the White Rose and Peterhead projects in the UK—are relatively close to a final investment decision, but the outcome is not certain. Notably, last September the White Rose project lost the support of one of its three commercial bakers, Drax Group PLC, allegedly due to a recent cut in low-carbon energy subsidies in the UK.

The White Rose project in the UK is one of two CCS projects advancing in the country. (Credit: Capture Power)

The White Rose project in the UK is one of two CCS projects advancing in the country. (Credit: Capture Power)


High upfront costs present the biggest barrier to the widespread use of CCS. While the technology is well understood, it is still far too expensive to be commercially competitive with unabated coal- and natural gas-fired power stations.

Based on the current cost of CCS technology, between €18 billion and €35 billion may need to be invested by 2030 in the EU to deliver the 10 GW of CCS power plants with CCS envisaged by the Energy Roadmap 2050. Just €1.3 billion of public European funding, coupled with some private investment, has been allocated to CCS to date—just a fraction of what is needed to make CCS technology commercially viable.

The costs associated with CCS are expected to decrease over time thanks to technological innovation, economies of scale, and increasingly efficient CO2 transport and storage infrastructure. However, realizing these advancements would require investment in fully operational plants as soon as possible.

There is already much being learned from existing projects. The developers of the world’s first operating CCS power plant, the Boundary Dam project in Canada, claim that they could save up to 30% of the costs building an identical CCS plant today, thanks to the knowledge gained in the course of the project. Other, more theoretical, estimates suggest that costs could decrease by 15–40% by 2030, especially through improvements in CO2 transport and reductions in the cost of financing projects.

The financing of CCS projects is particularly important. Currently, perceived risks surrounding first-of-a-kind CCS projects impair access to suitable finance, raising the cost of capital. UK estimates suggest the cost of capital faced by CCS developers could be in the order of 12–17% (mid-point 14.5%).8 By comparison, the cost of capital faced by more established low-emissions technologies, such as solar photovoltaic or offshore wind projects, is between 6 and 9%.

A simple financial model based on publicly available information from the Boundary Dam CCS power plant shows how different costs of capital can affect the average cost of electricity from a CCS power plant, measured in terms of levelized cost of electricity (LCOE). With a cost of capital of 9.5%, the LCOE would be around £180/MWh. For a cost of capital at 14.5%, the LCOE increases to £240/MWh (see Figure 2).

FIGURE 2. Estimated LCOEs based on the Boundary Dam project and different assumptions on cost of capital4

FIGURE 2. Estimated LCOEs based on the Boundary Dam project and different assumptions on cost of capital4

The policies introduced to support CCS in the European Union have so far failed to deliver the expected results. Notably, the price of carbon in the European Union Emissions Trading System (EU ETS) has been very low and is unlikely to increase to the level required to make CCS competitive with unabated fossil fuel installations.

Notably, the carbon price would need to increase from less than €8 to between €35 and €60/tonne CO2-eq if a coal-fired power station fitted with CCS is to be competitive with conventional coal-fired plants. For gas-fired power stations with CCS to be competitive, the carbon price would need to be even higher, between €90 and €105 per tonne. It is very unlikely that the EU ETS will achieve these levels for at least another decade or so.

Public funding programs have also been set up to support CCS development and deployment, such as the European Energy Programme for Recovery (EEPR) and the New Entrant Reserve (NER) 300. These too, however, failed to deliver strong results. This is partly because funds available through the NER 300 depended on the price of 300 million EU ETS allowances earmarked to CCS, and their selling price ended up being lower than expected. In addition, CCS projects were in competition with other low-emissions technologies for funding. Eventually only one of the 39 projects funded by NER 300 actually involved CCS.

In the coming years, additional financial resources are expected to become available through the new Innovation Fund (or NER 400), the Modernisation Fund, the European Fund for Strategic Investment, and the European Structural and Investment Funds. However, the scopes of these programs are much broader than CCS. It is unclear if, and to what extent, CCS projects will be financed through these channels.

Another challenge faced by CCS developers is that existing regulation imposes significant costs and liabilities on CO2 storage site operators, which discourages investment. In particular, site operators are requested to provide financial coverage for the cost of compensation in case of CO2 leakage. This financial liability is linked to the price of allowances in the EU ETS. The uncertainty over the amount of CO2 that could leak and the future EU ETS carbon price make this liability potentially open-ended.


The European Commission must provide leadership on CCS if it is to keep on course with its Energy Roadmap 2050. Europe needs an overarching strategy to stimulate much needed action to advance CCS. But what would a strategy on CCS involve?

First, such a strategy should encourage member states to assess their potential for CCS and characterize potential storage sites. It should provide policy guidance, set milestones to measure progress, and coordinate transport infrastructure planning.

Second, the strategy should identify additional market-based mechanisms to mobilize investment in the short to medium term. These would complement existing policies like the EU ETS.

These could include more direct funding for research and development, a new funding mechanism to finance early-stage CCS development projects, and financial incentives for electricity generation using CCS.

Furthermore, improvements to the existing European legislation will be required to allow the first demonstration projects to be developed in a timely manner and to create the right conditions for future investment. A key action would be to set an initial cap on long-term liability for CO2 leakage, to be reviewed as risks become better understood and private insurance mechanisms develop. This is not dissimilar to the way risk has been handled in the nuclear industry. A financial mechanism for damage remediation, such as a liability fund or private insurance, would also help spread risk across CCS site operators. Special treatment of early demonstration projects—for example, through a public liability scheme—would also be warranted, given the higher risks faced by first movers.


If CCS is to be successfully deployed in Europe, the private sector will also need to act. For instance, large, incumbent energy utilities could be well placed to develop the first CCS projects, as they have the size, experience, and capacity to undertake diversified, large-scale, and complex investments while minimizing many of the barriers and inherent risks to CCS projects.

This is not to say that large-scale energy utilities will find it easy to invest in CCS. In the current economic and political environment they are facing significant funding constraints. Furthermore, CCS project financing has a different risk profile compared to traditional capital-intensive energy infrastructure projects. In particular, the risks associated with construction of CCS installations differ considerably from the risks associated with its operation. Investors may be willing to absorb some of the risks, but the long-term nature of CCS means that risks will endure and can only be managed by private investors to a certain degree.

These complexities highlight a need for the involvement of public financial institutions. For instance, the European Investment Bank (EIB) or the European Bank for Reconstruction and Development (EBRD) could contribute convening power and know-how to attract additional private financing sources.

Upstream producers of fossil fuels—whether privately or publicly owned—should also contribute much more strongly to advancing of CCS in the EU. Ultimately CCS will increase the amount of their assets that can be potentially realized in compliance with climate change targets. It is likely that fossil fuel companies may oppose an additional tax to fund CCS development. However, I believe there is a case for encouraging the creation of a private-sector fund for CCS. These companies’ desire to lower the costs of CCS technologies could be fostered by simple agreement between key players to exploit a shared interest in developing CCS.


The EU and its member states must show much greater urgency and determination to develop and deploy CCS. Without action now, the EU may be unable to meet its targets for reducing greenhouse gas emissions. Evidence indicates that it will be more costly to meet these targets without CCS.

Thus, there is a strong case for stepping up ambition and action on CCS in the EU. The creation of a European Energy Union provides a timely opportunity to revamp European policy on CCS. The European Commission and the Energy Union, in particular, have a strong responsibility to engage and guide member states, helping them meet their emissions reduction targets at the least cost.

The first CCS installations will require significant public and private resources. This will likely be realized through a mix of higher carbon pricing, subsidies, and increased private investment. Further measures, however, need not be monetary in nature—these ought not to be difficult to implement in the short term. For instance, inviting member states to assess their own potential for CCS, and identifying the cost of alternative routes for decarbonization, may be a sensible first step. This could also lead to the identification of a coalition of countries willing to collaborate more closely on CCS.

At the very least, the European Union needs more certainty about which low-emissions energy technologies warrant investment. If the promotion of CCS is considered politically unfeasible, the EU’s stated expectations for CCS would have to be revised in a timely manner and alternative options should be explored immediately.

Ultimately, the public and private sectors both have a role to play. Within the private sector, the burden of investment in CCS has fallen especially on energy suppliers. However, these companies are not often in a position to invest in large multi-billion projects without sufficient public backing. Other players could be well placed to be more involved, such as upstream producers of fossil fuels. It is time to think about how to scale up investment on CCS, by improving public policy as well as further mobilizing private finance from a multiplicity of actors.


  1. International Energy Agency. (2012). Energy technology perspectives 2012, pathways to a clean energy system, www.iea.org/publications/freepublications/publication/ETP2012_free.pdf
  2. Intergovernmental Panel on Climate Change. (2014). Summary for policymakers. In O. Edenhofer et al. (Eds.), Climate change 2014, Mitigation of climate change. Contribution of Working Group III to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change. Cambridge, UK/New York, NY: Cambridge University Press. Available at: report.mitigation2014.org/spm/ipcc_wg3_ar5_summary-for-policymakers_approved.pdf
  3. European Commission. (2011). Impact assessment, accompanying the document, Communication from the Commission to the Council, the European Parliament, the European Economic and Social Committee and the Committee of the Regions, Energy Roadmap 2050. Commission Staff Working Paper. SEC(2011) 1565/2 Part 1:2, ec.europa.eu/energy/sites/ener/files/documents/sec_2011_1565_part1.pdf
  4. Bassi, S., Boyd, R., Buckle, S., Fennell, P., Mac Dowell, N., Makuch, Z., & Staffell, I. (2015). Bridging the gap: Improving the economic and policy framework for carbon capture and storage in the European Union. London: Centre for Climate Change Economics and Policy, Grantham Research Institute on Climate Change and the Environment at the London School of Economics and Political Science, and Grantham Institute at Imperial College, www.lse.ac.uk/GranthamInstitute/publication/bridging-the-gap-improving-the-economic-and-policy-framework-for-carbon-capture-and-storage-in-the-european-union/
  5. Council of the European Union. (2007). Presidency conclusions, Brussels European Council 8/9. Brussels: Council of the European Union, www.consilium.europa.eu/ueDocs/cms_Data/docs/pressData/en/ec/93135.pdf
  6. Massachusetts Institute of Technology. (2013). Carbon Capture and Sequestration Project database, sequestration.mit.edu/tools/projects/index_capture.html
  7. Global CCS Institute. (2014, 7 October). Status of CCS project database, www.globalccsinstitute.com/projects/status-ccs-project-database
  8. Oxera. (2011). Discount rates for low-carbon and renewable generation technologies, Prepared for the Committee on
    Climate Change, www.oxera.com/Oxera/media/Oxera/downloads/reports/Oxera-report-on-low-carbon-discount-rates.pdf?ext=.pdf

This article is based on a report by the Grantham Research Institute at the London School of Economics and Political Science and the Grantham Institute at Imperial College, “Bridging the gap: Improving the economic and policy framework for carbon capture and storage in the European Union”, by Samuela Bassi, Rodney Boyd, Simon Buckle, Paul Fennell, Niall Mac Dowell, Zen Makuch, and Iain Staffell. The report is available for download from the Grantham Research Institute website: www.lse.ac.uk/GranthamInstitute/publication/bridging
The lead author can be reached at s.bassi@lse.ac.uk


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Helping to Seed a CCS Industry: The White Rose CCS Project

By Leigh Hackett
Chief Executive Officer, Capture Power Limited

The White Rose Carbon Capture and Storage Project (White Rose) is a proposal to build a new ultra-supercritical coal-fired oxy-fuel power plant up to 448 MWe (gross) with full carbon capture and storage (CCS) deployed from the outset. The plant will be located at the Drax Power Station site, near Selby in North Yorkshire in the UK, and will generate enough low-carbon electricity to supply the equivalent needs of over 630,000 homes. White Rose would be one of the first large-scale demonstration plants of its type in the world and the first oxy-fuel coal-fired CCS plant to be built at commercial scale, representing a core step toward the advancement of CCS technology globally.

Artist’s rendition of Drax cooling towers (left) facing the White Rose oxy-fuel power plant (right) (image from Arup Associates, UK)

Artist’s rendition of Drax cooling towers (left) facing the White Rose oxy-fuel power plant (right) (image from Arup Associates, UK)

The project is currently in the FEED (front-end engineering and design) stage, having been awarded a contract in December 2013 by the UK government, under the UK CCS Commercialisation Programme. This program is one component of the UK’s Department of Energy and Climate Change (DECC) CCS Roadmap that sets out the necessary steps required to support the development of a CCS industry in order to meet the target of an 80% reduction in greenhouse gas emissions by 2050 (from a 1990 baseline).1

White Rose additionally secured an award decision in July 2014 for European Union (EU) funding through “NER300” (New Entrant Reserve 300)—one of the world’s largest funding programs for innovative low-carbon energy projects to be demonstrated at a commercial scale within the EU.2


Many aspects of coal-fired oxy-fuel combustion have been demonstrated; however, White Rose would be the first comprehensive project at commercial scale. To ensure an experienced team is in place to lead the first-of-a-kind project, a strong consortium, Capture Power Limited, has been formed by three companies: Alstom, Drax, and BOC. Each team member brings unique capabilities to the project.

Alstom is a recognized global leader in power generation; a quarter of the world’s power station fleet relies on Alstom technologies. The company is a pioneer in large-scale and efficient CCS technologies and is considered one of the foremost experts in coal-fired CCS development.

Drax owns and operates Drax Power Station, the largest power station in the UK. The output capacity from the station’s six units is a combined 3870 MW. Currently average output levels meet approximately 7–8% of the UK’s electricity needs. Two of the power station’s six generating units have been fully converted to burn sustainable biomass in place of coal and a third unit is planned to be converted in 2015/16.

BOC, part of the Linde Group, is the UK’s largest industrial, medical, and special gases provider. Its strategy is centered on innovation with clean energy technologies, including CCS, which is currently a major focus of the company’s research and investment.


Many independent studies have indicated that CCS on power stations is critical in enabling the lowest cost pathway to decarbonization, with the International Energy Agency proposing power plants with CCS contribute 14% of emissions reduction to 2050, or the equivalent of 950 GW globally.3 CCS demonstration and deployment must advance more rapidly for it to play the projected required role in carbon emission mitigation. Therefore CCS projects at commercial scale are of paramount importance. As one such project, White Rose will demonstrate that CCS oxy-fuel technology can be used to generate reliable, flexible, low-carbon electricity competitively, while helping to reduce global greenhouse gas emissions.

Limited options exist to achieve flexible, low-carbon power at a large scale. Power stations with CCS must displace conventional (i.e., unabated) load-following thermal plants in order to meet fluctuating consumer demand and ensure a secure power supply as greater intermittent renewables are incorporated into the energy mix. CCS on thermal power plants is the only low-carbon technology available to most countries that is of sufficient size, stage of commercial development, and cost competitiveness to provide this important role in enabling continuous, flexible, low-carbon power supply.


White Rose would be capable of capturing two million tonnes of CO2 per year, which is about 90% of all the CO2 emissions produced by the plant. In addition, White Rose will be capable of firing a range of fuels and has the potential to co-fire biomass alongside coal, a step that would enable the plant to release zero or even increasingly negative net CO2 emissions depending upon the level of biomass co-firing. This technology would enable a co-fired coal and biomass oxy-fuel power plant with CCS to form a carbon sink, offsetting carbon emissions from other sources. Such flexibility in fuels adds significantly to the value of an oxy-fuel power plant through the potential to assist total decarbonization over and above the power sector’s contribution.


CCS technology can enable the most cost-effective path to decarbonization at a large scale, according to reports by the Energy Technologies Institute, International Energy Agency, and UK Trade Union Congress, the latter estimating that the cost of decarbonization would be 20–25% higher in the UK without CCS.4 Similarly, the Intergovernmental Panel on Climate Change has projected that, without CCS, the cost of global carbon mitigation efforts will increase by approximately 140%.5

White Rose is expected to confirm cost effectiveness aligned with the findings of the UK’s CCS Cost Reduction Task Force (CRTF) that has identified pathways for reducing the costs of CCS as the industry develops. Specifically, the CRTF concluded: “UK gas and coal power stations equipped with carbon capture, transport and storage have clear potential to be cost competitive with other forms of low-carbon power generation, delivering electricity at a levelised cost approaching £100/MWh by the early 2020s, and at a cost significantly below £100/MWh soon thereafter.”6


The CO2 captured at White Rose will be transported by pipeline to a permanent geological storage site beneath the North Sea by National Grid through their Yorkshire and Humber CCS pipeline, which will be developed alongside this project (see Figure 1). The CCS pipeline would have the capacity to transport up to 17 million tonnes of CO2 every year, significantly in excess of the two million tonnes of CO2 captured annually at White Rose, which is intended to act as the anchor project and potential catalyst for development of the regional CCS pipeline network.

FIGURE 1. Approximate path of the Yorkshire and Humber CCS pipeline that White Rose could help establish

FIGURE 1. Approximate path of the Yorkshire and Humber CCS pipeline that White Rose could help establish

The Yorkshire and Humber region in the UK is an ideal location for CCS project proposals due to the number of power stations and large industrial plants in relatively close proximity, which together represent approximately 19% of the UK’s CO2 emissions. A report published by the research organization CO2Sense, “The National, Regional and Local Economic Benefits of the Yorkshire and Humber Carbon Capture and Storage Cluster”, found that the Yorkshire and Humber region is the “best strategic location in Europe” to establish a CCS cluster due to the high concentration of emitters, as well as the proximity to potential North Sea storage sites and the presence of an advanced supply chain.7

The CCS network connecting such facilities aligns with the recommendations of the Energy Technologies Institute report on the “Potential for CCS in the UK”, which states: “The most effective way to implement CCS is through a national infrastructure comprising a handful of shared transport and storage networks because this captures economies of scale and drives asset utilisation.”8


Although White Rose will be a first-of-a-kind demonstration, the specific components of coal-fired oxy-fuel combustion are commercially proven. The oxy-fuel process is based on a conventional power-plant steam cycle, but uses oxygen mixed with recycled CO2 instead of air in the combustion process (see Figure 2). The oxygen is provided by an air separation unit (ASU), using standard technology. The oxy-fuel combustion gas eliminates nitrogen from the system, producing a flue gas consisting mainly of CO2 and water. Additional components including particulates, SOx, and NOx are handled in conventional treatment steps. A CO2 processing and compression unit, similarly using established processes, is installed to treat and compress the CO2-rich flue gas before being transported to storage.

FIGURE 2. Alstom’s oxy-fuel process Source: Alstom

FIGURE 2. Alstom’s oxy-fuel process
Source: Alstom

The oxy-fuel process proposed at White Rose has a number of distinct benefits, including:

  • Oxy-fuel is similar to conventional air-fired operation, developed from well-known systems and processes and all the main components of an oxy-fuel power plant already exist, providing a reliable and proven technology basis.
  • The oxy-fuel process does not require large quantities of new chemicals compared to post-combustion technologies.
  • Oxy-fuel operation is highly flexible, beyond even the level of conventional coal-fired power plants, due to the integration of the ASU. This flexibility allows oxy-fuel plants to make and store liquid oxygen using low-cost power during periods with low demand, which can then be used to boost power production during peak power periods, through reducing the ASU load (as the oxygen being produced is supplemented by stored oxygen), enabling a higher net output.

In addition to these advantages for White Rose, oxy-fuel technology has been estimated to represent the lowest cost solution for CCS on coal-fired power stations, according to the UK’s CRTF report, where the levelized cost of electricity in 2013, 2020, and 2028 was estimated to be lower than other options.6


The UK government’s CCS Commercialisation Programme,9 providing funding support to the White Rose CCS project FEED Programme, is the first step toward advancing commercial-scale CCS in the UK. Subsequent policy mechanisms must be implemented in the UK and elsewhere to benefit from the lowest cost route to decarbonized power, capitalize on the much-needed flexible operation they offer, and make a competitive CCS industry a reality.

In the meantime, White Rose represents a unique opportunity to demonstrate that abated fossil-fuel power stations will be able to generate flexible, reliable, and affordable power as load-following plants, providing security of supply and grid stability complementing baseload nuclear generation and intermittent renewables.


  1. UK Department of Energy & Climate Change. (2012, April). CCS roadmap: Supporting deployment of carbon capture and storage in the UK, www.gov.uk/government/uploads/system/uploads/attachment_data/file/48317/4899-the-ccs-roadmap.pdf
  2. European Commission. (2014). NER 300 programme, ec.europa.eu/clima/policies/lowcarbon/ner300/index_en.htm
  3. International Energy Agency. (2013). Technology roadmap:
    Carbon capture and storage, www.iea.org/publications/freepublications/publication/technologyroadmapcarboncaptureandstorage.pdf
  4. TUC and Carbon Capture & Storage Association. (2014, February). The economic benefits of carbon capture and storage in the UK, www.tuc.org.uk/sites/default/files/carboncapturebenefits.pdf
  5. Intergovernmental Panel on Climate Change, Working Group III. (2014). Climate Change 2014: Mitigation of climate change, www.ipcc.ch/report/ar5/wg1/
  6. CCS Cost Reduction Task Force. (2013, May). Final report, www.gov.uk/government/uploads/system/uploads/attachment_data/file/201021/CCS_Cost_Reduction_Taskforce_-_Final_Report_-_May_2013.pdf
  7. CO2Sense. (2012). The national, regional and local economic benefits of the Yorkshire and Humber carbon capture and storage cluster, www.calderdaleforward.org.uk/workspace/uploads/files/ccs_co2sense_exec_summary_fina-508e6241bfdb8.pdf
  8. Energy Technologies Institute. (n.d.). Carbon capture and storage: Potential for CCS in the UK. A Summary Insights Report, www.eti.co.uk/ccs-potential-for-ccc-in-the-uk/
  9. Department of Energy & Climate Change, UK Government. (2015). UK government carbon capture and storage: government funding and support, www.gov.uk/uk-carbon-capture-and-storage-government-funding-and-support


The content in Cornerstone does not necessarily reflect the views of the World Coal Association or its members.
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Understanding the National Enhanced Oil Recovery Initiative

By Patrick Falwell
Solutions Fellow, Center for Climate and Energy Solutions
Brad Crabtree
Vice President, Fossil Energy, Great Plains Institute

Since 2011, the Center for Climate and Energy Solutions (C2ES) and the Great Plains Institute (GPI) have convened the National Enhanced Oil Recovery Initiative (NEORI). Bringing together leaders from industry, the environmental community, labor, and state governments, NEORI has worked to advance carbon dioxide enhanced oil recovery (CO2-EOR) as a key component of U.S. energy security, economic, and environmental strategy. Currently, most CO2-EOR is done with natural underground reservoirs of CO2, yet the industry’s future growth depends on taking advantage of the large amounts of CO2 that result from electricity generation and industrial processes. NEORI therefore is working to turn a waste product into a commodity and to encourage policies that will help bring an affordable supply of man-made CO2 to the market.

As such, NEORI has offered consensus recommendations for federal- and state-level policy action. In May, Senator Jay Rockefeller (D-WV) introduced legislation in the U.S. Congress adopting NEORI’s centerpiece recommendation to reform and expand an existing federal tax incentive for the capture of man-made CO2 and its geologic storage through CO2-EOR. Going forward, NEORI will work to educate policymakers across the political spectrum and the broader public about the opportunity for CO2-EOR to serve as a national solution to energy and environmental challenges.

In May 2014 Senator Jay Rockefeller introduced legislation incorporating the main principal of the National Enhanced Oil Recovery Initiative. (creativecommons.org/licenses/by/2.0/)

In May 2014 Senator Jay Rockefeller introduced legislation incorporating the main principal of the National Enhanced Oil Recovery Initiative. (creativecommons.org/licenses/by/2.0/)


Although commonly considered a “niche” extractive technology, CO2-EOR is a decades-old practice. Since the 1970s, CO2-EOR projects have utilized CO2 to produce additional oil from otherwise tapped-out fields. CO2 readily mixes with oil not recovered by earlier production techniques, swelling the stranded oil and bringing it to the surface. The CO2 is then separated from the oil and re-injected in a closed-loop process. Each time CO2 is cycled through an oil reservoir, the majority of it remains trapped in the underground formation, where, over time, all utilized CO2 will be stored permanently.

Today, CO2-EOR in the U.S. accounts for over 300,000 barrels of oil production per day, or nearly 5% of total annual domestic production.1 More than 4000 miles of CO2 pipelines are in place and, as of 2014, approximately 68 million tonnes of CO2 are being injected underground annually for CO2-EOR. Nearly 75% of this CO2 is from naturally occurring deposits, but over time the supply of CO2 from man-made sources is expected to grow significantly. Currently, 11 U.S. states have CO2-EOR projects. Most are in the Permian Basin of Texas, with new activity emerging on the Gulf Coast and in the Mountain West. Untapped opportunities exist in California, Alaska, and a number of states in the industrial Midwest. Estimates suggest that CO2-EOR could ultimately access 21.4–63.3 billion barrels of economically recoverable reserves.2 Recovering this oil would require 8.9–16.2 billion tonnes of CO2 that would predominantly come from man-made sources. Technically recoverable reserves offer potential to produce additional oil and utilize more man-made CO2 that is currently otherwise emitted into the atmosphere.

The main barrier to taking advantage of CO2-EOR’s potential has been an insufficient supply of affordable CO2. For an oilfield operator looking to implement CO2-EOR on a depleted oilfield, there is a cost gap between what they could afford to pay for CO2 under normal market conditions and the cost to capture and transport CO2 from power plants and industrial sources. For some industrial sources, such as natural gas processing or fertilizer and ethanol production, the cost gap is small (potentially $10–20/tonne CO2). For other man-made sources of CO2, including power generation and a variety of industrial processes, capture costs are greater, and the cost gap becomes much larger (potentially $30–50/tonne CO2). Recognizing the cost gap as a significant barrier, NEORI has worked to determine the role that public policy can play in narrowing it.


For the last three years, NEORI has brought together a broad and diverse group of constituencies that share a common interest in promoting CO2-EOR. Some NEORI participants support CO2-EOR as a way to provide a low-carbon future for coal by managing and avoiding its carbon emissions. Others are interested in the jobs and economic growth that deploying new CO2 capture projects, pipelines, and EOR operations will bring. Still other participants want to advance innovative technologies that can capture and permanently store CO2 underground. Despite differences of opinions among participants on other issues, all agree that CO2-EOR is a positive endeavor and that public policy can play an important role in realizing CO2-EOR’s many benefits. As such, NEORI’s participants have crafted a set of consensus recommendations for federal and state policy incentives to enable the widespread deployment of carbon capture technologies to provide CO2 for use in CO2-EOR, while addressing concerns about how incentives have been allocated in the past.

To support its consensus recommendations, NEORI also prepared a quantitative analysis to estimate the extent to which a federal initiative could spur new CO2-EOR projects and improve the federal budget at the same time. An incentive awarded for capturing CO2 from man-made sources for use in CO2-EOR has the potential to be self-financing, given that it could lead to new oil production that is taxed at the federal level. CO2-EOR in the U.S. generates federal revenue from three sources:

  1. Corporate income taxes collected on the additional oil production
  2. Income taxes on private royalties collected from CO2-EOR producers
  3. Royalties from CO2-EOR production on federal land

Together these sources equate to nearly 20% of the sales value of an additional barrel of oil and generate the source of public revenues that will in turn cover the cost of newly allocated incentives.

NEORI’s most recent analysis of the budget implications of a tax incentive reflects the legislation introduced by Senator Rockefeller. This analysis shows that an improved federal incentive could lead to the production of over eight billion barrels of oil and the underground storage of more than four billion tonnes of CO2 over 40 years and generate federal revenues that exceed the value of tax incentives awarded within the U.S. Congress’ standard 10-year budget window.


NEORI recommends a reform and an expansion of an existing federal tax incentive, the Section 45Q Tax Credit for Carbon Sequestration. First authorized in 2009, the 45Q tax credit provides a $10 tax credit for each tonne of CO2 captured from a man-made source and permanently stored underground through enhanced oil recovery (a $20 tax credit is available for CO2 stored in saline formations). While enacted with the best of intentions, the existing 45Q program has been unable to encourage widespread adoption of carbon capture technologies for two main reasons. First, 45Q is only authorized to provide tax credits for 75 million tonnes of CO2, a relatively small amount considering how much CO2 could possibly be utilized through CO2-EOR. As of June 2014, tax credits for approximately 27 million tonnes of CO2 had already been claimed, and it is foreseeable that the remaining pool of credits will be exhausted in the near future. Second, 45Q has been unable to provide needed certainty to carbon capture project developers that they will be able to claim the incentive, due to rigid definitions in the tax code and the lack of a credit reservation process. Carbon capture project developers have not been able to present the guarantee of credit availability when seeking private-sector finance.

Under NEORI’s proposal, a larger pool of 45Q credits would be established, while suggested reforms would increase certainty and private-sector investment, improve transparency, and help the program pay for itself fiscally within 10 years.

Allocating New 45Q Credits via Competitive Bidding and Tranches

To minimize the cost of new 45Q tax credits to the federal government, NEORI recommends that carbon capture projects of similar cost bid against one another for allocations of tax credits. Under annual competitive bidding processes, carbon capture projects would bid for a certain tax credit amount that would cover the difference between their cost to capture and transport CO2 and the revenue they would receive from selling CO2 for use in CO2-EOR. The project submitting the lowest bid would receive an allocation of tax credits, and allocations would be made to capture projects up to specified annual limits.

NEORI recommends the allocation of new 45Q tax credits.

NEORI recommends the allocation of new 45Q tax credits.

Given the wide difference in capture costs for potential man-made sources of CO2, three separate pools of credits, or tranches, would be established. The creation of separate lower-cost industrialA and higher-cost industrialB tranches for power plants would ensure that an incentive is available for the diversity of potential man-made sources of CO2.

Tax Credit Certification

A certification process would provide essential up-front certainty to carbon capture project developers and enable them to reserve their allocation of 45Q tax credits to be claimed in the future. Upon receiving an allocation of 45Q tax credits through competitive bidding, a project would have to apply for and meet the criteria of certification within 90 days. For example, a carbon capture project would need a contract in place to sell its CO2 for use in CO2-EOR to be certified. To maintain certification, a carbon capture project would have to complete construction in three years, if it is a retrofit, and five years, if it is a new facility.

Revenue Positive Determination and Program Review

Following the seventh annual round of competitive bidding, the U.S. Secretary of the Treasury would assess whether newly allocated 45Q tax credits have been revenue-positive to the federal government. If the new 45Q tax credits are not proving to be revenue-positive, the Secretary will make recommendations to Congress to improve the program. Otherwise, competitive bidding will continue until the next review.

The Secretary of the Treasury also would be advised by a panel of independent experts.

Annual Tax Credit Adjustment Based on Changes in the Price of Oil

Each year, the value of claimed 45Q tax credits would be adjusted up or down to reflect changes in the price of oil. In most instances, the price that CO2-EOR operators would pay CO2 providers for their CO2 is linked explicitly to the prevailing price of oil. When the price of oil rises and CO2-EOR operators are willing to pay more for CO2, the value of 45Q tax credits would be adjusted downward to ensure the federal government does not pay more than needed. Conversely, when oil prices fall, the value of 45Q tax credits would be adjusted upward, ensuring that carbon capture projects receive sufficient revenue.

NEORI is designed to boost U.S. domestic oil production while providing much-needed financial support for CCUS projects.

NEORI is designed to boost U.S. domestic oil production while providing much-needed financial support for CCUS projects.

Tax Credit Assignability

Potential carbon capture project developers include electric power cooperatives, municipalities, and startup companies. Not all of these entities have sufficient tax liability to allow them to realize the economic benefit of a tax credit. As such, NEORI recommends that carbon capture projects have the ability to assign 45Q tax credits to other parties within the CO2-EOR supply chain. This provision could facilitate tax equity partnerships, but only among entities directly associated with the project and managing the CO2.


In a time of considerable disagreement on U.S. energy and climate policy at the federal level, NEORI members believe that CO2-EOR offers broad benefits and the rare opportunity to unite policymakers and stakeholders in common purpose. The NEORI coalition therefore remains committed to educating members of both political parties and the broader public as to how CO2-EOR can generate net federal revenue from domestic oil production, meet domestic energy needs, safely store man-made CO2 underground, and help advance and lower the costs of carbon capture technology.


A.  Lower-cost industrial sources of CO2 include natural gas processing, ethanol production, ammonia production, and existing projects involving the gasification of coal, petroleum residuals, biomass, or waste streams.

B.  Higher-cost industrial sources of CO2 include cement production, iron and steel production, hydrogen production, and new-build projects involving the gasification of coal, petroleum residuals, biomass, or waste streams.


  1. Kuuskraa, V., & Wallace, M. (2014, 7 April). CO2-EOR set for growth as new CO2 supplies emerge. Oil & Gas Journal, www.ogj.com/articles/print/volume-112/issue-4/special-report-eor-heavy-oil-survey/co-sub-2-sub-eor-set-for-growth-as-new-co-sub-2-sub-supplies-emerge.html
  2. Wallace, M., Kuuskraa, V., & DiPietro, P. (2013). An in-depth look at “next generation” CO2-EOR technology. National Energy Technology Laboratory,www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/Disag-Next-Gen-CO2-EOR_full_v6.pdf

The authors can be reached at FalwellP@c2es.org and bcrabree@gpisd.net

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

Moving Forward With the Huaneng GreenGen IGCC Demonstration

By Xu Shisen
President, China Huaneng Clean Energy Research Institute

China has abundant coal reserves, but is short on oil and gas resources; therefore, its power generation fleet is expected to rely primarily on coal for the long term. However, coal-fired power generation can result in undesirable emissions such as particulate matter, SO2, NOx, Hg, and large quantities of CO2. As global environmental concerns mount, especially those related to climate change, controlling criteria emissions and greenhouse gas emissions has become increasingly important. How best to realize the goal of clean and efficient utilization of coal for electricity generation is a challenge facing China as well as the broader international energy community.

A 250-MW capacity IGCC power station was designed, constructed, and operated under Phase I of the GreenGen Plan.

A 250-MW capacity IGCC power station was designed, constructed, and operated under Phase I of the GreenGen Plan.

IGCC Can Be a Solution

Globally, integrated gasification and combined-cycle (IGCC) power plants are a potential option that would make possible lower-emissions, higher-efficiency coal utilization. However, costs must be decreased and reliability must improve before IGCC is ready for commercial application.

Emergence of IGCC

Research and development on IGCC began in the 1960s. Industry demonstrations started in the 1990s and commercial operation and further developments are now underway globally. IGCC technologies developed in the U.S., Europe,
and Japan share the following features:

  1. These countries regard IGCC technology development as an important part of their national energy strategies.
  2. Core technologies and key equipment are produced in their own countries or regions.
  3. Investment in demonstration projects has come from both governments and corporations.
  4. Through demonstration, project developers are hoping to commercialize their core technologies and become more competitive in the future.

To effectively meet the demands of the future IGCC market, GE (U.S.) and Siemens (Germany) respectively acquired their nationally developed coal gasification technologies. Along with the Mitsubishi Group (Japan), these companies have become global IGCC technology suppliers, offering two IGCC core technologies—coal gasification and syngas turbines.

The full Phase I GreenGen IGCC facility is shown.

The full Phase I GreenGen IGCC facility is shown.

State of IGCC in China

Currently, Chinese technology providers are able to design and optimize large IGCC power stations and provide gasification, syngas purification, waste heat boilers, steam turbines, air separation, and other systems and equipment for IGCC power stations. This lays a solid technical foundation for large-scale commercial construction and operation of IGCC power stations. In addition, China has recently seen breakthroughs in domestic gasification research and development. The two-stage dry pulverized coal pressurized gasification technology developed by the Huaneng Clean Energy Research Institute is competitive with internationally developed technologies in all key indices. Moreover, the design and manufacture of 1000-t/d and 2000-t/d gasifiers have been completed, which are being used in Inner Mongolia’s Shilin coal-to-methanol project and the CHNG GreenGen 250-MW IGCC power plant, respectively. The 1000-t/d and 2000-t/d multinozzle impinging stream coal-water slurry gasifiers developed by Yankuang and East China University of Science and Technology have also been placed into operation. However, gas turbine technology in China still lags behind systems developed internationally. Today the operating conditions for China’s systems are not yet suitable for the commercial application of low-heat-value syngas turbines for IGCC power stations. One ongoing project, however, is focused on the research, development, demonstration, and deployment necessary to advance Chinese IGCC systems.

The GreenGen Plan

In 2004, China Huaneng Group (CHNG) took the lead in putting forward the GreenGen Plan and joined with several power generation and coal-producing enterprises to launch an effort to demonstrate a coal-based power generation system with increased efficiency and near-zero emissions. The purpose of this plan was to research, develop, and demonstrate a new coal-based system that would include hydrogen production from coal gasification, power generation based on combined-cycle hydrogen turbines and fuel cells, and carbon capture, utilization, and storage (CCUS). The plan garnered support from China’s National 863 Program in the 11th and 12th Five-Year Plans.

The core technology for GreenGen is power generation based on IGCC—a well-known technology that includes gasification of coal to produce syngas, which is purified before being combusted to drive an electricity-generating gas turbine. The high-temperature exhaust gas from the gas turbine is utilized by a pre-boiler to produce steam, which then drives a steam turbine to produce additional electricity. Compared with supercritical pulverized coal combustion power generation, IGCC can be more efficient, may offer greater potential for improvements, and can be used to realize near-zero emissions, including increased ease of CO2 capture. Moreover, it can be combined with coal-derived hydrogen and fuel cell power generation technologies to form a more advanced and diversified energy production system. For these reasons, development of IGCC technologies is an important direction for the future of coal-based clean energy power generation in China.

GreenGen is being carried out in three phases. In Phase I, a 250-MW IGCC power station with proprietary technologies was constructed. In Phase II (currently underway), the key technologies involved in GreenGen will be further researched, developed, and demonstrated. Examples of key technologies include hydrogen production from coal gasification, the separation of H2 and CO2 (i.e., pre-combustion CO2 capture), fuel cell power generation, and CCUS. In Phase III, the plan is to build a 400-MW GreenGen demonstration project that will include full integration of key technologies, realizing high-efficiency coal utilization with near-zero emissions. During all phases the emphasis is on improving the technical reliability and economic feasibility of the GreenGen system in preparation for eventual deployment and widespread commercial use.

Progress to Date

From 2004 to 2008, CHNG completed the system design, equipment bidding, and all preliminary work for the 250-MW IGCC demonstration power station, which was sited in Tianjin. In May 2009, the project was approved by the National Development and Reform Commission, which made it clear that the core technologies should be domestically sourced. Construction began in July 2009 and was completed by September 2012. In November 2014 the plant successfully passed the standard test of 72 hours of continuous operation with another 24 hours of operation at full load. The IGCC facility was formally put into commercial operation in December 2012. Thus, as of late 2012, China joined the ranks of those countries that have mastered IGCC power station design, construction, and operation. This achievement marked a major breakthrough in China’s strategic effort to advance its clean coal power generation.

The Chinese-developed gasifier used in Phase I of GreenGen is shown.

The Chinese-developed gasifier used in Phase I of GreenGen is shown.

The overall system is based on a 2000-t/d two-stage dry pulverized coal pressurized gasification technology, a proprietary IGCC process design, and a power island with an E-class multi-shaft combined-cycle generating unit. This project realized independent development, design, manufacture, and construction. Many technologies had to be mastered to reach this stage, including the design of a large IGCC power station, gasification, purification, air separation, heat recovery boiler, and steam turbine power generation, all of which are important to further promoting clean coal power generation in China. As the technologies used for GreenGen were domestically sourced, China has also gained an enhanced capacity for independent innovation from project experience. Currently, the GreenGen IGCC demonstration power station has realized steady operation at high capacity (maximum 92% of design) for 29 consecutive days.

Since the successful completion of Phase I of the GreenGen Plan, CHNG has been actively pursuing Phase II: researching
and developing the key technologies within GreenGen. Specifically, with the support awarded under the 863 Program, CHNG is developing a pilot-scale system that will draw about 7% of the syngas from the GreenGen IGCC power station, shift CO and H2O to CO2 and H2, and then separate the CO2 from the H2 after desulfurization. The CO2 will be liquefied and used to explore how to enhance oil recovery with the end fate of the CO2 being geological storage. The separated H2-rich gas will be sent to the gas turbine for mixed firing after compression.

About 60,000–100,000 tonnes per year of CO2 will be captured and stored under the Phase II (CCUS) demonstration. Phase II will lay the foundation for subsequent research on CO2 capture for the entire IGCC power plant.

This demonstration of pre-combustion CCUS will boast the largest capacity and the most comprehensive process evaluation underway in China when it is in operation. Experiments will be undertaken under various loads and other operating conditions, paving the way for the exploration of low-energy consumption, high-recovery CCUS. With the research, development, and design of the demonstration plant for the CO2 capture technology already complete, the construction under Phase II began in early 2014. Since the sites for the oil displacement wells and CO2 storage were determined previously, CO2-EOR and CO2 storage experiments will be conducted as soon as the CO2 capture plant is ready.

Analysis of IGCC’s Technical Features

Table 1. Designed technical indices of the GreenGen IGCC Power Station

Table 1. Designed technical indices of the GreenGen IGCC Power Station

Table 1 lists the designed technical indices for the GreenGen IGCC Power Station. The designed power generation output is 265 MW, generating efficiency is 48%, power-supply efficiency is 41%, and coal consumption for power supply is 299 g/kWh.

Table 2 lists the actual technical indices of the GreenGen IGCC Power Station when it began operation. Compared with subcritical and most supercritical coal-fired units, GreenGen’s designed standard coal consumption of power supply is superior. However, it consumes more coal than a 1000-MW ultra-supercritical coal-fired unit. This can be attributed to the fact that the GreenGen IGCC power plant employs E-class  turbines. If F-class, G-class, or even the higher-rated H-class gas turbines are subsequently employed, the efficiency of the GreenGen IGCC power station will increase markedly. In terms of parasitic power, the power consumption from the IGCC power station remains quite high as the air compressor and supercharger units of the power station are currently driven by electricity. If gas-fueled drives are adopted, the station’s power consumption rate is expected to fall from 28% to just 5%, making the plant even more efficient.

Table 2. Actual technical indices of the GreenGen IGCC Power Station during initial operation compared with other power plant options

Table 2. Actual technical indices of the GreenGen IGCC Power Station during initial operation compared with other power plant options

Table 3 includes a comparison of the designed indices of three typical advanced coal-fired power stations: the 1000-MW ultra-supercritical power plant of the Phase III Shanghai Waigaoqiao Power Plant, the 1000-MW ultra-supercritical air-cooled Ningxia Lingwu Power Plant, and the GreenGen 250-MW IGCC power plant. Currently, the GreenGen IGCC demonstration power station is competitive with the most advanced ultra-supercritical units in several technical indices. Similar to the standard coal consumption, use of higher-rated turbines would further improve the technical indices of the GreenGen IGCC facility.

Table 3. Comparison of designed technical indices of typical advanced coal-fired power stations

Table 3. Comparison of designed technical indices of typical advanced coal-fired power stations

Currently, the GreenGen IGCC Power Station emits 0.9, 47.87, and 0.6 mg/Nm3 of SO2, NOx, and particulate matter, respectively. The emission rates are far below the emissions of some of the most advanced coal-fired power stations in China and are competitive with advanced gas-fired units. With further possibility to improve on performance as the scale of the technology is increased, the GreenGen project has already demonstrated that gasification can be an efficient, low-emissions option for coal utilization in China and the world.

Plans for Future Development

Industry-Wide Concepts

Compared with the widely used and fully commercial pulverized coal-fired power plants, IGCC is less developed and in the demonstration stage in China. The high construction and operating costs are among the main obstacles for future development and deployment. It is a top priority to speed up development and demonstration of IGCC technology in China and to promote the technology based on the following:

  • Use high-temperature and high-pressure gas turbines to improve IGCC efficiency. If G-class or even H-class gas turbines are used, IGCC power stations could become much more efficient (reaching 58%), making IGCC increasingly competitive.
  • Reduce the construction costs for IGCC power stations. Increasing the scale of equipment produced in China, coupled with standardized designs and integration of chemical and power industry standards, will considerably reduce construction costs and thus accelerate the commercialization process.
  • Increase the rate of the development of IGCC technology and the building of demonstration projects through support of several large-scale IGCC commercial demonstration power stations. This will advance relevant technologies and the mass production of equipment, so as to bring down specific investments and power generation costs.
  • Develop integrated IGCC/polygeneration systems to realize diversified production of chemical products, fuels, and power as end products and thus improve the overall cost-effectiveness of the IGCC system.
  • Strengthen research into and demonstration of IGCC-based CCUS technologies to lay a solid foundation to scale up coal-based energy power generation with near-zero emissions and drastic reductions of greenhouse gases in the future.

Future Plans for GreenGen

Based on the success of GreenGen Plan Phase I, CHNG is now executing Phase II with plans to subsequently move forward with Phase III. The steps involved in Phase II and Phase III are detailed below:

Phase II (2013–2017): Carry out trial operations and optimize to improve the existing systems and key equipment and further improve the operating safety, stability, and reliability of the individual units within the overall process. Research and develop IGCC-based CCUS technologies and advance fuel cell and hydrogen-enriched gas combustion technologies. Conduct feasibility studies on large-capacity, high-parameter IGCC and CCUS. Begin preliminary preparations for GreenGen Phase III.

Phase III (2018–2025): The plan is to build a 400–600-MW GreenGen demonstration plant that will include integration of key technologies such as IGCC, CCUS, fuel cell power generation, and combined-cycle power generation based on hydrogen-rich turbines and polygeneration. This demonstration plant will realize efficient coal-fired power generation with near-zero emissions of all major pollutants and CO2. Meanwhile, efforts will be made to continuously improve the cost-effectiveness and competitiveness of GreenGen-based IGCC units in preparation for widespread commercial deployment.

A Common Objective

With Phase I complete and Phase II successfully underway, the GreenGen project team is moving forward with the objective that this project can become the benchmark for commercial-scale, cost-effective, near-zero emissions, coal-based power generation. This is a goal that, if realized, would offer much strategic value not only to China, but to the world.


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

Developing High-Efficiency, Low-Carbon, Clean Coal in China

By Ni Weidou
Academician, Chinese Academy of Engineering, Professor, Department of Thermal Engineering, Tsinghua University
Song Shizhong
Ph.D. Candidate, Department of Thermal Engineering, Tsinghua University
Wang Minghua
Manager, Shenhua Science and Technology Research Institute Co., Ltd

In the last few decades, China has dramatically expanded access to energy and, as a result, has achieved nearly universal electrification. Although this accomplishment is notable, China’s energy mix is facing several pressing issues with important domestic and global implications.

China is coal-rich and, for this reason, continues to rely on coal for the majority of its primary energy (over 70%), resulting in cost, reliability, and energy security benefits. However, coal resources are being consumed rapidly. China has built, and is continuing to grow, massive industries that hinge on the availability of coal; therefore, coal conservation through more efficient utilization is in the nation’s best interest.

China has achieved near full electrification in recent years, but the country’s energy strategy is being revised.

China has achieved near full electrification in recent years, but the country’s energy strategy is being revised.

As with any country, energy security is an important issue for China. With few oil reserves, China relies on imports for a large percentage of its oil, a fact that will be difficult to change as China’s oil consumption continues to rise. Approximately 200 million tonnes of oil are produced domestically each year; experts have stated that this amount is a suitable volume for China’s oil production and larger volumes could hinder future drilling operations.1 China’s annual oil consumption has reached 450 million tonnes, which means that China must rely on imports for more than half of its oil.

In addition to national resource conservation and energy security issues, the environmental impact of China’s energy production and utilization has become an increasingly pronounced global concern. One of the most problematic issues is the poor air quality in China’s urban centers, which can be primarily attributed to two main factors: direct coal combustion without emissions controls and emissions from the combustion of transportation fuels.

The coal-fired power plants being built in China today are larger and more efficient than those of the past. However, many plants still operate at low efficiency and/or have minimal or no emission controls. In addition, direct combustion of coal in industrial applications or for household heating adds to the pollution. These factors contribute to the release of SO2, NOX, mercury and other heavy metals, and particulate matter (especially fine particulate matter such as PM2.5).

The burning of transportation fuels is another key contributor to air pollution. The gasoline and diesel produced by China’s oil refining industry have always had a relatively high sulfur content, which leads to increased production of particulate matter (including PM2.5).

Another environmental concern is climate change. If the future rise in global temperatures is to be limited to 2°C, some experts have projected that global CO2 emissions in 2050 would need to be about 50% lower than those in 1990.2 China has overtaken the U.S. as the world’s largest CO2 emitter with about seven billion tonnes released each year, which means that China’s actions are pivotal to achieving success in mitigating climate change. For this reason, China is under tremendous international pressure to reduce its emissions.

Even with developed countries committed to reducing their emissions by 80%, developing countries would still need to bring down their overall emissions to 36% below 2005 levels. Coal combustion and burning transportation fuels are the main sources of CO2 emissions in China. Although China has strengthened efforts on energy conservation and the development of nuclear and renewable energy, China’s CO2 emissions are expected to continue increasing; China must also be practical about reducing emissions as it remains a developing country. Therefore, China should be proactive about how best to address emissions reductions with solutions that can be realistically implemented.

While air pollution and climate change are very real concerns, China’s energy mix and infrastructure cannot be drastically modified in the short term, so strategies to improve the efficiency of coal utilization and improve transportation fuel quality have become an important topic.

Optimized approaches to coal utilization in a high-efficiency, low-carbon, cleaner manner, including producing cleaner transportation fuels from coal, could be the solution to the myriad concerns facing China’s energy industry. Although there are many approaches to cleaner and more efficient coal utilization, we believe the most valuable option that addresses all the problems explained is gasification of coal to produce chemicals, fuels, power (i.e., polygeneration), and eventually carbon capture, utilization, and storage (CCUS).

The Shanghai Waigaoqiao No. 3 power plant is one of the many high-efficiency power plants built in China in recent years.

The Shanghai Waigaoqiao No. 3 power plant is one of the many high-efficiency power plants built in China in recent years.

Approaches To Coal’s Role in High-Efficiency, Low-Carbon, Clean Energy

Several clean and efficient coal conversion methods are currently under development or already available.

Carbon Capture, Utilization, and Storage

Ultimately, the lowest-carbon use of coal is tied to capturing and storing CO2. China’s CCUS strategies should be implemented after considering the impact to China’s economy, energy infrastructure, and also the unique opportunities possible to China because it is still growing. We believe China should develop its own technologies and not simply follow the paths chosen by other nations. China’s CCUS strategies have potential; the key challenge is how best to coordinate and manage overall efforts.

The costs associated with CCUS are, in part, tied to the cost of the CO2 capture, which can vary dramatically between different coal utilization options. In terms of power generation, there are two main focus areas for clean coal technology development in China. The first is high-efficiency supercritical and ultra-supercritical coal-fired power plants and the other is gasification [for power production this entails integrated gasification combined cycle (IGCC)].

High-Efficiency Power Plants

China’s state-of-the-art high-efficiency power plants are some of the best in the world; these plants produce less CO2 compared to less efficient subcritical plants and are an important first step in reducing CO2 emissions.

An example of one such plant is Shanghai Waigaoqiao No. 3 power plant. At 75–81% capacity this plant has an average coal consumption rate of 276 g/kWh (including desulfurization and denitrification—an actual annual efficiency of 44.5%). This compares favorably with China’s current average coal consumption for power generation, 330 g/kWh, as well as with the world’s most efficient power plant, the 400-MW Nordjylland Power Station No. 3 in Denmark, with double reheat and cold seawater cooling units. At a capacity of 75%, the coal consumption rate at Nordjylland is 288 g/kWh.

China’s 600°C ultra-supercritical plants are constructed using expensive imported materials that account for 50% of the cost of a 1000-MW boiler. Increases in temperature and pressure would require even higher-standard materials. Furthermore, in direct coal combustion, collecting CO2 from the flue gas comes at a relatively high cost; much more research and development is needed to bring down costs.

Therefore, even though the development of high-efficiency coal-fired power plants is vital and will assuredly continue, notable challenges still exist and we believe this should not be the only option pursued by China.

Approaches Made Possible Through Gasification

Compared to high-efficiency coal-fired power plants, IGCC is at an early stage of development and, thus, may offer greater potential for improvements in terms of power generation efficiency. As IGCC also has unique advantages in terms of capturing emissions and can be coupled with polygeneration to reduce construction costs, it is worth further development.

Capture of emissions from a gasification system, including IGCC power plants, differs because it occurs upstream of power generation at a higher concentration and/or pressure. For a conventional power plant, CO2 capture will reduce the plant’s efficiency by about 11%; for an IGCC power plant, the efficiency loss for CO2 capture is less, about 6–7%. Although the efficiency is high and the capture of emissions is simpler, there is a substantial upfront investment for IGCC, RMB12,000/kWh (US$1900/kWh).

Thanks to many years of demonstration and commercial use, the reliability of IGCC plants has been gradually increasing. Still, in addition to the costs, another major issue with IGCC plants is that most such plants are not suitable for variable load operation.

For the sole purpose of power generation, gasification is not economically competitive in China and, in our opinion, therefore not currently a suitable solution for widespread deployment. Even so, with the aspiration of bringing down costs, some demonstration and deployment of IGCC is proceeding in China. For instance, the Huaneng Group has built and operated a 265-MW IGCC power plant in Tianjin under the GreenGen project.

Another important clean coal technology that employs gasification is polygeneration, which can be used to combine coal-to-chemicals/fuels and IGCC. In a polygeneration process, coal can be combined with wind, solar, biomass, etc., in a variety of configurations to produce a wide array of products (including chemicals, fuels, electricity, etc.). Of course, one potential product of polygeneration systems could also be low-sulfur transportation fuels—leading to energy security and environmental benefits. Importantly, polygeneration technology does not require major technical breakthroughs. It is based on existing, proven technologies and thus has much potential to advance the clean and efficient utilization of coal, making it an important direction for development.

Polygeneration allows for plants to be highly integrated and for the overall energy and materials flow to be optimized. With a single-product gasification process, the coal savings for parallel systems at the same facility is minimal. However, integrated serial systems at a polygeneration facility with multiple products can save a significant amount of coal. In fact, the efficiency of an integrated serial system can reach 45.5% without the CO shift. The water consumption per unit power produced for polygeneration systems is also lower than that of conventional power plants.

As the technology advances, the efficiency of polygeneration technologies can be further enhanced. For example, the efficiency of gasification systems with high-temperature syngas cleanup can be raised to 49.3%. When ionic membrane oxygen separation technology is employed, the system efficiency can be raised to 50.1%. For 1700°C-class gas turbines efficiency can reach 53%. Finally, coal-water slurry preheating technology gasification systems can offer efficiencies of 57.3%. Overall, coal-based polygeneration systems have tremendous potential for using coal cleanly and efficiently, particularly when power and chemicals are both produced.

If China does not expand outside only the traditional technological approaches to coal utilization (i.e., direct combustion), we believe this could lead to a series of problems related to the environment and greenhouse gas emissions. Therefore, from this point forward we believe China’s modernized energy development strategies must emphasize the deployment of polygeneration, which could offer energy efficiency, energy security, and environmental benefits.

Pressing Needs Under a Strong Polygeneration Energy Strategy

Under China’s current energy constraints and challenges, the synergetic use of coal with other energy sources is needed. We believe this integration is the key to low-carbon development in China and also to utilizing different energy sources in the most appropriate way possible. Polygeneration offers unique opportunities to use coal more efficiently, integrate coal energy systems with alternative energy sources, and dramatically reduce CO2 emissions (see Figure 1). In order to achieve better synergy, a smart energy network must be established, which will allow the integration of information technology within energy systems to optimize the flow of energy in China.

Figure 1. Coal can be integrated with renewable energy sources through gasification; in this example methanol can be produced with a CO2 stream ready for CCUS.

Figure 1. Coal can be integrated with renewable energy sources through gasification; in this example methanol can be produced with a CO2 stream ready for CCUS.

Polygeneration with Chemical Products

Considering the high costs of IGCC power generation, when taking into account the future requirements for controlling emissions, including SO2, NOX, particulate matter, and mercury, as well as CO2, the best approach today is to reduce costs through chemical product polygeneration.

China has recently built several hundred gigawatts’ worth of pulverized coal supercritical and ultra-supercritical generating units. These high-efficiency plants can be refitted with CO2 capture in the future. CCUS can also be applied to polygeneration facilities, which offer the lowest-cost option for CO2 capture and could be used to support demonstrations of CO2 utilization and storage in the near term. As it takes time for an energy process and systems to develop and mature, if the polygeneration model is not promoted now, the delay could mean paying a higher price in the future.

In terms of energy security, the liquid fuels produced by coal-based polygeneration, particularly methanol and dimethyl ether, are excellent coal-based alternatives for transportation fuels and can help alleviate China’s oil shortage with much-needed low-sulfur fuels. At the same time, methanol can be used to produce polyethylene and polypropylene, an example of using coal-to-chemicals to replace a portion of conventional petrochemicals—again reducing oil imports.

China has already mastered the leading polygeneration technologies including large-scale coal gasification, which has been successfully demonstrated in industrial applications. For example, the Yankuang Group’s IGCC and methanol polygeneration unit in Shandong is a global first-of-a-kind and has demonstrated long-term, stable operation. This system operates with an efficiency of up to 57.16%, which is 3.14 percentage points higher than has been achieved by independent coal-to-methanol and IGCC systems in China.3 Its power conversion efficiency is as high as 39.5%. As long as the various sectors in China (coal, chemical, and power) are able to break the barriers to cooperation, along with international cooperation, we can tap the potential of polygeneration to improve energy efficiency and reduce emissions.

Synergy with Renewables

China’s wind power capacity ranks first in the world, but about 30% of the wind turbines installed in China are off-grid. Even some of the on-grid wind farms are restricted in their power generation for various reasons, which results in wasted energy.

China now looks to find a way to deploy wind on a larger scale without adversely impacting the overall energy served by other sources. One strategy worth exploring is increased synergy between wind energy and the rapidly developing coal-to-chemicals as well as the proposed polygeneration sector. In China, remote areas are often rich in wind and coal; this remoteness poses challenges related to coal transportation as well as power transmission, but offers opportunities for synergetic energy utilization.

An example of a potential solution to using remote resources, including clean energy, is taking advantage of synergy between wind power and methanol production. The basis of such a concept is to use off-grid wind power to carry out electrolysis of water (i.e., breaking down water molecules to produce oxygen and hydrogen). The oxygen can be supplied to a gasifier and the hydrogen can be added to carbon-rich syngas produced by a coal gasifier. The ratio of H2 to CO can thus be adjusted to the appropriate level for methanol production. Compared to conventional coal-based methanol production systems, this integrated system eliminates the need for an expensive and energy-intensive air separation unit, which greatly reduces the amount of gas conversion. With the same amount of coal, the synergetic solution produces twice the amount of methanol. Most of the carbon molecules from the coal are used in the methanol products, thus significantly reducing CO2 emissions and thereby achieving the best overall results in the use of energy and resources. This is an example of a solution for the problems of wind energy application and that of substantial CO2 emissions.

Recently, many large cities have been eager to obtain more clean energy, leading many areas that are rich in coal resources (particularly the remote areas of Xinjiang in Western China) and large corporations to turn their attention to a new industrial chain for synthetic natural gas (SNG). Although the energy efficiency of converting coal to SNG is only about 60%, long gas pipelines are more efficient than transporting coal over long distances. In terms of end application, since it is a clean, gaseous fuel, it can be used in a variety of advanced energy systems, technologies, and equipment (such as distributed energy and combined heating, cooling, and power production) for more efficient applications. In this way, the full industry chain may reap the benefits of improved overall energy efficiency and reduced CO2 emissions. However, the key issue regarding the emission and treatment of CO2 generated from converting coal to SNG remains. Similar to the example with the methanol plant, if wind can be used to produce the oxygen and hydrogen from the electrolysis of water, the amount of SNG produced per unit coal could be multiplied, thus significantly reducing CO2 emissions.

Looking at the energy system as a whole, this type of synergy is worth in-depth research to resolve issues surrounding essential technical questions. Testing should take place as soon as possible, and from there, demonstration and deployment should be promoted to minimize the end cost of meeting energy security, energy efficiency, and environmental objectives.

CO2 Emission Reductions from the Coal-to-Chemicals Industry

China should pave its own way according to the country’s actual situation and reconsider how to reduce its CO2 emissions in phases from this point forward. China is currently making great efforts to develop the coal-to-chemicals sector (e.g., methanol, dimethyl ether, methanol-to-olefins [MTO], methanol-to-propylene [MTP], direct coal liquefaction, and indirect coal liquefaction). The CO2 released during these processes is already highly concentrated and pressurized and today most of this capture-ready CO2 is released directly into the atmosphere. China emits more than 40 million tonnes of CO2 from methanol production alone. Therefore, reducing CO2 emissions in China should begin with the coal-to-chemicals sector. We believe China should establish supportive policies such as carbon taxes and subsidies, and gain experience in CO2 capture from this process (chemical and physical applications, transportation, storage, etc.). The knowledge gained from studying CO2 emissions reductions in China’s coal-to-chemicals sector could be directly applied to polygeneration systems.


Considering the future of cleaner energy in China, coal-fueled polygeneration as a product should be demonstrated, with gradual advancement toward large-scale development, after which CCUS should be implemented according to CO2 reduction requirements.

As explained, collecting CO2 from conventional power plant flue gas requires a tremendous amount of energy resources and investment. We believe China must also conduct research and small-scale demos in this area, but further observation is needed before large-scale commercial implementation.

Coal will remain a driving force in China’s future energy mix. It is difficult to find suitable alternatives. Through the gasification of coal (or petroleum coke) and subsequent chemical synthesis, the polygeneration of electricity, liquid fuels, chemicals for products, heating, syngas, etc., can be achieved. In addition, synergetic integration of coal with renewable energy can help to meet overall energy requirements, alleviate liquid fuel shortages, and reduce coal combustion emissions and other energy-related issues simultaneously. From a technical perspective, polygeneration has been demonstrated, including the economic benefits and environmental capabilities, and thus carries great strategic significance for China and the world.



  1. Ministry of Land and Resources. (2011). Dynamic evaluation of national oil and gas resources 2010. (In Chinese)
  2. Meinshausen, M., et al. (2009). Greenhouse-gas emission targets for limiting global warming to 2°C. Nature, 458 (7242), 1158–1162.
  3. Ni, W., & Li, Z.  (2011). Polygeneration energy systems based on coal gasification. [Monograph]. Tsinghua University Press.
The content in Cornerstone does not necessarily reflect the views of the World Coal Association or its members.

The Drivers and Status of the Texas Clean Energy Project

By Laura Miller
Director of Projects, Texas, Summit Power Group, LLC

In a single week this past June, the U.S. Supreme Court voted 7-to-2 to affirm the right of  the Environmental Protection Agency (EPA) to regulate carbon dioxide (CO2) emissions from large industrial sources; four former EPA chiefs, all appointed by Republican presidents, testified before a Senate subcommittee that man’s contribution to climate change is a matter of national security; and a coalition of business leaders, including three former U.S. Treasury secretaries, issued a report detailing economic drivers for combating climate change.1 These are just the latest examples of a growing and increasingly bipartisan consensus in the U.S. that something can and must be done to reduce the amount of manmade greenhouse gas emissions.

The site of the Texas Clean Energy Project (photo courtesy of Jason Lewis, U.S. DOE, National Energy Technology Lab)

The site of the Texas Clean Energy Project (photo courtesy of Jason Lewis, U.S. DOE, National Energy Technology Lab)

The Carbon Capture Challenge

Despite this growing consensus, making carbon capture, utilization, and storage (CCUS) a standard feature of the U.S. power plant fleet—the largest source of America’s greenhouse gases—has proven to be easier said than done. According to a 2012 report by the Congressional Budget Office:

Since 2005, lawmakers have provided the Department of Energy (DOE) with about $6.9 billion to further develop CCS [carbon capture and storage] technology, demonstrate its commercial feasibility, and reduce the cost of electricity generated by CCS-equipped plants. But unless DOE’s funding is substantially increased or other policies are adopted to encourage utilities to invest in CCS, federal support is likely to play only a minor role in the deployment of the technology.2

Although the U.S. DOE announced a new $8B loan program last December for advanced fossil energy projects that capture or reduce carbon,3 no new grant monies for such projects are expected to be approved by Congress for the foreseeable future. Likewise, there is currently not an apparent (or at least sufficient) political will to put a price on carbon emissions that would incentivize carbon storage on a major scale.

One potentially cost-neutral approach, which West Virginia’s  Sen. Jay Rockefeller introduced recently as Senate Bill 2288, was developed by the National Enhanced Oil Recovery Initiative (NEORI)—a coalition of major companies, environmentalists, labor unions, and state officials; Summit Power Group (Summit) was also a participant. NEORI found that an expansion of current federal Section 45Q production tax credits for projects that capture CO2 for use in enhanced oil recovery (CO2-EOR) could generate over nine billion barrels of oil over 40 years in the U.S., quadrupling CO2-EOR production and displacing U.S. oil imports, all while preventing the release of four billion tons of CO2 to the atmosphere. The group also found that the short-term cost of expanding the 45Q program today would be more than covered by the revenue generated from the increased corporate income taxes and royalties paid on the oil produced from CO2 injections.4

Summit’s quest to build the most ambitious, pre-combustion, carbon-capture power plant in the world serves as an effective case study for a nascent industry where the science and the technology are fully proven, but the execution remains challenging for mostly unforeseen reasons: the global economic recession of 2008, a plunge in U.S. natural gas prices, sharply increased oil and gas supplies, and the lack of broad Congressional action to deal with the issue of CO2.

Summit is a power plant development company, founded 20 years ago by Donald Hodel, former U.S. Secretary of Energy, and Earl Gjelde, former COO of the U.S. Department of Energy. To date, the company has successfully developed over 9000 MW of natural gas, wind, and solar projects, but never any based on coal. In 2006, with national opposition to old-technology coal plants (i.e., subcritical plants not employing the best available technologies and not contemplating any future carbon capture) growing dramatically nationwide, Hodel and Gjelde concluded that for coal to have a future in an increasingly carbon-constrained world, it was time to build a world-class clean, low-carbon, coal-based power project.

Summit’s vision became what is today a fully permitted 400-MW coal gasification project with 90% carbon capture near Odessa, Texas, called the Texas Clean Energy Project.

U.S. Coal Gasification Is Not New

The science behind low-carbon emissions, coal-based power was already proven in the U.S. by 2006: Tampa Electric’s Polk Power Station in Florida and the Wabash River Coal Gasification Repowering Project in Indiana were up and running, both built in the mid-1990s with enormous financial support from the U.S. DOE. They demonstrated that electricity from coal gasification could be both efficient and offer significantly lower emissions—essentially vaporizing the coal into a gaseous state that permitted its impurities to be stripped out, rather than burning the coal and trying to capture the pollutants as they were blown through a smokestack.

Industrial-scale carbon capture and utilization was also already commercially proven in the U.S.: In 2000, the Great Plains Synfuels Plant in North Dakota began capturing 50% of the CO2 off its coal-feedstock synthetic natural gas manufacturing plant and piping it north to Canada for geological storage via CO2-EOR. The added revenue stream was such a boon to the coal-to-SNG project that its owners repaid the U.S. DOE $1 billion that it had spent taking over the project in 1986 when natural gas prices plummeted and the original owners bailed on the project.5

Hodel and Gjelde saw an opportunity to take these two proven technologies (i.e., coal gasification for electricity and CO2-EOR) and combine them, for the first time, to build a new generation of coal-based power plants. Despite the fact that burned coal was still powering half of America’s homes and businesses in 2006,6 the reality was an industry under siege from environmentalists, politicians, and consumers who were tired of the existing, high-emissions, plants and new-construction proposals that were not employing the very latest and best technology. As an example, TXU’s Big Brown, a 1150-MW plant in East Texas, had no sulfur-dioxide (SO2) scrubbers in 2006 and still doesn’t today—making it the No. 4 biggest SO2 producer of 449 coal plants nationwide7, with 62,494 tons emitted in 2013. No. 3 is another old TXU plant, Martin Lake, just 100 miles down the road. The EPA began regulating SO2 emissions in 1971—the same year Big Brown came online.

After her tenure in public office, Laura Miller has continued to push for the deployment of clean coal technologies globally.

After her tenure in public office, Laura Miller has continued to push for the deployment of clean coal technologies globally.

I was one of those unhappy politicians. As mayor of Dallas in 2006, I was shocked to learn that 18 new, pulverized coal plants were being proposed for our state—11 of them by Dallas-based TXU, which already owned three of the state’s largest, oldest, and highest-emission coal plants. With help from then-Houston mayor Bill White, we created a coalition of cities, counties, and school districts to fight TXU’s plans, which the EPA said did not include using the most technologically advanced pollution control equipment then available. Our widely publicized statewide challenge eventually led to a leveraged buyout of the company and a compromise by the new owners, forged by national environmental groups, to build only three of the 11 plants, including a two-unit, 1600-MW project northwest of Houston called Oak Grove.

During our yearlong battle, I had pressed TXU aggressively to consider doing gasification; when company officials insisted in public debate forums that gasification technology wasn’t available on a reliable, commercial scale, I traveled to Florida to tour the Tampa project so I could refute the claim. And when I repeatedly brought up doing carbon capture, TXU said it was happy to consider making the new plants “carbon capture ready”—which sounded promising at the time, but quickly proved to be an often-used excuse for doing nothing. As David Hawkins with the Natural Resources Defense Council once famously put it in a 2007 appearance before the U.S. Senate Committee on Energy and Natural Resources: “It could mean almost anything, including according to some industry representatives, a plant that simply leaves physical space for an unidentified black box. If that makes a power plant ‘capture-ready,’ Mr. Chairman, then my driveway is ‘Ferrari-ready’.” 8

I wasn’t against coal. I was against using coal if it wasn’t in the cleanest manner possible. When I left public office in 2007, I was asked by several environmental groups if I would go around the country teaching other mayors how to fight dirty coal plants. My response was that it would take forever, only defeat one project at a time, and be an uphill battle in states like Texas (where citizens, not project developers, had the burden in permit hearings to prove that a project wasn’t using the best technology available). Why not build the cleanest plant in the world, thus raising the bar forever on the standard for using coal? The Clean Air Task Force promptly introduced me to Summit Power Group.

Summit executive Eric Redman, now our company president and CEO, was passionate about our project for the same reason I was—we want our industry to capture and sequester carbon. Hodel and Gjelde had a somewhat different but related motivation: Both of them wanted to help assure the clean, responsible, publicly accepted future use of America’s 300-year supply of coal and other hydrocarbons9—one of our country’s most stable and plentiful resources—in part so that America can finally fulfill its long-held goal of energy independence and security. These overlapping approaches to the project have resulted in one of TCEP’s greatest strengths—solid bipartisan support on the federal, state, and local levels in both Texas and Washington.

While Summit was focused on pre-combustion carbon capture, other forward-looking power companies were determined to capture carbon off existing coal fleets—a far more difficult task. Most commendably, American Electric Power (AEP) had made it a goal as early as 2003 to capture carbon off its existing 1300-MW Mountaineer Power Plant, commissioned in 1980 in West Virginia. With assistance from U.S. DOE, EPRI, and Alstom, AEP proved in a pilot program (which it conceived in 2003 but took until 2009 to achieve) that CO2 could be captured off an emissions slipstream and stored underground. Despite a $334M award from DOE to take the pilot program to commercial scale and a 90% capture rate, AEPabandoned the project in 2011 after the U.S. Senate failed to pass a House bill that established a federal cap-and-trade program for carbon emissions, and regulatory authorities in West Virginia were unwilling to pass on Mountaineer’s CO2 capture costs to ratepayers.

“[A]t this time it doesn’t make economic sense to continue work on the commercial-scale CCS project beyond the current engineering phase,” said Michael G. Morris, AEP chairman and chief executive, in a statement at the time. “It is impossible to gain regulatory approval to recover our share of the costs for validating and deploying the technology without federal requirements to reduce greenhouse gas emissions already in place.”10

Although Mountaineer’s demise has been seen as a major setback for post-combustion capture in the U.S., NRG announced in July 2014 that it would start construction on a $1B tower that would capture 40% of the CO2 from one of four coal units at its existing, 2475-MW W.A. Parish power plant near Houston. The 1.6 million tons per year of captured CO2 will be used for CO2-EOR in a field NRG partly owns 80 miles away. U.S. DOE is contributing $167M of the cost.

Tenaska was also a major first mover in developing CCUS, proposing two new-build projects: Trailblazer in Texas, a supercritical pulverized coal project with 85 to 90% carbon capture, and Taylorville in Illinois, a gasification project with 65% carbon capture. In 2013, Tenaska abandoned both, citing similar reasons as AEP, plus increasing supplies and lower costs of natural gas and renewable energy.

Today, only one major, new coal-based CCUS power project is under construction in the U.S.: the Kemper County energy facility, a 582-MW IGCC project with 65% carbon capture—a rate that will result in the plant having the same carbon emissions profile as a highly efficient natural gas-fired power plant. Jointly funded by Mississippi Power and Southern Company, with a $270M award from the U.S. DOE, Kemper has suffered cost overruns and schedule delays, but is set to come online near Meridian, Mississippi, by the end of 2014, which would make it the U.S.’s first successful coal-based CCUS power project and a long-awaited milestone for the industry.

The Texas Clean Energy Project

The second new-build U.S. carbon capture power project slated for construction is Summit’s Texas Clean Energy Project (TCEP).

Like Kemper, TCEP has also received federal incentives—a $450M award from Round 3 of U.S. DOE’s Clean Coal Power Initiative (CCPI) program in 2009–2010, and two subsequent federal tax credit awards from the IRS under Section 48A of the Internal Revenue Code. With TCEP’s projected cost at about $2.5B, the federal assistance covers just part of total construction costs, which will be borne primarily by private investors and bank lenders, but is nevertheless essential to this type of large-scale, first-of-a-kind project (first-of-its-kind because unlike Kemper, TCEP will also produce urea fertilizer, plus capture a much higher percentage of its CO2). In the case of TCEP, the federal incentives allow it to sell all of its products, including power, at market prices, which is critical in Texas since the electricity market is no longer regulated by the Public Utility Commission and ratepayers are not responsible for cost overruns.

So why—when utilities and other power providers have scrapped their CCUS projects in recent years—is TCEP still moving forward?

One fortuitous factor is TCEP’s design: It is a polygeneration plant—a project that generates multiple products, instead of just electricity—resulting in multiple revenue streams (see Figure 1). About 25% of TCEP’s revenue will be generated by 195 MW of electricity sales; about 55% of revenue will come from the 760,000 tons/year of urea; about 20% of revenue will come from the sales of CO2 for CO2-EOR.

Figure 1. Summary flow chart for the Texas Clean Energy Project  Note: Other by-products represent ~3% of total revenue and have been eliminated via rounding; tpy = tons/year

Figure 1. Summary flow chart for the Texas Clean Energy Project
Note: Other by-products represent ~3% of total revenue and have been eliminated via rounding; tpy = tons/year

This unusual configuration came about when Summit decided early on to employ Siemens gasification technology to convert Powder River Basin (PRB) coal into clean, high-hydrogen, low-carbonsyngas. Because of the gasifier’s size, this resulted in more syngas being produced than would be needed to operate the Siemens combustion turbine to produce electricity. After reviewing market forecasts for various products—synthesized gasoline and diesel fuel, ammonia, methanol, synthetic natural gas—urea fertilizer was chosen for its low commodity price risk and ability to displace imports (the U.S. currently imports 70% of its urea). TCEP will sell all of its urea to Minnesota-based CHS, Inc., which sells crop nutrients, both wholesale and retail, to thousands of farmers for millions of acres across North America.

Other TCEP products include sulfuric acid, which will be manufactured onsite from the sulfur captured from the coal, which is also currently done by Tampa Electric’s Polk Power Station. TCEP’s sulfuric acid will be marketed by Houston-based Shrieve Chemical Company to its mining, manufacturing, and agricultural customers.

Finally, just as Kemper will do, TCEP will take virtually all of its captured CO2, compress it onsite, and sell it to area oil producers for CO2-EOR. In TCEP’s case, TCEP will transport its 1.8 million standard tons per year of compressed CO2 for less than one mile to connect with the existing Kinder Morgan system of dedicated CO2 pipelines, which will deliver it to TCEP customers Whiting Oil and two other Permian Basin producers.

By December 2011, TCEP had achieved virtually all of its project milestones, including: 1) issuance of all required permits, including its Texas air permit and its Record of Decision (ROD) at the end of U.S. DOE’s National Environmental Protection Act (NEPA) process; 2) a completed front end engineering and design (FEED) study; 3) signed engineering, procurement, and construction (EPC) contracts and operations and maintenance (O&M) contracts with three EPC contractors; 4) signed off-take agreements for all major commercial products; and 5) commitments of local and state financial incentives for locating the project in West Texas.

In September 2012, the project forged an important alliance with two of the largest companies in China: the Export-Import Bank of China (Chexim), which committed to loan TCEP all of its required debt financing of more than $1.6 billion, and Sinopec Engineering Group (SEG), a subsidiary of petrochemical giant Sinopec Corporation, which joined the project’s EPC team.

In July 2013, with TCEP’s project debt and equity funding committed, an update of project costs came in considerably higher than had been anticipated by Summit and its investors, because of a sharp increase in construction costs in West Texas. This in turn was due to an increasingly high demand for skilled labor in the midst of a statewide oil and gas boom. With no ceiling on labor costs—and big labor contingencies added to the new cost estimates from all three contractors—the project was unable to complete its financing by its goal of December 2013.

Undeterred, and with the support of DOE and state and local officials in West Texas, Summit is now simplifying its EPC structure by bringing in a lead contractor that has successfully built similar plants, China Huanqiu Contracting & Engineering Corporation (HQC), and making improvements to its project design to reduce costs and the amount of needed feedstock (and also residual emissions). In July 2014, Summit and HQC launched a FEED study update that is expected to conclude with new, signed EPC contracts and a financial closing by about 30 April 2015, with groundbreaking shortly thereafter.

HQC and Summit began the FEED update work during the
sixth round of the U.S.-China Strategic and Economic Dialogue in Beijing. In conjunction with that meeting’s U.S.-China Climate Change Working Group CCUS initiative, Summit’s TCEP was also selected by the U.S. DOE to enter a working partnership arrangement with Huaneng’s Clean Energy Research Institute (CERI) and that company’s GreenGen project—which is China’s cleanest fossil fuel power plant.

“TCEP is a key part of the U.S. CCUS portfolio, and DOE has invested $450 million into the project,” stated the U.S. DOE’s Principal Deputy Assistant Secretary of the Office of Fossil Energy, Christopher Smith, in a 3 July 2014 letter to China’s National Energy Administration Deputy Administrator Zhang Yuqing distributed in Beijing that week. “…Under the counter-facing project arrangement, Summit Power and Huaneng will help each other in the planning and operation of TCEP and Phase 2 of GreenGen by sharing non-proprietary information and results from the respective projects. Huaneng will also assist Summit Power in the commissioning of the TCEP plant.”11

Lessons Learned

We do not envision TCEP as a unique demonstration project, but rather the first full-scale commercial gasification plant in a new carbon capture business sector that Summit intends to pursue. This vision is shared by others in the industry, most especially U.S. DOE—without which none of the CCUS projects currently under construction, or in development, would be alive today. The prize for the entire energy sector is potentially enormous.

Hopefully, the challenges currently being experienced by projects like TCEP and the Kemper County energy facility will be viewed as necessary growing pains in the effort to replace the current low-efficiency, unabated fleet of coal-fired power generation. Through employing improved technologies this fleet could continue to provide reliable electricity while avoiding the release of 1.73 billion tons of CO2 into the atmosphere as was the case in 2010.12

One thing, though, is certain: Unless Congress approves additional financial incentives to build these innovative projects, this will be remembered as a decade that produced only a handful of commercial-scale carbon capture power projects in America—much like the 1990s are remembered for only two coal gasification projects, Tampa and Wabash. Perhaps the Rockefeller/NEORI proposal—which promises double rewards by both capturing CO2 and using it to bring up oil—can be the winning formula that quickly deploys a new and nimble fleet of game-changing CCUS facilities.

If the U.S. turns its back on coal entirely, the rest of the world will not. So for coal to remain relevant to a low-carbon U.S. power industry—and for worldwide carbon emissions from coal to be tamed—it is vital that TCEP and other coal-based CCUS projects succeed and stand as beacons, both here and abroad.

As in any industry, it’s simply a matter of getting the first movers up and operating.



  1. The Risky Business Project. (2014, June). Risky business: The economic risks of climate change to the United States, riskybusiness.org/uploads/files/RiskyBusiness_PrintedReport_FINAL_WEB_OPTIMIZED.pdf
  2. Congressional Budget Office, Congress of the United States. (2012, June). Federal efforts to reduce the cost of capturing and storing carbon dioxide, www.cbo.gov/sites/default/files/cbofiles/attachments/43357-06-28CarbonCapture.pdf
  3. U.S. Department of Energy. (2014, 12 December). Loan guar-antee solicitation announcement, energy.gov/sites/prod/files/2014/03/f14/Fossil-Solicitation-FINAL.pdf
  4. National Enhanced Oil Recovery Initiative. (2014). Carbon dioxide enhanced oil recovery: A critical domestic energy, economic, and environmental opportunity. Available at: neori.org/publications/neori-report/
  5. U.S. Department of Energy, National Energy Technology Laboratory. (2014). SNG from coal: Process & commercialization, www.netl.doe.gov/research/coal/energy-systems/gasification/gasifipedia/great-plains
  6. U.S. Energy Information Administration. (2013, 12 December). Electric power annual: Table 4.1. Count of electric power industry power plants, by sector, by predominant energy sources within plant, 2002 through 2012; Table 3.1.A. Net generation by energy source: Total (all sectors), 2002-2012, Electric power annual, www.eia.gov/electricity/annual
  7. U.S. Environmental Protection Agency. (2014, 17 June). Emissions tracking highlights. Table of emissions, emission rates, heat input: 2012 v. 2013, www.epa.gov/airmarkets/quarterlytracking.html
  8. Committee on Energy and Natural Resources, U.S. Senate. (2007, 16 April). Hearing on S. 731 and S. 962: Carbon capture and sequestration (testimony of David G. Hawkins, Climate Center, NRDC), www.energy.senate.gov/public/index.cfm/files/serve?File_id=d281a96a-5466-4f0c-b74c-d696811e67ee
  9. National Mining Association. (2008). U.S. coal reserves by state and mine type, www.geocraft.com/WVFossils/Reference_Docs/coal_reserves_NMA.pdf
  10. American Electric Power. (2011, 3 July). AEP places carbon capture commercialization on hold, citing uncertain status of climate policy, weak economy, www.aep.com/newsroom/newsreleases/?id=1704
  11. Smith, C.A. (2014, 14 July). Letter from the Principal Deputy Assistant Secretary, Office of Fossil Energy, U.S. Department of Energy, to Zhang Yuqing, Deputy Administrator, National Energy Administration, People’s Republic of China. Unpublished.
  12. U.S. Environmental Protection Agency. (2014). Clean energy, www.epa.gov/cleanenergy/energy-resources/refs.html


The author can be reached at lmiller@summitpower.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.