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Vol. 4, Issue 4

Volume 4 Issue 4

From the Editor

Carbon Capture, Utilization, and Storage

By John Kessels, Cornerstone

Kessels HeadshotIn November 2012, Cornerstone was launched as the official journal of the World Coal Association. Cornerstone has since become an internationally recognized credible, independent, high-quality publication, featuring some of the most insightful and informative articles on industry developments. We have looked closely at the technological innovations being pioneered across the coal industry and offered some remarkable thought leadership pieces—from academia, research institutes, investors, and mining companies—that have engendered discussion in the industry.

Cover Story

The Urgent Need to Move From CCS Research to Commercial Deployment

By Andrew Minchener, IEA Clean Coal Centre

Minchener TOCClimate change is a serious issue that requires a global response. However, that response will not be a “one size fits all global solution”. In this article the General Manager of the IEA Clean Coal Centre discusses the urgency of moving CCS research to large-scale demonstration and deployment.


Beyond HELE: Why CCS Is Imperative Now

By Brad Page, Global CCS Institute

Page TOCIt is now clear that the outcome of the Paris climate talks was a game changer, delivering a renewed global commitment to addressing climate change. No longer are we aiming to limit global warming to 2°C. We are now aspiring for well below that—perhaps as low as 1.5°C. Significantly, the agreement also sets out global ambition for carbon neutrality by midcentury. In the post-COP21 discussions, thinking has shifted from “how much do we do?” to “how do we do so much?”

The Role of CCS in a Well-Below 2°C World

By Kamel Ben Naceur and Samantha McCulloch, International Energy Agency

NaceurTOCThe ratification of the Paris Agreement marked an historic milestone for the energy sector and confirmed a global target of limiting future temperature increases to “well below 2°C”. Achieving this will require a much faster and more extensive transformation of the energy sector than previously contemplated. All technologies and all options for reducing emissions will need to be embraced—with carbon capture and storage (CCS) being core among these. The Paris Agreement therefore presents enormous opportunities for the deployment of CCS technologies.

The Challenges for CCS

By Tony Wood, Grattan Institute

WoodTOCAny hard-nosed assessment of the energy sector should conclude that there is no future for coal without carbon capture and storage (CCS). Yet for the last decade, governments, their agencies, and the coal industry have failed to support CCS development in a way that would be consistent with this existential threat. The result is that CCS has little credibility as a material contributor to reducing emissions with governments and those outside the fossil fuel industry. This is despite projections by reputable bodies such as the International Energy Agency (IEA) that show CCS does make a material contribution to delivering a low-emissions future at lowest cost. The prospects for bridging that gap rests with several demonstration projects or a major mobilization by a country such as China.

Energy Policy

Solving Energy Poverty, Unemployment, and Growth Challenges in South Africa

By Rob Jeffrey, Econometrix (Pty) Ltd

The three fundamental objectives of South Africa, and most emerging nations, are to address inequality, unemployment, and poverty. These objectives cannot be achieved by redistribution of wealth alone. They can only be achieved by raising the economic growth rate. A higher growth rate is dependent on having the correct public policies in place and having an adequate and growing supply of affordable electricity. In order to ensure economic growth, South Africa must develop its industrial base and therefore it is essential to supply electricity at the lowest possible cost.

Coal-Fired Power Generation in Japan and the World

By Sumie Nakayama, J-POWER

NakayamaTOCThe Japanese government set its 2030 power generation target shares for coal at 26%, nuclear at 22%, and gas at 27%. Due to concerns over the slow restart of nuclear power generation, the power sector’s interest in building more efficient coal-fired power generation facilities with low CO2 emissions is increasing. This article examines the reasons behind Japan’s energy policy and the choice of coal. In addition, it looks at the importance of coal for the future of Asian countries and the ways in which Japan is contributing to clean coal technologies both domestically and internationally.

Strategic Analysis

Dubai: Pioneering a Sustainable Energy Model for Sustainable Development and Security of Supply

By Taher Diab, Dubai Supreme Council of Energy

DiabTOCThe Emirate of Dubai is one of the fastest growing cities in the world and a regional hub for tourism, logistics, and finance. The Dubai government is implementing an innovative strategy to manage demand, diversify fuel sources, secure its energy supply, and foster green growth. One strategic aim is to continue to fuel Dubai’s economic growth and maintain its regional and global prominent position.

CO2 Utilization as a Building Block for Achieving Global Climate Goals

By Janet Gellici, National Coal Council

GelliciTOCConsensus is growing among industry, the environmental community, and international governments that future carbon dioxide emission reduction goals cannot be met by renewable energy alone and that carbon capture, utilization, and storage technologies for all fossil fuels must be deployed to achieve climate objectives in the U.S. and globally. Fossil fuels—including coal, natural gas, and oil—will remain the dominant global energy source well into the future by virtue of their abundance, supply security, and affordability.

Phasing Out Coal-Fired Power Plants in Alberta by 2030: Recent Developments

By Babatunde Olateju and Surindar Singh, Alberta Innovates, and Jamie McInnis, University of Calgary

BabatundeTOCThe province of Alberta, located in Western Canada, is regarded as the pillar of Canada’s energy economy. It is home to the third largest oil reserves in the world, produces 68% of Canada’s natural gas, holds significant renewable energy resources, and is the site of Canada’s first commercial windfarm. Yet the most abundant fossil fuel energy resource in Alberta is coal. The energy content of coal in Alberta is greater than the energy content of natural gas and oil combined, including the oil sands. Coal-bearing formations underlie 304,000 km2 or 46% of Alberta’s total area, making the formations larger than the United Kingdom. Alberta’s coal resource is estimated to be greater than 2 trillion tonnes.

New British Deep Mine to Deliver 50-Year Coking Coal Project

By Tony Lodge, Centre for Policy Studies

LodgeTOCThe British government’s plan to ban all coal-fired power stations by 2025 has made headlines around the world. Many will now close early and, with that closure, the mining, coal handling, and import facilities that once dominated British ports will become redundant. Though now in decline, this formerly large thermal coal dependency supported many deep and surface mines across Britain and supplied thermal coal internationally. Britain’s electricity supply industry is now looking to combined-cycle gas turbine plants, renewable energy, and new nuclear power plants in its quest to meet ambitious CO2 reduction targets.

Technology Frontiers

The Future of CCS in Norway

By Camilla Bergsli, Gassnova SF

BergsliTOCThe Norwegian government seeks to realize at least one full-scale carbon capture and storage (CCS) demonstration project by 2020, and three industrial carbon capture projects are about to enter the concept phase. Twenty years of experience with full-scale CCS combined with the world’s largest CCS test facility and more than 20 years of CCS research underlie the country’s ambition to contribute to further development of CCS. This article examines Norway’s efforts to mitigate CO2 emissions by applying CCS and the importance of industrial emissions being mitigated as well as power generation CO2 emissions.

R&D and Demonstration of CO2 Capture Technology Before and After Combustion in Thermal Power Plants in China

By Xu Shisen and Liu Lianbo, China Huaneng Clean Energy Research Institute

ShisenTOCCarbon capture, use, and sequestration (CCUS) technology can potentially reduce greenhouse gas emissions on a large scale, and represents an important technological option for slowing carbon dioxide emissions in the future. According to studies by the International Energy Agency, application of CCUS technology is a crucial emissions-reducing measure together with improving energy efficiency and employing nuclear energy and renewable energies. By 2050, emissions reductions realized through CCUS are anticipated to account for 17% of total emissions reductions. China’s energy structure is dominated by coal; development of CCUS technology will be an important measure to effectively control greenhouse emissions. Meanwhile, it will help promote the transformation and upgrade of the power industry.

Development of Coal Gasification Technology in China

By Wang Fuchen, Yu Guangsuo, and Guo Qinghua, East China University of Science and Technology

WangTOCCoal is utilized in three ways in China: direct combustion (through coal-fired power plants and industrial boilers), coking, and gasification. Among these three methods, coal gasification is the cleanest option, and the most complex. Coal gasification accounts for 5% of China’s total coal consumption; it is a core technology in efficient and clean coal conversion, and important in the development of coal-based bulk chemicals (chemical fertilizers, methanol, olefins, aromatics, ethylene glycol, etc.), coal-based clean fuel synthesis (oil, natural gas), advanced integrated gasification combined-cycle power generation, polygeneration systems, hydrogen production, fuel cells, direct reduction iron-making, and other process industries. Coal gasification is not only the foundation for the modern coal chemical industry, and widely used in the oil refining, power generation, and metallurgical industries, it is the common key technology of these industries.

Global News

GlobalNewsPhotoCovering global business changes, publications, and meetings

Volume 4 Author Index

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

International Outlook


The National Key Research and Development Plan “Ultra-supercritical Circulating Fluidized Bed Boiler Technology Research and Development and Demonstration Project” started in Beijing in October. The four-and-a-half-year project is led by Shenhua Group, with 16 organizations in China participating in research and development. This project will research improvements for 660-MW ultra-supercritical circulating fluidized bed boilers and furnaces. The aim of the project is to promote large-scale clean combustion of China’s low-grade coals.

United Arab Emirates

In the United Arab Emirates (UAE), construction has begun on the US$1.8 billion Hassyan clean coal plant. The first phase of the project will be the construction of 1.2 GW. The first 600-MW unit is expected to be operational in 2020, with the second 600-MW unit coming online a year later. By 2023 a total of 2.4 GW will be generating electricity. The Dubai Electricity and Water Authority plant will provide a 12.5% boost to Dubai’s current grid capacity on completion. The aim is that 7% of electricity in Dubai will be generated by coal by 2030.


The election of Donald Trump as President and the Republican majorities in Congress have the potential to change the energy regulatory landscape in the U.S. As a candidate, Trump indicated his administration would not implement the Clean Power Plan advanced by the Obama administration. Specific changes in policy remain to be seen as Trump assembles his leadership team.

The opening ceremony for NICE America Research Inc. was held in Mountain View, California, in October. Dignitaries from the Shenhua Group, Consulate-General of the People’s Republic of China in San Francisco, U.S. Department of Energy, NICE headquarters, and the local government were in attendance. Dr. Yuzhuo Zhang, Chairman of Shenhua Group, addressed the audience, articulating his vision for the center and his excitement for the opening of NICE’s first international facility. After the ribbon-cutting ceremony, NICE signed memoranda of understanding with General Electric and Air Products to explore collaboration on fuel cells and hydrogen fueling, respectively.

NICE America Research Inc. will be the U.S. headquarters of the National Institute of Clean and Low-Carbon Energy (NICE), a R&D institute funded and administered by the Shenhua Group. The new research facility is tasked with developing and commercializing technology on shale gas conversion to value-added chemicals, carbon capture, utilization, and sequestration (CCUS), energy internet, and hydrogen energy. In addition, the new facility allows NICE to partner with leading U.S. academic/research institutions and enterprises to accelerate its clean energy development strategy.

Ribbon-cutting ceremony for NICE America Research Inc.


In a recent article in the Indian newspaper The Hindu, the World Coal Association’s Chief Executive, Benjamin Sporton, highlighted that the World Bank and other global development lenders such as the Asian Development Bank are not financing clean coal projects. He pointed out that not investing in supercritical and ultra-supercritical plants is resulting in countries building less efficient subcritical plants with much higher CO2 and particulate matter emissions. He also noted that, without financial support from international global lenders, India and other developing countries would be unable to meet their Paris Agreement targets. Mr. Sporton stated: “India’s Paris commitment includes building more supercritical and USC plants and the international banks must help them do that. The Intended Nationally Determined Contributions submitted by 19 countries—India included—said they were going to use coal.”

On 29 November 2016, the ASEAN Centre for Energy (ACE)—an independent intergovernmental organization within the Association of Southeast Asian Nations’ (ASEAN) structure that represents the 10 ASEAN Member States’ (AMS) interests in the energy sector—held a webinar titled “Coal in ASEAN After the Paris Agreement”. A blend of regional and international perspectives was shared by the panelists from the Ministry of Energy and Mineral Resources of Indonesia, Chulalongkorn University on behalf of Ministry of Energy of Thailand, the World Coal Association, and Global CCS Institute. The ASEAN region is one of the fastest growing economic regions in the world. The ASEAN region will continue to depend on fossil fuels, with coal as the main energy source to meet the increasing electricity demand, due to its high availability and low costs. A key message from the webinar was that there is a need for international community support to implement high-efficiency, low-emissions (HELE) and CCS technologies in ASEAN, so the region can contribute to the Paris Agreement while meeting the needs of its economic growth. The recording video, presentations, and related materials from the webinar can be accessed at

Key Meetings & Conferences

Globally there are numerous conferences and meetings geared toward the coal and energy industries. The table below highlights a few such events. If you would like your event listed in Cornerstone, please contact the Executive Editor at

Conference Name Dates (2017) Location Website
2017 12th Mercury Emissions and Coal Workshop and Conference
28 Feb–3 Mar
Mpumalanga, South Africa
15th Coaltrans China
10-11 April
Shanghai, China
CO2 Summit III: Pathways to Carbon Capture, Utilization, and Storage Deployment
22–26 May
Calabria, Italy
2017 8th International Conference on Clean Coal Technologies
8–12 May
Cagliari, Italy
The 13th China (Beijing) International Coal Equipment and Mining Technical Equipment Exhibition
13–15 June
Beijing, China

There are several Coaltrans conferences globally each year. To learn more, visit

Recent Select Publications

20 Years of Carbon Capture and Storage – Accelerating Future Deployment — International Energy Agency — This report reviews progress with CCS technologies over the past 20 years and examines their role in achieving 2°C and well-below 2°C targets. Based on the International Energy Agency’s 2°C scenario, it also considers the implications for climate change if CCS was not a part of the response. And it examines opportunities to accelerate future deployment of CCS to meet the climate goals set in the Paris Agreement. The full report is available at


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Development of Coal Gasification Technology in China

By Wang Fuchen
Professor, Associate Dean,
School of Resources and Environmental Engineering,
East China University of Science and Technology
Yu Guangsuo
Professor, Director,
Institute of Clean Coal Technology,
East China University of Science and Technology
Guo Qinghua
Associate Professor,
Institute of Clean Coal Technology,
East China University of Science and Technology

Coal is utilized in three ways in China: direct combustion (through coal-fired power plants and industrial boilers), coking, and gasification. Among these three methods, coal gasification is the cleanest option, and the most complex. Coal gasification accounts for 5% of China’s total coal consumption; it is a core technology in efficient and clean coal conversion, and important in the development of coal-based bulk chemicals (chemical fertilizers, methanol, olefins, aromatics, ethylene glycol, etc.), coal-based clean fuel synthesis (oil, natural gas), advanced integrated gasification combined-cycle (IGCC) power generation, polygeneration systems, hydrogen production, fuel cells, direct reduction iron-making, and other process industries. Coal gasification is not only the foundation for the modern coal chemical industry, and widely used in the oil refining, power generation, and metallurgical industries, it is the common key technology of these industries.1

The Inner Mongolia Rongxin Chemical Company Plant with the largest coal-water slurry single gasifier capacity in the world.


Research and development on China’s coal gasification technology began in the late 1950s. Government support has resulted in many new developments over the last 30 years, including:

  • Coal-water slurry gasification technology and the construction of a pilot plant in the Northwest Research Institute of Chemical Industry;
  • IGCC key technologies (including high-temperature purification) project;
  • A Pyrolysis, Gasification and High-Temperature Purification of Coal project completed in 1999;
  • Large-Scale and High-Efficiency Entrained-Flow Coal Gasification Technology project completed in 2009;
  • Large-Scale and High-Efficiency Clean Gasification of Coal and Other Carbonaceous Solid Raw Materials project completed in 2014.

During the 9th–12th Five Year Plans the East China University of Science and Technology carried out several coal gasification projects, including:

  • Development of a new model (Opposed Multi-burner, OMB) of coal-water slurry gasifier (coal consumption 22 tons of coal per day, t/d) using a pilot plant that was built in 2000 in cooperation with Lunan chemical fertilizer plant and China Tianchen Engineering Corporation (TCC); 2
  • “New Technology of Coal-Water Slurry Gasification,” supported by the National High Technology Research and Development Program of China (863 Program). Two industrial demonstration plants for the OMB coal-water slurry gasification technology were built in Shandong Lunan and Shandong Dezhou, respectively. The successful operation of the 1000-ton industrial demonstration plant of Yankuang Cathay Pacific Chemical Co., Ltd. (single gasifier with a capacity of 1150 t/d of coal, 4.0 MPa), as well as the domestic large-scale fertilizer project of Shandong Hualu Hengsheng Chemical Co., Ltd. (single gasifier with a capacity of 750 t/d of coal, 6.5 MPa) demonstrated engineering feasibility of this technology;
  • “New Coal-Water Slurry Gasification Technology for 2000-t/d of Coal”, supported by the 863 Program, is being used in a large-scale fertilizer plant;
  • “Research and Development and Demonstration of 3000-t/d Large-Scale Coal Gasification Key Technology”, also supported by the 863 Program, is another important advancement in coal gasification technology with China’s independent intellectual property rights;
  • “Research and Development of New Technologies for the Preparation of Synthesis Gas by Pulverized Coal Pressurized Gasification” project, a refractory-wall-type gasifier pilot plant, for which the operations and assessment were completed in 2004.3 Following this, the successful operations of the membrane-wall-type gasifier pilot plant were completed in 2007.

Moreover, Thermal Power Research Institute of State Power Corporation and others have further developed dry pulverized coal gasification technology with an industrial demonstration plant using a 2000-t/d single gasifier for power generation with a 250-MW IGCC.4

The Institute of Coal Chemistry, Chinese Academy of Sciences, has developed an industrial demonstration plant for fluidized bed oxygen/steam-blown synthesis gas (syngas) production. Its bituminous coal capacity is 200 t/d (normal pressure).

Tsinghua University has also established an experimental unit for multi-stage oxygen-fed entrained bed gasification. Tsinghua University and Shanxi Fengxi Fertilizer Industry (Group) Ltd. have jointly developed the Tsinghua gasifier. The first-generation gasifier adopted the refractory brick structure and oxygen stage-fed entrained bed gasification, with seven gasifiers that are in or are about to enter operation; the second-generation gasifier adopted a membrane wall structure that reduces operating costs and broadens coal adaptability.5 Currently, 28 gasifiers are under construction and 7 gasifiers are operating.

At present, the OMB coal-water slurry gasification technology is the most widely used, especially in China; this is also China’s first large-scale domestically built coal gasification system.


East China University of Science and Technology established China’s first large-scale cold-model entrained-flow gasifier unit with the support of government and industry. Researchers studied the refractory brick, burner, and other issues, gaining an in-depth understanding of the principle, flow field, mixing process, and burner atomization mechanism of the coal-water slurry gasification process. This research resulted in a proposal to develop a multi-burner coal-water slurry gasification technology plan. Figure 1 depicts a schematic of the OMB coal-water slurry gasification process. The technology involves processing syngas from raw materials such as pure oxygen and coal-water slurry. The technical characteristics of the technology include: (1) OMB coal-water slurry entrained-flow gasifier and compound-bed gas washing and quenching equipment; (2) three-unit combination comprising the mixer, cyclone separator, and water scrubber of the preliminary purification process for syngas; (3) direct heat exchange-type wastewater treatment and heat recovery technology for evaporative separation.

FIGURE 1. Process flow of OMB coal-water slurry gasification technology


The OMB coal-water slurry gasifier (Figure 2) has four symmetrical burners, located at the upper part of the gasifier chamber. This type of opposed impact gasifier overcomes the flaw of irrational residence time distribution in the single-burner coal-water slurry gasifier, as well as short residence time of partial reaction materials in the gasifier. The result is an improvement in gasification efficiency. Evidence from the research shows improvements with a high carbon conversion rate, low oxygen consumption, and less coal consumption.

FIGURE 2. OMB coal-water slurry gasifier

In comparison to the single-burner gasifier, the OMB gasifier has obvious advantages in large-scale gasification. At present, the OMB coal-water slurry gasifier has been adopted for the Inner Mongolia Rongxin Chemical Company, the largest-scale coal-water slurry gasification plant in the world.

Process Burner

The pre-filmed structure is adopted for the process burner of the OMB gasifier. In comparison to the GE (Texaco) burner, the biggest difference is that the pre-filmed burner avoids the premixing of central oxygen and coal-water slurry in the secondary channel by reducing the central oxygen channel. The pre-filmed burner’s advantages are good atomization performance, simple structure, low velocity of coal-water slurry outlet, and its ability to reduce or avoid wear and tear. The demonstration proves this new type of burner has excellent technological results and long service life. At present, the service life of pre-filmed process burners can reach about 90 days on the average. At Yankuang Cathay Pacific Co., Ltd, the longest service life of such a burner was 152 days.

Syngas Washing and Quenching System

Raw syngas produced in the gasification process at a high temperature with a large quantity of slag enters the washing and quenching chamber located below the gasification chamber for quenching, washing, and humidification. The compound-bed washing and cooling chamber contains a spray bed and a bubbling bed. The spray bed is formed by the washing and quenching ring and the dip tube, and the bubbling bed formed between the bubble breaker and the metal shell. This type of washing and quenching chamber abandons the traditional riser. With several bubble breakers installed in the bubbling area, the effects of air bubble breakup and gas-phase dispersal are realized, promoting the formation of a homogeneous gas-liquid mixture, the reduction of liquefied gas, and slag separation through sedimentation. Industrial plants demonstrate the advantages of the spray-bubbling compound bed in terms of washing and cooling efficiency, load adaptability, and operational stability.

Preliminary Purification System for Syngas

The preliminary purification of syngas based on the OMB gasification process adopts the idea of purification in stages; the ash carried by the syngas is passed through the mixer and the cyclone separator for elementary separation. Subsequently, the ash undergoes further separation of fine particles in the water scrubber. This reduces system pressure drop, prevents clogging of the purification system, and greatly reduces the solid content (<1 mg/Nm3) of the syngas in the system. The operation results indicate a system pressure drop upon preliminary purification of the syngas in stages of ≤0.1 MPa. The amount of ash content in the syngas from the scrubber is low and it can directly enter the transformation section without any pre-transformation after the separation of coarse particles in the cyclone separator. Other benefits are improving the water quality at the bottom of the washing tower without any blockage of the quench ring, and preventing the phenomenon of pressure drop increasing in the conversion furnace catalyst.

Wastewater Treatment System

The evaporative hot water tower is key equipment for the wastewater treatment system in the OMB gasification process. The black water undergoes flash evaporation upon a reduction in pressure in the evaporation room of the hot water tower. The steam enters the hot water chamber for direct heat transfer with the gray water and results in an improved heat transfer effect. In addition, this prevents fouling. The operation results show that the temperature between the flash steam exported from the evaporative hot water tower and high-temperature gray water is with a temperature difference of <4°C. The smaller design of the system reduces the need for pumping. Consequently, in comparison to single-burner gasification process, there is less rotating equipment which improves operational reliability.

Continuous Feeding Operation Under Pressure and Online No-Fluctuation Switching of Gasifiers

A set of independent feed systems (including an oxygen and a coal slurry feed) is used for each set of opposed process burners of the OMB coal-water slurry gasifier. When a pair of burner feeding systems malfunctions, the work can be suspended to carry out repairs, and the pair of feeding systems can reoperate again after the malfunction is fixed. Throughout the entire process, the other pair of burner feeding systems maintains normal operation, and ensures that the gasifier is only working under a reduced-load condition without the need to fully stop the whole process, thereby greatly reducing the risk of stoppage.

The online no-fluctuation switching of the gasifiers can realize no fluctuations in the upstream and downstream load capacities during switching operations. During the switching process, the continuous feed feature under pressure using this type of gasification technology has advantages. Stoppage and commencement of operations for the two pairs of burners can be carried out successively through the in-operation gasifier and the active-standby gasifier, thus achieving the switching of gasifiers. This mode of operation greatly improves the operational stability of the gasification system and significantly reduces the consumption of raw materials in the switching process.

Figure 3 depicts a typical load variation curve of two OMB coal-water slurry gasifiers (one in operation and one on standby) in the switching process. The figure shows that, where there is an increase of approximately 15% production capacity in the air separation unit, the gasification plant can guarantee the completion of the switching operation between two sets of gasifiers under a minimum production capacity of 85% of the downstream gas supply. The entire system is smooth and controllable throughout the switching process.

FIGURE 3. Load changes during the no-fluctuation switching period of gasifiers

For each numbered point:

  1. A (operating) gasifier starts to ramp down from 100%
  2. The air separation unit (ASU) starts to ramp up from 100%
  3. ASU with 115% production rate
  4. ASU starts to ramp down
  5. ASU back to 100% production rate
  6. B gasifier starts to 100% production rate
  7. A gasifier with 85% production rate
  8. A gasifier shuts down 2 (opposed) burners
  9. B gasifier with 4 burners operating
  10. A gasifier shuts down other 2 burners (all burners shut down)
  11. B gasifier starts up with 30% capacity (60% of design capacity of single burner), operating pressure starts to increase
  12. B’s pressure reaches designed pressure value, B’s syngas combined with A’s syngas and flow downstream
  13. A gasifier totally shuts down

Application of OMB Coal-Water Slurry Gasification Technology Project

China’s first large-scale coal gasification technology project was established in Yankuang Cathay Pacific Chemical Co., Ltd. in 2005. Using OMB technology provided a viable alternative and reduced the monopoly on advanced coal gasification technology by international multinational companies.

In 2014, the Inner Mongolia Rongxin Chemical Company conducted a successful test run of its gasification plant. The plant has three OMB coal-water slurry gasifiers with single furnace capacity of 3000 t/d of coal. This coal-water slurry gasification gasifier has the largest coal capacity per gasifier in the world. Since 2015 two gasifiers have operated at full capacity and are currently operating without any gasifier problems.

Compared to other coal-water slurry gasification technologies from overseas, the OMB coal-water slurry gasification technology has greater advantages in areas such as large-scale single-furnace processing, system performance indicators, stability and reliability, and patent licensing fees. The OMB technology is operating with 60 coal-water slurry gasifiers with a further 68 under construction in China and in the U.S. and South Korea. The maximum design capacity of a single gasifier has reached 3150 t/d of coal (dry basis).6

East China University of Science and Technology concluded a technology licensing contract with Valero Energy Corporation, the largest oil refining company in the U.S., in 2008. The technology licensing fee amounts to more than RMB100 million.7 In September 2016, another technology license was implemented with Korea’s TENT Company.

China’s first large-scale gasification project using OMB technology

The OMB coal-water slurry gasification technology advantages include high carbon conversion rate, facilitation of large-scale processing, and stable and safe operations. The OMB coal-water slurry gasification technology is one of the three internationally recognized coal gasification technologies, ranking with those of Shell and GE.8


Coal-water slurry gasification technology requires coal with better slurry flowing compared to pulverized coal gasification technology, which is more adaptable to a wider range of coals. China has also been developing pulverized coal gasification technology.

Pressurized Two-Stage Pulverized Coal Gasification Technology

Pressurized two-stage pulverized coal gasification technology was developed by Xi’an Thermal Power Research Institute Co., Ltd, which built a 36-t/d pilot plant built in 2005. A demonstration of 2000-t/d dry pulverized coal gasification technology was carried out at the Tianjin 250-MW IGCC Project which began operating in 2012.

Aerospace Furnace (HTL) Gasification Technology

The HTL gasifier employs the single-burner pressurized pulverized coal gasification technology. The technology is applicable for medium-sized gasification plants, with a coal-feed limit of 500–1000 t/d. In 2010, the first demonstration plant was constructed and put into operations in Anhui Linquan Chemical Industry Co., Ltd.9

Pulverized Coal Gasification Technology of SE Gasifier

East China University of Science and Technology and Sinopec Group jointly developed the single-burner membrane wall pulverized coal pressurized gasification (SE Gasification Technology). The SE gasification demonstration plant became operational at the end of 2014 and has a daily capacity of 1000 tons of coal.

The gasification coal used is based on a mixture of Guizhou and Shenhua coal with a ratio of 6:4. The fusion temperature of pulverized coal fed to the furnace is approximately 1300°C, and the ash proportion is 16%. The full-load assessment indicators are as follows: oxygen consumption rate, 331 Nm3/kNm3 (CO+H2); coal consumption rate, 569 kg/kNm3 (CO+H2); carbon conversion rate, 98.3%; efficient gas content, 89%; and ash/slag ratio, about 4:6. There are currently 13 sets of gasifiers being built with a 1500-t/d design capacity for each gasifier.10


China’s research and development of coal entrained-bed gasification technology, as well as engineering demonstration, long-term and efficient operation, and further large-scale projects, strongly supported the development of modern coal chemical industry. China possesses the largest coal-slurry gasifier in the world, and coal gasification technologies are internationally recognized. The establishment of large coal-water slurry gasification plants with a daily capacity of 3000 tons of coal is a prelude to a larger-scale demonstration of coal gasification technology. Past, present, and future research has enhanced, and continues to enhance, industrial application of coal gasification technology in China.


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  2. Yu, G.S., & Yu, Z.H. (2006). Development and industrial application of opposed multi-nozzle coal-water slurry gasification technology [in Chinese]. Science & Technology Industry of China, 2, 28–31.
  3. Guo, X.L., Dai, Z.H., Gong, X., Chen, X.L., Liu, H.F., Wang, F.C., & Yu, Z.H. (2007). Performance of an entrained-flow gasification technology of pulverized coal in pilot-scale plant. Fuel Processing Technology, 88, 451–459.
  4. Ren, Y.Q., Xu, S.S., Zhang, D.L., Xia, J.C., Zhu, H.C., & Gao, S.W. (2004). Experimental study of dry pulverized coal pressurized gasification technology [in Chinese]. Coal Chemical Industry, 32(3), 10–13.
  5. Zhao, T.B. (2013). Investigation on the operation and performance of coal-water slurry gasification in Tsinghua furnace [in Chinese]. Inner Mongolia Petrochemical, 4, 85–86.
  6. China Youth Online. (2016, 27 September). Multi-nozzle opposite type coal-water slurry gasification technology of East China University of Science and Technology once again goes abroad [in Chinese],
  7. China Chemical Industry News. (2016, 31 May). Rewriting the history of China’s coal gasification technology import [in Chinese]. R&D of the Clean Coal Technology Research Institute of East China University of Science and Technology documentary [in Chinese],
  8. Higman, C. (2013, 16 October). State of the gasification industry—the updated worldwide gasification database. Presented at Gasification Technologies Conference, Colorado Springs, USA.
  9. China Chemical Industry News. (2016, 24 March). Aspects of Chinese coal gasification technology market [in Chinese],
  10. China Chemical Industry News. (2014, 6 May). Coal gasification marches towards a “big” era. [in Chinese],


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R&D and Demonstration of CO2 Capture Technology Before and After Combustion in Thermal Power Plants in China

By Xu Shisen
China Huaneng Clean Energy Research Institute, President
Liu Lianbo
China Huaneng Clean Energy Research Institute, Deputy Director

Carbon capture, use, and sequestration (CCUS) technology can potentially reduce greenhouse gas emissions on a large scale, and represents an important technological option for slowing carbon dioxide (CO2) emissions in the future. According to studies by the International Energy Agency, application of CCUS technology is a crucial emissions-reducing measure together with improving energy efficiency and employing nuclear energy and renewable energies. By 2050, emissions reductions realized through CCUS are anticipated to account for 17% of total emissions reductions.1–3 China’s energy structure is dominated by coal; development of CCUS technology will be an important measure to effectively control greenhouse emissions. Meanwhile, it will help promote the transformation and upgrade of the power industry.

China’s power system features centralized emissions sources and produces large quantities of CO2 emissions. The most challenging aspect of CCUS technology is capturing CO2 at power plants (see Figure 1). However, CCUS is also one of the most efficient ways to reduce carbon emissions. CO2 capture technologies are divided into three categories: post-combustion capture, pre-combustion capture, and oxygen-enriched combustion.4 Significant R&D progress has been made on CO2 capture technologies worldwide. However, the high cost and high energy consumption of CO2 capture remain obstacles. This is currently where major breakthroughs are being made in R&D technology. Demonstration tests solve various problems in the development of this technology through practice, but also create a path for its scaled and commercial application, so as to realize its full potential for reducing carbon emissions.

FIGURE 1. Technical approaches for CO2 capture

China’s largest power generation enterprise, China Huaneng Group, is interested in developing CO2 capture technologies suitable for power plant conditions, including post-combustion and pre-combustion capture. The company has built and put into operation several CO2 capture test and demonstration facilities, and is using the knowledge and information from these tests to undertake long-term operational experiments as well as the verification and evaluation of new technologies. Meanwhile, by combining fundamental application studies in experiments and engineering design reviews, mature technologies will be further expanded to adapt to future requirements on emissions reduction technologies in terms of energy consumption, scale, and reliability.

Pre-combustion CO2 capture unit in Tianjin IGCC plant


Post-combustion capture refers to capturing or separating CO2 from flue gas behind the combustion equipment. Technical approaches to post-combustion capture include chemical absorption, adsorption, and membrane separation methods. Chemical absorption, the method used most extensively, takes advantage of the acidic properties of CO2; it normally uses alkaline solutions to absorb CO2. Regeneration of the absorbent then takes place by means of a reverse reaction.5–7 Figure 2 shows a typical post-combustion CO2 capture process. Through the absorbent’s absorbing process in the absorbing tower and the absorbent’s regeneration process in the regeneration tower, the CO2 becomes concentrated.

FIGURE 2. Conventional post-combustion CO2 capture process using chemical absorption

Development and Verification of a New Compound Amine Absorbent

In terms of large-scale CO2 emission reductions in coal-fired power plants, high energy consumption, easy degradation, and large loss of traditional absorbents are factors in the high application costs of CO2 capture technology. Huaneng Group is targeting these problems by conducting independent R&D of new absorbents, such as organic amine molecules to which Huaneng researchers are applying design evaluations on molecular structure and functional groups. The evaluations explore the impact of such factors as carbon chain length, hydroxy group location, types and positions of substituents, as well as the steric hindrance effect on the performance of absorbents. By using theoretical simulation and high-flux selection evaluation on compound formulas and pilot optimization, and by combining the evaluation and selection of the performance of absorbents, Huaneng has managed to develop a new type of energy-conserving, highly efficient absorbent with properties that feature high circulating efficiency, high absorbing load, and low energy consumption for regeneration and low steam pressure, oxidization resistance, and low corrosion.

Progressing from the experimental stage to the pilot stage, Huaneng has developed the HNC-1–HNC-5 series of absorbents, suited for use in power plants with different flue gas conditions. The HNC-2 absorbent had a three-month trial run in Beijing Thermal Power Plant’s capture device, starting in September 2011. During the pilot stage, only a slight adjustment to the operating conditions of the capture system was required. The CO2 absorption speed increased 30% and the usage life of the absorbents improved 50% compared with the original absorbents, thus greatly reducing the cost of CO2 capture.

In 2015, the HNC-5 absorbent was run continuously for over 4000 hours at a capture facility in Shidongkou Second Power Plant with a 120,000-t/yr capacity, and compared with MEA absorbent under the same conditions. The results showed that, under the same operating conditions, the solvent consumption can be reduced to 1kg/t CO2 and the energy consumption for CO2 capture was below 3.0GJ/t, 20% lower than MEA’s energy consumption for CO2 capture. In addition, degraded products were produced at a speed of 50% compared to MEA. This absorbent can reduce approximately 20% of the overall operational costs of capture, and this system can operate consistently in the long term.

Development of Slurry CO2 Absorbent

With traditional chemical-absorbing methods, a high percentage of water in the absorbent is one of the main reasons for high energy consumption for CO2 capture. Thus, increases in temperature and volatilization of water in the high-temperature desorption process will consume a large amount of energy. To reduce water involvement in the regeneration process, Huaneng has developed a slurry CO2 absorbent based on potassium carbonate solution (see Figure 3). Taking advantage of the difference between K2CO3 and KHCO3 in solubility, by precipitating KHCO3 through the crystallization process and by regenerating high-concentration KHCO3 slurry, water involvement in the regeneration process can be reduced and full use can be made of steam heat to reduce energy consumption in CO2 capture. Scaled technical tests in the laboratory have shown that the potassium carbonate-based slurry CO2 capture technology’s energy consumption reaches 2.6GJ/t CO2, 20% lower than MEA. In addition, the cost of loss also decreases by 22–50% compared to MEA.

FIGURE 3. CO2 capture process (left) and pilot plant using slurry absorbent (right)
(In the schematic: 1–4, absorber; 7, crystallizer; 10, concentrator; 12, mixing tank; 17, regenerator; 21, reboiler; 5, 9, 18, 19. pump; 6, 8, 11, 13, 15, 16, valve; 14, 20, heat exchanger)

Development of Extraction and Phase-Change CO2 Absorbent

To decrease water usage in the regeneration process, extraction concentration technology and CO2 capture research have been combined to develop a CO2 absorbent that can achieve self-concentration extraction phase separation. Without the need for additional energy consumption, this type of absorbent, upon loading CO2, can automatically be divided into liquid-liquid phases, and achieve redistribution of CO2 in these two phases (see Figure 4). CO2 is concentrated in the phase-rich layer with a redistribution degree of more than 95%. The phase-poor layer has virtually no CO2 load, effectively concentrating CO2 in the rich phase with a concentration rate of 60%. Moreover, the extraction agent has limited influence on the organic amine’s speed of and capacity for CO2 absorption. The real thermal flow heat measuring method shows that, compared to direct desorption, phase-rich desorption after layer separation can significantly reduce regeneration energy consumption by 20–30%.

FIGURE 4. Solvent phase separation upon CO2 absorption after 2 min, 4 min, and 10 min

Beijing Thermal Power Plant Factory’s CO2 Capture Device (3000 t/yr)

In July 2008, Huaneng Beijing Thermal Power Plant established China’s first CO2 capture test demonstration device with a capacity of 3000 t/yr.8 Since becoming operational, this CO2 capture plant has achieved continuous and stable performance. A series of studies has targeted problems such as solution consumption, steam consumption, and system corrosion in the operation process. The system and equipment are optimized through such measures as anti-corrosion treatment, capacity expansion of the circulation cooling water system, and restructuring and recycling discharged steam water from the reboiler for reuse. In this process, the specific solution consumption and loss at each consumption point is analyzed. Corrosion types can be analyzed by taking samples and performing long-term clip-on tests. Using new types of absorbent, the capture performance has been significantly improved and the capture cost has been greatly reduced.

Huaneng Shanghai Shidongkou Second Power Plant’s CO2 Capture Device (120,000 t/yr)

To verify the operational stability and the technical and economic parameters of a larger scale CO2 capture system, Huaneng built and put into operation China’s largest coal-fired power plant CO2 capture demonstration project, Huaneng Shanghai Shidongkou Second Power Plant’s CO2 capture device with 120,000-ton/yr capacity, at the end of 2009.

Since it began production, a series of experiments and studies have been carried out during different seasons to test and perfect the operation optimization over a full year. Studies on device corrosion, safe treatment of waste liquid of the absorbent, and system reconstruction also have been conducted to ensure stable operation of the device. Meanwhile, to address the problem of large absorbent consumption by every unit of CO2, the integration of decarbonized flue gas pre-treatment technologies with the main unit desulfurization system is being discussed and developed, and flue gas pre-treatment devices have been installed. After using the new type of absorbing solvent, the device’s heat consumption for capture has been reduced to less than 3.0GJ/t CO2 and power consumption to less than 60kWh/t CO2.

Changchun Thermal Power Plant’s CO2 Capture Device (1000 t/yr)

To test the adaptability of the technology of post-combustion power plant flue gas capture to the extreme cold in Changchun (northeast China), Huaneng Changchun Thermal Power Plant built and tested a CO2 capture device.9 Completed in early 2014, this pilot device has undergone a 1000-hour continuous test on multiple types of solutions, including MEA, over the past two years, verifying the operational status of the carbon capture system in extremely cold weather, and analyzing the CO2 absorption-desorption features and stability of various new solutions.

This capture device’s absorption tower uses medium-cooling technology that effectively increases the CO2 absorption rate of the solution and reduces the amount of solution in circulation. The regeneration tower uses mechanic vaporization recompression (MVR) technology to effectively recycle and reuse the residual heat at the bottom of the regeneration tower, thus increasing the system’s heat regeneration efficiency while reducing its energy consumption. The impact of important operational parameters (such as the liquid-gas ratio, volume fraction of CO2, and regeneration pressure) on the capture system’s regeneration power consumption was systematically studied. In addition to studying each solution’s corrosion on the system, corrosion-measuring tags were hung at the bottom of the absorption tower (rich solution), inside the disk of the middle cooler (half-rich solution), and at the bottom of the regeneration tower (hot lean liquid) to provide reliable evidence for choosing construction materials for a full-size design.

Gas Turbine Flue Gas CO2 Capture Test Demonstration Device

Currently, in addition to the demonstration projects mentioned above, many post-combustion capture projects have been put into use in coal-fired power plants across China, with a level of technical research in line with international standards.10 However, R&D on CO2 capture technologies for the gas turbine are still in the initial stages.

In recent years, with increasingly strict environmental standards, more and more power generation units globally have been using natural gas combined-cycle (NGCC) power generation. The promotion of R&D and the industrialization of CO2 capture technologies has also become a new topic of interest. Compared to flue gases in coal-fired power plants, the concentration of CO2 in gases during the NGCC power generation process is lower (approximately 3% compared to a coal gas CO2 concentration of 12–15%) and the oxygen concentration is higher (13–18% vs. 5% in coal gas).

Based on the characteristics of flue gas in gas turbines, and having learned from experience with carbon capture in coal-fired power plants, Huaneng independently developed China’s first pilot device for the capture of CO2 from gas turbine flue gas (see Figure 5). There are plans to use the device for further R&D testing. This device is designed to capture CO2 in NGCC flue gas, with a processing capacity of 1000 tons of CO2/year. The main part of the system is similar to a coal-fired power plant’s capture system and adds new types of energy-conserving units such as medium cooling and mechanical compressing units. To study the problem of secondary pollution from emissions, an online system and a test device with comprehensive functions were added and continuous follow-up and sampling inspection are being conducted on the flue gas discharge.

FIGURE 5. Pilot plant for CO2 capture from flue gas of natural gas burner

This project is part of a first-stage technical verification at a CO2 capture project in Mongstad, Norway, with a capacity of 1.2 million t/yr. The project is being operated in strict accordance with EU standards and management models. Under the precondition of guaranteeing a 84–91% capture rate, this device has continuously operated for over 3000 hours, with highly stable system functions and each parameter meeting the designated targets. It features low emissions of pollutants in tail gases of the absorption tower and low consumption of solvents; emission of solvents in tail gases was <0.17 ppmv and discharge of nitrite amine was <3μg/m3. No amine was identified. The discharge performance meets the environmental requirements of northern Europe.


Pre-combustion capture technology refers to transferring the chemical energy from carbon before the combustion of carbon-based fuel and separating the carbon from other substances carrying energy, thus achieving carbon capture prior to fuel combustion. Integrated gasification combined-cycle (IGCC) technology is commonly used for pre-combustion carbon capture. IGCC combines gasification and a gas-steam combined cycle, wherein fossil fuels will gasify and transform to synthetic gas (with the main contents being CO and H2). Then, using the water-coal gas transformation reaction, the CO2 concentration is increased. Hydrogen-rich gas after CO2 capture can be used for combustion and power generation, and the separated CO2 can be compressed, purified, and then utilized or sequestered.

IGCC integrates many advanced technologies to achieve higher thermal efficiency and extremely low discharge of pollutants. It is receiving more and more attention from major power companies worldwide. Because of the high pressure and low flow volume of synthetic gases in the IGCC power generation process, the concentration of CO2 is very high after the transformation reaction. Choosing pre-combustion capture technology will effectively reduce energy consumption and allow for a decrease in equipment size. The IGCC-based pre-combustion CO2 capture technology is an important technical category in large-scale carbon capture demonstration projects in today’s power generation field. The CCUS plans for the Hypogen (EU), ZeroGen (Australia), and New Sunshine (Japan) projects are all based on IGCC and pre-combustion CO2 capture.11

In 2004, Huaneng became the first power enterprise in China to create a “GreenGen” plan for near-zero carbon emissions.12 This plan studied, developed, demonstrated, and promoted an IGCC-based, coal-gasified hydrogen generation, hydrogen gas turbine combined-cycle power generation, and fuel battery power generation-focused coal base energy system, which would also facilitate CO2 separation and treatment. This plan will significantly improve the efficiency of coal-fired power generation and realize near-zero emissions of CO2 and other pollutants in coal-fired power generation.

In 2012, the first stage of “GreenGen” was completed when the Tianjin IGCC demonstration power station began operation. With an installed capacity of 265 MW, the station features the world’s first two-sectioned, dry coal powder pressure, pure oxygen combustion gasification furnace. This technology is Huaneng’s independently developed intellectual property. After a long cycle of demonstrated operation, the emissions performance of the power station has proven significantly superior to conventional coal-fired power generation units. Its major emissions parameters—dust, 0.6 mg/m3; SO2, 0.9 mg/m3; NOx, 50 mg/m3— indicate that the IGCC station has reached the emissions level of a gas turbine power generation unit.

During the design stage of the IGCC power station, Huaneng also began R&D and demonstration of a pre-combustion CO2 capture system. The technological design model of an IGCC-based CO2 capture system was established through technical comparison and selection. The technical approach chosen used a sulfur-tolerant shift, MDEA decarbonization and purification, compression, and liquefaction of CO2. The energy and material balance of the system were calculated using a model; the optimization of the fundamental design plan took into account the characteristics of the site.13 The transformation technology of this project adopts a low water-vapor ratio sulfur-tolerant shift and makes full use of the low water content in the feed gas of the two-sectioned furnace by regulating the inlet temperature of the first section of the furnace and water-vapor ratio. The transformation furnace’s reaction depth can be controlled, achieving partial transformation of high-concentration CO, and reduces vapor consumption and increases output. The MDEA desulfurization and decarbonization device uses the technology of sectioned absorption with lean solution and semi-lean solution. The regeneration process combines regeneration of a normal-pressure absorption tower with regeneration of the stripping tower, fully utilizing the physical and chemical absorption properties of the solutions to lower energy consumption.

This device began operation in July 2016. The CO content at the outlet of the transformation section is approximately 1%. The system has been running consistently. Calculations based on on-site operation data indicates the following: the device’s CO2 capture rate is more than 85%; the system’s energy consumption is lower than 2.5GJ/t CO2; and the CO2 capture capacity is 60,000–100,000 t/yr. After the compression and liquefaction of CO2, the next step is to conduct experiments on increasing the oil recovery rate and applying geo-sequestration. The separated hydrogen-rich gases will be compressed and sent into the gas turbine for mixed combustion. Relevant geological evaluation and research into CO2 injection is still underway. This demonstration system, upon completion, will become a pre-combustion CCUS system with the largest capacity internationally. It will be able to conduct various experiments under different loads and operating conditions, accumulating experience for exploration of CCUS technologies with low energy consumption and high recycling rate.


Dealing with climate change is receiving increased attention worldwide, but the sustainable development of traditional fossil fuel power generation technologies are facing a bottleneck. CO2 capture technology provides a new approach for power enterprises’ carbon emissions. Huaneng Group was the first in China to carry out research into capture technologies for coal-fired power plants. They are executing near-zero emissions projects with pre-combustion capture technologies and have carried out industrial demonstration of post-combustion capture in power plants. Focusing on the critical issue of reducing energy consumption and cost, Huaneng conducts application experiments on new technology and continuous operation demonstration projects of various sizes. Relevant technologies have reached an advanced standard worldwide, laying a solid foundation for Chinese power plants to use the technologies in the future.


  1. International Energy Agency (IEA). (2012). Energy technology perspectives 2012,
  2. IEA. (2013). Technology roadmap: Carbon capture and storage 2013,
  3. Intergovernmental Panel on Climate Change. (2014). Contribution of Working Group III to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change. Cambridge: Cambridge University Press.
  4. Metz, B., Davidson, O., Coninck, H., Loos, M., & Meyer, L. (2005). IPCC Special Report on carbon dioxide capture and storage. Prepared by Intergovernmental Panel on Climate Change Working Group III,
  5. Rochelle, G.T. (2009). Amine scrubbing for CO2 capture. Science, 325, 1652–1654.
  6. Wang, M., Lawal, A., Stephenson, P., Sidders, J., & Ramshaw, C. (2011). Post-combustion CO2 capture with chemical absorption: A state-of-the-art review. Chemical Engineering Research & Design, 89, 1609–1624.
  7. Kohl, A.L., & Nielsen, R. (1997). Gas purification. Houston, Texas: Gulf Publishing Company.
  8. Liu, L.B., & Huang, B. (2008). Technologies and critical equipment in 3000-5000t/a CO2 capture demonstration unit at a coal-fired power plant [in Chinese]. Electrical Equipment, 9(5), 21–24.
  9. Wang, S.Q., Liu, L.B., Wang, J.T., Guo, D.F., Gao, S.W., & Xu, S.S. (2015). Experiment on the optimization of regeneration power consumption in a 1000t/a flue gas CO2 capture unit [in Chinese]. Chemical Engineering, 43(12), 53–-57.
  10. Zhong, P., Peng, S.Z., Jia, L., & Zhang, J.T. (2011). R&D and demonstration of CCUS technologies in China [in Chinese]. China Population, Resources and Environment, 21, 41–45.
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  13. Cheng, J., Xu, S.S., & Xu, Y. (2012). Design of IGCC-based pre-combustion CO2 capture system [in Chinese]. Proceedings of the CSEE, 32 (S1), 272–276.


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The Future of CCS in Norway

By Camilla Bergsli
Communication Adviser, Gassnova SF, Norway

The Norwegian government seeks to realize at least one full-scale carbon capture and storage (CCS) demonstration project by 2020, and three industrial carbon capture projects are about to enter the concept phase. Twenty years of experience with full-scale CCS combined with the world’s largest CCS test facility and more than 20 years of CCS research underlie the country’s ambition to contribute to further development of CCS. This article examines Norway’s efforts to mitigate CO2 emissions by applying CCS and the importance of industrial emissions being mitigated as well as power generation CO2 emissions.


In 1990, Norway implemented a CO2 tax. This led to two CO2 storage projects on the Norwegian continental shelf: Sleipner and Snøhvit,1 both operated by the Norwegian oil company Statoil. Since 1996, CO2 from natural gas production on the Norwegian shelf has been captured and reinjected into sub-seabed formations. The CCS projects on the Sleipner and Snøhvit petroleum fields are the only CCS projects currently in operation in Europe and the only projects offshore. Since 1996, up to one million tonnes of CO2 annually has been separated during processing of natural gas from the Sleipner Vest field, and stored in the Utsira formation. Since 2014, CO2 from natural gas production at the Gudrun field has also been separated out at the Sleipner Vest platform and stored in the Utsira formation. Since 2008, the Snøhvit facility on Melkøya has been separating the 5–6% content of CO2 from the well stream before the gas is chilled to produce liquefied natural gas (LNG). This CO2 is transported back to the Snøhvit field by pipeline and injected into a sub-seabed formation.

Location of CCS projects in Norway

Gassnova, owned by the Norwegian Ministry of Petroleum and Energy, was established in 2007. Its purpose is to manage Norway’s interests regarding technology development, and capture, transport, injection, and storage of CO2, as well as to implement the projects determined by the enterprise. Gassnova’s work is aimed at reducing the costs of CCS, as well as advising the Ministry on CCS matters.

Mongstad CCS worker (Courtesy of Styrk Tronsen)

World’s Largest Technology Center for CO2 Capture

In addition to administering the government’s full-scale projects and the CCS research and demonstration program CLIMIT, Gassnova oversees the state’s interest in the CO2 Technology Centre Mongstad DA (TCM). TCM was inaugurated in 2012, and is still the world’s largest and most advanced test center for CO2 capture technologies. It is a joint venture between the Norwegian state, Statoil, Shell, and Sasol.

TCM’s focus is on testing and improving CO2 capture technology in the final stage before full-scale operation. It aims to help reduce the cost and risks of CO2 capture technology deployment by providing an arena where vendors can test, verify, and demonstrate proprietary CO2 capture technologies.

TCM provides access to two intrinsically different, real-life flue gases for testing: flue gas from a gas turbine power plant and flue gas from a refinery catalytic cracker, which resembles flue gas from a coal-fired power plant. The CO2 concentration is about 3.5% and 13%, respectively, with flexibility to dilute/enrich the flue gas sources. Uniquely, this enables vendors to flexibly test their capture technologies for both coal- and gas-fired power plants, as well as on other industrial applications, using the same facility. The TCM test site is equipped with two distinct units for post-combustion capture technology verification with space available to add others.

Four companies have successfully validated their technology at TCM: Aker Solutions, Alstom (now GE), Shell Cansolv, and Carbon Clean Solutions Limited (CCSL). ION Engineering has just started its testing program.

Industrial CCS

Without CCS, the global climate objectives set in Paris in 2015 will be difficult to achieve. The importance of using CCS has been stated by the UN’s Climate Panel (IPCC) and the International Energy Agency (IEA). The Norwegian parliament agreed to the government’s CCS strategy when it was proposed in 2014. The strategy encompasses a broad range of activities.

Feasibility studies were completed in July 2016.2 Three companies studied the feasibility of CO2 capture at their industrial facilities and Gassco and Statoil studied transport and storage feasibility:

  • Norcem AS assessed the possibility for capturing CO2 from the flue gas at its cement factory.
  • Yara Norge AS assessed CO2 capture from three different emission points at its ammonia plant.
  • The Waste-to-Energy Agency for the Oslo municipality (EGE) assessed CO2 capture from its energy recovery plant.
  • Gassco completed a ship transport study (CO2 fullskala transport, mulighetsstudierapport [Gassco DG2], June 2016).
  • Statoil ASA completed feasibility studies of CO2 storage at three different sites on the Norwegian continental shelf.

The purpose of the studies was to identify at least one technically feasible CCS chain (capture, transport, and storage) with corresponding cost estimates. The results from the feasibility studies showed that it is technically feasible to realize a CCS chain in Norway.

The studies demonstrate a flexible CCS chain. Instead of transporting CO2 by pipeline to a storage site, the plan is to transport CO2 by ship to a hub tied to the storage site. A flexible transport solution and ample storage capacity could contribute to realizing capture from additional CO2 sources. That would mean that the initial investment in CO2 infrastructure could be utilized by several projects.

CO2 capture is technically feasible at all three emission locations. An onshore facility and a pipeline to the Smeaheia marine aquifer is considered the best storage solution; the CO2 captured will be transported by ship. The cost is lower than for projects considered in Norway earlier: Planning and investment is estimated at US$0.86–1.5 billion (excluding VAT). These costs will depend on the quantity of CO2 captured, where it is captured, and the number of transport ships needed. Operational costs vary between approximately US$42 and US$106 million per year for the different alternatives. The cost estimates are based on the reports from the industrial players and have an uncertainty of ±40% or lower.

The government’s budget proposal for 2017 includes funding for the continued planning of full-scale CO2 capture plants on all three industrial sites. The government proposes allocating US$44 million to concept studies. The timeline is for a full-scale CCS plant to be operational by 2022 with a basis for investment decision presented in autumn 2018. The Norwegian parliament will then make a final investment decision in spring 2019.

Industrial Emissions Sources

In its feasibility study, Norcem (owned by Heidelberg Cement) assessed solutions for capturing 400,000 tonnes of CO2 per year from its cement plant in Brevik. Norcem seeks to achieve zero CO2 emissions from its concrete products in a life-cycle perspective by 2030. In this context, the company investigated the possibilities of CO2 capture from the flue gases in cement production. In 2010, Norcem started CLIMIT-supported projects to assess alternative capture technologies. Results from these projects were used as a basis for the feasibility study.

Before the feasibility study, Norcem determined that, from the perspective of what is achievable by 2020, amine technology is the most suitable capture technology and chose Aker Solutions as its technology supplier through a broad-based technology and supplier evaluation process. Aker Solutions conducted more than 8000 hours of testing on Norcem’s flue gas, and the technology was thus considered sufficiently qualified by Norcem to remove CO2 from its flue gas. Norcem placed particular focus on how residual heat from cement production can be used for CO2 capture. Available heat makes it possible to capture about 400,000 tonnes of CO2, which corresponds to approximately half of the plant’s total CO2 emissions. This was key when designing the CO2 capture plant. Suitable solutions have also been found for interim storage and shipping of CO2 on the quay in Norcem’s area. When Norcem is able to capture 400,000 tonnes of CO2 per year, in combination with the use of CO2-neutral energy (biofuel) in production, it will be able to achieve its goal for zero CO2 emissions from its products in a life-cycle perspective.

Yara Norge has total CO2 emissions annually of 895,000 tonnes from its ammonia plant in Porsgrunn. The company estimates it could capture 805,000 tonnes of CO2 from the plant per year or 90% of the plant’s CO2 emissions. This would come on top of the annual 200,000 tonnes that Yara already captures annually and sells for use within food production.

Mongstad CCS Plant (Courtesy of Styrk Tronsen)

Yara has prioritized reducing greenhouse gas emissions from its production for many years. Its primary focus has been reducing nitrous oxide (NOx) emissions, with major reductions achieved. NOx is a greenhouse gas with a high CO2 equivalent, and a worldwide agreement on NOx reductions is included in the Gothenburg Protocol, signed in 1999.3 Yara first examined the establishment of a CO2 capture plant from ammonia production while working on the feasibility study. The production chain for compound fertilizer starts with making ammonia. This is the most CO2-intensive step in the process.

Ammonia can also be purchased in a global market. The ammonia plant in Porsgrunn is thus in a competitive situation where the cost of producing ammonia for compound fertilizer production must be cheaper than purchasing ammonia (including transport costs). There are three primary sources of CO2 emissions from the ammonia plant. The first two come from the process of cleaning CO2 from the production stream (through absorption of CO2 in water, so-called water wash). The third source is flue gas from a gas-fired reformer. This will require a CO2 capture plant with secondary combustion technology. Yara chose not to commit to one technology supplier in the feasibility study, but rather used an independent study supplier who designed and calculated the costs for an amine-based plant using freely accessible information about the commercially available amine, monoethanolamine (MEA).

Oslo municipality, represented by the Waste-to-Energy Agency (EGE), has assessed the possibility of capturing 315,000 tonnes of CO2 per year from the energy recovery plant at Klemetsrud. This constitutes about 90% of the total CO2 emissions from the plant. Klemetsrud is planning to ramp up production, thereby also increasing CO2 emissions from the plant. EGE has assessed two different capture technologies, and chose Aker Solutions and GE as sub-suppliers in an open competitive tender process. Both GE’s and Aker Solutions’ capture technologies are based on absorption technology, but they use different types of solvents. Aker Solutions’ technical solution is based on use of their proprietary amine, whereas GE’s technology is based on chilled ammonia. Both technologies use heat pumps and steam turbines to recover and return sufficient thermal energy to allow the energy recovery plant to maintain the same thermal energy balance, thus allowing it to maintain its deliveries to the district heating grid in Oslo. Both technologies will use electricity produced at the energy recovery plant. Efficient energy integration and the use of air coolers have removed the need for establishing a cooling water system or reinforcing the electricity supply for the plant.


In Norway, there is a broad commitment to CCS in the climate policy. Gassnova SF is the Norwegian state’s tool for CCS, following up the state’s interests in CCS, coordinating the projects selected, and advising the authorities on CCS matters.

The Norwegian government’s strategy for CCS aims at identifying measures to promote technology development and to reduce the costs of CCS. The government’s CCS policies span a broad range of measures including funding for research, development, and demonstration; realizing a full-scale CCS facility; transport, storage, and alternative use of CO2; and international cooperation for promoting CCS.

An important purpose of the CCS strategy is to increase knowledge sharing and contribute to global deployment of CCS.

The different business sectors in Norway have in 2016 worked on their roadmaps toward 2030/2050 as support for the government in following up on its commitments made in the Paris Agreement. The industry sector in Norway is highly engaged in CCS. The Federation of Norwegian Industries’ new roadmap for the process industry contains a vision of combining growth and zero emissions by 2050.4 This is impossible without CCS due to emissions being unavoidable in many industrial processes. Both Norcem and Yara have contributed to the work on this roadmap.

The municipality of Oslo has adopted its own climate and energy strategy.5 The CCS project at its fully owned waste-to-energy plant at Klemetsrud is an important project for this strategy.


  1. Hagen, S., et al. (2015, 10 September). Offshore CCS-projects in Norway. 20 years of experience and 20 million tons CO2 stored. CCS workshop at ISO/TC 265 Plenary Meeting. Statoil,
  2. The Norwegian Ministry of Petroleum and Energy. (2016, July). Feasibility studies on full-scale CCS in Norway,]
  3. United Nations Economic Commission for Europe (UNECE). (1999). Protocol to Abate Acidification, Eutrophication and Ground-level Ozone. The 1999 Gothenburg Protocol to Abate Acidification, Eutrophication and Ground-level Ozone,
  4. The Federation of Norwegian Industries. (2016, May). Økt verdiskaping med nullutslipp i 2050 [in Norwegian],
  5. Municipality of Oslo. (2016, June). Climate and energy strategy for Oslo,

The author can be reached at


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New British Deep Mine to Deliver 50-Year Coking Coal Project

By Tony Lodge
Research Fellow, Centre for Policy Studies, London

The British government’s plan to ban all coal-fired power stations by 2025 has made headlines around the world.1 Many will now close early and, with that closure, the mining, coal handling, and import facilities that once dominated British ports will become redundant. Though now in decline, this formerly large thermal coal dependency supported many deep and surface mines across Britain and supplied thermal coal internationally. Britain’s electricity supply industry is now looking to combined-cycle gas turbine (CCGT) plants, renewable energy, and new nuclear power plants in its quest to meet ambitious CO2 reduction targets.

But the end of thermal coal mining and coal-fired electricity generation in Britain risks overshadowing significant new coal mining ambitions to supply Europe’s growing coking coal demand. The British metallurgical coal (also known as hard coking coal) resource is significant and of high quality. It is this prospect, as well as the growing markets in the recovering European steel-making sector, that has prompted a pioneering British project to propose and seek to develop Britain’s first new deep coal mine for 30 years.

West Cumbria Mining (WCM) is at the forefront of plans to produce some of the finest hard coking coal in the Western Hemisphere with production planned to start in 2020. Importantly, this coal production will not face the UK government’s high carbon taxes that have penalized thermal coal burning power plants as it will be used in the steel-making sector. This distinction is important; this is not an energy-related project, but rather a 50-year mining operation to supply the steel- and iron-making industries with high-quality metallurgical coal.

A visual image of the proposed new mine’s surface buildings

The timing of this project is important. Morgan Stanley has declared coal to be “the spectacular turnaround story of 2016”.2 On the back of Chinese coal production caps, coal prices have soared with coal vastly outperforming other commodity markets. The value of coking coal shipped from Australia, the world’s top exporter of the industrial commodity, had tripled by December 2016 to more than US$300 a metric ton for the first time since 2011. Macquarie forecasts coking coal to stabilize at around US$200 a ton, with global output of metallurgical coal remaining in high demand as steel mills source more supply.

WCM has secured the rights to extract metallurgical coal from the rich offshore coal seams of the Cumbrian coast in the North West of England. The company, led by CEO Mark Kirkbride, plans to use two abandoned drift tunnels constructed to access a former anhydrite mine. These will connect the offshore coal resource with an abandoned industrial site onshore where modern, low-profile coal treatment and handling buildings will be sited. An underground conveyor will move coal to a rapid rail loader situated on the existing coastal railway less than a mile from the site.

The proposal is ambitious both in its design and output targets. It will utilize state-of-the-art technology and mining methods to achieve production of around 3 million tonnes per annum, aiming to deliver up to 2.5 million tonnes of saleable metallurgical coal product a year.A The target seams are High Volatile Hard Coking Coals (HV HCC). They are sought by European steelmakers due to their excellent furnace performance characteristics (very high fluidity) and extremely low ash and phosphorous content.

Planning consent is being sought in spring 2017 from local government bodies to take the initial development of the project to the next phase of what will be one of the major metallurgical coal mining operations in Europe. Local political figures strongly support the project, which will create more than 510 skilled mining, engineering, and supporting jobs.B

The Cumbrian coast has a rich mining history

Bad headlines dominated the European steel sector in 2015 with prices at record lows, but there are now signs of growing stability and rising prices.3 WCM’s product would be a core component for incorporation within a blend of other types of metallurgical coals to produce suitable coke for use in iron and steel production. Indeed, it is extremely similar in character to the premium hard coking coals mined in the eastern U.S. and currently imported and consumed by the UK and European steel industry. The WCM coal is the equivalent of US HV-A material, a key market benchmark coal for pricing purposes.C

Consequently, the future global market outlook for HCC demand is key. World and European steel demand is set to grow significantly by 2030, particularly in the construction sector. The forecast global HCC demand to meet such growth is unlikely to be met by operating and proposed new metallurgical coal mining projects. There is a real risk of a future global shortage in HCC supply with so few new mining projects being proposed.D

Forward planning by WCM has already identified a sea freight export facility in North East England, where its metallurgical coal can be exported easily and quickly from the deep-sea wharf Redcar bulk terminal facility into Europe. This was until recently part of the vast SSI steelworks that became an early victim of the collapse in world steel prices. This coal loading berth at Redcar is a direct 100-mile rail journey from the proposed mine. WCM will also seek to supply metallurgical coal to British steelworks which are showing signs of recovery following the recent slump in output and prices.

The mine’s development and operation will be undertaken by bolter-miners and remote operated continuous miners, working a partial extraction run-out and pocket retreat mining method. WCM argues that this method offers the greatest flexibility and can respond quickly to prevailing ground conditions to maintain consistent production levels, especially where multiple mining sections are operated.

Importantly, given local environmental considerations, the mine will have state-of-the-art low-profile surface buildings to ensure minimum visual impact. This will be in stark contrast to the large headstock and winding gear of traditional mine buildings, which can still be seen in the area where they have been preserved as a monument to the area’s industrial legacy. There will be no tips of mine discard, as this will be transported from the site by rail to a quarry where it will be crushed and screened prior to use as fill material on construction and other such projects.

Although the UK is turning away from thermal coal to generate electricity, this new project is attracting considerable interest as curious observers learn that not all coal is the same. As readers of this journal know only too well, there are various types, qualities, and consequently different markets.

As coal’s thermal markets come under greater policy strain, projects like this allow the fuel a valuable platform to demonstrate its alternative and varied uses. Consequently, it deserves the attention, focus, and support it is receiving.


  • A. Author interview with WCM CEO Mark Kirkbride, December 2016.
  • B. WCM has met and is working closely with Jamie Reed, local Member of Parliament, local councillors, and policy leaders.
  • C. Key parameters and qualities of WCM coal are equivalent to US High Volatile ‘A’ Hard Coking Coal type.
  • D. Analysis and forecasts provided to WCM by Wood Mackenzie.


  1. Reed, S. (2015, 18 November). Britain calls for closing of coal-fired power plants by 2025. New York Times,
  2. Hoyle, R. (2016, 11 November). Coal prices on fire. The Wall Street Journal,
  3. Staff. (2015, 9 November). Steel industry calls for EU action on Chinese imports. BBC News,


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Phasing Out Coal-Fired Power Plants in Alberta by 2030: Recent Developments

By Babatunde Olateju
Manager, Carbon Capture and Utilization, Alberta Innovates
Surindar Singh
Executive Director, Clean Technology, Alberta Innovates
Jamie McInnis
Portfolio Manager,
Reservoir Simulation and Modelling Research Group,
University of Calgary


The province of Alberta, located in Western Canada (see Figure 1), is regarded as the pillar of Canada’s energy economy. It is home to the third largest oil reserves in the world,1 produces 68% of Canada’s natural gas,2 holds significant renewable energy resources, and is the site of Canada’s first commercial windfarm.3 Yet the most abundant fossil fuel energy resource in Alberta is coal. The energy content of coal in Alberta is greater than the energy content of natural gas and oil combined, including the oil sands.4 Coal-bearing formations underlie 304,000 km2 or 46% of Alberta’s total area, making the formations larger than the United Kingdom. Alberta’s coal resource is estimated to be greater than 2 trillion tonnes.4

FIGURE 1. Location of Alberta in Western Canada

Since the deregulation of the Alberta electricity market in 1996, electricity supply has been dominated by coal. It accounted for 51% of electricity generation in 2015 and 39% of the current generation capacity in the province.5 Alberta’s electricity sector accounted for 17% of its greenhouse gas (GHG) emissions6 in 2013. Coal-fired plants are the primary source of these emissions. Against this backdrop, a newly elected provincial government in May 2015 brought a change to the political leadership and also to the provincial climate change policy. In June 2015, the provincial government introduced bold new changes to the Specified Gas Emitters Regulation (SGER).A The emissions levy was increased from the original $CDN15/tonne (US$11.19) to $CDN30/tonne (US$22.13) by 2017.7 Additionally, a higher performance criterion was put in place: By 2017, emissions intensity must be reduced by 20% from an established baseline, as opposed to the original target of 12%.7 In November 2015, the government articulated the following points relevant to the electricity sector, as part of its Climate Leadership Plan:

  • Mandated phaseout of pollutant emissions from coal-fired plants by 2030.
  • Coal-fired plants will pay $CDN30/tonne for emissions, based on an emissions performance standard, by 2018.
  • Replacement of existing coal-fired plant capacity (6299 MW), with about 4200 MW of renewables (two-thirds of existing coal capacity) and 2100 MW of natural gas (one-third of existing coal capacity), will be achieved by 2030.
  • Thirty percent of Alberta’s electricity generation (MWh) will be from renewables by 2030.8

Keep Hills 3 coal-fired power plant

In November 2016, plans for a capacity market (by 2021) to complement Alberta’s current energy-only market system were announced.9 In the energy-only market system, generators are only compensated for the actual amount of energy (MWh) supplied to the grid. The introduction of a capacity market is intended to strengthen the reliability of supply and stabilize electricity prices, while providing an opportunity for generators to earn revenue by making generating capacity (MW) available to be dispatched when required.

In light of this new era in Alberta’s electricity market, this article aims to address the following questions: (1) What do these changes mean for coal-fired power plants in the context of Alberta’s electricity market? (2) What are the key determining factors for the successful phaseout of coal and what are the implications? (3) Are we living in a post-coal era or is a future coal resurgence possible?

To address these questions, we first need to understand the current basic Alberta economics of electricity generation as it pertains to coal-fired plants.


In Alberta’s wholesale electricity market, the price is determined by supply and demand forces; a price floor of $0/MWh and a price celling of $999/MWh are set in place. The mechanism to determine the price of electricity involves the Alberta Electric System Operator (AESO) using a merit-order system where generators offer bids to supply electricity at various prices (often related to their marginal cost of electricity generation). The AESO dispatches supply bids in ascending order of costs—i.e., the least-cost bid is dispatched first, and so on—to service demand. The last bid dispatched within a one-minute time frame sets the system marginal price (SMP). Finally, the average of the SMP for each minute in a given hour sets the hourly pool price. The hourly pool price is used to compensate all generators that supply electricity in a particular hour.10 An exception occurs when a supply bid was dispatched for only part of an hour, at a price greater than the average price in that hour. In such a case, the AESO pays the supply bid price for that portion of that hour.10

The economics of operating coal-fired plants in Alberta are quite challenging for several reasons. First, to coincide with the oil price shock in the last quarter of 2014, electricity demand weakened (about two-thirds of Alberta’s electricity demand is industrial) as new supply capacity was about to be commissioned.B As a result, the pool price began a steep descent and reached levels (< $CDN20/MWh) not seen in two decades.11 Second, sustained low natural gas prices make gas plants a competitive option relative to coal, particularly for baseload operations. Third, the April 2015 introduction of wind power plants into the merit-order system10,12 added downward pressure on the pool price. Wind plants have near-zero marginal costs and can afford to bid into the market at low energy prices that are uneconomic for coal. With significantly increased renewable penetration anticipated (plants with generally low marginal costs), the downward pressure exerted on prices will likely increase in magnitude. Last, the changes to the SGER resulted in a material increase in the cost of compliance for coal power plants; it is expected to rise from $CDN2/MWh in 2015 to $CDN6/MWh in 2017.13


The difficult economic circumstance of coal-fired plants is not unique to Alberta; it is indicative of a broader trend in electricity markets across North America. For example, both the Electric Reliability Council of Texas (ERCOT) and wholesaler PJMC have low natural gas prices. Additionally, the increased penetration and cost-efficiency of renewables such as wind and solar are reducing the market share and competitiveness of coal significantly.14 A successful phaseout of coal by 2030 must be done in a planned, orderly fashion to ensure the reliability of the grid, affordability of energy prices, and the continued downward trend of GHG emissions in the future. This is dependent on several factors that serve as key determinants of success in the impending phaseout.

Striking a Delicate Balance

The rate at which coal is phased out vis-à-vis the rate at which gas and renewable generators are phased in is a delicate balance that needs to be carefully struck.

There are many implications to this careful balancing act. The phaseout of coal will result in gas becoming the dominant baseload energy generation option. Moreover, due to the intermittency of renewable generators, natural gas peaking plants will increasingly be relied upon to firm up supply; these peaking plants will have attendant GHG emissions during their operation. With this in mind, there is an opportunity for technological innovation that will facilitate the penetration of utility-scale low-carbon energy storage technologies (e.g., pumped hydro, redox flow batteries, sodium sulfur batteries, etc.) in Alberta’s electricity market. Energy storage has the potential to mitigate the intermittency of renewables, without the attendant operational GHG emissions aforementioned. Gas being the anchor baseload generator will also lead to the increased exposure of the grid to the dynamics of natural gas prices which, historically, have been quite volatile. Furthermore, the concentration of electricity supply from one fuel type, i.e., gas, is likely to create the same challenges of phasing out a dominant generation option such as coal. From a GHG perspective, gas-fired plants of today are likely to be the coal-fired plants of tomorrow, as our energy economies become increasingly GHG averse. A portfolio approach that ensures sufficient diversification of the energy supply mix will provide stability for the grid in the future.

The Incentive to Build

In light of the coal phaseout, the need for additional renewable capacity in Alberta’s electricity market cannot be overstated, if the climate leadership objectives8 are to be realized. However, in a low-price electricity market, the incentive to build additional capacity is practically nonexistent. Addressing this issue is quite complex and presents several challenges. The Alberta government has introduced a renewable electricity incentive program (to be carried out by AESO) that will provide support for the addition of 5000 MWD of renewable capacity by 2030. The details of the first auction (400 MW of renewable capacity) have been released by AESO.15 Some key features of the auction include: a competitive bidding process; use of existing transmission or distribution infrastructure; renewable credits provided will be indexed to the pool price, i.e., a contract for difference; and plants must be operational by 2019. As reported by AESO,15, the indexed renewable credits create three possible scenarios that are a function of the (winning) bid priceE in the auction and the pool price of the market.

In the first scenario, if the pool price is lower than the bid price—the government pays the difference to support the project. Second, if the pool price is equal to the bid price—there are no payments made by the government. Last, if the pool price is higher than the bid price—the plant owner pays the government the difference. Going forward, the competitive nature of this entire 5000-MW program and the effective apportioning of the risks involved will be crucial in creating a favorable investment environment, while also making electricity prices affordable.

Genesee 3 Coal Power Plant

Accessing the Opportunity of Change

Alberta’s electricity market is in a state of transition. This fluid state of the market has included competitive auctions for renewable energy generation, along with the planned addition of a capacity market by 2021. The capacity market, depending on the way it is designed, holds significant promise not just in enhancing the reliability of supply, but in incenting innovation. Apart from “traditional” generators (gas, hydro, wind, solar, biomass), nontraditional generators, which have baseload and load following functionalities, with low to zero GHG emissions during operation, are likely to benefit significantly from the revenue certainty a capacity market provides in a carbon-constrained electricity sector. Nontraditional technologies that hold some potential in this regard include commercial technologies such as geothermal power, as well as emerging technologies including next generation small modular nuclear reactors. These technologies create opportunities for innovation and the mitigation of greenhouse gas emissions from the electricity sector.

That said, whether Alberta’s future electricity market will encompass the nontraditional technologies as legitimate participants will become clearer as time progresses.


Some would argue that coal in Alberta has no future and is slowly becoming a relic of the past. This argument is founded on a number of factors, but often, it does not consider that coal is a resource, not just a fuel for electricity. Coal as a resource will remain the same; recovery and production technologies will evolve. The evolution of technology in response to the economic, environmental, and social constraints will be a crucial determinant of the question: Will coal be back? In this light, several technological trends and opportunities are worth highlighting.

In the near term, before the 2030 phaseout, the co-firing of coal with other carbon-neutral feedstock such as biomass, economics permitting, provides an opportunity to lower the cost of compliance of coal-fired plants (due to the reduced GHG emissions) and utilizes potentially stranded coal assets.

The technological development and maturity of carbon capture and sequestration as well as underground coal gasification, considering their cost effectiveness, environmental performance, and social acceptability, has the potential to introduce new life into coal for the production of fuels; for example, hydrogen, synthesis gas, dimethyl ether, and others. Carbon conversion technologies that transform CO2 into a value-added product such as fuel or cement introduce additional potential for the environmentally sustainable use of coal. Finally, coal can be used in non-combustion applications. Current efforts are being made to extract rare earth metals from coal,16 which enable crucial functionalities in renewable technologies and other technology platforms such as consumer electronics and aerospace. New materials produced from coal, such as carbon foam,F are alternative uses of coal that could be sustained in a low-carbon era.


For the phaseout of coal to be conducted successfully without adverse impacts on Alberta’s grid, it must be undertaken in a careful, deliberate, and orderly manner. Despite the need for new capacity to come online to replace coal-fired plants, the effective apportioning of the risks involved should be carefully considered. The future concentration of supply on one fuel type (i.e., gas), with limited diversification of the supply mix, is likely to create the same challenges currently being experienced in phasing out coal-fired plants, as energy economies become increasingly GHG adverse. Finally, we must remember that technology rose to the occasion to find ways to access and utilize coal during the Industrial Revolution. Technological innovation will be vital if coal is to have a place in an energy future with heightened environmental consciousness.G


  • A. The SGER was originally introduced in 2007. It required large emitters (≥100,000 tonnes CO2e/yr) to reduce their emission intensity against an established baseline, earn emission offsets or performance credits, or pay a levy of $CDN15/tonne into a Climate Change and Emissions Management Fund. The 2007 SGER is available at:
  • B. Alberta’s largest gas-fired plant (800 MW of capacity) began commercial operation in March 2015.
  • C. PJM is the wholesale electricity market for all or parts of several northeastern states in the U.S. More information is available at:
  • D. More information on the Renewable Electricity Program is available at:
  • E. The bid price is, ideally, the lowest possible price the project developer can accept to advance the project.
  • F. CFOAM® carbon foam and CSTONE are enabling technologies for a host of next-generation material systems and components. More information is available at:
  • G. The views expressed are that of the authors and do not represent the opinions of Alberta Innovates or the University of Calgary.


  1. Canadian Association of Petroleum Producers (CAPP). (2016). Canada’s petroleum resources,
  2. Alberta Energy Regulator (AER). (2016). ST98-2016: Alberta’s energy reserves 2015 and supply & demand outlook 2016–2025. Executive summary,
  3. Canadian Wind Energy Association (CANWEA). (2016). Wind energy in Alberta,
  4. Alberta Innovates Energy and Environment Solutions, Canadian Clean Power Coalition. (2013). In-situ coal gasification in Alberta—Technology and value proposition: Final outcomes report,
  5. Alberta Energy. (2016). Energy statistics: Electricity supply,
  6. Government of Alberta. (2016). Alberta’s current emissions,
  7. Osler, Hoskin & Harcourt LLP. (2016, 15 April). Carbon and greenhouse gas legislation in Alberta,
  8. Government of Alberta. (2016). Climate Leadership Plan—Ending coal pollution,
  9. Alberta Electric System Operator (AESO). (2016). Capacity market transition,
  10. EDC Associates Ltd. (2016). Quarterly forecast update – Second quarter 2016,
  11. Varcoe, C. (2016, 9 July). Alberta’s power market in turmoil as prices hit 20-year lows and demand falls. Calgary Herald,
  12. Market Surveillance Administrator. (2015). Market share offer control, 2015.
  13. Leach, A., & Tombe, T. (2016, August). Power play: The termination of Alberta’s PPAs. University of Calgary, School of Public Policy Communique, 8(11),
  14. Schlissel, D.A. (2016, 16 September). A sustained coal recovery? “When you get there, there’s no there”. Institute for Energy Economics and Financial Analysis,
  15. Alberta Electric System Operator (AESO). (2016). First competition,
  16. Rozelle, P.L., Khadilkar, A.B., Pulati, N., Soundarrajan, N., Kilma, M.S., Mosser, M.M., Miller, C.E., & Pisupati, S.V. (2016). A study on removal of rare earth elements from U.S. coal byproducts by ion exchange. Metallurgical and Materials Transactions, 3, 6–17.


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CO2 Utilization as a Building Block for Achieving Global Climate Goals

By Janet Gellici
Chief Executive Officer, National Coal Council

Consensus is growing among industry, the environmental community, and international governments that future carbon dioxide (CO2) emission reduction goals cannot be met by renewable energy alone and that carbon capture, utilization, and storage (CCUS) technologies for all fossil fuels must be deployed to achieve climate objectives in the U.S. and globally. Fossil fuels—including coal, natural gas, and oil—will remain the dominant global energy source well into the future by virtue of their abundance, supply security, and affordability.

Achieving global climate objectives will require a portfolio of approaches that balance economic realities, energy security, and environmental aspirations. The most influential action the U.S. can employ to reduce CO2 emissions is to incentivize the rapid deployment of CCUS technologies. CO2 utilization can, in theory, help to reduce CCUS costs and incentivize deployment, but most CO2 use technologies face numerous and significant challenges in moving toward commercialization.

A way forward for CCUS in the U.S.

Geological CO2 utilization options have the greatest potential to advance CCUS by creating market demand for anthropogenic CO2. The use of CO2 for enhanced oil recovery (CO2-EOR), including production and storage activities in residual oil zones (ROZ), remains the CO2 use technology with the greatest potential to incentivize CCUS.

Non-geological CO2 utilization options are unlikely to significantly incentivize CCUS in the near to intermediate term because of technical, greenhouse gas (GHG) life-cycle analysis (LCA) considerations, and challenges associated with scalability. Despite these barriers, further investments in non-geologic CO2 utilization technologies may, on a case-by-case basis, hold promise for turning an uneconomic CCUS project into an economic one. A broadly deployed mix of CO2 utilization technologies may help advance CCUS deployment incrementally, providing sufficient incentive to keep CCUS technologies moving forward.


The National Coal Council (NCC) is a federally chartered advisory group to the U.S. Secretary of Energy, providing advice and recommendations on general policy matters relating to coal and the coal industry. In August 2016, the NCC completed a white paper for Energy Secretary Ernest Moniz that assessed opportunities to advance commercial markets for carbon dioxide (CO2) from coal-based power generation. This article highlights key findings and recommendations from the report, “CO2 Building Blocks: Assessing CO2 Utilization Options”.1

In the U.S., CO2-EOR offers opportunities for utilizing and storing CO2


CCUS technologies provide the most impactful opportunity to capture, use, and store a significant volume of CO2 from stationary point sources. These technologies can be used to reduce CO2 emissions from electric generation as well as from key industrial sectors, such as cement production, iron and steel making, oil refining, and chemicals manufacturing. Additionally, CCUS technologies significantly reduce the costs of decarbonization.2 Not including CCUS as a key mitigation technology is projected to increase the overall costs of meeting CO2 emissions goals by 70% to 138%.3,4 Finally, the commercial deployment of CCUS preserves the economic value of fossil fuel reserves (coal and natural gas) and associated infrastructure.

Commercial markets for CO2 from fossil fuel-based power generation and CO2-emitting industrial facilities have the potential to provide a business incentive for CCUS. The extent of that economic opportunity will depend on many factors, including but not limited to expediting the development of and reducing the cost associated with CO2 capture technologies. And while commercial markets may provide significant opportunities for CO2 utilization, the global scale of CO2 emissions suggests a continued need to pursue geologic storage options with significant CO2 storage potential and initiatives such as those being undertaken by U.S. Department of Energy (DOE) through its Regional Carbon Sequestration Partnerships Program and related programs.

Fossil fuels generally, and coal specifically, are dependent upon CCUS technologies to comply with U.S. GHG emissions reduction policies. A number of U.S. regulatory policies have been adopted to reduce GHG, with geologic storage options (specifically including CO2-EOR) as preferred mitigation technologies. Included among existing and pending U.S. regulations that encourage compliance via the use of CCUS technologies are the Clean Air Act’s Prevention of Significant Deterioration (PSD) and Title V Operating Permit programs; the Environmental Protection Agency’s (EPA) Standards of Performance for GHG Emissions from New, Modified and Reconstructed Electric Utility Generating Units (111b); and the Clean Power Plan (CPP). These U.S. policies are reinforced by the 2015 Paris Agreement, which largely envisions the decarbonization of major energy systems through the use of CCUS and other technologies by the 2050 timeframe.

U.S. law currently favors geologic storage/utilization technologies; non-geologic CO2 uses must demonstrate that they are as effective as geologic storage. Additionally, the emissions reduction targets and deadlines associated with U.S. and international climate goals point toward the use of CO2 utilization technologies that are either already commercialized or near commercialization.

CO2-EOR represents the most immediate, most mature, and highest value opportunity to utilize the greatest volumes of anthropogenic CO2 to meet U.S. and global climate objectives (see Table 1).

TABLE 1. U.S. regional CO2 utilization/storage and oil recovery potential
1 Includes 0.1 billion barrels already produced or proved with CO2-EOR.
2 Includes 2.2 billion barrels already produced or proved with CO2-EOR.
3 Includes 0.3 billion barrels already produced or proved with CO2-EOR.
4 Evaluated using an oil price of $85/B, a CO2 cost of $40/mt and a 20% ROR, before tax.
Source: Advanced Resources International


A 2011 report from the Global CCS Institute5 estimated current global demand for CO2 at about 80 million tons per year (MTPY) and suggested potential future demand could grow by an order of magnitude, reaching nearly 300 MTPY for each of a handful of technologies—most notably CO2-EOR—and more modest growth for an additional group of technologies. The potential global demand for CO2 for EOR was confirmed in 2015 in an International Energy Agency (IEA) study indicating that, by 2050, conventional CO2-EOR could lead to storage of 60,000 MTPY of CO2 and, through the application of advanced technologies, so-called EOR+ could increase to 240,000–360,000 MTPY of CO2.6

In the U.S., CO2-EOR offers major potential for utilizing and storing CO2 in a diversity of geological settings.

  • CO2 floods in the main pay zone (MPZ) of discovered oil fields (onshore lower-48 states, Alaska, and offshore Gulf of Mexico) offer a technical potential for utilizing and storing 38,320–52,240 MMmt of CO2.
  • Although the economically viable potential from the MPZ (at an oil price of $85 per barrel and with CO2 costs linked to oil prices) is more limited, the CO2 utilization and storage volumes are still significant at 10,740–23,580 MMmt plus 28–81 billion barrels of economically viable oil recovery.
  • CO2 floods in the residual oil z (ROZ) resources assessed to date could provide an additional 25,300 MMmt of technically viable CO2 utilization and storage, and significant volumes of associated oil recovery.

Other geologic utilization markets—including tight oil/shale gas formations, enhanced coal bed methane (ECBM), and enhanced water recovery (EWR)—also hold current and future promise as incentives for CCUS deployment. Key knowledge gaps and technical barriers remain in the pursuit of commercial deployment of these technologies. Progress has been and is being made with these emerging technologies but additional research is required to advance to the next stages of technological maturity.


Outside of CO2-EOR and other geologic CO2 use markets, research is underway on two general paths for non-geologic CO2 utilization: breaking down the CO2 molecule by cleaving C=O bond(s) and incorporating the entire CO2 molecule into other chemical structures. The latter path holds relatively more promise as it requires less energy and tends to “fix” the CO2 in a manner akin to geologic storage. Utilizing CO2 in non-geologic applications faces hurdles, including yet-to-be resolved issues associated with thermodynamics and kinetics involved in the successful reduction of CO2 to carbon products and inadequate support for demonstration projects leading to commercialization. Still, these technologies are worthy of continuing evaluation, and many hold long-term potential in specific applications.

Non-geologic utilization opportunities that tend to “fix” CO2 include (1) inorganic carbonates and bicarbonates; (2) plastics and polymers; (3) organic and specialty chemicals; and (4) agricultural fertilizers. Various technical and economic challenges face these commercially immature technologies, suggesting they are unlikely to incentivize CCUS deployment in the immediate future. They may, however, have an advantage over other non-geologic markets, such as fuels, which require cleaving of the CO2 bond through chemical and biological processes.

Transportation fuels do represent a significant market opportunity. They are, however, unlikely to incentivize CCUS in the immediate future for a variety of technical and economic reasons, including: (1) transportation fuels are ultimately combusted and thus release CO2 to the atmosphere and (2) current U.S. policy favors geologic-based utilization pathways for Clean Air Act (CAA) compliance. Although the case could be made that some CO2-derived transportation fuels have lower GHG emissions than fossil-based fuels on a GHG LCA basis, non-fossil-based transportation fuels still face significant market competition and displacement hurdles.


Market forces alone are unlikely to incentivize CCUS as CO2 utilization faces numerous hurdles.

  • Cost of capture. The current major user of CO2, the EOR industry, typically cannot offer a “price” for CO2 that overcomes the cost of capture for a coal-based utility. This conclusion applies even in the face of existing economic incentives, such as the current Section 45Q CCUS tax incentive.
  • Insufficient scope of the market/supply considerations. Only CO2-EOR holds promise for incentivizing CCUS at any reasonable scale for compliance purposes for coal-based utilities.
  • Nearly all non-geologic CO2 utilization technologies are not yet commercialized. Even if some of the nascent utilization technologies being explored worldwide hold potential for use at scale, they face a decades-long slog along the technology development path and typical technology deployment “valley of death” investment hurdles. These time frames suggest that, on their current trajectory, many utilization technologies will not be commercially available in time to influence CCUS deployment in the context of 2050 climate goals.
  • Geographic/infrastructure considerations. Unless the utilization technology is deployed beside every coal-based facility, the captured CO2 must be transported to industrial facilities making use of CO2. This issue remains a challenge even for EOR, let alone nascent technologies that are not yet commercial.
  • Legal & regulatory considerations. Under current law, CO2-EOR owners and operators must (1) conduct their injections under Class II of the Underground Injection Control (UIC) Program and (2) opt into Subpart RR of the Greenhouse Gas Reporting Program, which includes a federally approved monitoring, reporting, and verification (MRV) requirement, if they wish to demonstrate regulatory compliance under the CPP or the section 111(b) rule for long-term storage of CO2. Companies conducting non-EOR geologic storage must (1) conduct their injections under Class VI of the Underground Injection Control (UIC) Program and (2) report under Subpart RR. Each of these compliance pathways is potentially problematic.
    • CO2-EOR storage. Some in the U.S. CO2-EOR industry take the position that the MRV requirement is inconsistent with oil and gas law. They have noted, for example, that an EOR operator may not be authorized to conduct storage operations under existing mineral leases. On the other hand, EPA recently approved the first MRV plan for a CO2-EOR operation. There is not uniform agreement within the U.S. CO2-EOR industry on these and related issues. The International Organization for Standardization (ISO), through the efforts of Working Group 6 under Technical Committee 265, is separately endeavoring to address these and related issues as part of the ongoing efforts to prepare the world’s first technical standard governing CO2 storage in association with EOR operations.
    • Non-EOR storage. The current Class VI permit process creates a disincentive and an unnecessary hurdle. For example, the Archer Daniels Midland (ADM) Decatur CO2 storage project, which was part of the Regional Carbon Sequestration Partnerships Development Phase III program and partly funded by DOE, submitted its application for Class VI well permits in July and September of 2011, but the permits were not granted until April 2014.7 Similarly, North Dakota has envisaged and made progress toward a CO2 storage program. After a lengthy process with EPA to shape its submission, the state finally made an application for Class VI primacy regulatory authority in June 2013, which has not been granted by the EPA more than three years later, in essence delaying vital work on CCUS that is necessary to advance the technology.8

Thermodynamics & Kinetics of CO2

The CO2 molecule is particularly stable and has a Gibbs energy of formation of -394.4 kJ/mol, which must be overcome.

Thus, breaking the C=O bond(s) and forming C-H or C-C bond(s), or producing elemental carbon, is possible. However, such molecules are at a much higher energy state, meaning that a tremendous amount of energy must be used. Converting CO2 to fuels or other high energy state molecules requires more energy input than could ever be derived from the end products.

CO2 can also be incorporated into various chemicals as a C1 building block. This is not thermodynamically challenged because the entirety of the CO2 molecule is used and thus the C=O bonds are not broken. For this application, the principal challenge is the scale of available reactants and market for products, both of which are dwarfed by global CO2 emissions.


In its “CO2 Building Blocks” report for Energy Secretary Moniz, the National Coal Council recommended that research investments in CO2 utilization technologies should be prioritized first according to the ability of the CO2 utilization technology to:

  • Make use of CO2 at scale.
  • Make use of CO2 at scale in the 2020–2030 time frame.
  • Be commercially demonstrated prior to 2020 or as soon as possible thereafter.
  • Be deployed onsite at fossil fuel-based power plants and CO2-emitting industrial facilities.
  • Have realistic market potential, taking into account displacement considerations.
  • Be as effective as geologic technologies.
  • Provide non-trivial economic returns.
  • Favorably score under existing and forthcoming GHG LCA.

Kemper County Energy Facility (Courtesy of Southern Company)

The Council further noted that monetary, regulatory, and policy investments in the following CO2 utilization and storage technologies, in descending order, are most likely to incentivize the deployment of CCUS technologies:

  1. Current CO2-EOR technology. It is imperative that the government clarify the existing regulatory structure, provide support for infrastructure, such as pipeline networks, and offer financial incentives for carbon capture deployment so that the promise of this existing commercial technology is fully realized.
  2. “Next generation” CO2-EOR technologies. Advances to existing CO2-EOR technologies would enable ROZ resources to be efficiently recovered.
  3. Other geologic storage technologies that provide economic return. ECBM and CO2 injections into ROZs provide market demand for CO2 under certain general oil and gas market conditions. They also fit within the current U.S. legal framework that gives preference to geologic storage over non-geologic uses of CO2. Not all geologic formations (ECBM, for example) have access to protocols and/or methodologies to document storage.
  4. Saline storage. Saline storage remains EPA’s gold standard for CO2 storage and may be required to provide a backstop for CO2 utilization projects. The hurdles facing saline storage are primarily economic and regulatory, which current DOE policy recognizes, i.e., the new CarbonSAFE program. The fact remains, however, that the federal government needs to put more resources into these projects and reduce the regulatory impediments currently facing them.
  5. Non-geologic storage technologies that provide economic return and that are effective as geologic storage. The current U.S. legal framework prefers geologic storage over other CO2 uses. However, non-geologic technologies that keep the CO2 out of the atmosphere may be credited for the purposes of federal programs with appropriate evidence of atmospheric benefit.
  6. Non-geologic storage technologies that provide economic return yet are not as effective as geologic storage if appropriate EPA research waivers may be obtained. On a case-by-case basis, a CO2 utilization technology may exist or emerge that provides an economic return to a fossil fuel-based power plant or a CO2-emitting industrial facility. The technology nonetheless could be helpful in lowering the cost of capture. Appropriate legal recognition would be needed, however, for purposes of compliance with emission reduction obligations.


Achieving stabilization of GHG concentrations in the atmosphere requires the deployment of CCUS technologies worldwide. Consensus grows among industry, the environmental community, and international governments that future CO2 emission reduction goals cannot be met by renewables alone and that advancing CCUS is not just about coal.

CO2 utilization technologies can serve as building blocks in advancing a foundation on which to achieve global climate goals. A broadly deployed mix of CO2 utilization technologies, including geologic and non-geologic, may help to advance CCUS incrementally and may, even if they do not offer full-scale carbon management solutions, provide sufficient incentive to keep CCUS technologies moving forward. CO2-EOR offers the most immediate, most commercially mature, and highest value opportunity to utilize the greatest volumes of anthropogenic CO2. Monetary, regulatory, and policy investments that prioritize geologic CO2 use technologies first while continuing to support non-geologic applications on a longer-term basis provide the greatest promise of achieving global climate goals.


  1. National Coal Council. (2016, August). CO2 building blocks: Assessing CO2 utilization options,
  2. Intergovernmental Panel on Climate Change (IPCC) Working Group III. (2014). Climate change 2014: Mitigation of climate change 60. Fig. TS-13,
  3. National Coal Council. (2015, January). Fossil forward: Bringing scale and speed to CCS deployment,
  4. International Energy Agency. (2015). World energy outlook 2015 New Policies Scenario,
  5. Global CCS Institute & Parsons Brinckerhoff. (2011, March). Accelerating the uptake of CCS: Industrial use of captured carbon dioxide,
  6. International Energy Agency. (2015). Storing CO2 through enhanced oil recovery: Combining EOR with CO2 storage (EOR+) for profit,
  7. Massachusetts Institute of Technology. (2016). Illinois Industrial Carbon Capture and Storage (IL-CCS) fact sheet: Carbon dioxide capture and storage project. Carbon Capture & Sequestration Technologies program,
  8. Connors, K. C. (2013). Presentation by North Dakota Oil and Gas Division: IOGCC task force report,


The content in Cornerstone does not necessarily reflect the views of the World Coal Association or its members.
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Dubai: Pioneering a Sustainable Energy Model for Sustainable Development and Security of Supply

By Taher Diab
Senior Director of Strategy & Planning, Dubai Supreme Council of Energy

The Emirate of Dubai is one of the fastest growing cities in the world and a regional hub for tourism, logistics, and finance. The Dubai government is implementing an innovative strategy to manage demand, diversify fuel sources, secure its energy supply, and foster green growth. One strategic aim is to continue to fuel Dubai’s economic growth and maintain its regional and global prominent position.

Dubai’s installed generation capacity is about 10 GW. The main source of this power is from imported natural gas, which makes Dubai a net energy importer. Therefore, energy security is a high priority with forecasted electricity demand for the next decade projected to increase annually by 5–6%. In addition, the Emirate is pursuing a sustainable development path and plans to use clean energy technologies.

The economic success story of Dubai demonstrates how it managed to design and implement an energy strategy that captures the key levers driving its economy: energy security, demand-side management, and sustainable growth. Dubai is a living model of a coherent and cohesive energy strategy that meets future energy needs through an optimal energy mix that delivers affordable, sustainable, and clean energy to its citizens and residents.


The Emirate’s energy model originates from the Dubai Integrated Energy Strategy (DIES) 2030, which was launched in 2011 by the Dubai Supreme Council of Energy (DSCE) and is reviewed periodically. The DIES strategy was recently extended until 2050 with a detailed roadmap on how to achieve various CO2 free generation source targets by 2030 and 2050 (Figure 1).

FIGURE 1. Dubai Integrated Energy Strategy 2050.

The strategy builds on a world-class regulatory framework to accelerate the diversification of the energy mix, ensure security of supply, and facilitate effective demand-side management, as shown in Figure 2 with Dubai’s Integrated Energy Strategy up to 2030.

FIGURE 2. Dubai Integrated Energy Strategy – 2030.

The DIES includes the following elements:

    • Governance and Policies: To achieve the DIES targets, the policy and regulatory regime in Dubai’s energy sector has been overhauled. New principles such as public–private partnerships have been put in place to increase market participation in key projects, including clean coal and solar power generation. The regulatory framework for district cooling and energy service companies (ESCOs) is also supporting the implementation of DIES 2030.

Dubai is undergoing an energy transition.

  • Energy Efficiency and Demand Reduction: Demand reduction through energy efficiency is a focus of Dubai’s policy interventions to rationalize the use of power and water. The demand-side management (DSM) strategy has led to nine different programs and technical levers for energy efficiency and demand reduction. This has resulted in savings in capital, operational, and opportunity costs (as discussed in the next sections).
  • Energy Security and Sustainable Cost of Gas: Diversification of Dubai’s energy sources is a key focus of DIES 2030. This has led to several projects to increase future energy security including the proposed building of a clean coal power plant, solar, and encouragement of Independent Power Producer (IPP) projects. The Mohamed bin Rashid Al Maktoum Solar Park is an example of Dubai’s commitment to renewable energy. Other important elements in development include the use of imported nuclear energy, clean coal, waste-to-energy, hybrid and electric vehicles, and the distributed solar program (Shams Dubai).
  • Financial Mechanism and Capacity Building: DIES 2030 has launched measures and projects targeting DSM, renewable power, energy service contractors, Green Building Codes, and energy efficiency technologies. Financial mechanisms, such as the announced Dubai Green Fund currently under development, will encourage deployment of clean energy technologies in Dubai.


A market-based approach using public–private partnerships (PPPs) has been developed to meet the fast-growing demand for infrastructure in Dubai. The PPP approach leverages funding sources and helps balance the risk between the government and private investors. By fostering partnerships with leading international firms in clean energy, Dubai also aims to expand its local capacities through transfer of knowledge and skills.

Since the DSCE’s inception, it has rolled out a series of step-by-step regulatory reforms and policies to open the electricity market for independent power producers. This involved establishing the Regulatory and Supervisory Bureau (RSB) for the electricity and water sector in 2010. The RSB’s responsibilities include licensing of new entrants in the power sector.

One of the pillars of the DSEM, and a crucial factor in transforming Dubai’s energy market, was the review of the electricity and water tariff structure. In 2011, the Dubai Electricity and Water Authority (DEWA) introduced cost-reflective tariffs to incentivize lower consumption and more efficiency in the use of electricity and water. This sent positive signals to clean energy investors as the market became economically attractive for clean technologies, allowing for successful PPPs. Dubai’s robust regulatory framework provided investors with three key elements for long-term investment: transparency, longevity, and certainty.


After evaluating the options to provide supply security of supply for Dubai, the government decided to shift from dependency on fossil fuel and to increase the renewable energy share. This culminated in a target of 25% of clean installed capacity by 2030 and 75% by 2050 using CO2-free generation sources. To achieve these targets, Dubai is taking progressive strides to integrate solar power into an energy mix portfolio that is currently dependent mainly on imported natural gas.

The robust regulatory framework and commercial terms have attracted international and regional investors resulting in the lowest levelized cost of electricity (LCOE) for 200 MW at 5.64 US cent/kWh and recently DEWA announced an 800-MW solar photovoltaic (PV) power plant at 3.0 US cent/kWh. This development marked a turning point in the journey to diversify Dubai’s energy mix and demonstrated the value proposition of strategic PPPs for procuring energy at a record low price.

The transformation of the energy sector in Dubai is also occurring on the customer side. Residents can generate their own electricity using solar panels that can also feed extra energy to the Dubai power grid. This step will gradually transform the consumers to “prosumers”, a term used to describe consumers that also generate part of their own energy consumption. Dubai currently deploys a simple net-metering system wherein customers achieve savings by generating their own electricity.


For Dubai to diversify its energy mix, a decision was made to integrate clean coal to reduce dependency on imported natural gas and meet rising energy demand. Several reasons led to the decision to develop coal as an energy source. Coal is highly competitive with its low prices, dispatchability, and baseload compatibility. In addition, the combination of technological advances that allows both for higher efficiencies and reduced pollutants and emissions make it an ideal option to meet Dubai’s future energy needs.

In fact, Dubai’s commitment to a clean future stipulates the clean energy targets of the DIES 2050 strategy do not include clean coal without carbon capture and storage (CCS). Dubai has some of the most stringent emission standards and limits in the world for flue gas emissions. The deployment of clean coal technology will require meeting aggressive emissions and international environmental standards set for flue gas emissions. The limits are stricter than those in the Industrial Emissions Directive (IED) of the European Union and in the International Finance Corporation (IFC) guidelines. Dubai’s clean energy targets also include achieving CO2-free generation sources of 25% of its installed capacity in 2030 and 75% in 2050.

In 2016, Dubai awarded the first phase of the Hassyan Clean Coal Power Project comprising four 600-MW units. The ultra-supercritical technology to be deployed will aim for 50% high heating value (HHV) efficiency compared to only 35% efficiency in the current pulverized coal-fired plants. The first 600-MW unit will be commissioned in 2020. The full project size is 2400 MW; it will be the first clean coal power plant in the Gulf Cooperation Council (GCC) region. The electricity from the coal-fired power plant will be utilized during the high peak demand periods of the summer season to ensure security of supply at a reasonable cost.

Dubai has developed attractive commercial terms to secure the lowest levelized cost of electricity (LCOE) of about 4.5 US cent/kWh for the Hassyan project based on an IPP procurement model on a build-own-operate (BOO) basis. The project is 78% debt and 22% equity financed. This IPP model also fosters partnerships with leading international firms in clean energy, leverages funding sources, and helps balance the risk between the government and private investors.


DIES 2030 also has an objective to reduce 30% of Dubai’s energy demand from the current business-as-usual scenario. To achieve this reduction by 2030, a detailed DSM strategy for electricity and water has been implemented, which is the first of its kind in the region. The DSM strategy has opened up new business opportunities for sustainable and efficient businesses by outlining policies, regulations, awareness schemes, technologies, and finance schemes.

The strategy is based on nine programs with a specific database, reduction targets, and enablers to influence behavior and encourage well-thought-out measures. To ensure that the measures are effective, the government has engaged key stakeholders for consultation on the proposed programs, reduction measures, and timeline with a clear roadmap targeting 30% consumption reduction of water and electricity by 2030. The stakeholders’ engagement and global benchmarking will provide information and knowledge in the following areas: building regulations, building retrofits, district cooling, standards and labels for appliances and equipment, water reuse and irrigation, outdoor lighting, change of tariffs, demand response, and distributed solar.


To accelerate the uptake of hybrid and electric vehicles (EVs), the Emirate established the Green Mobility Initiative to lead the world in becoming more sustainable using smart technologies. The initiative complements the spirit of Dubai Plan1 2021 by providing alternative modes of transportation that reduce fuel usage and CO2 emissions. Road transportation is the third largest source of Dubai’s greenhouse gas (GHG) emissions. This initiative is an important contributor to Dubai Carbon Abatement Strategy 2021, which aims to reduce carbon emissions by 16% in 2021 compared to the business-as-usual scenario in 2021.

The Dubai Supreme Council of Energy and its entities have developed a comprehensive approach founded on the principle of “leading by example”. A detailed analysis was undertaken by the government of the market potential of hybrids and EVs. Based on this analysis a decision was made that the government vehicle fleet would be 10% hybrid or EVs by 2021.2

In addition to creating a market for hybrids and EVs, leading by example will enable the government to build the learning curve necessary to expand the deployment of such vehicles in the arid climate of Dubai. The Road and Transportation Authority (RTA) has already demonstrated the successful use of hybrid vehicles. The RTA3 employed over 140 hybrid taxis in 2015 and reported that around 30% fuel savings were achieved and found no performance challenges with the vehicles. The RTA is currently planning to convert 50% of its fleet to hybrid taxis by 2021 and is monitoring feasibility of hydrogen cell vehicles based on recent advancement in this technology.


In a short time, the Emirate has created a platform to find solutions for energy challenges by development of specific programs and projects. The first-in-the-region Dubai Carbon Abatement Strategy 2021 details programs that integrate alternative and renewable energy to diversify Dubai’s generation mix. This strategy will allow the Emirate to manage its energy demand, to increase efficiency, and to develop sector-based GHG reduction targets.

To design a performance-based program for carbon abatement, the strategy defined major sectors contributing to carbon emissions, referred to as “high-impact sectors”. Based on the carbon emissions profile for 2011, these sectors are power and water, manufacturing, road transportation, and waste. An unpublished technical evaluation of the emissions reduction potential for these high-impact sectors was carried out with the support of the Dubai Carbon Centre of Excellence, resulting in a target of 16% reduction of GHG by 2021 in comparison with the business-as-usual estimations for the same year.

In 2015, members of the Dubai Carbon Abatement Strategy saved 5.7 million tons of CO2e, which is equivalent to 10.6% reduction from business as usual in 2015.


The efforts of the UAE and Dubai to spearhead clean energy development in the region contribute greatly beyond the borders of the UAE. In a rapidly changing world, Dubai has seized the opportunity to follow a sustainable development pathway as it continues to grow. The clear and supportive vision of its leadership paved the way to develop a long-term strategy and deliver phased, but steadily implemented progress to achieve the goals of its DIES 2030. The strategy has resulted in investment certainty for the private sector and in several successful PPPs that resulted in low-cost solar energy, with positive ramifications for the future of solar not only in Dubai but the entire region.

The Emirate’s model as illustrated in Figure 3 is becoming a benchmark for the transition to a clean energy future in a region historically perceived as a synonym for “oil”. By 2030, Dubai expects to turn its sunny days into a sustainable fuel for generations to come and deliver strategic programs to support its Green Agenda to become a role model in energy management and sustainability in the region.

FIGURE 3. Dubai’s Sustainable Energy Model.


  1. Government of Dubai. (2016). Dubai Plan 2021,
  2. Dubai Supreme Council of Energy. (2016). Our members,
  3. Emirates 24/7. (2006, 6 February). 50% of Dubai Taxi fleet hybrid by 2021,


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