Category Archives: Technology Frontiers

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.


  1. Yu, Z.H., & Wang, F.C. (2010). Coal gasification technology [in Chinese]. Beijing: Chemical Industry Press.
  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.
  11. Huang B., Liu, L.B., Xu, S.S., & Feng, Z.P. (2008). The current situation and development of CO2 trapping and treatment technique in coal-fired power plant [in Chinese]. Electrical Equipment, 9(5), 3–6.
  12. Wu, R.S. (2007). Coal-fired power plant in the future—China’s GreenGen Project [in Chinese]. Electric Power, 40(3), 6–8.
  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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Resource Utilization and Management of Fly Ash

By Jinder Jow
National Institute of Clean-and-Low-Carbon Energy (NICE),
Beijing, China

China’s primary energy resources are fossil-based fuels: oil, natural gas, and coal, with coal being the least expensive. From a material aspect, coal has both organic and inorganic components, quite different from oil and natural gas which have only organic materials. Figure 1 depicts the process of a coal-fired power plant and its by-products—from coal mine to electricity or heat. The by-products are (1) NOx, sulfur oxides, Hg, particulate matter (PM), and CO2; (2) wastewater; and (3) fly ash, bottom ash, and flue-gas desulfurized gypsum when an external desulfurization process is used. The solid by-product with the largest volume is fly ash. The fly ash retains the inorganic components of coal after combustion.

FIGURE 1. By-products of coal-based energy from coal mine to coal-fired power plant.

Three different coal combustion processes are used to produce energy: pulverized coal (PC), circulating fluidized bed (CFB), and integrated gasification combined-cycle (IGCC). The first two are the most commonly used by coal-fired power plants. The PC process typically has a higher combustion temperature and efficiency than the CFB process, and produces less fly ash with better quality. Fly ash is mostly used in low-end applications, such as buildings and constructions, due to significant property variations that strongly depend on how each coal-fired power plant operates. This article describes the approach taken by the National Institute of Clean-and-Low-Carbon Energy (NICE), a subsidiary of Shenhua Group, to utilize and manage fly ash as a resource to increase its utilization volume and value. The same concept and approach can be applied to the utilization of fly ash or any other by-product related to coal-based energy. Coal-fired power can be cleaner if its by-products can be reduced or utilized.

Up to 60% of fly ash is used in cement and concrete construction in China.


Figure 2 depicts the three fundamental properties of fly ash: particle size distribution and morphology, chemical composition, and mineral composition. As noted, fly ash will differ in these properties, due to the operational differences of various coal-fired power plants. Factors that influence these properties include the coal type/source, pretreatment, combustion process, environmental control system, and the ash collection system.

FIGURE 2. Fundamental properties of fly ash.

Figure 3 shows how these three fundamental properties are linked with the operation of a coal-fired power plant. Several steps need to be taken to utilize fly ash as a resource. Identifying and understanding the properties of the fly ash is the first key step. Obtaining fly ash with consistent properties is the second step. Identifying suitable applications and development of specific products for different uses is the last step to maximize its properties and utilization value.

FIGURE 3. Fundamental properties of fly ash related to coal-fired power plant operation.

Particle size distribution of fly ash depends on the coal’s pretreatment, combustion process, and ash collection system. In general, fly ash has a particle size range of 0.1–600 µm. Fine coal particles produce finer fly ash. Higher combustion efficiency also tends to produce finer fly ash. Fly ash collected at the same plant using different electrostatic precipitators will have a different average particle size and distribution. Finer fly ash usually has a better utilization value due to its higher surface area and reactivity.1 The particle morphology depends on the combustion process. The PC process produces spherical particles due to natural cooling, whereas the CFB process creates irregularly shaped particles due to the fluidizing action.1 The images in Figure 4 show the differences in particle morphologies using a scanning electron microscope. A spherical shape has a better flow property but less aspect ratio effect than an irregular shape.

FIGURE 4. Particle morphology of pulverized (left) and circulating fluidizing bed (right) fly ash.

The chemical composition of fly ash depends on the coal type and the extent and temperature of combustion. The environmental control units used to remove NOx, sulfur, or Hg will also affect the composition. The major chemical compositions are dominated by SiO2 and Al2O3 as an aluminosilicate material followed by four secondary components, CaO, Fe3O4 or Fe2O3, SO3, and unburned carbon (loss on ignition, LOI). Combustion of lignite or subbituminous coal usually produces more fly ash, due to its high ash and CaO content, than does combustion of an anthracite or bituminous coal. The internal desulfurization process where lime is injected into the combustion process can also produce fly ash with high CaO content. Fly ash with more CaO tends to have higher cementitious reactivity. Typically, the PC process produces better fly ash quality with lower LOI, SO3, and CaO contents than the CFB process.

Mineral composition depends on the coal type, coal particle size, and boiler temperature. In general, higher boiler temperatures and smaller coal particles produce fly ash with higher glass content. Fly ash typically has a glass content range of 35–70%. Fly ash with more glass and smaller particle size has a higher pozzolanic reaction. Fly ash with high aluminum content tends to have lower glass content but higher mullite content in its crystalline phase.


Two key issues for fly ash utilization are significant property variation and local supply-demand issues. In China fly ash is used in various applications, such as cement and concrete, walls and building materials, aggregates in road pavement, agricultural use, mine refilling, and mineral extraction.2 The building and construction sectors are major users of fly ash which can meet their low performance requirements. For example, China produced 540 million tons of fly ash in 2014 with a utilization rate of 70%, higher than the global average of 54%.3 The fly ash was used as follows: 60% for cement and concrete, 26% for bricks and walls, 5% for road pavement, 5% for agriculture and mine refilling, and 4% for mineral extraction and other applications. The utilizations are categorized into three types as shown in Figure 5: local massive utilization, high-value utilization, and local ecologic utilization.

FIGURE 5. Utilization types of fly ash.A

Fly ash from coal-fired power plants located near metropolitan areas or large industrial complexes can be utilized to meet local demand in building and construction applications. However, these local applications are typically of low value (low price-to-performance) and only economic within a 100-km distance due to the transportation cost. Coal-fired power plants located in remote areas have limited options for fly ash utilization. Both high-value (high price-to-performance) and local ecologic utilizations become critical to increase its usage. Utilization and management of fly ash must be economically viable in remote locations or regions. In order to increase current utilization value and volume, efforts are underway to identify new applications for high-value and local utilizations. This requires an understanding of materials science and knowledge of possible applications.


To address fly ash utilization and management issues, the first step is to characterize its fundamental properties from individual coal-fired power plants and re-characterize when the operational conditions change. The second step is to obtain fly ash with consistent property qualities through a cost-effective particle control system, particularly for particle size, LOI, and Fe3O4 content. The third step is to select suitable applications based on consistent fundamental properties of fly ash and to develop core technologies and products for full utilization of fly ash to achieve the maximum value. Figure 6 shows how these three steps address both property variation and supply-and-demand issues.

FIGURE 6. Approaches to address fly ash utilization issues.

The fly ash R&D team at NICE has adapted this approach to characterize different types of fly ash and establish a cost-effective particle control system. This particle control system has obtained at least three grades of fly ash with consistent particle size distribution used to develop four products: hydraulic fracturing proppants, fillers, highly active supplemental cementitious (HASC) products, and river sand (RS) products (see Table 1). All products are based on at least one of these three fly ash grades, which are produced from the PC process. The processes of making fly ash-based products do not generate any by-products and consume less energy than the existing products to be replaced.1

TABLE 1. Fly ash-based products developed by NICE.

HASC products can replace up to 50% cementitious materials including cement used in concrete. Concretes using HASC products have higher compressive strengths, including three-day compressive strength which is one of the most important properties of concrete.3 The RS product fully replaces ultrafine sand used in mortar. Fillers can fully replace CaCO3 and other inorganic fillers (2500 mesh or above) used in polymers with better flow property. When the polymers are molten and pushed to flow, spherically shaped fillers help the molten polymer flow better than do irregularly shaped fillers. Fly ash-based proppant properties are either equivalent to or better than three commercially available bauxite-based proppants, identified as SG overseas, YT China, and CQ China, as shown in Table 2.4

TABLE 2. Performance comparison of four different low-density, high-strength proppants.

The three cases described below demonstrate how these products increase the utilization rate and value in local massive and high-value utilizations. The fly ash reference case was obtained from a pulverized coal-fired power plant. The fly ash is rated as Class II according to Chinese National Standard GB1596-2005 for concrete and mortar uses. For the particle size requirements, the GB 1596-2005 standard specifies fly ash with particle size greater than 45 µm and no higher than 25% by weight as Class II fly ash, while ASTM C618 specifies no higher than 34% by weight as Class F. The fly ash cost reference is assumed to be RMB50/ton from a coal-fired power plant and sold to a concrete producer at RMB150/ton, resulting in a gross margin of RMB100/ton.

Case I demonstrates two fly ash-based products used for concrete and mortar as an example of local massive utilization. Case II shows the viability of fillers for high-value utilization along with two products used for concrete and mortar for local massive utilization as a mixed example. Case III maximizes the utilization value and rate by making fillers and proppants using fly ash with an Al2O3 content of at least 35% as the example of high-value utilization only.

Case I: The reference fly ash is classified and converted into a highly active supplemental cementitious (HASC) product to replace 50% cement in concrete, Class II fly ash as an existing product, and a river sand (RS) product to fully replace ultrafine river sand used in mortar at a price of RMB350/ton, RMB150/ton, and RMB50/ton, respectively, under a product split ratio of 20%, 75%, and 5%. The average cost of conversion is RMB80/ton. The calculated gross margin is RMB105/ton. The market size of Class II fly ash used in concrete is assumed to be 71 million tons. The expected fly ash volume processed is 84 million tons to achieve a total extra gross margin of RMB420 million in China. The extra fly ash volume is 21 million tons used for HASC and RS products.

Case II: The same fly ash is classified and converted into fillers, Class II fly ash, and an RS product priced at RMB1000/ton, RMB150/ton, and RMB50/ton, respectively, under a product split ratio of 30%, 60%, and 10%. The average cost of conversion is still RMB80/ton. The calculated gross margin is RMB265/ton. The market size of fillers is assumed to be 1.8 million tons. The total fly ash volume processed is 6 million tons to achieve a total extra gross margin of RMB990 million. The total extra fly ash volume is 2.4 million tons used for filler and RS products.

Case III: Fly ash with high Al2O3 content is classified and converted into fillers and proppants priced at RMB1000/ton and RMB2500/ton under a product split ratio of 30% and 70%, respectively. The average cost of conversion rises to RMB800/ton. The calculated gross margin is RMB1250/ton. The market size of proppants is assumed to be 1.4 million tons in China. The extra fly ash volume is 2 million tons used for both proppants and fillers to achieve a total extra gross margin of RMB2300 million.

All prices stated are a reference for economic comparison and not necessarily the actual prices. Table 3 summarizes the extra fly ash volume and margin created by these three cases. As expected, high-value utilization creates more value and consumes less fly ash volume, while local massive utilization consumes more fly ash volume but creates less value.

TABLE 3. Products to create extra fly ash volume and total gross margin in China.


The development of options to make coal-fired power cleaner by reducing or utilizing more waste by-products is critical to maintain long-term sustainability. Coal has the organic component used to generate heat or electricity while its inorganic component is converted into fly ash through the combustion process. This article discusses options to increase the utilization of fly ash from coal-fired power generation. The fundamental properties of fly ash are particle size distribution and morphology, chemical and mineral composition, and significant variability depending on the operational conditions of individual power plants.

This article demonstrates how to increase fly ash utilization volume and value based on understanding the fundamental properties of fly ash and their property-driven applications for high-value and local building materials uses. Local ecologic utilizations are other options to increase volume and add value to fly ash, including mine refilling, agricultural use, land reclamation, and road construction. These usages are of extremely low value but useful in achieving full utilization, particularly in remote regions. How to achieve positive economic benefits for any ecologic utilization is another important and challenging goal. Resource utilization and management of fly ash requires collaborative efforts among local coal-fired power plants, governments, R&D teams, and enterprises to achieve a full utilization with an overall positive economic benefit in each region.


  • A. High-value utilization includes fillers, flame retardants, low-density foam for fire protection, thermal insulation, and industrial ceramics. Local massive utilization includes building materials for cement, mortar, and concrete, pre-cast, wall materials, and high-density foam. Local ecologic utilization includes mine refilling, aggregates for road pavement, land reclamation, and agricultural use.


  1. Dong, Y., Jow, J., Su, J., & Lai, S. (2013). Fly ash separation technology and its potential applications. Paper presented at the 2013 World of Coal Ash Conference, 22–25 April, Lexington, Kentucky.
  2. National Development and Reform Commission. (2013, 18 February). Fly ash comprehensive utilization management regulation (translated from Chinese).
  3. Jow, J., Dong, Y., Zhao, Y., Ding, S., Li, Q., Wang, X., & Lai, S. (2015). Fly ash-based technologies and value-added products based on materials science. Paper presented at 2015 World of Coal Ash Conference, 5–7 May, Nashville, Tennessee.
  4. Ding, S., Gao, G., & Jow, J. (2016). Resource utilization of high-alumina fly ash: High performance proppant application and development. Paper to be presented at 2016 Asia Coal Ash Conference. Shuozhou, China.


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The Łagisza Power Plant: The World’s First Supercritical CFB

By Malgorzata Wiatros-Motyka
Author and Analyst, IEA Clean Coal Centre

The Łagisza power plant in Będzin, Poland, is home to the world’s first 460-MW supercritical circulating fluidized bed boiler (CFB), which remains the largest of its kind outside China. Since beginning commercial operation in June 2009, the plant has attracted considerable interest from all over the world. Experience gained from its design, construction, and operation has been a valuable stepping stone in further developing the technology and implementing it in other countries.


The power plant is currently owned by Tauron Wytwarzanie S.A., the second largest energy company in Poland. The first subcritical units at Łagisza were built in the 1960s. At the turn of this century, when Łagisza consisted of seven 120-MW pulverized coal-fired boilers, the decision was taken to build a new, larger coal-fired unit to replace the smaller, less efficient ones. As described by Szymon Jagodzik,1 Łagisza’s Deputy Director and Chief Energy Generation Engineer, various options were initially considered, including both pulverized (PC) and CFB combustion designs. All the possibilities were carefully evaluated before the company decided to build a supercritical CFB unit—even though, at the time, no such boilers were operating anywhere in the world. A number of factors influenced the decision. First, it was calculated that the total plant investment cost for the CFB was approximately 15% lower than for a comparable pulverized coal-fired boiler. Second, a CFB would not require the installation of expensive wet flue gas desulfurization (FGD) and selective catalytic reduction (SCR) systems as both sulfur dioxide (SO2) and nitrogen oxides (NOx) could be removed from within the boiler. Third, CFB units have greater fuel flexibility than pulverized coal combustion units.

General view of the CFB unit (Courtesy of Tauron Wytwarzanie S.A.).1

Foster Wheeler Energy Polska and Foster Wheeler Energia OY (currently Amec Foster Wheeler) designed and built the boiler. To keep costs down, a number of suppliers and contractors were chosen, both locally and from abroad. Alstom Power supplied the turbine set and Elektrobudowa S.A. Katowice provided the electrical system. The ash handling and limestone sorbent systems came from Mostostal Kraków and the Energo–Eko-System Katowice consortium. The CiepŁo–Serwis Będzin and PURE Jaworzno consortium provided the coal-feed system, and the distributed control systems (DCS) came from the consortium of Metso Automation Finlandia and Metso Automation Polska.2 This strategy was successful as the unit was completed below the budget price; the total cost was about 1.9 mld zl (€0.422B, $0.594B). The money was raised by the company, bonds, and various Polish government environmental funds. It took three and a half years from the start of construction in January 2006 to commissioning of the unit in June 2009. Between 1500 and 2000 people were involved in its design, construction, and commissioning.1,2


The design of the Łagisza unit was based on Foster Wheeler’s second-generation CFB technology, which features solids separators (cyclones) constructed from water- or steam-cooled panels integrated with the furnace combustion chamber. Prior to Łagisza, Foster Wheeler’s largest second-generation CFB boilers were the 262-MW units at the Turów power plant, also in Poland.3,4 The main design parameters of the boiler are listed in Table 1 and a schematic is shown in Figure 1.

FIGURE 1. General arrangement of the Łagisza boiler.1

TABLE 1. Main design parameters of the Łagisza 460-MW CFB boiler.2

Although CFB boilers have considerable fuel flexibility and can fire many low-grade fuels, including low-rank coals, biomass, and different types of waste,5,6 the boiler at Łagisza plant was designed specifically for locally mined hard coal and the limestone used for desulfurization. In 2015, the average parameters of the fired coal were as follows: calorific value 20,522 kJ/kg; 19.21% ash; 1.03% sulfur; and 14.49% moisture content.

The most significant design features of the Łagisza CFB unit are the boiler’s compact size, its once-through operation mode, the single fluidizing grid, the integrated steam-cooled solids separator, the INTREX fluidized bed heat exchanger, and the flue gas heat recovery system.

The parameters of the coal and limestone to be used were analyzed extensively, which led to the design of a compact boiler 27.6 m wide, 10 m deep, and 28 m high. In fact, it is only slightly larger than the boilers designed for Foster Wheeler’s subcritical 235-MW CFB units 1–3 at Turów power plant (22 m wide, 10.1 m deep, 42 m high).

The unit uses a single fluidizing grid in the bottom of the boiler, with four separate air plenums for the primary air flows. The primary air flow to each plenum is measured and controlled separately to ensure equal air flow to all sections of the grid and uniform fluidization as well as simple control.

The application of vertical Benson tubing (low mass flux once-through technology) and Siemens supercritical steam flow technology allows steady operation of the boiler at variable load conditions (40–100% load).

The unit has eight integrated steam-cooled solids separators arranged in parallel, four separators on two opposite furnace walls. This arrangement allows a high collection efficiency with low flue gas pressure loss. The inlet is tall and narrow in shape to provide a uniform flow of flue gas and solids, thus avoiding high local velocities. The result is a collection efficiency equal to the best conventional cyclones with substantially lower loss of pressure. To minimize the required amount of refractory material, the separators are designed with panel wall sections and have a thin refractory lining anchored with dense studding. The separator tubes are steam cooled, forming a third superheater stage.4

Foster Wheeler’s integrated recycle heat exchanger (INTREX) incorporates the heat exchanger water wall with the furnace water steam system and the return channel. As well as cooling the externally circulated solids, openings in the furnace’s rear wall provide access for additional solids to circulate internally through the heat exchanger tube bundles, ensuring sufficient hot solids to the INTREX™ heat exchanger at all loads.3,4 As the system is located in the solids return part of the solids separator, corrosion from high temperature and the acidic flue gas component is avoided.3,6

The flue gas heat recovery system (HRS) cools the flue gas from 130°C to 85°C and improves the total efficiency of the unit by around 0.8 %.4 The HRS operates in the clean gas after the electrostatic precipitator (ESP) and induced draft fans. The flue gas is cooled in a heat exchanger made of PFA tubing to avoid corrosion problems. After HRS cooling, the flue gas is conducted to the cooling tower via a fiberglass duct. The recovered heat is transferred by a primary water circuit to the combustion air system of primary and secondary air. As the combustion air temperature before the rotary air preheater is increased, the incoming cold combustion air flow is not able to absorb all the heat from the flue gases. Hence part of the flue gas is directed to a separate low-pressure bypass economizer that allows the heat from the flue gas to be used to heat the main condensate.7

The temperature of the flue gas after heat recovery is relatively low and would cause problems for a traditional stack. Thus a decision was made to construct a 133.2-m-high “cooling stack”. This was more economical than constructing a cooling tower and a separate stack. More importantly, it allows higher and better dispersal of the flue gas than would be achieved with a stand-alone stack.1

The advantages that resulted from these applied solutions include significant fuel flexibility and a low combustion chamber temperature of 800–900°C. This means that screen tube slagging is avoided, as well as high-temperature corrosion.

Łagisza’s CFB unit operates with much greater efficiency and emits significantly less carbon dioxide and other air pollutants than the 120-MW pulverized units it replaced (see Table 2).7

TABLE 2. Operating efficiencies and emissions levels of the 460-MW CFB and replaced 120-MW pulverized coal-fired units at 100% load operation.7


Currently, Łagisza power plant consists of the 460-MW CFB and two subcritical 120-MW pulverized coal-fired units. The plant employs 326 people, of which approximately 60 are required to operate the CFB unit. In 2015, the unit was in operation for 6000 hours, used 905,000 tonnes of local coal, and generated 2.3 TWh of electricity. It operated at 65–100% load, with an average load of 85% (392 MW). Obviously, variations in the load translate to variation in the boiler’s efficiency.7 As shown in Figure 2, when operating at full load, net efficiency is in the region of 43% (lower heating value, LHV) and net power output is 439 MW.

FIGURE 2. Gross and net efficiency (LHV) of the unit in relation to the load.7

Sulfur dioxide emissions are controlled by feeding limestone into the boiler; last year, 62,500 tCaCO3 were used for that purpose. NOx emissions from a CFB combustion unit are only around one fifth of those produced by pulverized coal combustion as the combustion occurs at lower temperature and thus less NOx is formed.6 Hence, NOx emissions are effectively controlled by staged combustion as well as the addition of ammonia as part of a selective non-catalytic reduction process. In 2015, 2885 tonnes of ammonia were used.1 An ESP system is used to control PM emissions. Consequently, in 2015 the emissions were as follows: 17,000.2 kg PM (<30 mg/Nm3); 454,962.3 kg SOx (<200 mg/Nm3); 521,274.3 kg NOx (<200 mg/Nm3); and 721,367 tCO2. These pollution control options enable compliance with the relevant EU legislation.

Fuel is delivered to the boiler by 14 screw-type feeders, as reported by Jagodzik.1 Coal is crushed to 1–30 mm; 80% of it to between 1 and 10 mm to allow seamless combustion. About 40–50 kg of coal is delivered each second to the boiler, corresponding to around 4000 tonnes of fuel being used per day. When in operation, the total mass of solids (fuel, sand, sorbent, ash) in the boiler is about 200 tonnes. Although the CFB boiler can fire different types of fuel, unsurprisingly it is most efficient when using the fuel for which it has been designed: local hard coal.

It is worth noting that the Łagisza CFB unit also has the Dual-Reflux Vacuum-Pressure Swing Adsorption (DR-VPSA) CO2 capture pilot installation in place. The installation is operated by Częstochowa University of Technology and Eurol Innovative Technology Solutions Sp. z o.o. with the participation of Tauron staff. When in operation, the installation utilizes a slipstream of the CFB flue gas (100 m3/h) to investigate two adsorbents (activated carbon and zeolite types) for their potential to remove CO2.8


As noted by Lockwood,9 despite attaining the status of “cleaner” coal technology because the emissions of NOx and SOx emissions are more easily controllable, the use of CFB combustion at the utility scale has been limited by smaller boiler sizes than those used in pulverized coal combustion. However, scale-up and optimization over recent years have allowed CFB boilers to benefit from economies of scale. Larger units have been built since the commissionsing of the Łagisza CFB unit, and CFB combustion is beginning to provide a viable alternative to pulverized coal combustion for utility power generation, especially where low-grade fuel will be used. The successful operation of the world’s first supercritical CFB boiler at Łagisza power plant in Poland has been crucial to this progress. Łagisza has validated Foster Wheeler’s supercritical CFB design platform, providing a solid base for its development of units of up to 600–800-MW capacity.4

Tauron Wytwarzanie S.A. has generously shared its knowledge and experience gained during the operation of the world’s first supercritical 460-MW CFB unit. The company has hosted many tours and provided training and learning opportunities for plant operators from around the world. This included training for a team from KOSPO, South Korea, which is expected to commission four 550-MW units in Samcheok later this year. And as Szymon Jagodzik1 noted, as Tauron staff train others during such interactions, they are also open to suggestions because they never stop improving operation of their coal-fired fleet.


After over six years of operation, the decision to build the world’s first supercritical CFB unit in Łagisza appears to have been both economically and environmentally successful. Łagisza’s operating experience has provided a good knowledge base for further development of CFB units all over the world. The Łagisza CFB unit is predicted to be in operation until 2046 and there are plans for it to produce heat as well as electricity. The amount of heat to be produced is not yet known, as it will depend on local demand. Nevertheless, the future of Łagisza CFB unit looks good.


  1. Szymon Jagodzik, Tauron Wytwarzanie S.A., Łagisza Power Plant, Będzin, Poland. Personal communication, July 2016.
  2. Tauron Wytwarzanie S.A. (n.d.). 460 MWe power unit with circulating fluidized-bed Boiler with supercritical parameters,
  3. Jäntti, T., Lampenium, H., Ruuskanen, M., & Parkkonen, R. (2011). Supercritical OTU CFB projects – Lagisza 460 MWe and Novercherkasskays 330 MWe Available at:
  4. Jäntti, T., & Parkkonen, R. (2010). Łagisza 460 MWe supercritical CFB—Experience during first year after start of commercial operation. Paper presented at Russia Power, Moscow, Russia, 24–26 March,
  5. Guangxi, Y., Wen, L., & Li, N. (2015). China brings online the world’s first 600 MW supercritical CFB boiler. Cornerstone, 3(1), 43–47.
  6. Zhu, Q. (2013, April). Developments in circulating fluidised bed combustion. CCC/219. London: IEA Clean Coal Centre.
  7. Tokarski, S. (2012, 20 November). TAURON Wytwarzanie S.A. nowy blok energetyczny w Elektrowni Łagisza [in Polish]. Presentation given at Tauron Wytwarzanie S.A., Katowice, Poland.
  8. Tauron Wytwarzanie S.A. (2015). Vacuum-pressure swing adsorption CO2 capture pilot installation,
  9. Lockwood, T. (2013). Techno-economic analysis of PC versus CFB combustion technology. CCC/226. London: IEA Clean Coal Centre.


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Improving Flexibility of Hard Coal and Lignite Boilers

By Michalis Agraniotis
Innovation & New Products Department,
Mitsubishi Hitachi Power Systems Europe
Malgorzata Stein Brzozowska
Innovation & New Products Department,
Mitsubishi Hitachi Power Systems Europe
Christian Bergins
Innovation & New Products Department,
Mitsubishi Hitachi Power Systems Europe
Torsten Buddenberg
Innovation & New Products Department,
Mitsubishi Hitachi Power Systems Europe
Emmanouil Kakaras
Innovation & New Products Department,
Mitsubishi Hitachi Power Systems Europe

The EU energy strategy for 2020 and 2050 sets specific targets for the transition of the current European energy system and energy market. The aim of the strategy is to encourage a low-carbon energy system with decreased greenhouse gas (GHG) emissions (by 50% compared with 1990 levels until 2050), increased energy efficiency, and a larger share of renewable energy sources (RES).1 All these developments set new challenges in the conventional thermal power sector. Under these new market conditions, modern, highly efficient natural gas combined-cycle (NGCC) power plants cannot be competitive in several countries and lose market share. Hard coal and lignite power plants are often requested by grid operators to stay in operation as the backbone of the electricity generation system and to increase their operational flexibility, in order to cover the increasing fluctuations of the residual load due to the intermittent RES.2

Moorburg Power Plant.

Most efforts to improve flexibility in existing hard coal and lignite plants begin with measures taken to improve the flexibility of firing systems. Indirect firing systems may play a key role through utilization of pulverized coal dust or pre-dried lignite dust that can be stored in intermediate silos. In addition, the development of new ignition systems without expensive auxiliary fuels enables successful ignition and stable combustion conditions using only electricity. This reduces start-up costs and increases flexibility. This article discusses new developments in firing system technologies. Additional information can be also found in the literature.3–6


Increasing flexibility in coal power plants is not a straightforward task, because several operating parameters must be optimized under a high number of constraints. In general terms, the key targets toward increasing flexible plant operation are:

  • reduction of minimum load
  • increase of ramp up/down rates
  • reduction of start-up cost and start-up time
  • increase of maximum load period

In parallel, the above-mentioned targets must be achieved under the following conditions:

  • lowest investment and operating costs
  • highest plant efficiency rate and lowest CO2 emissions, and
  • by always keeping within flue gas emission limits

A graphical representation of these parameters is depicted in Figure 1. Several of these targets are not fully complementary to each other. Hence, new design principles need to consider a broad range of plant operating modes, so that plant operating parameters can be adjusted and optimized based on system operators’ and market demands.

FIGURE 1. Overview and comparison of flexibility measures and impact on the operating mode.

An overview of the current state-of-the-art technical parameters related to flexible operation of coal plants is provided in Table 1 for (1) older plants commissioned in the 1990s, (2) newer plants commissioned after 2000 representing the state of the art, and (3) future plants following highly flexible design characteristics.

TABLE 1. State-of-the-art and future targets in operating parameters related to plant flexibility.


Mitsubishi Hitachi Power Systems Europe (MHPSE) has presented a comprehensive overview of possible technical measures for retrofit and flexibility increase in existing boilers in several papers.5–7 A short list of the key measures is provided in Table 2 with an acceding order from the “simpler” or “limited” measures to the more “advanced” or “extensive” measures. Similarly, the measures presented on the top of each class are the most “limited” ones within this class. The classification provides only initial guidance and may differ between cases. Furthermore, additional checks on low-load operation are required before undertaking any retrofit measure. The checks have to be carried out within the framework of a comprehensive study-and-measurement campaign and include checking:

  • current instrumentation and control system installed in each plant and the upgrade possibilities
  • the boiler’s static and dynamic stability with different load changes and the planning of retrofit measures
  • all other main plant components apart from the boiler (steam turbine, condenser) as well as the balance of the plant (fans, pumps)
  • flue gas emissions performance in low-load and dynamic operation (NOx, SO2, CO, particulates)

TABLE 2. Possible measures to increase flexibility in existing power plants and expected impact.

flexibility increase measures (SELECTED EXAMPLES): INDIRECT FIRING

A key bottleneck to increasing the flexibility in existing hard coal and lignite boilers is the firing systems. A possible retrofit through installation of additional indirect firing systems can contribute to overcoming limitations and extending the operating range of existing boilers. Indirect firing systems can include an additional pulverized fuel storage (Figure 2). During normal boiler operation the pulverized fuel produced can be partly stored in an additional coal dust silo. The dried fuel dust can be used (1) as supporting fuel for combustion stabilization in low-load operation, (2) as supporting fuel in case of very low-quality fuels, and (3) as a start-up fuel alternative to oil or natural gas during start-ups and shut-downs.

FIGURE 2. Indirect firing system.

In indirect firing systems the fuel dust is directly injected into the boiler via a special burner. For these applications MHPSE developed the DST-burner (Figure 3), suitable for indirect firing of different pre-dried fuels. Due to the high turn-down ratio, the DST-burner may be used in a broad load range during start-up and shut-down, leading to savings in conventional start-up fuels of up to 95%. Furthermore, in lignite power plants the potential integration of an external pre-drying system may be used for the production of pre-dried lignite, which can be utilized as start-up and supporting fuel in existing and future lignite power plants (Figure 4).

FIGURE 3. DST-Brenner® burner for dried fuel dust (1-core air, 2-fuel, 3-secondary air, 4-tertiary air, 5-fuel nozzle, 6-swirler).

FIGURE 4. Lignite pre-drying system can aid increase in flexibility of current and new power plants.

DEVELOPMENT ACTIVITIES: electric ignition systems

To reduce the consumption of costly auxiliary fuels such as oil and natural gas, MHPSE is evaluating the possibility for ignition of solid fuels by electric start-up technologies. Two technologies are currently in development: the electrically heated burner nozzle and the plasma ignition system. The electrically heated burner nozzle is designed for start-up of further burner levels when increasing the boiler load; the plasma ignition system is designed for cold, warm, and hot start-up. The concept is to induce ignition of pulverized fuels through the radiation heat from and through contact with the burner nozzle, which is electrically heated (Figure 5). The proof of concept was successfully demonstrated in 2013 with industrial-scale experiments. The first prototype, modified DS® burners with electrically heated nozzles, has been installed in a 300-MWe CHP plant providing electricity and heat to the city of Hannover and nearby industries (Gemeinschaftskraftwerk Hannover).8–10 Ignition using a plasma flame (Figure 6) is possible given that plasma is a highly reactive blend of electrons, radicals, atoms, and molecules. Development aims to optimize the plasma flame in low NOx swirled burners for safe ignition of a wide range of fuels while minimizing the necessary plasma power. The implementation of such electric ignition systems aims to reduce supporting fuels and maintenance costs of the complex infrastructure and/or storage of heavy fuel oil, light fuel oil, and gas start-up systems, which require regular safety inspections.11

FIGURE 5. (a) Bituminous coal ignition with electrically heated burner nozzle: proof of concept;

(b) installation of DS® burner with electrically heated nozzle in PP Hannover.

FIGURE 6. 70-kW plasma flame incorporated in a 30-MW DS®-burner during the cold commissioning tests.


This article summarizes recent developments and state-of-the-art technology using firing systems to increase flexible plant operation on hard coal and lignite boilers. Depending on coal quality and market conditions, today’s boilers and combustion systems can be optimized for maximum flexibility with reasonable capital investment. If necessary, coal-fired power plants can be designed for fast-load ramps as well as minimum load operation at 15–20% or lower independent of fuel type. For this application, indirect firing systems are already considered as state-of-the-art technology. Electrical ignition concepts are also currently under development and in a prototype stage. Additionally, the article provides a list of measures toward plant flexibility and provides a ranking of these measures from the simpler concepts to the concepts with the higher complexity. All flexibility options have to be evaluated case by case and take into account the particular technical and economic boundary conditions of each considered case.


  1. European Commission. (2016, September). Energy strategy,
  2. Mayer, J. (2014). Electricity production and spot-prices in Germany 2014. Fraunhofer Institute for Solar Energy Systems,
  3. Jeschke, R., Henning, B., & Schreier, W. (2012). Flexibility via high efficient technology. Paper presented at PowerGen Europe 2012, Cologne, Germany.
  4. Bergins, C., Leisse, A., & Rehfeldt, S. (2014). How to utilize low grade coals below 1000 kcal/kg? Paper presented at PowerGen Europe 2014, Cologne, Germany.
  5. Stein-Brzozowska, M., Agraniotis, M., Bergins, C., Buddenberg, T., & Kakaras E. (2015). Improving flexibility of coal fired power plants. Paper presented at Clean Coal Technologies Conference, Krakow, Poland.
  6. Bergins, C., Agraniotis, M., Kakaras, E., & Leisse, A. (2015). Improving flexibility of lignite boilers through firing system optimisation and retrofit. Paper presented at Powergen Europe 2015, Amsterdam, The Netherlands.
  7. Project Partnerdampfkraftwerk. (2016). Final report [in German],
  8. Rehfeldt, S., Leisse, A., & Saponaro, A. (2014). Ignition of solid pulverized fuel by heated surfaces. Paper presented at the 39th International Technical Conference on Clean Coal & Fuel Systems 2014, 1–5 June, Clearwater, Florida.
  9. Leisse, A., Rehfeldt, S., & Meyer, D. (2014). Ignition behaviour of pulverised solid fuel particles at hot surfaces. [Abstract]. VGB Powertech Journal, 11/2014.
  10. Leisse, A., & Stöll B. (2016). Zündung staubförmiger Brennstoffe an elektrisch beheizten Brennstoffdüsen [in German]. Paper presented at VGB Conference Dampferzeuger, Industrie- und Heizkraftwerke 2016.
  11. Stein-Brzozowska, M., Bergins, C., Kukoski, A., Wu, S., Agraniotis, M., & Kakaras, E. (2016), The current trends in conventional power plant technology on two continents from the perspective of engineering, procurement, and construction contractor and original equipment manufacturer. Journal of Energy Resources Technology, 138(4), 044501,

The lead author can be reached at


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Effect of Coal Beneficiation on the Efficiency of Advanced PCC Power Plants

By Nenad Sarunac
Associate Professor
University of North Carolina at Charlotte
Charles Bullinger
Senior Principal Engineer, Great River Energy
Mark Ness
Principal Engineer, Great River Energy
Sandra Broekema
Manager of Business Development, Great River Energy
Ye Yao
Senior Engineer, Great River Energy

Pulverized coal combustion (PCC) dominates power generation and will continue to do so for the foreseeable future.1 Due to aging of the existing fleet of PCC plants and global increase in electricity demand, especially in emerging economies, a fleet of new highly efficient PCC plants is likely to be deployed.

Thermal efficiency of a power plant is one of the key parameters affecting the fuel cost, emissions (both non-greenhouse (GHG) and GHG), and capital cost. An increase in plant efficiency reduces coal consumption and fuel costs and lowers the amount of flue gas treated by the flue gas cleaning system, thus resulting in lower emission compliance cost. The published data concerning performance of advanced PCC generation is almost exclusively for the bituminous (hard) coals with no or very little information available for lower rank coals. Addressing this information gap and quantifying the effects of fuel quality on efficiency of USC and A-USC plants are the main goals of the study discussed in this article.

Thermal efficiency of a power plant is a key parameter. (Courtesy of Great River Energy)

Increasing steam parameters with the resulting increase in turbine cycle efficiency is one of the most effective ways of improving plant efficiency. The state-of-the-art ultra-supercritical (USC) technology can reach a steam temperature of 600°C at the superheater outlet and net efficiency of 47% (LHV) for bituminous (hard) coals. The new target for advanced ultra-supercritical (A-USC) technology is a main steam temperature in excess of 700°C and net unit efficiency estimated at 50% (LHV) for hard coals.1

In addition to increasing steam parameters, improvement in coal quality is an effective method to increase the efficiency of PCC plants. This is particularly important for the advanced PCC technologies (USC and A-USC) operating at high steam parameters. The negative effect of high coal-moisture content on efficiency rises as steam parameters increase, reducing the operating benefits of the USC and A-USC.

Low-rank, high-moisture coals constitute about 50% of the world coal reserves.2 Given such coals’ abundance and low cost, a significant portion of advanced PCC generation built in the future will be fueled by low-rank coals. To achieve the highest operating efficiency, capacity, and availability, smallest equipment size, and lowest CAPEX and OPEX will require reducing coal moisture.

The effects of coal quality improvement achieved by thermal dewatering of high-moisture coals on net efficiency and capital cost of the USC and A-USC plants are discussed below. The results were obtained by predicting performance of a reference 860-MWgross plant for four high-moisture coals.


The use of high-moisture coals with a low HHV (higher heating value) results in higher coal and stack flue gas flow rates, higher station service power, and lower net plant efficiency compared to that of hard coals (see Figure 1). In addition, the mill, coal pipe, burner, and coal-handling equipment maintenance requirements are higher. The properties of coals used in our analysis are summarized in Table 1.

FIGURE 1. Effect of coal rank and steam parameters on net unit efficiency.

TABLE 1. Properties of the coals used in our analysis.

As shown in Figure 1, coal quality significantly impacts plant efficiency—for low-quality coals, plant efficiency is significantly lower compared to the bituminous (hard) coals. This negative effect is higher for plants with high steam parameters, thus reducing the benefits of advanced PCC operation. For example, an USC PCC plant firing high-moisture German lignite will have 7.3%-points lower net efficiency compared to the same plant using hard coal. Considering the high capital cost of the advanced PCC technology, such a reduction in performance is highly undesirable.

Pre-drying of High-Moisture Coals

Given that HHV increases as the total coal moisture (TM) is reduced (the average improvement in HHV is in the range of 100–120 Btu/lb per 1%-point reduction in TM), countries with large resources of high-moisture, low-quality coals are developing coal dewatering and pre-drying processes to improve unit efficiency, plant operation, and economics, as well as to reduce emissions from existing and future-built power plants firing low-rank coals. However, many thermal drying processes are either highly complex or require high-grade heat to remove moisture from the coal. This significantly increases the process cost, which represents a major barrier to industry acceptance of this technology.

Two previous IEA Clean Coal Centre (CCC) studies identified two low-energy-based coal pre-drying technologies: the U.S.-developed DryFiningTM and German-developed WTA (Wirbelschicht-Trocknung mit interner Abwämenutzung, fluidized bed drying with internal waste heat utilization) as commercially available and suitable for implementation at power plants burning high-moisture coals.3,4

DryFiningTM: A Low-Temperature Coal Drying and Refining Process

DryFiningTM is a novel low-temperature coal drying and cleaning process that employs a multistage moving bed fluidized bed dryer (FBD). The process uses low-grade heat rejected in the main steam condenser and sensible heat from the flue gas leaving the boiler to decrease moisture content of the high-moisture coals, such as North Dakota (ND) lignite. The technology was developed by a team led by Great River Energy (GRE). The DryFining system has been in continuous commercial operation at Coal Creek Station in North Dakota since December 2009 and has processed in excess of 40 million tons of raw ND lignite.

Implementation of DryFiningTM at the Coal Creek lignite-fired power plant has improved unit heat rate by more than 5%, simultaneously achieving 30% reduction in SO2 and Hg emissions, 20% reduction in NOx emissions, improving plant availability, and lowering plant water usage.5–10 Pre-combustion Hg removal is currently a topic of considerable interest.


There is significant interest in coal quality improvement through thermal pre-drying in markets experiencing high electrical load growth combined with local resources of low-rank coals. A number of lignites and sub-bituminous coals from North America, Europe, Indonesia, and other regions have been tested using the GRE pilot dryer in Underwood, ND. Drying kinetics of tested coals was similar, starting with the removal of surface moisture, followed by progressive removal of intrinsic moisture.

Process models of the reference plant and DryFining fuel enhancement process were thermally integrated to determine the effect of reduced coal moisture content and system integration on net plant efficiency ηnet, fuel feed, flue gas flow rate, and CO2 emissions. Table 1 lists the coals that were analyzed. Table 2 lists steam conditions over a range of coal moisture contents for subcritical (SUBC), supercritical (SC), ultra-supercritical (USC), and advanced ultra-supercritical (A-USC) operations.

TABLE 2. Steam conditions.

We performed an economic analysis for each of the cases to determine the capital investment needed for the coal drying system, reduction in plant capital cost due to improved coal quality (higher HHV), and resulting capital cost savings. The results are presented as overnight $/kW. The overnight capital cost of $2933/kW for the A-USC firing Powder River Basin coal published in a recent EPRI study, “Materials for Advanced Ultrasupercritical Steam Turbines”,11 was used in the analysis.


The results for the high-moisture coals presented in Table 1 are depicted in Figures 2 to 4. For clarity, only the results for the USC and A-USC steam conditions are shown here. The improvement in ηnet relative to the subcritical steam conditions and raw coal is shown in Figure 2 as a function of the reduction in TM. For all analyzed coals, ηnet increases as TM is reduced (coal quality is improved). The efficiency improvement is higher for the higher moisture coals and higher steam conditions; the largest improvement with the lowest TM is achieved with A-USC steam conditions.

FIGURE 2. Improvement in net efficiency as a function of reduction in TM for USC and A-USC steam conditions.

FIGURE 3. Reduction in CO2 emission intensity as a function of reduction in TM for USC and A-USC steam conditions.

FIGURE 4. CAPEX savings as functions of reduction in TM for USC and A-USC steam conditions.

For the decrease in coal moisture of 25%-points, high-moisture German lignite, and A-USC steam conditions, the improvement in ηnet is 12 %-points; for identical conditions and lower moisture PRB coal, the efficiency improvement is approximately 10.5%-points.

TM can be reduced by approximately 15%-points using exclusively the power plant waste heat. To achieve deeper coal drying requires process heat. In this study, the low-pressure (LP) steam extracted from the LP turbine was used as a source of the process heat. Because this steam extraction lowers the steam turbine power output, the achieved improvement in unit efficiency is smaller and the efficiency curves change slope at ΔTM greater than 15%.

The reduction in CO2 emission intensity EFCO2 relative to the subcritical steam conditions and raw coal is presented in Figure 3 as a function of ΔTM for the USC and A-USC steam conditions. The magnitude of the reduction in EFCO2 increases with the reduction in TM and improvement in steam conditions. For the ΔTM of 25%, high-moisture German lignite, and A-USC steam conditions, the reduction in the CO2 emission factor exceeds 28%. For identical conditions and lower moisture PRB coal, the reduction in EFCO2 is lower, approximately 22%. As the figure shows, improvement in coal quality by thermal drying results in significant reduction in CO2 emissions.

The results of the economic analysis performed for the USC and A-USC steam conditions are presented in Figure 4. The capital cost (CAPEX) savings for all analyzed coals are given as functions of the reduction in coal moisture content.

For a new plant, the CAPEX savings increase with the reduction in TM and are higher for the A-USC conditions compared to the USC due to the smaller size and lower cost of the DryFining system. The highest CAPEX savings from the analyzed coals were achieved by the Indonesian WARA coal, followed by the U.S. lignite and PRB coals. For these coals, A-USC steam conditions, and ΔTM of 25%, CAPEX savings are in the US$170–220 per kW range, or 6–7.5% of the plant capital cost. For the USC steam conditions, the CAPEX savings are approximately US$75–85 per kW lower.

As the results show, thermal drying of high-moisture coals provides significant capital cost savings for the USC and A-USC steam conditions, and should be considered for all new advanced PCC plants.


An effective method of increasing net efficiency of PCC plants is to increase steam parameters and improve coal quality. This is particularly important for advanced PCC technology (USC and A-USC), which operates at high steam parameters. The negative effect of high coal-moisture content on efficiency increases as steam parameters increase, reducing the benefits of USC and A-USC operation.

Analyses applying DryFining to advanced PCC power plants were carried out to determine the effect of reduced coal moisture content on plant performance, CO2 emissions, and capital cost. Results indicated that plant efficiency increases as TM is reduced and steam conditions are increased; the largest improvement can be achieved with combustion coal having the lowest moisture content at A-USC steam conditions. The efficiency improvement from coal drying increases with higher moisture coals in comparison to lower moisture coals. Plant efficiency is improved due to reduction in fuel moisture from thermal drying, resulting in decreased flow rates of coal, flue gas, and emitted CO2.

In conclusion, improvement in coal quality by thermal drying has a significant positive effect on the power plant efficiency and reducing CO2 emissions. Economic analysis results show that CAPEX savings increase with the reduction in TM. The savings are better for higher steam conditions due to the smaller size and lower cost of the DryFining system.

Thermal drying of high-moisture coals provides significant capital cost savings, especially for the USC and A-USC steam conditions, and should be considered for all new PCC plants.


  1. Nicol, K. (2013). Status of advanced ultra-supercritical pulverised coal technology. CCC/229. London: IEA Clean Coal Centre.
  2. Mills, J.S. (2011). Global perspective on the use of low quality coals. CCC/180. London: IEA Clean Coal Centre.
  3. Dong, N. (2014). Techno-economics of modern pre-drying technologies for lignite-fired power plants. CCC/241. London: IEA Clean Coal Centre.
  4. Reed, I. (2016). Retrofitting lignite plants to improve efficiency and performance. CCC/264. London: IEA Clean Coal Centre.
  5. Bullinger, C.W., & Sarunac, N. (2006). Lignite fuel enhancement final technical report: Phase 1. DOE Award Number: DE-CF26-04NT41763.
  6. Bullinger, C.W., & Sarunac, N. (2010, June). Lignite fuel enhancement. Final Technical Report. DOE Award Number: DE-CF26-04NT41763,
  7. Sarunac, N., Levy, E.K., Ness, M., Bullinger, C.W., Mathews, J.P., & Halleck, P. (2010). A novel fluidized bed drying and density segregation process for upgrading low-rank coals. International Journal of Coal Preparation and Utilization, 29(6), 317–322.
  8. Sarunac, N., Bullinger, C.W., & Ness, M. (2015). Four years of operating experience with DryFiningTM fuel enhancement process at Coal Creek generating station. Presented at 39th International Technical Conference on Clean Coal & Fuel Systems, Clearwater, FL.
  9. Sarunac, N., Bullinger, C.W., & Ness, M. (2015). Four years of operating experience with DryFiningTM fuel enhancement process at Coal Creek generating station. Journal of Energy and Power Engineering, 9, 526–538.
  10. Yao, Y., Levy, E.K., Wang, X., Sarunac, N., Bullinger, C.W., & Ness, N. (2016). Low temperature drying process improves heat rate and water balance for power plants. Presented at 41th International Technical Conference on Clean Coal & Fuel Systems, Clearwater, FL.
  11. Booras, G. (2015, September). Engineering and economic analysis of an advanced ultra-supercritical pulverized coal power plant with and without post-combustion carbon capture. Topical Report Task 7: Design and Economic Studies, DOE Cooperative Agreement No. DE-FE0000234, Energy Industries of Ohio, EPRI, and GE Power and Water,

The author can be reached at


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Doing the Right Work at the Right Time in the Power Plant of Tomorrow

By Steven Seachman
Senior Technical Leader, Electric Power Research Institute

Cisco estimates 21 billion devices will connect to the Internet by 2018 (three times the world population and up from 14 billion in 2013).1 This number will include sensors and other devices that aid in the supply and use of electricity. The proliferation of these sensors, the data they collect, and sophisticated new technologies that enable transformational applications of that data will profoundly change society, including the way we generate, distribute, and use electricity.

There are, however, some challenges. They include the sheer volume of data; proprietary legacy systems; the need for enhanced security; inconsistent life-cycle timescales of utility assets and connectivity technologies; rapid technological change; and effective integration of technologies into the power system, including intelligent devices, sensors, advanced metering, and even customer technologies. Fortunately, these challenges also bring opportunities spanning the energy value chain. A digital world full of new technologies with vast potential for addressing most needs via a pocket-held device offers an as-yet untapped arsenal of tools that could meet these challenges and transform the industry’s generating assets.

The I4GEN concept includes connectivity at every level of information, providing the data needed to the proper systems and personnel. (Courtesy EPRI)

The bottom line is this: The power plant of tomorrow is likely to generate electricity in much the same way it has in the past, but the way in which the plant is controlled and operated—using digital technology—will change dramatically. And these changes will be driven by new, advanced sensors and data analytics.


Today’s typical large-scale power plants have existing systems, communication capabilities, and work processes. Some of these processes are paper based and communication occurs through a variety of disconnected, ad hoc channels such as e-mail, phone, text, radio, paper, and electronic data/entry into various software-based solutions/data management tools. Considerable time is wasted seeking, assembling, and aggregating data, as well as re-entering data in disconnected systems, which limits the amount of time available to analyze data and develop a comprehensive understanding of an issue or solution.

I4GEN includes digital worker technologies that provide all needed information to the technician based on component and job requirements. An EPRI video ( provides an example of a plant worker using a wearable technology to assess equipment condition. (Courtesy EPRI)


The future power plant operating workforce will use a digital platform in which information produced in real time is used to estimate equipment condition, and algorithms are used to forecast a set of operating conditions. The connected and integrated digital networks automatically integrate data and produce the information for various systems, functions, analysis, personnel, and actions. The computation, communication, and linking of systems are embedded with interfaces that are easy to use, but secured at various levels within the network. An open-architecture modular system allows for “plug and play” of new devices, software, and other algorithms regardless of the developer or vendor.

The Electric Power Research Institute (EPRI) and other companies are developing detailed visions of tomorrow’s power plant with seamless integration of data, autonomous communication of information, and corresponding response, action, or control. EPRI’s I4GEN (Insight through the Integration of Information for Intelligent Generation) concept is a holistic approach that creates a digitally connected and dynamically optimized power plant by using a modular and scalable platform of tools, techniques, and technologies that integrate the business, maintenance, and operational aspects of generating power. The goal is to enhance performance, reduce failures, increase availability, improve flexibility, and minimize cost. Dynamically optimizing a plant requires collection and aggregation of data and production of real-time information; embedded distributed and adaptive intelligence that supports decision-making; and identification of actions and responses to account for risk, reward, and uncertainty.

The I4GEN concept is to optimize the use of all available information to make better decisions for the plant, be it autonomous or by the plant operator. Emerging data analytic algorithms are intended to detect degradation at early stages, diagnose the most likely cause of degradation, and estimate the remaining time to take action before an operability limitation will be reached. Successful development and deployment of detection and diagnosis algorithms can result in increased plant reliability, decreased plant O&M costs, reduced forced outages, more efficient use of O&M resources, and minimization of the impact resulting from flexible operations. This is performed through many different avenues. Data can come from operating data from instrumentation in the plant; external sources such as weather conditions, expected demand on the plant and plant flexibility; archived data; and subject-matter expert (SME) specifications and guidelines.

Successful collection and analysis of the most appropriate data enables important advances such as prognostics—doing the right work at the right time—maintaining, repairing, or replacing equipment when needed, instead of when recommended based on hours of service or other, less precise metrics. This enhanced diagnosis of component condition and remaining life can come from optimizing sensor suites. Information is then gathered where needed and vital type and location sensors are identified (what types, how many, where they are located, reduced redundancies); sensor groupings and embedding intelligence into sensors so that they continue to retrieve valuable information even as sensor data drifts or certain sensors fail; and data analytics, statistical methods, model-based methods, SME input (when needed), and machine learning.

The ultimate goal of I4GEN is to make the most useful information available to a person at the time it is needed to make a decision or perform an action. A power plant using I4GEN produces, shares, manages, and manipulates information at the appropriate time, within proper context, and at a level of detail sufficient to support a response. It is enabled through an open-architecture communication framework that is scalable, modular, and secure. Its foundation relies on dense and distributed data collection, aggregation, and computational analytics to generate actionable information. Optimization and effectiveness are the result of having actionable information in context and at the appropriate time to achieve an objective.

The drivers for adopting the new digital technologies for power generation envisioned in I4GEN are many:

  • Grid modernization and integration: As part of an integrated grid, power will be generated from a range of sources; the mix of types, sizes, locations, and intermittent operations adds layers of complexity to the grid control. Dynamic, fully integrated generation assets are required to achieve the full benefits of the integrated grid.
  • Critical cost-competitiveness: Maintaining the reliability and availability of power generation is paramount when introducing new facets of flexible operation. Quantifiable benefits from implementing and adapting the I4GEN architecture/framework would be specific to the generating asset, how it is used within a fleet, and how it is used for a region’s dispatch to the grid.
  • Changes in the generation resource portfolio and the need for operational flexibility: The mix of generating assets is changing as the portfolio becomes more diverse with the advent of advanced power cycles, renewables, energy storage, microgrids, and other distributed generating assets.
  • Changing workforce: Highly skilled and experienced workers are either retiring or preparing to retire from the power industry. The new workforce brings a different set of skills and capabilities, including an in-depth familiarity and expertise with digital technologies. Plants facing a significant turnover with staff and a potential loss in expertise may also view an investment in digital technologies as a means to capture and automate the expertise, facilitate training of new personnel, and reduce risk associated with staff turnover.
  • Inherent value in owning, managing, and controlling data and information: Generating plants produce vast amounts of data: Managing and sharing that data is a critical function for moving from a reactive state to a more proactive state. As organizations recognize and assign value to plant data and information, similar to how they currently treat financial data, the opportunities, benefits, and drivers associated with this valuation emerge.

Workflow is optimized and automated through connectivity of all needed information. (Courtesy EPRI)


The I4GEN concept can be applied to all types of generating assets. Remotely located generating assets, such as hydroelectric and wind, which do not maintain large, onsite staffs may develop highly advanced monitoring and diagnostics to support more effective use of onsite inspection and maintenance. Slightly different drivers and emphasis may be placed on large-scale central power stations in which enhancements in process controls may be needed to support operational flexibility.

Besides producing electricity, all these generating assets have something in common, the two keys to success in their transition to the generating plants of tomorrow: advanced sensors and the data analytics needed to realize the value of the information they provide. After the sensor suite has been developed, the sensors are able to communicate, and data is being fed into the data analytics suite, the plant should be able to detect, diagnose, and act rapidly with much less downtime than current methods allow.

The I4GEN concept requires connectivity and communication between systems, hardware, and software users. This requires an increase in data collection; autonomous data integration; methods for massive data management; ability to reconfigure data integration and analysis; incorporation of advanced query capabilities; and application of intelligence algorithms (e.g., cognitive, analytics, artificial intelligence, etc.). Enabling technologies include component and system modeling, augmented reality, visualization, and networked systems (hardware and software) to provide real-time information, distributed and adaptive intelligence, and action and response.

Novel sensor technology, such as this torsional vibration sensor, can be used for early detection of component faults. (Courtesy EPRI)

Real-time data on component status will identify developing problems and support condition-based maintenance to help prevent failures and avoid outages. Improved situational awareness will allow operators to extend maintenance intervals and maximize asset utilization, helping reduce costs and improve productivity without affecting safety and reliability. The ability to monitor key parameters in areas that could not previously be accessed—or only accessed with significant cost and safety implications—will enable operating and maintenance interventions to address incipient problems and otherwise improve the performance of electricity infrastructure.

EPRI’s Technology Innovation (TI) program is pursuing novel sensor designs for steam turbine and combustion turbine compressor blades and pressure-retaining components, as well as overhead transmission lines, transformers, underground distribution cables, and other applications. This effort also focuses on core technologies for data analysis, decision support, and power harvesting for self-powered sensor technologies.

Three examples of sensor technology developments specific to power generation that are supported by EPRI TI projects include blade vibration sensors, laser-based sensors for coal gasifiers, and fiber Bragg grating (FBG) sensors for nuclear plant applications. Since 2009, EPRI has been leading efforts to create a microelectromechanical (MEM) sensing system for direct online vibration monitoring of large blades in low-pressure steam turbine stages to detect incipient damage and avoid catastrophic failure, which poses major cost and safety risks at thermal power plants. The system is also applicable for combustion turbine compressor blades.

The shaft systems on large grid-connected steam turbine generators can be subjected to dynamic torque (or “twisting”) oscillations caused by negative sequence currents in the generator. To date, prototype EPRI torsional sensors to detect these oscillations have been installed and field tested on three shaft locations on two separate generating units. The accumulated operating time represents a total of 11 unit-months of operation without failure of the shaft sensors, circuit boards, or the stationary antenna assemblies. Compared to earlier technologies, the system is highly sensitive and provides more data, with a higher degree of granularity, making it easier to tell where the torsional peaks are. The data provides an accurate picture of each individual torsional node, enabling assessments of the failure mechanisms. It is anticipated that highly sensitive and low-noise shaft strain monitoring will be the basis for advances in a range of new condition-monitoring applications on a wide array of power generating equipment.

Reliability problems challenge the economics of integrated gasification combined-cycle (IGCC) plants, creating the need for a system to prevent the temperature excursions that damage refractory linings. Based on exploratory research initiated in 2000, EPRI demonstrated the feasibility of applying tunable diode laser (TDL) technology for this application. An initial prototype delivered accurate temperature readings and the first direct, real-time measurements of key chemical species in the high-temperature, high-pressure, particulate-laden gasifier environment. Follow-on scale-up experiments supported development of a TDL sensor system incorporating advanced spectroscopy techniques and multiple diodes tuned to the wavelengths of targeted species. Commercial TDL sensors are expected to provide real-time data for precise monitoring and control of the gasification process to improve reliability, conversion efficiency, and environmental performance at IGCC plants.

Other EPRI TI advanced sensors and data analytics projects include:

  • Transient analysis methods: Much like autos running at highway speed, most bulk power generation assets operate most efficiently in steady states at high capacity. Their components are under the most stress during start-up, load change, and shut-down cycles. EPRI has explored use of transient analysis methods to uncover data anomalies and trends that indicate the onset of aging or failure. In a proof-of-concept study, aging-related performance degradation of a high-speed motor not evident in steady-state data was clearly detected in start-up data. Follow-on work has established a novel method, sharp time distribution mapping, as a generalizable approach for applying transient sensor data to improve anomaly detection for power generation and delivery system components.
  • Decision-support technologies: EPRI is creating a knowledge and capability base to enable accurate and timely decision-making in power plant and grid control centers where personnel are challenged to handle large amounts of complex and diverse data from sensors and other sources with support from growing amounts of automation. A long-term, multidisciplinary research plan has been defined for addressing the industry’s decision-making needs with interactive human–system interface (HSI) technologies, including analysis, visualization, and simulation tools. In addition, based on advanced HSI test cases, design guidelines have been developed to ensure that decision-support technologies meet application-specific needs while avoiding loss of situation awareness and other new types of errors associated with increased automation. The guidelines will aid in the design of user-centered HSIs, responsibilities, and workloads to support decision-making in environments where cognitive processing is essential, such as control rooms, control centers, and monitoring and diagnostics centers.
  • Power harvesting and storage: A number of promising methods have been identified for exploiting ambient energy sources to support the autonomous operation of sensors and associated electronics within power generation and delivery infrastructure. A laboratory test bed for evaluating harvesting technologies has been constructed, and this project continues to focus on applications of self-powered sensors in nuclear, fossil, and renewable generation systems and on the transmission and distribution grid.


Adopting the I4GEN approach in totality will be a large undertaking. In many cases, adoption of selected digital technology platforms and capabilities over time, with short-term returns on investment and measurable benefits, is a more likely scenario. Near-term development and demonstration opportunities that offer tangible benefits and utilize many of these enabling technologies include:

  • Digital worker: Tablets, smart phones, laptops, wearable monitoring devices, headsets, and augmented reality devices can be used by staff to carry out or complete a given job function. Wireless communication capabilities; developing relevant information, procedures, guidance, equipment tagging, operator rounds, and work order entries in a digital format that is easy to access and intuitive; and ergonomics, safety, and impact on situational awareness need to be evaluated under different scenarios.
  • Virtual reality and simulated plant analytics and operation: 3-D interactive images of workspaces and equipment layouts support training and assists in work planning and can be linked to digital devices to support work execution. A plant process simulation running in near time using data from the plant can be used to assist in optimization of the process and provides a safe environment to forecast a number of operating conditions to aid the plant in performance.
  • Low-cost sensing and monitoring: Additional data can help produce information and insights about the process, equipment and component conditions, and other operational aspects, but the cost to purchase, install, and maintain these sensors can be a challenging hurdle. Many new types of sensors are entering the market that are both low-cost and wireless; installation costs can be comparably less if a wireless network is available and powering the sensors can be managed cost-effectively. A number of low-risk opportunities exist to demonstrate new sensor technology and evaluation of additional data may bring in greater insights and proactive operations and maintenance.

The I4GEN concept uses monitoring and diagnostics centers to provide needed information from the equipment level to the fleet-wide operations level. (Courtesy TVA/EPRI)

EPRI plans to develop and implement the I4GEN technologies discussed above that will support power generation companies at various stages of maturity. Whether an organization is at the beginning stages of learning about I4GEN-associated technologies and applications or have already invested in advanced remote monitoring centers, digital worker applications, etc., this development and implementation will provide opportunities for collaboration, technology transfer, and development of industry guidelines to further work in this area.


  1. Cisco®. (2016). Visual Networking Index: Global mobile data traffic forecast update, 2015–2020. White Paper. San Jose, CA: Cisco Systems, Inc.,


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Advances in Pressurized Oxy-Combustion for Carbon Capture

By Richard L. Axelbaum
Jens Professor of Environmental Engineering Science,
Washington University in St. Louis
Benjamin Kumfer
Research Assistant Professor, Washington University in St. Louis
Xuebin Wang
Associate Professor, Xi’an Jiaotong University

Coal provides enormous benefits to society and continues to be a major energy source for power generation because of its large reserves, ease of transportation and storage, and low price. Coal-fired power generation also is one of the largest contributors to CO2 emissions. One promising technology for CO2 mitigation is oxy-combustion. However, first-generation oxy-combustion technologies, which operate under atmospheric pressure, suffer from a significant penalty in net generating efficiency—over 10 percentage points—primarily due to the auxiliary energy consumption from the air separation unit (ASU), flue gas recirculation (FGR), and gas processing unit (GPU). A promising new technology is pressurized oxy-combustion (POC), which can increase the plant efficiency by recovering the latent heat in the flue gas moisture and coupling it back into the steam cycle. An advanced POC technology is currently being developed at Washington University in St. Louis (WUSTL), Missouri, U.S.A. This technology can achieve an increase of more than six percentage points in net generating efficiency over the first-generation oxy-combustion process and is paving the way for low-cost carbon capture.1


In the simplest sense, pressurized oxy-combustion is oxy-combustion occurring within a pressurized vessel with a condensing heat exchanger downstream. There are several justifications for this added complexity. First, the large white plumes emitting from the stacks of a power plant, as seen from Figure 1, represent a large amount of moisture. When this moisture condenses in the atmosphere, the heat being released has no benefit to the power cycle. Thought of another way, the amount of energy needed to evaporate water to form this plume is quite large and this energy is lost to the power plant. POC harnesses this energy.

FIGURE 1. Typical power plant showing the plume of condensed moisture leaving the stacks

Since carbon capture and storage (CCS) requires pressurization of CO2, there is no change to net loss of efficiency to pressurizing the combustion process. When the flue gases are at an elevated pressure, the condensation temperature for the moisture can be high enough that the latent heat can be captured and fed into the steam cycle, increasing the efficiency of the process. Although a pressure of 10–16 bar is sufficient to recover most of the latent heat, pressures up to 80 bar have been proposed.2,3

The basic flow sheet for POC is similar to that of atmospheric pressure oxy-combustion, which includes the ASU, FGR, and GPU, but it also includes a condensing heat exchanger to capture the latent heat of the moisture. The ASU supplies oxygen at around 95% purity to the boiler. FGR is a widely accepted method in oxy-combustion for moderating combustion temperature and boiler wall heat flux, and FGR may also be employed as carrier gas to deliver pulverized coal to the boiler. Even though coal water slurry feeding has been proposed for pressurized coal delivery,4 dry feeding of pulverized coal yields higher boiler efficiency and has been widely used in gasifiers at pressures up to 40 bar.5 After the warm flue gas leaves the boiler(s), particulates are removed using a filter. The warm particle-free gas then enters a condensing heat exchanger designed to recover the latent heat of the flue gas moisture and feed it into the steam cycle. Pressurization allows for simultaneous removal of SOx and NOx and the capture of latent heat in one device. The CO2 is further compressed and purified in the GPU before it is pipeline ready.


The primary benefits of POC include:

  1. capturing the latent heat of condensation and utilizing it to increase cycle efficiency;
  2. reducing the efficiency penalty associated with using high-moisture fuels, since latent heat is recovered, thereby making low-rank coal more valuable;
  3. simplifying the capture of SOx and NOx because pressure allows for co-capture of these pollutants in a simple water wash column;
  4. greatly reducing gas volume, thereby reducing the size and cost of equipment;
  5. avoiding air ingress, thereby reducing the GPU purification cost, and
  6. increasing the optical thickness in the boiler, which allows for optimization of radiant heat transfer and reduced flue gas recycle.

The first few benefits are explained in more detail below.

High Efficiency Through Latent Heat Recovery From Flue Gas

The primary motivation to use POC, rather than atmospheric oxy-combustion, is to utilize the recovered latent heat from the flue gas, which compensates for the parasitic energy consumption of carbon capture. The temperature at which phase change occurs is strongly dependent on operating pressure. For example, at atmospheric pressure the flue gas moisture condenses at 50–55°C. At a pressure of 80 bar, condensation occurs at 150–200°C.6 The significant increase in condensation temperature makes it feasible to utilize the latent heat. Both direct-contact and non-contact heat exchangers could be used for latent heat recovery.

The latent heat that is captured can be utilized in the steam cycle by heating boiler feed water. This approach leads to replacement of roughly half of the steam extraction from the turbines. Less extraction allows more steam flow through the turbine and, thus, an increase in gross power.6

Integrated Emissions Removal

Higher pressure enables integrated emissions control, which can replace traditional and expensive emission control equipment such as the Selected Catalytic Reduction (SCR) for NOx and Flue Gas Desulfurization (FGD) for SOx.

Earlier studies have demonstrated that when flue gases are compressed in the presence of water, conversion of gaseous pollutants to weak sulfuric and nitric acids is enhanced by chemical interactions between S- and N-containing species. This occurs at elevated pressure, but not atmospheric pressure. While the precise chemical reaction mechanism that occurs under pressure is still a subject of study, the process is loosely referred to as the “lead chamber” process, which is a well-known process for manufacturing sulfuric acid. Test results have shown that almost all the SOx and about 80% of NOx is removed at 15 bar. An extra column operating at about 30 bar may also be employed for a more complete removal of NOx.7 The key requirements for the process are that the NOx/SOx ratio is greater than about 0.5, the pressure is greater than 15 bar, and the process occurs in the presence of liquid water.8, 9

This process of emissions capture can be combined with the process of flue gas moisture condensation and latent heat recovery in a single counter-flowing water wash column, as illustrated in Figure 2. Wet flue gas at a temperature greater than the acid-gas dew point (≥300°C) flows into the gas-liquid reactor column from the bottom. The flue gas flows against a stream of cooling water, thereby reducing the flue gas temperature. When gas temperature decreases to the dew point, condensation of the flue gas moisture occurs, releasing the latent heat, which is captured in the cooling water. Dew point increases with pressure, and thus the temperature of the water leaving the column increases with pressure. At 16 bar the value is about 167°C, which is sufficiently high to allow the heat to be used for boiler feed water heating.

FIGURE 2. Direct contact cooler (DCC) column for flue gas cooling, latent heat recovery, and SOx and NOx capture

When applied in a POC system, this approach includes the following benefits:

  1. Unlike the protocol for atmospheric pressure oxy-combustion systems, the flue gas need not be compressed because it is already at elevated pressure; thus, the challenges of avoiding corrosion when compressing a sour gas is eliminated.
  2. The capture of flue gas latent heat occurs along with SOx and NOx, which is more economical as compared to separate capture systems.
  3. Acid gas condensation occurs in a single device, reducing the chance of corrosion in other parts of the system.
  4. Because no cooling is necessary before the flue gas enters the DCC, the overall efficiency of the process is maximized.


An extension of POC, the novel staged, pressurized oxy-combustion (SPOC) process, can reduce the efficiency penalty for carbon capture in coal-fired power plants by over half. The SPOC process incorporates a unique boiler configuration to enable combustion of pulverized coal at elevated pressure (approx. 15 bar) with minimal flue gas recycle.


The SPOC process is depicted in Figure 3. A key feature, as compared with the traditional oxy-combustion processes, is that two or more pressurized boilers are connected in series on the gas side. In addition to allowing for reduced FGR, the use of multiple boiler modules also provides added flexibility in plant design and operation under variable loads. Although four boilers, or stages, are shown in the figure, fewer stages may be employed by increasing the amount of flue gas recycle. The optimum operating pressure of the SPOC boilers is around 15 bar.10 Coal is fed to the centerline at the top of each boiler, and burns as it flows through each of the respective boilers. The products of the upstream boiler, including any excess oxygen, are passed to the following stage, wherein more coal is introduced. The process repeats until nearly all of the oxygen is consumed in the final stage. The temperature of the products is further reduced in a convective heat exchanger, followed by ash removal. The flue gas is then cooled in a direct contact cooler (DCC), where moisture is condensed, the latent heat is captured, and SOx and NOx are removed. The majority of flue gas then goes to the GPU where it is further purified to meet the stringent specifications for storage or EOR.

FIGURE 3. The gas and steam flow diagram of the SPOC process

Higher Net Generating Efficiency

The SPOC process has several other benefits to increase efficiency and reduce capital and operating costs: (1) FGR is minimized, which decreases flue gas volume, equipment size, and parasitic pumping loads, and increases boiler efficiency; (2) a high gas temperature is maintained to maximize the overall amount of radiative heat transfer, as compared to convective, thereby minimizing the amount of heat transfer surface area and reducing boiler exergy losses; and (3) moisture condensation and emissions removal are combined in a compact DCC device to remove SOx and NOx while recovering latent heat, which minimizes equipment size and cost.

As shown in Table 1(a), the net generating efficiency of the SPOC process can be over six percentage points greater than that of first-generation atmospheric pressure oxy-combustion. The penalty associated with carbon capture on net generating efficiency can be as low as three percentage points, as compared with the traditional air-fired power plant. The improvement in net generating efficiency over the reference atmospheric pressure case is due to a number of factors, but most of the savings are related to the SPOC process.

The capture of latent heat in the DCC is a major contributor to the increase in net generating efficiency of the SPOC process over atmospheric pressure oxy-combustion, adding 10% more heat to the steam cycle. The increase in efficiency and reduction in equipment costs translate into substantial reduction in the added cost of electricity (COE) associated with carbon capture, thereby showing potential to meet the U.S. Department of Energy’s target of less than 35% increase in COE.13 Électricité de France independently evaluated the SPOC process and an alternative pressurized oxy-combustion process and compared them with atmospheric pressure oxy-combustion and air-fired combustion (Table 1(b)).14 The goal was to understand the advantages and disadvantages of the different approaches to pressurized oxy-combustion from an energetic and exergetic standpoint. This study showed that the increase in radiative heat transfer relative to convective heat transfer in the SPOC process increases the overall exergy transfer from the flue gas to the steam cycle, which increases the plant efficiency. In addition, since the SPOC process required less FGR, the auxiliary load was lower, further increasing the plant efficiency.

TABLE 1. Comparison of the net generating efficiency of air-fired, atmospheric-oxy, and pressurized-oxy combustion power plants

Controllable Radiation Heat Transfer

Pressurization of the combustion process enables operation at higher combustion temperature and, thus, reduced FGR, to a degree that is not possible at atmospheric pressure. This is because at sufficient pressure, radiation heat transfer is dramatically altered since the combustion gas, which contains char and ash particles, becomes optically dense. Recognizing this, the team has developed, through CFD-aided design and fundamental studies, a unique approach to pressurized boiler design that can provide control of wall heat flux under very high flame temperatures.15,16 This approach is called “radiative trapping” as it utilizes the optically dense medium to trap the radiative energy emitted by the high-temperature flame within the reactor core (Figure 4) and control the heat transfer to the boiler tube surfaces. The SPOC boilers have additional design features to ensure that there is no flame impingement on the water wall. The ash deposition rate is substantially lower than that of a traditional air-blown boiler, and ash fouling and slagging are minimized.

FIGURE 4. Illustration of “radiative trapping” in SPOC furnace

Research Facility

WUSTL has recently completed construction of a lab-scale (approx. 100-kWth) pressurized combustion facility, shown in Figure 5. The facility will be utilized to demonstrate the staged oxy-combustion approach and obtain key experimental data to validate the computational fluid dynamics results.

FIGURE 5. The 100-kWth lab-scale SPOC facility at WUSTL


Pressurized oxy-combustion, with the potential to capture over 90% of the CO2 at high efficiency and affordable costs, is poised to transform coal-based power generation. Through the recovery of flue gas moisture latent heat and the minimization of flue gas recycling, staged, pressurized oxy-combustion is able to achieve a net generating efficiency of 36.7% (HHV, supercritical conditions) with only about 3% penalty on net generating efficiency. Further improvements are anticipated as advances are made in ASUs and CO2 purification technology, and in the development of modular boilers for pressurized coal combustion.


  1. Gopan, A., Kumfer, B.M., Phillips, J., Thimsen, D., Smith, R., & Axelbaum, R.L. (2014). Process design and performance analysis of a Staged, Pressurized Oxy-Combustion (SPOC) power plant for carbon capture. Applied Energy, 125, 179–188.
  2. Hong, J., Field, R., Gazzino, M., & Ghoniem, A. (2009). Performance of the pressurized oxy-fuel combustion power cycle with increasing operating pressures. Paper presented at the 34th International Technical Conference on Clean Coal & Fuel Systems, 31 May–4 June, Clearwater, FL, U.S.
  3. Fassbender, G. (2001). Power system with enhanced thermodynamic efficiency and pollution control, Patent US 619600 B1. Washington, DC: U.S. Patent and Trademark Office.
  4. Hong, J.S., Chaudhry, G., Brisson, J.G., Field, R., Gazzino, M., & Ghoniem, A.F. (2009). Analysis of oxy-fuel combustion power cycle utilizing a pressurized coal combustor. Energy, 34(9), 1332–1340.
  5. U.S. Department of Energy National Energy Technology Laboratory (U.S. DOE NETL). (n.d.). Entrained flow gasifiers,
  6. Zheng, L.G. (Ed.). (2011). Oxy-fuel combustion for power generation and carbon dioxide (CO2) capture. Woodhead Publishing Series in Energy. Cambridge: Elsevier.
  7. White, V., Wright, A., Tappe, S., & Yan, J. (2013). The Air Products Vattenfall oxyfuel CO2 compression and purification pilot plant at Schwarze Pumpe. Energy Procedia, 37, 1490–1499.
  8. Normann, F., Jansson, E., Petersson, T., & Andersson, K. (2013). Nitrogen and sulphur chemistry in pressurised flue gas systems: A comparison of modelling and experiments. International Journal of Greenhouse Gas Control, 12, 26–34.
  9. Murciano, L.T., White, V., Petrocelli, F., & Chadwick, D. (2011). Sour compression process for the removal of SOx and NOx from oxyfuel-derived CO2. Energy Procedia, 4, 908–916.
  10. Gopan, A., Kumfer, B.M., Axelbaum, R.L. (2015). Effect of operating pressure and fuel moisture on net plant efficiency of a staged, pressurized oxy-combustion power plant. International Journal of Greenhouse Gas Control, 39, 390–396.
  11. U.S. DOE NETL. (2010). Cost and performance baseline for fossil energy plants. Vol. 1, rev. 2: Bituminous coal and natural gas to electricity, DOE/NETL-2010/1397.
  12. U.S. DOE NETL. (2012). Advancing oxy-combustion technology for bituminous coal power plants: An R&D guide, DOE/NETL- 2010/1405.
  13. Axelbaum, R. (2014, 1 August). Staged, pressurized oxy-combustion for carbon capture: Development and scale-up. Presentation at 2014 NETL CO2 Capture Technology Meeting, Pittsburgh, PA, U.S.
  14. Hagi, H., Nemer, M., Le Moullec, Y., & Bouallou, C. (2014). Towards second generation oxy-pulverized coal power plants: energy penalty reduction potential of pressurized oxy-combustion systems. Energy Procedia, 63, 431–439.
  15. Xia, F., Yang, Z., Adeosun, A., Gopan, A., Kumfer, B.M., & Axelbaum, R.L. (2016). Pressurized oxy-combustion with low flue gas recycle: Computational fluid dynamic simulations of radiant boilers. Fuel, 181, 1170–1178.
  16. Xia, F., Yang, Z., Adeosun, A., Kumfer, B.M., & Axelbaum, R.L. (2016). Control of radiative heat transfer in high-temperature environments via radiative trapping—Part I: Theoretical analysis applied to pressurized oxy-combustion. Fuel, 172, 81–88.

The first author can be reached at


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Using Automation to Increase Mining Safety and Productivity

By Hua Guo
Research Director, Coal Mining Research Program, CSIRO

Improving longwall mining safety, and with it productivity, is a priority for Australia’s leading applied research agency, the Commonwealth Scientific and Industrial Research Organisation (CSIRO). CSIRO’s Coal Mining Research Program, based at the Queensland Centre for Advanced Technologies, is made up of some 70 specialists who work with industry to improve ground stability and mine gas and fire control, and to develop advanced technologies that enhance workplace safety and productivity.

The team is credited for the development of an automation technology known as LASC (Longwall Automation Steering Committee), which is used by the majority of longwall mining operations in Australia.1,2 Its implementation has arguably improved longwall mining safety and productivity more than any other innovation in the last decade.3 The technology automates the longwall mining process and has improved safety by moving people away from the hazards of the mine’s working face. At the same time, LASC has delivered productivity gains of up to 10% during peak operating periods. Over the long term, this translates to a productivity gain of 5%, saving mine operators millions of dollars each year.

Today CSIRO is close to even more innovative advancements in its automation technology, by adapting this technology to the continuous miner (CM) operations used to develop underground coal mine roadways. This adaptation will again protect lives and boost productivity in an area that is widely considered a bottleneck in the coal supply chain.

Longwall mining shearer


LASC is a suite of enabling technologies and systems that allows longwall mining equipment of any brand to be automated using inertial navigation system (INS) technology. The INS technology allows the 3D position of the major elements of the longwall mining system to be measured accurately for the autonomous operation of mining systems underground.

The LASC suite automates the hazardous manual tasks of face alignment and steering, as well as horizon control. Thanks to a WiFi-enabled shearer communication system, a world’s first in the LASC project, the whole process can be controlled remotely.

Four technologies were developed to achieve automation and make up the LASC suite:

  1. Shearer Position Measurement System (SPMS)—a combination of software and hardware that measures and communicates the 3D position of the shearer, and processes the raw data to a meaningful format.
  2. Automated Face Alignment—software that allows the user to monitor and adjust the position of the shearer by sending corrections to the roof support control system to maximize production by keeping the longwall face straight.
  3. INS-Based Automated Horizon Control—a combination of software that manages the transfer of horizon information to the original equipment manufacturer’s (OEM) shearer control system and provides an interface for users to control, monitor, and adjust the shearer’s cutting horizons.
  4. Automated Creep Control—a system comprised of sensors mounted adjacent to the main gate to measure the cross gate road creep distance of the main gate hardware, and supporting software that displays the information and computes corrections.


The key to achieving automation was developing effective enabling technologies that would open up the use of high-accuracy INS underground. The idea in itself was not new, and during the 1990s CSIRO demonstrated that it was possible to guide highwall mining machines using inertial navigation. Realizing that the principle could also be applied to measuring and controlling the motion of a longwall shearer, CSIRO began developing strategies that would allow an INS to be effectively used underground.

An INS calculates the position of a moving object based only on its motion without the need for an external reference, but a small error in the measurement is always present. This error increases over time and makes the INS unusable, so, from time to time, INS information needs to be checked against other navigation methods.

Above ground, almost all navigation systems use GPS to provide position information to correct or minimize measurement errors. It’s a different story underground, where GPS is unavailable, and the rough, dusty, and hazardous conditions hamper the use of other assistive methods.

CSIRO achieved long-term INS stability by using very high-quality, accurate, low-drift inertial measurement systems and then by ensuring the SPMS included a calculation of the (almost) closed path of the shearer throughout each shear cycle. The horizontal closing distance is used in a patented approach in the automated face alignment system to back-correct the shearer path at the completion of each shear cycle.

The result was a world-first system that could provide 3D measurement of the longwall shearing machine with constant, centimeter-order position accuracy, which is now widely used in the industry.


Finding a way to track the 3D path of the shearer by developing multiple and diverse sensing technologies to support INS underground was a key technology breakthrough.

Other factors that contributed to LASC’s success include:

  • Its design as an open-source platform, with freely available interconnection specifications allowing seamless integration with any brand of mining equipment
  • A unique commercialization model with OEMs, based on a nonexclusive technology license
  • The provision of guaranteed technical assistance to OEMs during the initial roll-out, including detailed implementation guides and access to upgrades
  • The nonexclusive technology license, critical to LASC’s success, was brokered largely because mine operators led the push for automation

The technology development could not have occurred without collaborative support. The coal mining industry, through the Australian Coal Association Research Program (ACARP), provided funding for CSIRO’s automation research and development program, and viewed the resulting technology as a must-have safety feature. Industry participants required a nonexclusive technology license so that they could access it through any OEM industry supplier. OEMs supported this unique arrangement in recognition of the existing market interest, and the savings they had made on research and development activities.


The fact that two thirds of Australian longwall mines are using LASC technology is a testament to the safety and productivity benefits it delivers. Exact figures are hard to obtain due to the commercially sensitive nature of the information; however, an independent evaluation conducted in 2014 by ACIL Allen Consulting found that LASC:

  • contributes to improving the working conditions and safety of coal mine employees as it moves them away from the hazards of the longwall;
  • will likely save mining firms millions of dollars annually as a result of improved safety;
  • delivers productivity increases of up to 10% during peak periods, and, significantly, up to 5% over the long term.

LASC is able to directly improve productivity by up to 10% during peak periods because it facilitates consistency in the longwall mining machine. Over the long term, a 5% increase in productivity can be gained because LASC technology requires all other systems and machines in the mining operation to be in peak condition for automation to be achieved consistently.

When combined with the lower risk of accident and injury, this means fewer process delays and greater efficiency in the entire mining operation.


In just seven years since its commercialization, LASC technology has been adopted by the majority of OEMs—Joy Global, Caterpillar, Eickhoff, Kopex, and Nepean Longwall—for use in their mining machines.

With the strong uptake in the Australian market, CSIRO is now focused on international opportunities. One OEM has taken the technology to global markets and CSIRO is currently working with a number of others active in the Chinese and European markets.

CSIRO’s research team continues to make refinements to the performance of the overall system, particularly in the development of improved mining horizon-sensing strategies using techniques like thermal imaging for coal seam tracking.4,5 Improved horizon control will lead to further economic and new environmental benefits for mine operators through a reduction in the amount of ash. This ultimately results in a cleaner coal product.

Perhaps the most exciting recent developments are based on CSIRO’s ongoing investigations into enhanced inertial system mining applications. In research which is now near commercialization, extra performance has been extracted from inertial systems so that the back-correction step referred to earlier for shearer position measurement is not required, paving the way for “real-time LASC”, which will deliver even more productivity improvement for longwalls.6

CSIRO is also refining inertial navigation aiding strategies so that the technology can be used to automate navigation and control of the continuous miner operations used to develop longwall roadways.


Roadway development has not experienced the same rate of innovation as other areas of longwall coal-mine production and, as a consequence, it continues to be a bottleneck in the coal supply chain. The application of automation technology in this context will speed up roadway development, with huge gains for productivity and personnel safety.

CSIRO is nearing the end of a four-year research and development project aimed at delivering a ”self-steering capability, called ‘”LASCCM” guidance technology, that will enable a continuous miner (CM) to maintain 3D position, azimuth, horizon, and grade control within a variable seam horizon under remote monitoring and supervision.7

Inertial navigation is again central to the design of LASC-CM. Thus, CSIRO has been working to develop aiding strategies to mitigate the effects of INS time-dependent position drift that will work in the roadway development setting, which is less structured than in longwall mining.

CSIRO’s experimental trial involved modifying a skid steer remote control vehicle so that it mimicked most of the CM dynamics in terms of motion profile, wheel slip, and vibration characteristics. This meant that the technology suite could be tested above ground, on a representative surface, which was important because gaining access to a working mine for extended prototype testing is impractical. The vehicle was fitted with CSIRO’s LASC-CM technology, as well as a high-performance GPS system. This allowed the positioning performance of LASC-CM to be compared with an accurate GPS-derived position.

In the trial, the vehicle was programmed to autonomously mimic the action of a CM developing a two-heading drive with cut-throughs. The practical accuracy of the LASC-CM system is demonstrated in Figure 1, which displays a waypoint during a trial. This and other trials have provided a high level of confidence in CSIRO’s approach.

FIGURE 1. Waypoint: practical accuracy of the system

Importantly, the results obtained show that decimeter 2D position accuracy can be achieved with an INS supported by CSIRO’s combination of aiding strategies over long distances, including sharp turns, reversing, and vibration. CSIRO’s work continues to improve the underlying navigation performance of the LASC-CM system, as well as its deeper system integration.

A field trial of the navigation technology during roadway development at an operating mine has now been completed. In this trial, conventional manual roadway development was carried out according to a mine plan and the position of the continuous miner was logged using CSIRO’s system. Results of the trial are shown in Figure 2. Extremely close agreement was obtained between the mine plan and the measured machine position.

FIGURE 2. Trial data from continuous miner using CSIRO’s system

Already the new high-quality miner position information can be used for performance analysis and improvement of existing manual processes. Thus, in the near future, full automation of the process becomes a real possibility because the miner position can be measured robustly with unprecedented accuracy. In a technology transfer process similar to LASC for longwalls, CSIRO will work with leading continuous miner manufacturers on licensing arrangements to deploy the LASC-CM technology commercially.


CSIRO’s research into longwall automation and the subsequent development of commercially available LASC automation technologies have produced clear productivity and safety benefits for longwall mining, and have opened the way to automation of continuous miner operations. Although the basic problems of machine positioning and process control are now close to being solved, barriers to fully autonomous mining operations still remain. Much work remains to be done in machine sensing of the mining environment and consistent automated management of the interaction of the mining process with ground conditions, before the process can be truly autonomous and workers can be removed from underground hazards. CSIRO’s ongoing research is concentrating on resolving these outstanding issues and will contribute significantly to the mining industry’s ultimate goal of zero harm to its people.


  1. Reid, P.B., Dunn, M.T., Reid, D.C., & Ralston, J.C. (2010). Real-world automation: New capabilities for underground longwall mining. Presented at Australasian Conference on Robotics and Automation (ACRA 2010), Queensland University of Technology, Brisbane, Australia.
  2. Reid, D.C., Ralston, J.C., Dunn, M.T., & Hainsworth, D.W. (2015). Longwall shearer automation: From research to reality. In J. Billingsley & P. Brett (Eds.), Machine vision and mechatronics in practice (pp. 49–57). Berlin–Heidelberg: Springer.
  3. Beitler, S., Holm, M., Arndt, T., Mozar, A., Junker, M., & Bohn, C. (2013). State of the art in underground coal mining automation and introduction of a new shield-data-based horizon control approach. SGEM2013 Conference Proceedings, 1, 715–730.
  4. Ralston, J.C., Reid, D.C., Hargrave, C.O., & Hainsworth, D.W. (2014), Sensing for advancing mining automation capability: A review of underground automation technology development. International Journal of Mining Science and Technology, 24, 305–310.
  5. Ralston, J.C., & Strange, A.D. (2015). An industrial application of ground penetrating radar for coal mining horizon sensing. International Symposium on Antennas and Propagation (ISAP 2015), Hobart, Australia, pp. 402–405.
  6. Ralston, J.C., Reid, D.C., Dunn, M.T., & Hainsworth, D.W. (2015). Longwall automation: Delivering enabling technology to achieve safer and more productive underground mining. International Journal of Mining Science and Technology (IJMST), 25, 865–876.
  7. Reid, D.C., Dunn, M.T., Ralston, J.C., & Reid, P.B. (2011). Current research in the development of a self-steering continuous miner, 22nd World Mining Congress and Expo 2011, Istanbul, pp. 197–202.

The author can be reached at

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