CORNERSTONE VOLUME 2 ISSUE 4 THE OFFICIAL ......tries, coal is the only economically available bulk...

The Energy Frontier of Combining Coal and Renewable Energy Systems

WINTER 2014

VOLUME 2 ISSUE 4 THE OFFICIAL JOURNAL OF THE WORLD COAL INDUSTRY

Developing Country Needs Are Critical to a Global Climate Agreement

The Flexibility of German Coal-Fired Power Plants Amid Increased Renewables

Exploring the Status of Oxy-fuel Technology Globally and in China

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Stephen MillsSenior ConsultantIEA Clean Coal Centre

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Our mission is to defend and grow marketsfor coal based on its contribution to a higherquality of life globally, and to demonstrate andgain acceptance that coal plays a fundamentalrole in achieving the least cost path to a sustainable low carbon and secure energy future.

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Renewables and coal are the two fastest growing forms of energy today. The growth of these energy sources is particularly prominent in developing countries, where most expansion in electricity capacity is occurring. Coal and

renewables often require less upfront investment, less infrastructure, and are more widely distributed globally than other energy options, making them ideal choices for regions that need to add electricity capacity in the near term.

Coal and renewable energy systems can be integrated in such a way that the advan-tages of each energy source can be more fully harnessed. For instance, coal and biomass cofiring and cogasification, the most widespread combinations practiced today, allow for larger, more cost-effective plants than would be possible with only biomass, but a smaller carbon footprint than would be possible using coal with-out carbon capture, utilization, and storage (CCUS). In fact, there are many more examples of optimized systems in which renewable and coal energy systems could be optimally integrated.

The main issues facing increased integration of coal and renewable energy sys-tems are not technical. Instead, they are generally institutional. Advocates for such integration are few and far between. However, some of the advantages are worth consideration: Integration can produce more power than a standalone renewable plant and can be an enabling technology to get high-cost renewables, such as uncon-ventional geothermal and concentrated solar power, deployed in the near term. Yet such projects are generally not included under renewable portfolio standards or clean energy standards. In addition, negative net greenhouse gas emissions, which can be achieved through cofiring coal and biomass with CCS, are often not recog-nized by emissions trading schemes.

The deployment of renewables is already changing the operation of coal-fired power plants; tomorrow’s plants will need to be smarter and more responsive than those of the past. As is being demonstrated by Germany’s fleet of coal-fired power plants, rapid turndown to 25–40% of full capacity as well as rapid ramping is now not just possible, but has become standard operating procedure.

Recently, low-carbon energy production from coal took a major step forward with the commencement of operation of SaskPower’s Boundary Dam project. This monumental CCUS project is now demonstrating that low-carbon coal is within our grasp. As coal and renewables grow globally, improved integration and efficiency as well as deployment of CCUS can ensure that coal and renewables can both con-tribute to decreasing the carbon footprint of the energy sector without sacrificing reliability, energy security, and eventually cost. Further demonstration, develop-ment, and deployment will be necessary to reduce costs, which emphasizes why increased integration of coal and renewables must find support within the global energy discussion today.

This issue of Cornerstone offers a wide range of articles that discuss the many areas in which coal and renewables do and could intersect. On behalf of the editorial team, I hope you enjoy it.

Finding Common Ground

FROM THE EDITOR

Holly Krutka Executive Editor, Cornerstone

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CONTENTS

FROM THE EDITORFinding Common GroundHolly Krutka, Cornerstone

VOICESThe Rise of Electricity: Offering Longevity, Improved Living Standards, and a Healthier PlanetFrank Clemente, Penn State University

ENERGY POLICYUnderstanding the National Enhanced Oil Recovery InitiativePatrick Falwell, Center for Climate and Energy SolutionsBrad Crabtree, Great Plains Institute

Developing Country Needs Are Critical to a Global Climate AgreementBenjamin Sporton, World Coal Association

STRATEGIC ANALYSISThe Flexibility of German Coal-Fired Power Plants Amid Increased RenewablesHans-Wilhelm Schiffer, World Energy Council

Toward Carbon-Negative Power Plants With Biomass Cofiring and CCSJanne Kärki, Antti Arasto, VTT Technical Research Centre of Finland

Evolution of Cleaner Solid Fuel CombustionChristopher Long, Peter Valberg, Gradient

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4 Cover Story

The Energy Frontier of Combining Coal and Renewable Energy SystemsStephen Mills

The global demand for energy continues to increase—as the fastest growing sources of energy, coal and renewables are largely responsible for meeting that demand. A Senior Consultant at the IEA Clean Coal Centre explores the projections for coal and renewable deployment as well as opportunities for optimization.


TECHNOLOGY FRONTIERSMaking Coal Flexible: Getting From Baseload to Peaking PlantJaquelin Cochran, National Renewable Energy LaboratoryDebra Lew, Independent ConsultantNikhil Kumar, Intertek

Geothermal Assisted Power Generation for Thermal Power PlantsNigel Bean, Josephine Varney, University of Adelaide

Shenhua’s Development of Digital MinesHan Jianguo, Shenhua Group Co., Ltd

Direct Carbon Fuel Cells: An Ultra-Low Emission Technology for Power GenerationChristopher Munnings, Sarbjit Giddey, Sukhvinder Badwal, CSIRO Energy Flagship

Exploring the Status of Oxy-fuel Technology Globally and in ChinaZheng Chuguang, Huazhong University of Science and Technology and Clean Energy Research Center

GLOBAL NEWSCovering global business changes, publications, and meetings

LETTERS

VOLUME 2 AUTHOR INDEX

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Chief EditorGu Dazhao, Katie Warrick

Executive EditorHolly Krutka, Liu Baowen

Responsible EditorChi Dongxun, Li Jingfeng

Copy EditorLi Xing, Chen Junqi, Zhang Fan

Production and LayoutJohn Wiley & Sons, Inc.

CORNERSTONE (print ISSN 2327-1043,online ISSN 2327-1051) is published four times ayear on behalf of the World Coal Association byWiley Periodicals Inc., a Wiley Company111 River Street, Hoboken, NJ 07030-5774.

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The Energy FrontierBy Stephen Mills Senior Consultant IEA Clean Coal Centre

COVER STORY

The world is undoubtedly hungry for energy and this hunger is growing. There are strong incentives to develop improved sources of energy. By 2040, the

world’s population will have reached nearly nine billion.1 All of these people will need to be housed, fed, and have the opportunity to make a living; this inevitably means that much more energy is going to be needed. By 2040, global energy demand will be about a third greater than current levels.2 Oil,

natural gas, and coal will continue to be used widely, although in some situations, the increasing use of renewable energy sources may reduce the amount of fossil fuels currently used. Regardless, on a global basis, coal will continue to play a major role. This will be particularly true in some of the emerging economies where growing industrialization and urbanization continue to relentlessly drive electricity demand upward.

“Although coal and renewable energy

sources might appear to be strange

bedfellows … we could see increased

deployment of combinations of the

world’s two fastest-growing energy

sources becoming a reality.”


of Combining Coal and Renewable Energy SystemsAt the moment, over 1.2 billion people lack access to any electricity, and another two billion are considered to have inadequate access. A key goal of the 2010 Copenhagen Accord is to provide energy to these underserved populations. There may be few energy source options available—in some coun-tries, coal is the only economically available bulk source capable of providing reliable energy. Although its use is set to decline in some developed economies, coal will continue to be used widely and in considerable quantities. For over a decade, global coal consumption has risen steadily; in some non-OECD countries, in particular, both production and consumption have increased dramatically. During this time, consumption has risen by nearly 60%, from 4.6 Gt in 2000 to about 7.8 Gt in 2012.3 Despite efforts to diversify, coal remains vitally impor-tant for many economies. Since 2000, apart from renewables, it has been the fastest-growing global energy source. It’s the second source of primary energy after oil, and provides more than 30% of global primary energy needs.

The biggest individual coal reserves are in the U.S., Russia, China, Australia, and India. In all of these countries, coal is used to generate large percentages of electricity. In several, it also provides important economic benefits as it is exported to other power-hungry economies. At the moment, coal’s princi-pal use remains electricity generation; coal-fired power plants produce 41–42% of the world’s electricity. In the coming years, electricity will continue to be provided by many differ-ent generating technologies, but the projected combinations are highly site-specific. The IEA World Energy Outlook (2012) suggests that, for the foreseeable future, power production from most sources will continue to increase (Figure 1).4 In many countries, coal and renewable energy systems are being deployed at greater percentages and, thus, there is increased interest in how to optimally integrate these systems. In fact, there are a significant number of opportunities.

AN ODD PARTNERSHIP?

With the ever-increasing use of all types of fossil fuels, there has also been a marked increase in the uptake of renewable energy sources. In many economies, these now represent a rapidly growing share of electricity supply; Table 1 shows the top regions and countries at the end of 2012.

In 2013 renewables made up more than 26% of global gen-erating capacity; in 2013 they produced 22% of the world’s

electricity. Global renewable power capacity continues to increase. In 2013, hydropower and solar PV each accounted for about 33% of new renewable capacity, followed by wind at about 29%.5

Several driving forces support the growth in renewables. All developed nations rely heavily on an adequate and acces-sible supply of electricity and, for a long time, demand has continued to rise in nearly every country. However, in recent years, concerns over issues such as the depletion of energy resources and global climate change have been heightened. The preferred response of many western governments has been a supply-side strategy—namely, to raise the share of renewables (especially renewables other than hydropower) in the energy mix toward 20% and beyond. To date, wind power has emerged as the most competitive and widely deployed renewable energy, although levels of solar power are also growing steadily. Renewable energy technologies such as wind and solar have obvious features that make their use attractive.

FIGURE 1. Global power generation mix4

Poland’s Belchatów coal-fired power station is Europe’s largest thermal power plant (courtesy PGE Elektrownia Belchatów).

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COVER STORY

Although initial capital costs for renewables-based systems can be high, operating costs can be low; emissions generated during day-to-day operation are effectively zero.

Especially in faster-growing energy markets, these renew-able energy systems are not replacing existing or even new coal-fired power plants. Renewables and coal-fired power generation are growing simultaneously. Therefore, it is worth exploring the many options for combining these very different forms of energy in the most cost-effective, environmentally conscious, and efficient means possible. A growing number of hybrid coal-renewables systems have been proposed or are being developed around the world, several of which could offer significant potential.

Coal and Biomass

Combining biomass with coal is a prime example of combining renewables and coal. Such a combination is already deployed fairly widely in the form of cofiring biomass in large conven-tional coal-fired power plants. Around the world, a growing number of power plants regularly replace a portion of their coal feed with suitably treated biomass. More than 150 coal-fired power plants now have experience with cofiring biomass or waste fuels, at least on a trial basis. There are ~40 pulver-ized coal combustion (PCC) plants that cofire biomass on a commercial basis, with an average of 3% energy input from biomass.6

Biomass comes in many forms and can be sourced from dedicated energy crops (such as switchgrass and miscanthus), short-rotation timber, agricultural crops and wastes, or forestry residues. When combined with coal, biomass can provide a number of advantages. However, its use on a large commercial scale could create a number of issues. For example, the vol-umes to be harvested and handled can be substantial, some

forms may be subject to limited or seasonable availability, and various pre-treatments may be needed. Inevitably, such chal-lenges can add complexity and cost to energy production.

Co-utilization of coal and biomass need not be limited to co-combustion in existing power plants—there are a number of other possibilities such as co-gasification. Coal gasification is a well-established versatile technology. Combining these two different feedstocks can be beneficial. For instance, facilities that co-gasify biomass in large coal gasifiers can achieve high efficiencies and improve process economics through greater economies of scale compared to a biomass-only facility. Such a combination can also help reduce the impact of fluctuations in biomass availability and its variable properties. Combining biomass and coal in this way can be useful, both environmen-tally and economically, as it may be possible to capitalize on the advantages of each feedstock, and overcome some of their individual drawbacks. Biomass can have an impact on CO2 emissions from a combustion or gasification process. Replacing part of the coal feed with biomass (assuming that it has been produced on a sustainable basis) can effectively reduce the overall amount of CO2 emitted. Potentially, the addition of carbon capture and storage (CCS) technology could result in a carbon-neutral or even carbon-negative process. Globally, con-siderable quantities of biomass are potentially available—in many countries, biomass remains an underexploited resource.

Similar to many conventional coal-fired power plants, several commercial-scale, coal-fueled, integrated gasification combined cycle (IGCC) plants in operation have at least trialed combining biomass with their coal feed, and several proposed IGCC projects aim to do the same. For instance, a planned IGCC and chemicals production plant (with CCS) at Kędzierzyn in Poland will co-gasify coal and biomass.7 To date, useful operational experience in co-gasifying has been gained with all major gasifier variants (entrained flow, fluidized bed, and fixed bed

TABLE 1. Global renewable electric power capacity5 (end 2013) (GW)

Technology World Total EU-28 BRICS China U.S. Germany Spain Italy India

Bio-power 88 35 24 6.2 15.8 8.1 1 4 4.4

Geothermal 12 1 0.1 ~0 3.4 ~0 0 0.9 0

Tidal 0.5 0.2 ~0 ~0 ~0 0 ~0 0 0

Solar PV 139 80 21 19.9 12.1 36 5.6 17.6 2.2

CSP 3.4 2.3 0.1 ~0 0.9 ~0 2.3 ~0 0.1

Wind 318 117 115 91 61 34 23 8.6 20

Total RE power capacity* 560 235 162 118 93 78 32 31 27

Hydropower 1000 124 437 260 78 5.6 17.1 18.3 44

Total RE power capacity 1560 360 599 378 172 84 49 49 71

*Excludes hydropower.Note: BRICS = Brazil, Russia, India, China, and South Africa


Most major wind and solar facilities do not operate in isola-tion. Generally, they feed electricity into existing power grids or networks. Often, such grids are fed by a variety of different types of power plants—there may be various combinations of coal- and gas-fired power plants, some hydro, and possi-bly nuclear. The grid makeup and ratio between plant types is never the same, as these factors differ from country to country based on the local circumstances. On the face of it, the addition of a large amount of wind power into a grid, for example, is a positive development. However, a large input from intermittent sources into existing power systems can upset grid stability and have major impacts, particularly on how thermal power plants within the system operate. Many coal- and gas-fired power plants no longer exclusively provide baseload power, but are now required to operate on a more flexible basis. Many are increasingly switched off and on, or ramped up and down, much more frequently than they were designed to be. Inevitably, this is guaranteed to throw up a number of issues—significantly increasing wear and tear on plant components, reducing the operating efficiency of units not designed for variable operation, and impairing the effec-tiveness of emission control systems. Ideally, such important impacts should be taken into consideration and factored into any energy-producing scheme, but this is particularly true in cases where coupling intermittent renewables with conven-tional thermal power plants is being proposed.

Clearly, the most significant drawback with wind and solar power is their intermittency. Consequently, periods of peak power output often do not correspond with periods of high

systems). Different types of coal have been co-gasified suc-cessfully with a wide range of materials, many of which are wastes that would have otherwise ended up in landfills or, at least, created disposal problems.

Co-utilizing coal and biomass is not limited to power gen-eration. In a number of countries, hybrid concepts for the production of SNG, electricity and/or heat, and liquid trans-port fuels have either been proposed or are in the process of being developed or tested. Coal/biomass co-gasification features in some of these. However, as well as incorporating biomass, some propose to take this a step further by adding yet another element of renewable energy to the system, gen-erally by incorporating electricity generated by intermittent renewables (such as wind and solar power).

Coal, Wind, Solar, and Geothermal

Wind power has become the most widely deployed renewable energy. In 2013, global capacity hit a new high of 318 GW. In that year, China alone installed more than 16 GW; by 2020, the IEA projects the country will more than double its wind power capacity from the present level of 90 GW to around 200 GW.8 For comparison, the European Union countries have a com-bined ~90 GW of installed capacity. In 2013, wind surpassed nuclear to become the number three source of energy after coal and hydropower in China.9 Reportedly, this is part of the greatest push for renewable energy that the world has ever seen.10

International Power’s 1-GW Rugeley power station in the UK. Like many others, this power plant has trialed cofiring various biomass materials with coal (courtesy Russell Mills Photography).

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COVER STORY

electricity demand, and vice versa. At times, there can be significant amounts of surplus unwanted electricity available, particularly from wind farms. This can be quite a widespread phenomenon, and the usual solution is to take wind turbines offline. However, rather than “waste” this electricity, it would be much more beneficial to find an effective means of using it. One option is to use electricity not needed to fill demand to electrolyze water, producing hydrogen and oxygen. Both gases have the potential to be component parts of hybrid energy systems and there are various schemes that propose feeding the hydrogen into syngas from gasification systems, use it in fuel cells or directly as a transport fuel, or combust it in gas turbines to generate electricity.

Similarly, the oxygen could be used for a host of commercial and industrial applications, or fed to a coal/biomass gasifier or an oxy-fuel combustion plant to generate electricity. Different concepts and schemes combining gasification, intermittent renewables, and electrolysis are currently being examined. Some aim to incorporate carbon capture and storage. For example, an on-going project in Germany is combining coal-based power generation with aspects of carbon capture and wind-generated electricity with trials of advanced electrolyzer technology (to produce hydrogen and oxygen from water).11 Success could encourage increased uptake of, for instance, electrolysis, as a component part of various coal/renewables systems. Assuming that the economics can be made to work, several schemes look promising.

Another ongoing project in Germany is expected to lead to significant improvements in the overall efficiency of the elec-trolysis process: E.On’s power-to-gas project at Falkenhagen. This technology utilizes multiple electrolyzers driven by excess electricity from a nearby wind farm to provide the power to produce hydrogen and oxygen. Output from the region’s wind farms frequently exceeds demand, so instead of taking the turbines offline when this happens, some of the electricity is now being fed to the electrolyzers. In this case, the hydro-gen produced is being injected into the local natural gas grid, which acts as a large storage system. Effectively, it’s a clever way of storing renewable energy.

There is also an opportunity to integrate coal-fired power plants with renewable sources of thermal energy, such as geothermal or solar thermal. The benefit of this type of inte-grated hybrid system is that the renewable source of energy can take advantage of the existing infrastructure of the coal-fired power plant, such as the steam cycle, connection to the grid, and transformers. Generally, this makes the economics much more attractive compared to a stand-alone renewable plant. Obviously, the availability of the renewable resource at the coal-fired power plant site is a prerequisite for such hybrid systems to be successful.

Hybrid thermal systems operate by using heat from renewable energy to increase the temperature of the coal-fired power plant boiler feedwater. This increases the efficiency of the power plant, effectively displacing some coal for renewable energy (or using the same amount of coal and producing more electricity). Such thermal hybrid projects may be the most cost-effective option for large-scale use of solar thermal and geothermal energy, although, to be employed, this approach must be recognized under renewable energy incentives. In the future, there may also be an opportunity for renewable sources of energy to provide the thermal load required for carbon capture and storage, thus significantly reducing the overall impact to the power plant and contributing to large-scale reductions in greenhouse gas emissions.

Smøla wind farm in Norway (courtesy Statkraft)

E.On’s power-to-gas project at Falkenhagen in Germany (courtesy E.On)


Currently, around 15 hybrid solar thermal plants, including those on coal- and natural gas-fired power plants, are being developed, with a total capacity of 460 MW.12 Thermal hybrid projects based on unconventional geothermal resources are at an earlier stage of development and the field will require additional research prior to large-scale demonstrations.13

CURRENT STATUS

Some systems are at early stages in their development or have been undertaken at a very small size, hence extrapo-lating to commercial scale and obtaining firm process costs remains problematic. For a variety of reasons, not all of the different schemes being considered appear to be technically and/or economically viable. However, some do appear to be more robust. On-going developments (in, for instance, gasifier and electrolyzer design) should improve cost competiveness. Where hydrogen and/or oxygen production forms part of a hybrid energy scheme, reductions in the cost of electric-ity provided by renewable energy sources (such as wind and solar) would also be beneficial in making electrolysis more cost effective. Some examples of on-going hybrid projects are given in Table 2. Although some are currently focused only on biomass, potentially different elements from these processes

could also be incorporated into systems fueled by coal/bio-mass combinations.

A number of projects are more advanced than others, with development programs well underway. Some components (such as co-gasification) have now been well established, and others are under development or being trialed (such as the commercial-scale demonstration of hydrogen production from wind power and testing of advanced electrolyzers). A number of proposed hybrid systems show potential—although in the near to medium term, assuming outstanding technical and economic issues can be resolved fully, most seem likely to be applied initially to niche markets, or to find application under specific, favorable circumstances.

CLOSING THOUGHTS

Set against a background of growing global population and ris-ing energy demand, there is a pressing need to come up with new, cost-effective, clean, reliable energy systems. To help tackle this, many hybrid energy schemes have been proposed, some more practical than others. Despite efforts by many countries to diversify their fuel mix, fossil fuels such as coal will continue to provide a significant part of the world’s energy for

TABLE 2. Examples of hybrid energy-producing systems proposed

Organization Technologies Proposed Status

NREL, U.S. Gasification/co-gasification + electrolysis (wind)

Various studies underway:• combining wind power and biomass gasification• combining biomass gasification and electrolysis• combining coal and biomass co-gasificationSeveral gasification-based hybrid systems being examined

NETL, U.S. Coal gasification + electrolysis (wind)

Systems to produce SNG, electricity, and biodiesel.3000 t/d plant proposed.Unconverted coal from gasifier fed to oxy-fuel combustor

CRL Energy, New Zealand

Coal/biomass co-gasification + electrolysis (wind)

Systems could be used to produce F-T chemicals, synfuels.O2 fed to gasifier. H2 to enrich product gas, stored, or used as transport fuel or in fuel cells.

Leighty Foundation, U.S.

Coal/biomass co-gasification + electrolysis (wind) O2 from electrolysis fed to gasifier

Univ. Lund, Sweden Biomass (wood) gasifier + electrolysis (wind) O2 from electrolysis fed to gasifier

Elsam/DONG, Denmark

Biomass gasification + electrolysis (wind, solar)

Various co-generation concepts to produce power, heat, and transport fuels examined. H2 added to syngas. O2 used for biomass gasification

Univ. Lausanne, Switzerland

Wood gasification + electrolysis Several processes examined for SNG production

China Various: gasification + electrolysis (wind)

O2 from electrolysis fed to gasifier. H2 fed to syngas. Mainly for SNG, methanol, ethylene glycol production

Note: SNG = synthetic natural gas; F-T = Fischer-Tropsch.

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the foreseeable future. For a number of reasons, where possi-ble, it makes sense to look at coupling coal use with renewable energy sources. Each power-producing system has its own pros and cons, but combining these different systems in creative ways may offer the possibility of overcoming some of these shortcomings. With this in mind, various energy production concepts that propose combining a number of different tech-nologies with coal are being developed around the world.

To be a practical proposition, as with all power-producing sys-tems, any hybrid scheme needs to be clean, workable, and economically sound. Based on work carried out recently by the IEA Clean Coal Centre, some hybrid systems appear to be viable and have potential.14,15 Although coal and renewable energy sources might appear to be strange bedfellows, it’s not unrealistic to suppose that in the coming years we could see increased deployment of combinations of the world’s two fastest-growing energy sources becoming a reality.

REFERENCES

1. United Nations Population Division. (2014). Concise report on the world population situation 2014, www.un.org/en/develop ment/desa/population/publications/pdf/trends/Concise%20Report%20on%20the%20World%20Population%20Situa tion%202014/en.pdf

2. International Energy Agency (IEA). (2012, 25 July). State of play: New IEA statistics publications highlight latest global and OECD trends across major energy sources, www.iea.org/newsrooman devents/news/2012/july/name,28615,en.html

3. IEA. (2014). Coal information, www.iea.org/w/bookshop/646-Coal_Information_2014

4. IEA. (2012). World energy outlook 2012, www.worldenergyout look.org/publications/weo-2012/

5. Renewable Energy Policy Network for the 21st Century (REN21). (2014). Renewables 2014 global status report, www.ren21.net/Portals/0/documents/Resources/GSR/2014/GSR2014_full%20report_low%20res.pdf

6. Adams, D. (2013). Sustainability of biomass for cofiring. CCC/230. London: IEA Clean Coal Centre. www.iea-coal.org.uk/documents/83254/8869/Sustainability-of-biomass-for-cofiring,-CCC/230

7. Cornot-Gandolphe, S. (2012, October). The European coal mar-ket: Will coal survive the EC’s energy and climate policies? Paris: Institut Français des Relations Internationals.

8. IEA. (2011). Technology roadmap: China wind energy develop-ment 2050. Available at: www.iea.org/publications/freepubli cations/publication/technology-roadmap-china-wind-energy-development-roadmap-2050.html

9. Yang, C. (2013). Wind power now No. 3 energy resource. People’s Daily English Edition, english.peopledaily.com.cn/90778/8109836.html

10. Shukman, D. (2014, 8 January). China on world’s “biggest push” for wind power. British Broadcasting Corporation, www.bbc.co.uk/news/science-environment-25623400

11. Farchmin, F. (2013, 6 November). Integration of regenerative en-ergy into Power2Gas by PEM electrolyzer technology. CO2RRECT Project. Smart Grid-Infotage 2013, Munich, Germany, www.in dustry.siemens.com/topics/global/en/pem-electrolyzer/silyzer/Documents/2013-11-06_SMARTGRID_Munich_stick.pdf

12. Electric Power Research Institute. (2012, April). Utility perspec-tive: Solar thermal hybrid projects. Clean Energy Regulatory Forum, National Renewable Energy Laboratory, Golden, Colo-rado, U.S., www.cleanskies.org/wp-content/uploads/2012/04/Libby_CERF3_04192012.pdf

13. Bean, N., & Varney, J. (2014). Geothermal assisted power gen-eration for coal-fired power plants. Cornerstone, 2(4), 46–50.

14. Mills, S.J. (2011). Integrating intermittent renewable energy technologies with coal-fired power plants. CCC/189. London: IEA Clean Coal Centre.

15. Mills, S.J. (2013). Combining renewable energy with coal. CCC/223. London: IEA Clean Coal Centre.

The author can be reached at [email protected]

COVER STORY

Hybrid coal and renewable energy systems offer synergistic benefits. (photo courtesy of Russell Mills Photography)


VOICES

By Frank Clemente Professor Emeritus of Social Science and

Former Director of the Environmental Policy Center, Penn State University

In 1972, The United Nations’ Stockholm Conference on the Human Environment issued the following Declaration: “Both aspects of man’s environment, the natural and the man-

made, are essential to his well-being and to the enjoyment of basic human rights, the right to life itself.”1 In other words, people are part of the environment too. The Stockholm Declaration stressed that vast numbers of people continue to live far below the minimum conditions required for a decent human existence, deprived of adequate food and clothing, shelter and education, health and sanitation. The Conference concluded that economic and social development are essen-tial for ensuring a favorable living and working environment for humans and for creating conditions on earth that are nec-essary for the improvement of the quality of life.

Electricity is the foundation of such development and is the lifeblood of modern society. The U.S. National Academy of Engineering identified societal electrification as the “greatest engineering achievement” of the 20th century, during which the global population grew by over four billion people, the rise of the metropolis occurred, transportation was revolutionized,

medical care improved dramatically, and a vast system of elec-tronic communication emerged.2,3

Electricity supports quality of life increases, economic well-being, and a clean environment. Electricity is highly unique compared to other forms of energy:

• Flexible—convertible to virtually any energy service—light, motion, heat, electronics, and chemical potential

• Permits previously unattainable precision, control, and speed• Provides temperature and energy density far greater than

those attainable from standard fuels• Does not require a buildup of inertia—offering instanta-

neous access to energy at the point of use

Although it may seem counterintuitive to some, electrification offers tremendous environmental benefits. Electro-

The Rise of Electricity: Offering Longevity, Improved Living Standards, and a Healthier Planet

“Since 1970, the global demand for

electricity has more than quadrupled

... with ~42% of this incremental

demand being met by coal.”

New power lines providing access to electricity allow for energy to be utilized with increasing efficiency.

12

technologies are more efficient than their fuel-burning coun-terparts and, unlike traditional fuels burned by the user, no waste and emissions evolve at the point of use—no smoke, ash, combustion gas, noise, or odor. Clearly, it’s important that there are emissions controls in place when electricity is gen-erated; controlling criteria emissions (e.g., particulate matter, SOx, NOx, mercury) at the source of large-scale electricity gen-eration is possible using commercially available technologies. In addition, electrification increases the efficiency of society’s primary energy consumption and, therefore, reduces the energy intensity of greenhouse gas emissions. Carbon capture and storage (CCS) technologies are also being developed that will allow for the carbon footprint of fossil fuel-based sources of electricity to be dramatically reduced.

Given these beneficial attributes of electric power, it is not sur-prising that demand continues to increase. Since 1970, the global demand for electricity has more than quadrupled from approxi-mately 5200 TWh to almost 23,000 TWh, with ~42% of this incremental demand being met by coal, which is why this fuel source has been referred to as the cornerstone of global power.4

Despite the staggering past growth of electricity demand, the future world will require far greater amounts of power. The Current Policies scenario in the IEA’s 2013 World Energy Outlook projected a 80% increase in power generation between 2011 and 2035.4 However, the center of that pro-jected incremental growth reflects a global shift; from 1980 to 2000, almost a quarter of the global increase in genera-tion came from the U.S., Japan, and Europe. Over the next 20 years, these developed nations will be relatively minor players in growth, while developing Asia will account for over 60% of new generation, led by China, where the increase alone will be about 6500 TWh—or about twice the current output of the EU. Coal will be the mainstay of the next generation as well, accounting for over 40% of electricity in 2035.4

The empirical realities of at least three societal trends demon-strate the magnitude of the emerging need for major increases in electricity generation:

1. Economic growth2. Population increase3. Urbanization

The projections are staggering. By 2050, the global economy is projected to quadruple to US$280 trillion in real terms. At least 80% of this increase will be in the developing world, and many of these nations will depend on coal to advance their economies. By 2050, the world will add 2.4 billion people—67 million every year or 184,000 every day.5 In essence, the entire population of Rome is added to the global rolls every two weeks. Most of these people will either be born in, or

will move to, ever-growing cities. Urbanization may offer the chance to lift oneself out of poverty, but the electricity must be available to support the business and industries that can provide much-needed opportunities.

THE DISPARITY OF ELECTRIFICATION

Figure 1 provides a comparison of the UN’s Human Develop- ment Index (HDI) and the per capita electricity utilization of many nations. Note that the major aspects of the HDI, such as life expectancy, educational attainment, and per capita GDP, are statistically related to increased access and utilization of electricity.

The Copenhagen Accord of 2009 concluded that “economic and social development and poverty eradication are the first and overriding priorities of developing country Parties.”7 Energy, particularly electricity, is the pathway to achieving these goals. More than 1.3 billion people have no electricity at all and billions more have inadequate access to power.4 Electricity deprivation in the developing world takes a mighty toll. The impact on children and women is stark: According to the UN, about 17,000 children die each day from causes that are preventable with sufficient electricity, including access to

FIGURE 1. Human Development Index versus electricity use6

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Brazil

VOICES

“Urbanization may offer the chance

to lift oneself out of poverty, but

the electricity must be available to

support the business and industries

that can provide much-needed

opportunities.”


clean water, better sanitation, adequate food, medicine, and more education to improve earning power—all things that can be taken for granted in the developed West.8 At least 1.5 billion women and girls live on less than $2 per day, and this feminization of poverty is endemic to areas without electric power.9 Merely gathering traditional fuels consumes a large part of a woman’s day throughout the developing world. Girls are kept out of school to obtain fuel. In areas such as South Darfur, women walk up to seven hours per day to collect fuel, making mothers and their daughters highly susceptible to rob-bery, violence, and rape. This inequitable access to energy has far-reaching socioeconomic ramifications. For example, the infant mortality rate in Germany is less than four per 1000 live births; in Nigeria, it is 74. In the European Union, virtually 100% of the population has improved sanitation; in Indonesia alone, 104 million people lack such sanitation.10

No nation holds more of the world’s poor than India. At least 300 million people have no power whatsoever and more than 700 million people lack access to modern energy services for lighting, cooking, water pumping, and other productive pur-poses. One hundred million do not have an improved water supply and over 800 million lack access to improved sanita-tion. These problems will only intensify going forward as India has about 630 million people less than 25 years old and will surpass China as the most populated nation before 2030.11

Sub-Saharan Africa, a region with a population of more than 900 million people, uses less electricity per year (145 TWh) than the U.S. state of Alabama (155 TWh) with just 4.8 million residents.12,13 There is only enough electricity generated in the sub-Sahara to power one light bulb per person for three hours a day.14 Africa has 15% of the world’s population—50% of these people live without electricity. In fact, of the 25 nations at the bottom of the UN HDI (see Figure 1), 24 are in Africa.15

In Cambodia, 69% of the population lacks access to electricity. In Pakistan, it is 33% and in Uganda an astounding 92%. Of the almost 160 million people in Bangladesh, 63 million lack access to any sort of electric power.16 About three billion people use rudimentary stoves to burn wood, coal, charcoal, and animal dung, releasing dense black soot into their homes and the environment. Annual deaths from this household air pollution exceed four million per year.17,18 This gathering and burning of wood and other biomass leads to deforestation, erosion, land degradation, and contaminated water supplies. Families are pushed off the land and migrate to cities in search of a better life.

URBANIZATION REVEALS THE IMPORTANCE OF ON-GRID ELECTRICITY

Much energy poverty occurs in rural locations; in such set-tings, off-grid options, such as roof-top solar, have much to

An increasingly urban global population presents challenges, but also an opportunity to increase electrification rates.

14

contribute. Undoubtedly, such solutions must play a role. In the near term, more efficient stoves and cleaner cooking fuels could dramatically improve indoor air quality and save lives. However, rural off-grid solutions may only meet the minimum standards for electricity. It would be difficult, if not impossible, for rural, minimal electrification to support the job-creating growth and industries so sorely needed to fundamentally address energy poverty. Perhaps most importantly, to expect to rely only on off-grid solutions because of where energy poverty occurs today ignores a pressing reality: rapid global urbanization.

Urban migration is occurring on an unprecedented scale—over seven billion people will live in cities by 2050. The cities of the future will be massive. In 1990, the world had 10 cities of over 10 million people. By 2050, there could be as many as 100 such “megacities”.19 The number of people urbanizing in India alone will exceed 11 million per year—equivalent to the cur-rent population of Delhi proper. Cities cannot be built without electricity, steel, cement, and associated materials. The level of production required for these materials depends on ade-quate resources, including electricity, being available. There is a model for such growth and urbanization that already exists. China has demonstrated that low-cost electricity, fueled 70% by coal, can be a solution to debilitating energy poverty. Over the last 20 years, China has expanded access to electricity and lifted over 650 million people out of poverty.20 In fact, at the global level, over 90% of people lifted from poverty since 1990 were Chinese; power generation from coal in China increased 700% and GDP per capita rose eightfold.21

During the same period, life expectancy increased by five years, infant mortality declined 60%, and 600 million people gained new access to improved water sources.22 As women are disproportionately affected by energy poverty, they are also major beneficiaries when it is alleviated. The maternal mortality ratio in China has dropped from 110 per 1000 live births to 32 in 2013.23 Today universal access to electricity has been achieved in China, allowing families to light their homes, refrigerate food and medicine, and reduce indoor air pollution through more efficient means of cooking.

The industrialization and electrification of China has come at a price. The largest cities are experiencing major air pollution problems and both direct coal combustion for heating and coal-fired power plants contribute to this problem. Although China is expected to continue to rely on coal for electrifica-tion, the country plans to dramatically reduce the emissions from coal-fired power plants by replacing older plants with advanced coal-fired units, adding environmental controls, and increasing efficiency via cogeneration of heat and power. In addition, state-of-the-art coal conversion facilities are mov-ing forward. These ultra-clean facilities will produce synthetic

natural gas, liquid fuels, and chemicals, although CCS, which will be much less expensive at such facilities, will be required to control CO2 emissions. The liquid fuels produced from coal conversion inherently have less sulfur than petroleum-derived fuels, which can address another major contributor to air pollution by offering cleaner transportation fuels. Finally, the potential for less direct coal use is significant: Only about 53% of China’s coal demand is for power generation, compared to over 90% in the U.S.4 Together, these steps could significantly reduce China’s air quality problems and allow continued eco-nomic growth.

WHAT IS NEEDED TO MEET ELECTRICITY DEMAND AT SCALE?

The International Energy Agency (IEA) has defined basic elec-tricity access as an average of 250 kWh per rural household per year and 500 kWh per urban household per year.24 Such limited access is far removed from levels of modern consump-tion. Basic energy access as defined for rural areas would be enough for a household to power a fan, a mobile phone, and two fluorescent light bulbs for five hours a day (see Figure 2).

Although even this basic level of electrification would increase the standard of living for some people, it is not enough to enable the growth and job creation needed to combat poverty. Perhaps this is best explained by the Worldwatch Institute: “Modern energy sources provide people with lighting, heat-ing, refrigeration, cooking, water pumping and other services that are essential for reducing poverty.”25 I believe that pro-viding only basic energy to developing nations will constitute “global poverty maintenance” programs in the name of uni-versal energy access.

TOMORROW’S ENERGY SOURCES

All viable electricity sources will play roles in coming decades if real strides are going to be made to alleviate energy poverty. In fact, the world will need more electricity from all sources. Forecasters such as the IEA are already projecting major increases in on-grid electricity generation from gas (89%), nuclear (51%), and non-hydro renewables (358%) from 2011 to 2035 under the Current Policies Scenario.4 These resources will be pushed, as will be coal. Today coal provides about 6000 TWh of electricity in the developing world. In 2035, the IEA’s Current Policies Scenario projects coal will provide 12,300 TWh. Even in the IEA’s much more conservative New Policies Scenario (assuming all new policies announced are fully enacted), coal accounts for over 9500 TWh in 2035. Replacing coal in this growth context would be impossible—and such efforts would yield an increase in energy poverty. In many countries, com-paring the percentage of generation capacity to percentage of

VOICES


actual generation also helps to highlight coal’s real role: Coal’s share of generation (as a percentage) is almost always signifi-cantly greater than its capacity percentage. For decades, coal has been the default fuel when sanguine projections of gas, nuclear, and wind have fallen short. This is one of the reasons the IEA has projected that coal will supply at least 50% of the on-grid electricity to eliminate energy poverty by 2030.24

Clearly, attempting to remove the contribution of one energy source is not a viable strategy—especially when attempting to eradicate energy poverty. Nevertheless, western finan-cial institutions such as the U.S. Export-Import Bank, the World Bank, and the European Bank for Reconstruction and Development have refused to fund coal projects even in areas of abject electricity poverty. Such a stance disregards the need for widespread electrification above and beyond basic access. It can also be argued that such a position is counterproductive to the fundamental objective of such institutions, which is to promote development and alleviate poverty.

ENVIRONMENTAL IMPACT

Development banks and other poverty alleviation groups do not need to choose between alleviating poverty and environ-mental protection. As has been explained, there are substantial environmental benefits to electrification. In addition, clean electricity generation from coal could be assured by supporting plants with high efficiency, advanced environmental controls, and that are made ready to implement CCS/CCUS.

Clean coal technologies are in use today and allow for the con-sumption of more coal with greatly reduced emissions. New pulverized coal combustion systems, utilizing supercritical

technology, operate at increasingly higher temperatures and pressures and, therefore, achieve higher efficiencies than conventional plants. Upwards of 500 GW of supercritical units are in operation or planned around the world, but many more are needed.26 Highly efficient modern coal plants emit up to 40% less CO2 than the average coal plant currently installed.27 Importantly, these supercritical plants are a prerequisite for next-generation development of CCUS, which itself is broadly recognized as required for global emission goals, which was the other important component of the Copenhagen Accord.

A PLAN TO END ENERGY POVERTY

The underlying theme of the position presented here is straightforward: Electricity, socioeconomic security, and a clean environment are inalienable human rights. Efforts to eliminate coal-fired power plants would forgo an opportunity to help meet burgeoning electricity demand, reduce depriva-tion, elevate the global quality of life, and significantly reduce emissions from energy. Without contributions from coal, economic growth will be stunted, the environment will be degraded, and the crisis of energy poverty will not be solved. If a global goal is truly the “[e]radication of poverty in the field,” the world’s most abundant source of electricity must remain an integral part of the solution.28 Policymakers must recognize the scale of electricity required to meet that goal. By 2050, the world will have 9.6 billion people, with the large majority in cities, where they have fuller access to electricity. I agree with many coal industry leaders that we should implement a technologically based plan, which will help meet the ever-rising need for power and improve the lot of all members of the human race.

0

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6000

8000

10,000

12,000

14,000

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age

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tric

ity A

cces

s[k

Wh/

(cap

ita·y

r)]

U.S. EU China

5 hours a day of...1 fan...1 mobile phone...2 flourescent bulbs

World India Pakistan Sub-SaharanAfrica

IEA Avg.*

12

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3910 2

4

11 1

587

FIGURE 2. Electricity access of select nations and a comparison to IEA’s basic energy service in rural settings24

*250 kWh per rural household, 500 kWh per urban household

16

The five most important steps of a plan to increase access to clean electricity include:

1. Work to eliminate energy poverty by ensuring that at least half of on-grid new generation is fueled by coal

2. Replace older, traditional coal plants with plants utilizing advanced coal technologies

3. Develop at least 100 major CCS/CCUS projects around the world within 10 years

4. Deploy significant coal-to-gas, coal-to-chemicals, and coal-to-liquids projects globally in the next decade, which will spur industry and reduce pollution from transportation fuels. Note that such projects would be particularly useful for low-cost CCS/CCUS demonstrations.

5. Commercialize next-generation clean coal technologies to achieve near-zero emissions, with supercritical power plants as the next step along that path

This plan employs 21st century coal technology to cleanly and affordably use abundant global reserves—which approach 900 billion tonnes, are distributed across 70 countries, and are accessible through a far reaching and expanded network of established infrastructure—to produce and deliver electricity to all, especially to the billions of children, women, and men who currently live in energy poverty.29

REFERENCES

1. United Nations (UN). (1972, 16 June). Report of the United Nations Conference on the Human Environment, www.unep.org/Documents.Multilingual/Default.asp?documentid=97&articleid=1503

2. National Academy of Engineering. (2003). The greatest engineering achievements of the 20th century, www.nationalacademies.org/greatachievements/List.PDF

3. International Energy Agency (IEA). (2002, September). World energy outlook 2002, www.worldenergyoutlook.org/media/weo website/2008-1994/weo2002_part1.pdf, www.worldenergy outlook.org/media/weowebsite/2008-1994/weo2002_part2.pdf

4. IEA. (2013, October). World energy outlook 2013. 5. UN News Centre. (2013, 13 June). World population projected

to reach 9.6 billion by 2050, www.un.org/apps/news/story.asp?NewsID=45165#.VDXo9haNWFI

6. World Bank. (2013). World development indicators: Human Development Index, 2013, data.worldbank.org/indicator

7. UN Framework Convention on Climate Change. (2009). Full Text of the Convention, unfccc.int/essential_background/convention/background/items/1362.php

8. UN. (2014). We can end poverty, www.un.org/millenniumgoals/childhealth.shtml (accessed October 2014).

9. SowHope. (2013). About us, www.sowhope.org/aboutus

10. Central Intelligence Agency. (2013). The world factbook, Nigeria, Germany, Indonesia, www.cia.gov/library/publications/the-world-factbook/

11. Rajendram, D. (2013, 10 March). The promise and peril of India’s youth bulge. The Diplomat, thediplomat.com/2013/03/the-promise-and-peril-of-indias-youth-bulge/

12. U.S. Energy Information Administration. (2014, February). Electric power monthly, www.eia.gov/electricity/monthly/current_year/february2014.pdf

13. IRENA. (2012). Africa’s renewable future, www.irena.org/DocumentDownloads/Publications/Africa_renewable_future.pdf

14. World Bank. (2013). Fact sheet: Infrastructure in sub-Saharan Africa, web.worldbank.org/WBSITE/EXTERNAL/COUNTRIES/AFRICAEXT/0,,contentMDK:21951811~pagePK:146736~piPK:146830~theSitePK:258644,00.html

15. SABC. (2013, 25 May). Free Africa from poverty and conflict: AU, www.sabc.co.za/news/a/8bce1b804fc0bb519d4eff0b5d39e4bb/Free-Africa-from-poverty-and-conflict:-AU-20132505

16. World Bank. (2013). Access to electricity (% of population), data, worldbank.org/indicator/EG.ELC.ACCS.ZS

17. Yamada, G. (2013). Fires, fuel and the fate of 3 billion. New York: Oxford University Press.

18. World Health Organization. (2014). Household (indoor) air pollution, www.who.int/indoorair/en/

19. World Energy Council. (2011, December). Global Transport Scenarios 2050, www.worldenergy.org/publications/2011/global -transport-scenarios-2050/

20. Mackenzie, A. (2013, 8 August). Productivity boost will keep us at No. 1. The Australian, www.theaustralian.com.au/business/opinion/productivity-boost-will-keep-us-at-no-1/story-e6frg9if-1226693062147

21. UN. (2013). We can end poverty, www.un.org/millenniumgoals/poverty.shtml

22. World Bank. (2013). World development indicators, data, worldbank.org/indicator, (accessed 2013).

23. World Bank. (2014). World development indicators, data, worldbank.org/indicator, (accessed October 2014).

24. IEA. (2011, November). World energy outlook 2011, www.iea.org/publications/freepublications/publication/world-energy-outlook-2011.html

25. Worldwatch Institute. (2012, 31 January). Energy poverty remains a global challenge for the future, www.worldwatch.org/energy-poverty-remains-global-challenge-future-1

26. Platts. (2014). New Power Plant Database, 2014. 27. World Energy Council. (2013). World energy resources: Coal,

www.worldenergy.org/wp-content/uploads/2013/10/WER _2013_1_Coal.pdf

28. European Bank for Reconstruction and Development, Eradicating poverty in the field, www.ebrd.com/pages/news/features/taff.shtml

29. BP. (2014, August). Statistical review of world energy, www.bp.com/content/dam/bp/pdf/Energy-economics/statistical-review-2014/BP-statistical-review-of-world-energy-2014-full-report.pdf

The author can be reached at [email protected]

VOICES


By Patrick FalwellSolutions Fellow, Center for Climate and Energy Solutions

Brad CrabtreeVice President, Fossil Energy, Great Plains Institute

Since 2011, the Center for Climate and Energy Solutions (C2ES) and the Great Plains Institute (GPI) have convened the National Enhanced Oil Recovery Initiative (NEORI).

Bringing together leaders from industry, the environmental community, labor, and state governments, NEORI has worked to advance carbon dioxide enhanced oil recovery (CO2-EOR) as a key component of U.S. energy security, economic, and environmental strategy. Currently, most CO2-EOR is done with natural underground reservoirs of CO2, yet the industry’s future growth depends on taking advantage of the large amounts of CO2 that result from electricity generation and industrial pro-cesses. NEORI therefore is working to turn a waste product into a commodity and to encourage policies that will help bring an affordable supply of man-made CO2 to the market.

As such, NEORI has offered consensus recommendations for federal- and state-level policy action. In May, Senator Jay Rockefeller (D-WV) introduced legislation in the U.S. Congress adopting NEORI’s centerpiece recommendation to reform and expand an existing federal tax incentive for the capture of man-made CO2 and its geologic storage through CO2-EOR.

Going forward, NEORI will work to educate policymakers across the political spectrum and the broader public about the opportunity for CO2-EOR to serve as a national solution to energy and environmental challenges.

BACKGROUND ON CO2-EOR

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

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

Understanding the National Enhanced Oil Recovery Initiative

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

“Improved federal incentive

could lead to the production of

over eight billion barrels of oil

and the underground storage of

more than four billion tonnes

of CO2 over 40 years…”

ENERGY POLICY

18

recoverable reserves.2 Recovering this oil would require 8.9–16.2 billion tonnes of CO2 that would predominantly come from man-made sources. Technically recoverable reserves offer potential to produce additional oil and utilize more man-made CO2 that is currently otherwise emitted into the atmosphere.

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

NEORI’S CONSENSUS RECOMMENDATIONS AND ANALYSIS

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

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

1. Corporate income taxes collected on the additional oil production

2. Income taxes on private royalties collected from CO2-EOR producers

3. Royalties from CO2-EOR production on federal land

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

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

NEORI PROPOSES AN ENHANCED FEDERAL INCENTIVE

NEORI recommends a reform and an expansion of an existing federal tax incentive, the Section 45Q Tax Credit for Carbon Sequestration. First authorized in 2009, the 45Q tax credit provides a $10 tax credit for each tonne of CO2 captured from a man-made source and permanently stored underground through enhanced oil recovery (a $20 tax credit is available for CO2 stored in saline formations). While enacted with the best of intentions, the existing 45Q program has been unable to encour-age widespread adoption of carbon capture technologies for two main reasons. First, 45Q is only authorized to provide tax credits for 75 million tonnes of CO2, a relatively small amount consider-ing how much CO2 could possibly be utilized through CO2-EOR. As of June 2014, tax credits for approximately 27 million tonnes of CO2 had already been claimed, and it is foreseeable that the remaining pool of credits will be exhausted in the near future. Second, 45Q has been unable to provide needed certainty to carbon capture project developers that they will be able to claim the incentive, due to rigid definitions in the tax code and the lack of a credit reservation process. Carbon capture project

ENERGY POLICY

“For the last three years, NEORI

has brought together a broad and

diverse group of constituencies

that share a common interest in

promoting CO2-EOR.”


developers have not been able to present the guarantee of credit availability when seeking private-sector finance.

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

Allocating New 45Q Credits via Competitive Bidding and Tranches

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

Given the wide difference in capture costs for potential man-made sources of CO2, three separate pools of credits,

or tranches, would be established. The creation of separate lower-cost industrialA and higher-cost industrialB tranches for power plants would ensure that an incentive is available for the diversity of potential man-made sources of CO2.

Tax Credit Certification

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

Revenue Positive Determination and Program Review

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

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

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

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

Tax Credit Assignability

Potential carbon capture project developers include electric power cooperatives, municipalities, and startup companies. NEORI recommends the allocation of new 45Q tax credits.

20

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

CONCLUSION

In a time of considerable disagreement on U.S. energy and cli-mate policy at the federal level, NEORI members believe that CO2-EOR offers broad benefits and the rare opportunity to unite policymakers and stakeholders in common purpose. The NEORI coalition therefore remains committed to educating members of both political parties and the broader public as to

how CO2-EOR can generate net federal revenue from domestic oil production, meet domestic energy needs, safely store man-made CO2 underground, and help advance and lower the costs of carbon capture technology.

NOTES

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

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

REFERENCES

1. Kuuskraa, V., & Wallace, M. (2014, 7 April). CO2-EOR set for growth as new CO2 supplies emerge. Oil & Gas Journal, www.ogj.com/articles/print/volume-112/issue-4/special-report-eor-heavy-oil-survey/co-sub-2-sub-eor-set-for-growth-as-new-co-sub-2-sub-supplies-emerge.html

2. Wallace, M., Kuuskraa, V., & DiPietro, P. (2013). An in-depth look at “next generation” CO2-EOR technology. National Energy Technology Laboratory, www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/Disag-Next-Gen-CO2-EOR_full_v6.pdf

The authors can be reached at [email protected] and [email protected]

ENERGY POLICY

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

“NEORI members believe that

CO2-EOR offers broad benefits

and the rare opportunity to unite

policymakers and stakeholders in

common purpose.”


By Benjamin Sporton Acting Chief Executive, World Coal Association

As another round of climate talks approaches, recent headlines have highlighted the critical role developing countries play in achieving a climate agreement—and

they are. Concerned about the restrictions it might place on their efforts to grow their economies and eradicate poverty, many developing countries are cautious about what a future global agreement on climate change might mean. With one billion people living in extreme poverty in addition to a similar number with incredibly low standards of living, it is hardly sur-prising that poverty eradication ranks number one on the list of priorities for developing country governments.1 The recent proposal document for new Sustainable Development Goals also acknowledged that “poverty eradication is the greatest global challenge facing the world today”.2

This is the reason that developing countries are key to a global climate agreement: Any proposed agreement that hampers their ability to grow their economies and eradicate poverty will not win their support.

THE LONG AND WINDING ROAD

Negotiations toward a global agreement on climate change have been long and tortuous. Beginning in 1992 with the

original “Earth Summit” in Rio de Janeiro, the negotiation pro-cess produced the Kyoto Protocol, which came into effect in 2005 but covered only around one third of global CO2 emis-sions. A 2009 summit in Copenhagen was originally intended to be the apex of the process with a binding global deal on emissions reduction, but it failed to live up to expectations. World leaders will gather again in Paris in November 2015 for the 21st Conference of the Parties (COP21) to the United Nations Framework Convention on Climate Change (UNFCCC) for what is now expected to be the pinnacle of the climate negotiations process.

This September, UN Secretary General Ban Ki-moon hosted a summit in New York intended to push climate change back up the international agenda and spur action toward November 2015. With celebrity endorsements and a series of coordinated announcements from activists, governments, and the private sector, the summit did have some success in raising the profile of an issue that has struggled to maintain the profile it once had, but which has since been drowned out by other priori-ties, chief among them economic and security crises.

Ultimately, however, the negotiation process has struggled for more than two decades because of a fundamental disconnect between developed and developing countries. This discon-nect centers on a desire by developed countries to require emissions reductions commitments by developing countries while they are still developing—potentially limiting the ability of those countries to grow their economies and eradicate poverty. It comes about because many in the developed world refuse to acknowledge that the development pathway their countries took—one that relied on abundant, affordable, and reliable energy—is the pathway that the developing world will need to take if it is truly to eradicate poverty.

All sources of energy have a role to play in achieving climate and development objectives. An overemphasis on renewable tech-nologies, however, risks limiting developing countries to “light

Developing Country Needs Are Critical to a Global Climate Agreement

United Nations Secretary-General Ban Ki-moon, left, is joined by President François Hollande of France at a news conference on climate change during the Climate Summit, New York, U.S., 23 September 2014. (AP Photo/Jason DeCrow)

“There is a pathway that provides a

role for coal in achieving both climate

and development objectives.”

22

bulb and cook stove” solutions: that is, solutions that address the immediate needs of poverty and climate without addressing the longer-term fundamentals needed for poverty alleviation.

This fact was recognized in recent remarks by World Bank President Jim Yong Kim at the U.S.–Africa Leaders Summit in August when he said that “there’s never been a country that has developed with intermittent power”3 and that, despite recent policy announcements, the World Bank would still likely fund coal projects. His statement came as African leaders argued they were living in “energy apartheid” and demanded the right to use their natural resources, particularly coal, to fuel their economic development.4

If the climate negotiation process is to have any success it must integrate development and climate objectives.

THE DEVELOPMENT AND ENERGY CHALLENGE

With 1.3 billion people globally lacking access to modern electricity and about double that number lacking access to clean cooking facilities, it is hardly surprising that developing country governments are focused on affordable and reliable energy to help grow their economies.5 Energy is fundamen-tal to development. Without reliable modern energy services hospitals and schools can’t function and business and industry can’t grow to provide employment and economic growth.

In its 2011 World Energy Outlook, the International Energy Agency (IEA) reviewed what would be needed to meet their own “minimal energy access for all” scenario—a scenario that would barely meet basic energy needs, but is the basis for the proposed Sustainable Development Goal on energy access for all. Even in this minimal energy access scenario, half of the on-grid electricity needed comes from coal.6 A more ambitious target would likely see a much larger role for coal—and it is a more ambitious scale of development and energy access that developing and emerging economies are targeting. That is why statistics about coal’s growing role in the world continue to confound those who forecast its demise.

Coal’s role in development explains why coal consumption in Southeast Asia is projected to grow at 4.8% a year through to 2035 along with significant growth in other developing regions (see Figure 1).7 It is why a 2012 report from the World Resources Institute8 identified 1199 planned new coal plants (representing 1400 GW) across 59 countries—most of them in developing and emerging economies.

Coal’s critical role in development is one of the reasons coal has been the fastest growing fossil fuel for decades and why its share of global primary energy consumption in 2013 reached 30.1%, the highest since 1970.9 Even under the IEA’s New Policies Scenario (which accounts for all currently announced climate pol-icies) coal demand is expected to grow from 3800 million tonnes of oil equivalent (Mtoe) today to almost 4500 Mtoe in 2035.5

These figures alarm climate activists who argue for an end to coal and encourage divestment from the coal industry. What they ignore, however, is that there is a pathway that provides a role for coal in achieving both climate and development objectives.

A PATHWAY THAT INTEGRATES CLIMATE AND DEVELOPMENT

Alongside last year’s climate summit in Warsaw, the World Coal Association joined with the Polish government to host the International Coal and Climate Summit. The summit was widely criticized by environmental groups for trying to take the focus away from climate negotiations, an argument which ignored the significant contribution cleaner coal technologies can make to achieving ambitions to reduce CO2 emissions. A key part of the summit was the launch of the Warsaw Communiqué, a document that called for increased interna-tional action on deployment of high-efficiency, low-emissions (HELE) coal-fired power generation.

21st-century HELE coal technologies have huge potential. It is well known by now that a one percentage point increase in efficiency at a coal plant results in a two to three percentage point decrease in CO2 emissions. Less widely known is that the average efficiency of the global coal fleet currently stands at 33%. Off-the-shelf technologies for supercritical and ultra-supercritical coal have about 40% efficiency or higher, while more advanced technologies expected to become available in the near future will approach 50% efficiency. The IEA estimates that increasing the average efficiency of the global coal fleet up to 40% would save around two gigatonnes of CO2 annu-ally—roughly equivalent to India’s total annual emissions.10

Taken in the context of other climate policies the potential impact of improving the efficiency of the global coal fleet is sig-nificant. The Economist recently published a graphic showing the impact various policies or events have had on global CO2

ENERGY POLICY

FIGURE 1. Southeast Asia incremental electricity generation by fuel: 2011–20357

Coal

Renewables

Gas

Nuclear

Oil

-100 0 100 200 300 400TWh

500 600 700


emissions, which has been reproduced in Figure 2.11 If a global initiative were in place to increase the average efficiency of the global coal fleet to the level of off-the-shelf technology, its two gigatonnes of savings would place it fourth on this list of 20 activities. It would be more than three times more effective in reducing CO2 emissions than the global deployment of all non-hydro renewable energies combined.

Nowhere is the potential of HELE technology better demon-strated than at J-Power’s Isogo power plant outside of Tokyo. J-Power is the largest producer of coal-fired electricity in Japan and is leading the way in HELE deployment with its 600-MW ultra-supercritical plant. The plant achieves gross thermal effi-ciency of 45% and has reduced emissions to the equivalent of a high-performing natural gas plant.

However, plants like that come at a cost. Developing countries need international support to deploy the most efficient plants. In the face of decisions by the World Bank and European Bank for Reconstruction and Development to limit funding for coal projects, the IEA raised some serious concerns:12

While increased investor awareness of climate-related issues is a positive development, policies deliberately

adverse to coal may have unintended consequences. In the 450 Scenario, which limits the global average temperature increase to 2°C, world investment in coal-fired capacity totals $1.9 trillion (25% higher than in the New Policies Scenario), of which $800 billion is for plants fitted with carbon capture and storage (CCS). Coal-fired power plants become more expensive on average because, in most regions, more efficient tech-nologies are deployed, as well as greater emphasis on CCS technologies. If development banks withhold financing for coal-fired power plants, countries that build new capacity will be less inclined to select the most efficient designs because they are more expen-sive, consequently raising CO2 emissions and reducing the scope for the installation of CCS. In addition, many of the countries that build coal-fired capacity in the 450 Scenario need to provide electricity supply to those who are still without it, a problem that may be resolved less quickly if investment in coal-fired power plants cannot be financed.

This is a warning from the IEA: International action against coal creates two distinct risks. First, from a climate perspective, failing to invest in new coal technologies risks higher future

FIGURE 2. Emissions reductions impact (in terms of billions tonnes CO2 equivalent)11

*Annual emissions are cumulative emissions divided by the relevant period. The estimate for the current emissions avoided under the Montreal protocol is eight billion tonnes CO2 equivalent. The annual figure for the collapse of the USSR refers to the years 1992–1998.**Cars and light trucks***Heavy trucks

Policy/Action Cumulative emissions Period Annual emissions*

Montreal protocol 135.0 bn 1989–2013

Hydropower worldwide 2.8 bn 2010

Nuclear power worldwide 2.2 bn 2010

Increase avg. global efficiency of coal-fired power to 40%

China one-child policy 1.3 bn 2005

Other renewables worldwide 600 m 2010

U.S. vehicle emissions & fuel economy standards** 6.0 bn 2012–2025

Brazil forest preservation 3.2 bn 2005–2013

India land-use change 177 m 2007

Clean Development Mechanism 1.5 bn 2004–2014

U.S. building & appliances codes 3.0 bn 2008–2030

China SOE efficiency targets 1.9 bn 2005–2020

Collapse of USSR 709 m 1992–1998

Global Environmental Facility 2.3 bn 1991–2014

EU energy efficiency 230 m 2008–2012

U.S. vehicle emissions & fuel economy standards*** 270 m 2014–2018

EU renewables 117 m 2008–2012

U.S. building codes (2013) 230 m 2014–2030

U.S. appliances (2013) 158 m 2014–2030

Clean technology fund 1.7 bn project lifetime

EU vehicle emission standards 140 m 2020

5.6 bn

2.8 bn

2.2 bn

1.3 bn

2.0 bn

600 m

460 m

400 m

177 m

150 m

136 m

126 m

118 m

100 m

58 m

54 m

29 m

10 m

10 m

N/A

N/A

24

emissions from coal; second, failing to invest in coal threatens the energy access and development priorities in some of the world’s poorest countries.

AFFORDABLE, LONG-TERM ACTION

As the IEA notes, deployment of HELE plants is also an impor-tant first step in the longer term drive for near-zero emissions coal-fired plants incorporating carbon capture, utilization, and storage (CCUS). CCUS technology is critical to achieving global climate objectives. More importantly, CCUS plays a significant role in reducing the economic costs of limiting CO2 emissions.

The recent New Climate Economy report by the Global Commission of Energy and Climate, led by former Mexican President Felipe Calderón, argued that substantial emissions cuts would effectively pay for themselves when a range of co-benefits are considered.13 That reflected recent work from the Intergovernmental Panel on Climate Change (IPCC) which stated that annual GDP growth would decline by as little as 0.006 percentage points with substantial emissions reduction.

Many environmental activists argue that this demonstrates the viability of renewable energy technologies as the exclu-sive energy pathway toward a near-zero emissions economy. However, analysis by the Council on Foreign Relations’ leading energy expert Michael Levi noted that CCUS is far more critical to achieving the 2°C target.14 He highlighted that in the IPCC research, failing to deploy CCUS causes the cost of climate action to rise by about 140%, but that the most likely outcome is that the 2°C target could not be reached at all.

A CLIMATE DEAL CAN ACHIEVE BOTH OBJECTIVES

If global action to reduce CO2 emissions is to be affordable and have a realistic chance of meeting the 2°C target it must account for the role of cleaner coal technologies in achieving that aim. That is even more critical when the need for afford-able and reliable energy for development is accounted for.

India’s new Environment Minister made clear recently where his country’s priorities lie: “India’s first task is eradication of poverty … Twenty percent of our population doesn’t have access to electricity, and that’s our top priority.”15

It is clear that if the November 2015 climate summit in Paris is going to achieve any level of success, then it must support the development ambitions of the world’s poorest countries. It must integrate the priorities of countries like India, which need to address their poverty situation and provide affordable and reliable electricity, with global climate ambitions. It means that rather than ignoring coal, the international community must recognize 21st century coal as part of the solution.

REFERENCES

1. World Bank Group. (2014). Ending poverty and sharing pros- perity: Global Monitoring Report 2014/2015, www.worldbank.org/en/publication/global-monitoring-report

2. United Nations. (2014). Outcome document – Open Working Group proposal for Sustainable Development Goals, sustainable development.un.org/focussdgs.html, (accessed 29 September 2014).

3. Ginski, N. (2014, 5 August). World Bank may support African coal power, Kim says. Bloomberg, www.bloomberg.com/news/2014-08-05/world-bank-may-support-african-coal-power-kim-says.html, (accessed 30 September 2014).

4. Scientific American. (2014). Africa needs fossil fuels to end energy apartheid, www.scientificamerican.com/article/africa-needs-fossil-fuels-to-end-energy-apartheid/, (accessed 30 September 2014).

5. International Energy Agency (IEA). (2013). World energy outlook 2013, www.worldenergyoutlook.org/publications/weo-2013/

6. IEA. (2011). World energy outlook 2011, www.worldenergy outlook.org/publications/weo-2011/

7. IEA. (2013). World energy outlook special report 2013: Southeast Asia energy outlook, www.iea.org/publications/free publications/publication/SoutheastAsiaEnergyOutlook_WEO2013SpecialReport.pdf

8. World Resources Institute. (2012, November). Global coal risk assessment, www.wri.org/publication/global-coal-risk-assessment

9. BP. (2014). Statistical review of world energy 2014, www.bp.com/en/global/corporate/about-bp/energy-economics/statistical-review-of-world-energy.html

10. IEA. (2012). Energy Technology Perspectives 2012 – How to secure a clean energy future.

11. The Economist. (2014, 20 September). The deepest cuts, www.economist.com/news/briefing/21618680-our-guide-actions-have-done-most-slow-global-warming-deepest-cuts

12. IEA. (2014). World energy investment outlook, www.iea.org/publications/freepublications/publication/WEIO2014.pdf

13. The New Climate Economy. (2014). New climate economy, newclimateeconomy.report/, (accessed 20 September 2014).

14. Levi, M. (2014). Is solar power making climate policy cheap?, blogs.cfr.org/levi/2014/09/19/is-solar-power-making-climate-policy-cheap/, (accessed 30 September 2014).

15. Davenport, C. (2014, 24 September). Emissions from India will increase, official says. The New York Times, www.nytimes.com/2014/09/25/world/asia/25climate.html?_r=0, (accessed 30 September 2014).

ENERGY POLICY


STRATEGIC ANALYSIS

By Hans-Wilhelm SchifferExecutive Chair,

World Energy Resources of the World Energy CouncilConsultant and Advisor to the Executive Board of RWE AG

German energy policy is determined by different ambi-tious targets. That is especially true as far as the electricity sector is concerned. The main characteris-

tics of electricity-sector policy are a complete phasing out of nuclear energy, the transition to a power supply based mainly on renewable energy, and the reduction of energy consump-tion by continuously increasing efficiency. The main purpose of these changes is to reach a nearly CO2-free power supply by 2050. The central challenges are keeping the power sys-tem stable and secure while maintaining consumer electricity prices at a competitive, affordable level.

CURRENT STATUS AND TRENDS

The German government´s energy policies have undergone a profound change over recent years. In September 2010, the government launched a comprehensive “Energy Concept” featuring a large number of policy goals for future decades

concerning energy and electricity consumption, the share of renewable energy, and the reduction of greenhouse gas emis-sions. A central component of this concept was to extend the operation time of nuclear power plants, at that time seen as a bridge technology in the era of renewable energy.

Following the Fukushima nuclear disaster in March 2011, however, the German conservative-liberal government coali-tion made an abrupt U-turn by mandating the complete phase-out of 8.4 GW of nuclear capacity immediately, with the remainder (12.1 GW) to be decommissioned between 2015 and 2022. With the decision to shut down all nuclear capacity by 2022, the government returned to a phase-out schedule conceived in 2001 by the socialist-green govern-ment in power at the time. In the coalition contract of the new conservative-socialist government, signed in November 2013, the phasing-out decision for nuclear energy was con-firmed. Furthermore, the coalition partners agreed on slightly modified targets concerning the reduction of greenhouse gas emissions, the consumption of electricity, and the increase of the share of renewables in the electricity supply for 2020 (35%), 2025 (40–45%), 2035 (55–60%), and 2050 (80%).

The decision to phase out all nuclear power plants is generally considered a final one due to public pressure that accompa-nied the nuclear debate over past decades.

The envisaged expansion of renewable energy is a techno-logical and financial challenge. The principal objectives of the Energiewende (Germany’s transformational energy policy) are:

• Transitioning German power supply from a conventional-based system to one mainly based on renewable energy;

The Flexibility of German Coal-Fired Power Plants Amid Increased Renewables

“Today, fluctuations in the feed-in

of renewables-based electricity

are already having a considerable

impact on the load to be covered by

conventional power stations.”

Germany’s coal- and gas-fired power plants are responsible for meeting fluctuations from the increased deployment of renewables.

26

• Keeping power prices on a competitive level for industry and an affordable level for private households;

• Ensuring continuous, secure supply.

The main instrument being used to make renewable energy the backbone of the German power supply is the Renewable Energy Sources Act, last amended on 1 August 2014. This law provides guaranteed feed-in tariffs for renewable electricity for 20 years after a power plant is commissioned. Grid opera-tors are obliged to purchase the entire quantity of renewable electricity with priority. The trade companies pass on the deficit (i.e., feed-in tariff minus market price) to customers by imposing a reallocation charge.

The renewable capacity for power generation increased from 12,330 MW in 2000 (less than 10% of total capacity) to 40,357 MW by the end of 2008 and to 84,404 MW by the end of 2013 (45%) (see Figure 1). In 2000, renewable energy’s share of consumption was less than 7%, then grew to over 25% by 2013. The total amount of renewable energy capacity on 31 December 2013 is shown in Table 1.

Within just the last five years (between the end of 2008 and the end of 2013) the capacity increase was 29,828 MW for photovoltaics (PV) and 10,845 MW for wind energy. This dem-onstrates that the funding system for renewables has been quite effective.

However, the growth of renewables in Germany has come at a cost. The total feed-in amounts based on subsidized renewables in Germany stood at 125.7 TWh in 2013. The remuneration paid to plant operators and premium payments totaled €20.4 billion in 2013. Deducting income from mar-keting, on balance, net subsidy payments were approximately €16.2 billion in 2013.

The subsidies are financed via a reallocation charge that is paid by electricity consumers through a markup on the grid-access fee. Starting on 1 January 2014, this reallocation charge was increased to €62.40/MWh. The reallocation charge has now reached a level at which it is twice as much as the wholesale price of electricity.

A comparison between electricity prices reveals the dilemma facing Germany today. Power prices for industry are on the same level as those in Japan. In fact, private customers in Germany pay even more for electricity than private consum-ers in Japan. Within the EU, Germany’s private consumers pay a higher price than any country except Denmark. Electricity prices in Germany are more than twice the OECD average and three times as high as in the U.S.

CHALLENGES FOR POWER PRODUCERS1

With the increase in renewable energy, power producers also face a new challenge. In the past a main focus was offsetting fluctuations in consumption between day and night, work-days and weekends, and seasonal variations. Today, feed-in intermittency has added a new source of fluctuations that are at least the same magnitude as those from changes in consumption.

These demand and renewable energy feed-in fluctuations must be continuously balanced to provide electricity grid sta-bility, which is putting pressure on the conventional power generation portfolio. Power generation from conventional plants has to be able to flexibly adjust to the residual load at any time (i.e., to compensate for the difference between consumption and fluctuating renewable energy). This is a chal-lenge for grid operators, especially when high wind feed-ins in northern Germany force the “redispatching” of thermal units intraday, often leading to lower coal-based output in the north and a ramp up of capacity in the south to keep the system in balance.

STRATEGIC ANALYSIS

FIGURE 1. Percentages of capacity and production of various electricity sources (December 2013)1

7 1512

2514

19

15

11

7

5

7

11

19

5199

Power plant capacity186.8 GW (net)

Electricity production596.4 TWh (net)

Nuclear

Lignite

Hard coal

Natural gas

Wind

Photovoltaics

Fuel oil and otherHydropower, biomass

TABLE 1. Renewable energy capacity in Germany as of the end of 2013

Source Capacity (MW)

Wind Onshore 33,757

Wind Offshore 903

Hydropower 5619

Biomass 8153

Solar Photovoltaic 35,948

Geothermal 24

Source: AGEE-Stat, August 2014


The need for load adjustments by flexible power plants is par-ticularly critical when an increase in electricity demand occurs at the same time as the feed-in from wind power plants dra-matically decreases.

There has been a need for load adjustments of >50 GW (i.e., >60% of the peak load) within an eight- to 10-hour period. This sort of demand fluctuation is generally random, but can be forecast up to two days in advance (e.g., via a wind forecast).

Thus, conventional power generation plants are faced with massive technical and economic challenges. Today, fluctua-tions in the feed-in of renewables-based electricity are already having a considerable impact on the load to be covered by conventional power stations. To illustrate the effect of such fluctuations, looking closely at electricity demand and sources can be helpful. Due to the high demand and low feed-in of electricity from renewable energies, on 24 January 2013 up to 74,335 MW—92% of the peak demand of 80,739 MW in Germany—had to be covered by conventional power plants. Conversely, on 24 March 2013, a Sunday with low electric-ity demand coupled with high feed-in from wind and solar, a minimum of 14,405 MW had to be covered by conventional power stations. This represents a tremendous shift in the role of conventional power plants.

Flexibility to Meet Load Fluctuations

The German electricity transmission network is part of the European synchronous zone and is connected with neighbor-ing European markets. A regular exchange of electricity takes place with all adjacent countries (i.e., France, Netherlands, Denmark, Poland, Czech Republic, Austria, and Switzerland).

However, since these markets are also expanding wind capaci-ties and consumer behavior in all markets shows substantial similarity, the capacity to adjust imports and exports to meet German electricity market fluctuations is limited.

Therefore, the required flexibility to meet load fluctuations must be predominantly managed by existing national power plants. Existing power plants in Germany are all designed to cater for flexible operation, and these requirements are equally met by new NGCC plants and new coal-fired power plants.

Many of the conventional power plants operating in Germany today were built in the 1980s and 1990s, before expansion targets for wind and photovoltaic plants had been adopted. In many plants, measures to allow greater flexibility have been implemented subsequently, so that power plants can meet increased requirements for market load adjustments. As a result, there are very few dedicated German baseload power plants that do not allow for flexible operation.

The necessary operational flexibility of coal- and gas-fired power plants can be illustrated with an example from 1 and 2 January 2012 (see Figure 2). On Sunday, 1 January, power demand was relatively low due to low industrial demand and mild temperatures of approximately 8°C (46°F). Around the evening peak, a temporary daily maximum consumption of 56 GW was reached in the German power grid, after which demand decreased to a minimum value of less than 41 GW until the late evening.

At the same time, the amount of wind feed-in temporarily reached a very high level of more than 16 GW. Further feed-ins

FIGURE 2. Power consumption (left) and dispatch (right) of German power plants1

0

10

20

30

40

50

60

70

80

0

10

20

30

40

50

60

70

80

Increasingpower demand

Decliningwind feed -in

Must-run

Coal

Gas

Nuclear

Wind

GW GW

Sunday, 1.1.2012 Monday, 2.1.2012 Sunday, 1.1.2012 Monday, 2.1.2012

28

that day came from other renewable energy sources, including run-of-the-river hydro and biomass power plants, which also benefit from feed-in priority. The feed-in from those plants consistently amounted to about 5 GW. The power generation from photovoltaic plants was negligible due to the season as well as the cloudy weather that weekend.

On Sunday evening, after the renewable energy feed-ins were accounted for, only a residual load of 21 GW had to be tem-porarily covered by other power plants available according to schedule.

At 4:00 am on Monday, 2 January, power consumption soared and reached a demand level of approximately 73 GW at around noon. This corresponds to an increase of 32 GW within eight hours. At the same time the feed-in from wind power plants decreased in the early hours of the morning due to declining wind speeds and intermittently amounted to only 4 GW at around noon. In parallel, a decrease in feed-in of about 12 GW was registered on the supply side. Thus, overall, an additional power output of nearly 45 GW had to be provided by the ther-mal power plant portfolio within those eight hours.

The left-hand side of Figure 2 displays the parallel development of increased power consumption and decreased, intermittent wind feed-in, requiring a high degree of load adjustment from the conventional power generation portfolio.

Power generation from German nuclear power plants contrib-uted, almost without interruption, a supply of about 12 GW. There is a degree of flexibility available from the German nuclear power stations, although their low-variable power generation costs ensure that this is only used once the load adaptability of the fossil-fired power plants has been exhausted. As seen in the right-hand side of Figure 2, the necessary load adjustment of about 50 GW on Monday morning was almost completely provided by the coal- and gas-fired power plants.

On Sunday night, almost 40% of the coal-fired power plants were still in operation, although the requirements for coal-fired power plants at that time had reduced to about 20–60% of their installed output capacity. Overall, their contribution was only about 10 GW.

The conventional gas-fired power plants were almost com-pletely off the grid on Sunday night, since part-load operation of gas-fired power plants is considerably more expensive than it is for coal-fired power plants.

In the early hours of Monday morning the increase of residual load was initially covered by coal-fired power plants supporting the grid by means of less than full load operation. In parallel, additional coal-fired power plants went into operation that

had previously been off the grid. Grid synchronization of fossil-fired plants commences approximately one to four hours after initial boiler firing. Subsequent to the grid synchronization, newly started coal-fired power plants met the required load increase until about midday.

Generally, available gas-fired power plants are returned from downtime to meet the load peaks on Monday. The first feed-ins from gas-fired plants are normally in the early morning, from 5:00 am onward. Over the course of the day, load bal-ancing is mainly regulated by gas-fired power plants, and the coal-fired power plants remain at full load until the evening.

On the particular Monday being evaluated, load adjustments were made by a combination of available coal- and gas-fired power plants. In doing so, the coal-fired power plants pro-vided about 75% of the required flexible output.

Flexible Use of Coal- and Gas-Fired Power Plants due to Fluctuations of PV Feed-In

The average cycle between strong and weak wind phases is about three to five days in northwest Europe. Even in the event of short-term changes, as portrayed in the first example, the thermal power plant portfolio has several hours in which to adjust load.

Short-term feed-in fluctuations are also triggered by the out-put of widely developed solar photovoltaic power plants in

STRATEGIC ANALYSIS

FIGURE 3. Feed-in from renewables on 16 March 20121

*Regular operation of two gas turbines and one steam turbineSource: www.transparency.eex.com

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0

2

4

6

8

10

12

14

16

18

20

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Load

fact

or (%

)

Rene

wab

le g

ener

ation

(GW

h)HourWindPhotovoltaics CCPP new build*

Hard coal new-build Existing hard coal, optimized


Germany. The effects can be seen from the beginning of spring as the daily level of solar radiation increases.

The timing of the increase in solar radiation in the morning does not coincide with the increase in power consumption. While electricity demand increases between 4:00 and 8:00 am, the increase in photovoltaic feed-in occurs between 8:00 am and 1:00 pm. Similarly, photovoltaic feed-in decreases in the evening, some hours before the decline in power con-sumption. Consequently, thermal power plants have to kick in at short notice twice—in the morning and in the evening—on days with a high photovoltaic generation.

16 March was one of the first days in 2012 with intensive solar radiation in Germany. The feed-in from photovoltaic plants increased by about 16 GW between 8:00 am and 1:00 pm. Between 2:00 and 6:00 pm, it decreased. On that day, wind levels were extremely low (see Figure 3).

To cover peak consumption in the morning, coal- and gas-fired power plants started operation. In order to accommodate the temporarily high photovoltaic feed-in around midday, and afterward provide full load to cover the evening peak, the gas-fired and coal-fired power plants were intermittently operated between partial and full-load operation.

TABLE 2. Sample flexibility parameters for coal- and gas-fired power plants

Parameter Unit Natural Gas CCPP New Builda

Hard CoalNew Build

LigniteNew Build

Hard Coal Existing Plant (Optimized)

Capacity MW 800 800 1100 300

Minimum-load point/rated-load point (Pmin/PRated)

% ~60 ~25–40 ~25b–40 ~20

Mean load change ratec %/min ~3.5 ~3d ~3 ~3

a Regular operation of two gas turbines and one steam turbineb Thanks to the “BoA-Plus” design (lignite-fired power plant with optimized plant technology plus upstream coal drying) a minimum-load point of 25% is pos-sible today, but has not been implemented yetc With respect to rated loadd In the lower load range (25–40%) the operating gradient differs from this value

FIGURE 4. Comparison of load flexibility of new-build gas- and lignite-fired power plants in the Rhineland1

Notes: BoA is a German abbreviation for “lignite-fired power station with optimized plant engineering“. BoA 1–3 are in operation and BoA PLUS is in the planning stages.

LINGEN CCPPMax capacity: 2x440 MWMin capacity: 520/260 MWMax load change rate: +/-32 MW/min

BoA1–3Max capacity: 1000 MWMin capacity: 500 MWMax load change rate: +/-30 MW/min

BoA PLUSMax capacity: 2x550 MW Min capacity: 350/175 MWMax load change rate: +/-30 MW/min

2-boiler operation

1100 MW

1000

800

600

400

200

5 10 15 20 25min 5 10 15 20 25min 5 10 15 20 25min

1-boiler operation2-boiler operation

1-boiler operation

30

Figure 3 shows the course of intermittent feed-ins and the adjusted operation of conventional power plants (new gas and steam power plant, new coal-fired power plant, and an existing coal-fired power plant with optimized flexibility parameters), following changes in demand and available generation from renewable energy sources. In the case of 16 March 2012, German coal- and gas-fired power plants were able to accom-modate photovoltaic feed-in variations mutually because of their short-term flexible operating capability.

Flexibility Characteristics of German Coal- and Gas-Fired Power Plants

In the regular configuration of two gas turbines and one steam turbine, the minimum load of a new gas-fired combined-cycle plant is typically around 60% of its installed capacity. An even lower minimum load is achievable by switching off one gas turbine; this, however, causes a substantial decrease in effi-ciency, and thus is rarely employed.

STRATEGIC ANALYSIS

FIGURE 5. Gross power generation in Germany 1993–20231

Source: AG Energiebilanzen (for 1993–2013); target of federal government according to coalition agreement: 40–45% renewables in 2025

1993 2003 2013 2023

Nuclear

Fossilenergy

sources(coal, gas etc.)

Renewables527 TWh

29.2%

66.8%

609 TWh634 TWh

4.0%27.1%

65.4%

7.5%

15.4%

60.7%

23.9%~40%

~60%

In contrast, a new coal-fired power plant has a lower minimum load capability of approximately 40%, with further potential to reduce this to 20–25%. The reason is that the output of the coal boiler is controlled via direct fuel combustion and not, as is the case with a gas combined-cycle power plant, via a heat recovery steam generator with an upstream gas turbine.

German power plant operators have also made it possible to reduce the minimum load of operation at existing power plants by optimizing the boiler-turbine system using modern control systems. Today’s optimized coal-fired power plants are able to operate at a partial-load level of less than 20% of full-load capacity.

The change (i.e., ramp) between partial load and full load at power plants involves load changes of approximately three percentage points per minute, and the change in mode of operation can therefore be achieved at all plants in less than half an hour (see Table 2 and Figure 4).

PROSPECTS1

Despite the continued increase in renewable capacity, the role of fossil fuels for power generation in Germany will be more or less the same in 2023 as in 2013 (see Figure 5).

The fundamental reason is the complete phasing out of nuclear power capacity by the end of 2022. By 2034 the total capacity on the basis of renewables is expected to be approximately 173 GW, which is twice as much as the peak load in Germany.2 However, a conventional capacity of 82 GW will still be needed (compared to 100 GW in 2012) to cover the demand when the wind is not blowing and/or the sun is not shining.2 The required flexibility to meet the fluctuations is being fulfilled just as well by coal-fueled as by gas-fueled power plants. These plants are being made increasingly flex-ible, ensuring that they can continue to serve their important role in Germany’s electricity market.

REFERENCES

1. IEA Coal Industry Advisory Board. (2013). 21st century coal: Advanced technology and global energy solution. Paris: OECD/IEA. www.iea.org/publications/insights/21stcenturycoal_final_web.pdf

2. 50Hertz Transmission/Amprion/ TenneT TSO/TransnetBW, Grid development plan electricity 2014, Berlin/Dortmund/Bayreuth/Stuttgart, 2014. (in German)

“Despite the continued increase

in renewable capacity, the role of

fossil fuels for power generation in

Germany will be more or less the

same in 2023 as in 2013.”


By Janne KärkiResearch Team Leader, VTT Technical Research Centre of Finland

Antti ArastoBusiness Development Manager,

VTT Technical Research Centre of Finland

The goal of CO2 emissions reductions and renewable energy incentives have led some power plant operators to broaden their fuel palette to include various carbon-

neutral biomass fuels. Biomass can be carbon neutral because it binds carbon from the atmosphere that is then released when it is burned, minimizing net emissions.

Carbon capture and storage (CCS), another potential option to cut CO2 emissions from the power sector, is currently under extensive research, development, and demonstration glob-ally. CCS is advancing toward commercialization, but there are still hurdles, mostly nontechnical, that are impeding its wide-spread deployment.

Greenhouse gas emission reduction targets are expected to be higher in the future and, therefore, the power sector and several other major industries may need solutions that can offer up to 80% reductions in emissions. In large-scale ther-mal power plants, this level of emissions reduction can be

achieved by employing CCS, utilizing high shares of biomass fuels, or a combination thereof. By combining biomass cofiring and CCS, it is possible to achieve negative emissions (defined as capturing CO2 from biomass combustion and storing it per-manently isolated from the atmosphere). This is one of the few large-scale options to remove CO2 from the atmosphere, which highlights the importance of these technologies. However, such technologies require stronger government and international support to encourage deployment. In addition, increased costs for CO2 emissions or CO2 emission perfor-mance standards (EPS) could help advance the technology.1–3

FEASIBILITY OF COFIRING WITH VARYING BIOMASS SHARES

Cofiring of coal and various types of biomass is now a mature technology and is currently being successfully practiced glob-ally. With technological advances, many limitations associated with it have been overcome. Many coal-fired plants have been converted or retrofitted to accommodate cofiring with limited impact on efficiency, operations, or lifespan.

However, there is much more to cofiring than simply adding a secondary fuel. Boiler technology and design remain critical issues when evaluating the maximum share of biomass that can be used without compromising boiler performance (out-put, efficiency, and power-to-heat ratio) or the lifetime of the boiler components.4

Various technologies have been developed to enable cofir-ing biomass with coal in pulverized coal (PC) boilers. The vast capacity of existing PC boilers offers great potential for increas-ing biomass utilization and economic benefits compared to new stand-alone biomass power plants, which also are usually

Toward Carbon-Negative Power Plants With Biomass Cofiring and CCS

In locations where sustainable biomass is readily available, cofiring with coal harnesses the advantages of each fuel.

“Combining biomass cofiring and

CCS … is one of the few large-scale

options to remove CO2 from the

atmosphere...”

32

significantly smaller than PC plants. With cofiring, capital costs are increased only marginally, while the high electrical effi-ciency of large PC boilers and the favorable properties of coal ash can be exploited to reduce the operational risks.

Utilizing biomass in an existing thermal power plant can be accomplished through direct or indirect cofiring. Direct cofir-ing is the most straightforward, most commonly applied, and lowest-cost concept for partially replacing coal or other solid fossil fuels with biomass. In direct cofiring, biomass and coal are burned together in the same furnace using the same or separate fuel handling and feeding equipment, depending on the biomass, targeted biomass share, and site-specific charac-teristics. The percentage of biomass that can be successfully employed in direct cofiring is modest, typically about 10%, and the type of biomass is limited mostly to pellet-type fuels. With torrefied biomass, however, higher shares are expected, up to tens of percentages. Indirect cofiring consists of convert-ing the solid biomass to a gas or liquid prior to combustion in the same furnace with the other fuel. This allows for greater amounts of biomass to be used, up to 50%. However, this approach requires greater investment and a larger footprint.5

In general, fluidized bed boilers offer the best fuel flexibility. In a properly designed boiler, biomass fuels can be used with coal in any percentage from 0–100% in circulating fluid-ized bed (CFB) boilers. The variety of biomass fuel options is increasingly diverse, although the availability of some biomass fuels can be limited. Power plants with high fuel flexibility can adapt to the prevailing fuel market by optimizing the fuel mix.6

One possibility to utilize biomass in existing PC boilers is to convert them into bubbling fluidized bed boilers. These retro-fits are routine for the major fluidized bed boiler technology suppliers, and numerous such conversions have been con-ducted in Europe. For example, at least eight conversions to enable pure biomass combustion have been carried out in Poland since 2008, with capacities from 100–200 MWth.

CONCEPTUAL STUDY OF BIOMASS COFIRING VERSUS CCS

VTT Technical Research Centre of Finland has conducted several conceptual case studies on the feasibility of CCS and biomass cofiring. In the case study discussed below, the fea-sibility of a coal-fired oxy-combustion CFB boiler with 99% CO2 capture and storage (Case I) is compared to cofiring large shares of biomass (Case II 70% and Case III 30%, with the bal-ance from coal). These cases are compared to a base-case CFB coal-fired (air-fired, no biomass cofiring, and no CCS) 500-MWfuel greenfield power plant situated in Finland that emits approximately 1.2 million tonnes CO2/year.

The fuel mix affects the plant design, investment required, and operational parameters. The plant fuel input (on an energy basis) and designed steam parameters remain constant in all cases. Therefore, the use of biomass or oxy-combustion increases the required plant investment and operating costs. Additional investment for biomass cofiring is required for bio-mass handling and feeding equipment, additional loop seal heat exchangers, advanced coarse material removal, more expensive materials for heat transfer surfaces, larger flue gas ducts and fans, extra soot-blowers, and possibly injection of combustion additives. Additional O&M costs include addi-tional chemical and maintenance costs. For the CFB-Oxy-CCS case, the main additional investment involves boiler block modifications, a cryogenic air separation unit (ASU), and a CO2 purification unit (CPU). The greatest impact of CCS on the O&M costs is the efficiency penalty, which in this study was assumed to be eight percentage points. The captured CO2 was assumed to be transported and stored abroad with an overall cost of €12/tonne CO2.7,8 The main assumptions and results, including net electricity output, are provided in Table 1.7,8

The principal goal of the modeling was to evaluate annual cash flows from an investor’s point of view in the three reduced-CO2 emission cases compared with the base case.

TABLE 1. Key assumptions and results from economic modeling

Factor Base Case Case I(CFB-Oxy-CCS)

Case II(70% bio)

Case III(30% bio)

Combustion mode Air Oxygen Air Air

CCS No Yes No No

Biomass share (%) 0 0 70 30

CO2 emissions reduction compared to base case (million tonnes/yr) 0 -0.91 -0.91 -0.39

Electricity output (MWe) 213 173 208 210

STRATEGIC ANALYSIS


The assumed fuel purchase prices were €10/MWh for coal and €20/MWh for biomass (based on LHV, including all costs and taxes), €75/MWh for electricity, and a CO2 allowance of €35/tonne [an estimated future price that is higher than EU Emissions Trading Scheme (EU ETS) trading values today]. Peak load utilization rates of the plants were 7500 hours per year. The overall costs (capital and operating) and profits for the four cases are presented in Figure 1.

The differences in electricity production, which can be attrib-uted to the energy penalty in the CCS case, are taken into account as “substitutive electricity”, which enables the com-parison of costs rather than annual cash flows, where income from electricity would dominate the chart. From Figure 1 it can be determined that operation of the base-case coal-fired power plant is the only option that is profitable under the economic assumptions made, although Case I with 30% biomass cofiring is relatively close to the base case. Based on the economics and emissions assumed, break-even prices (BEP) for CO2 emis-sion allowances in the EU ETS, at which specific cases become favorable compared to the base case, were calculated. The BEPs were 46, 42, and 39 €/tonne CO2 for CFB-Oxy-CCS, 70% biomass cofiring, and 30% biomass cofiring, respectively. These break-even points are a bit higher than, but generally in line with, estimates presented by Lüschen and Madlener for bio-mass cofiring with CO2 avoidance cost range of €25–32/tonne.9

Note that if the modeling assumptions change, the model results vary dramatically. The most economical solution is

mostly dependent on electricity prices, CO2 and fuel costs, and estimated peak load hours, which are all uncertain. For Finnish thermal power plants with CCS, break-even prices of €70–100/tonne were presented by Teir et al.10 In comparison to these reported values, the CFB-Oxy-CCS case was quite competitive, but this is highly dependent on CO2 transport and storage costs, which were much lower in our estimation.10 In addition, at some locations sufficient biomass may not be logistically or economically available. Similarly, CO2 storage sites are not universally accessible. Therefore, the exact modeling results should not be extrapolated to other regions or situations.

The CO2 emissions in the different cases modeled are pre-sented in Figure 2. Both cases of biomass cofiring as well as the CFB-Oxy-CCS offer significantly reduced emissions. It can be seen that significant emission reductions can be achieved with CCS and high shares of biomass cofiring. Note that for the energy penalty in CFB-Oxy-CCS case, the substitutive elec-tricity production is assumed to be produced by unabated coal-fired power; if the replacement electricity was provided by coal with CCS or some other blend of electricity, the carbon footprint of the oxy-combustion case would be even lower.

If more aggressive climate policies are enacted in the future, including other targets for renewable energy and other com-petition for biomass (existing forest industry, targets for liquid biofuels, etc.), a significant increase in biomass prices could result, at least in areas where sustainable biomass availability is limited. Increasing biomass prices would result in coal-fired

FIGURE 1. Annual operating costs and overall profits of compared technologies (with default input values) in millions € per year

-140

-120

-100

-80

-60

-40

-20

0

CAPEX Fuel purchase(including subsidies and taxes)CO2 allowancesCO2 transport and storage

Substitutive electricityOther operating costsProfit

-14

-13

-64

-31

Case II

-5.0 -11

-31

-49

-28

Case III

-0.3-10

-44

-38

-27

Base Case1.3

-12

-23

-15

-38

-45

Case I

-12.4

-1,500,000

-1,000,000

-500,000

0

500,000

1,000,000

1,500,000

2,000,000

Biogenic CO2 Fossil CO2 Replacement electricity

Other Captured fossil CO2

CO2 emissions relative to base case

Case I

-914,307

Case II

-911,389

Case III

-387,916

Base Case

0

FIGURE 2. Categorized CO2 emissions for the four cases modeled in tonnes per year

34

oxy-combustion with CCS becoming economically advanta-geous compared to biomass cofiring with large shares.

Based on our results, CFB oxy-combustion with CCS could become more competitive with quite realistic prices for bio-mass and CO2 in the future. For example, with prices of €24/MWh for biomass, €85/MWh for electricity, and €50/tonne CO2 allowance, the CFB-Oxy-CCS becomes the most profitable case modeled, although all are almost equally competitive.7

IS CCS SUITABLE FOR BIOMASS COFIRED PLANTS?

The cases discussed thus far reduced CO2 emissions, but did not eliminate them. An opportunity exists, however, for coal/biomass cofiring with CCS to not only eliminate CO2 emissions, but actually offer negative CO2 emissions. This approach could help reach climate targets by offsetting historical emissions and emissions from sectors with expensive or more difficult large-scale emission reductions (e.g., the transportation sec-tor) in the near term. In general, similar solutions are suitable for capturing CO2 from applications utilizing biomass as for fossil fuels. The main differences relate to the different kinds of impurities in the combustion process: ash and flue gas. In principle, there are no technical restrictions for capturing bio-genic CO2 via cofiring. However, the current EU ETS does not recognize negative emissions, and thus no economic incentive exists for capturing biogenic CO2 from installations combust-ing even partly biomass.

Despite fluidized bed technology’s high flexibility regarding the fuels, challenges exist in the case of biomass cofiring. Some of these challenges may be emphasized when CCS is employed at the plant. For example, with oxy-fired fluidized bed boilers even small concentrations of chlorine from the biomass fuel can lead to harmful alkaline and chlorine compound depos-its on boiler heat transfer surfaces. This is because of lack of nitrogen in furnace and the components’ increased concen-trations as a result of flue gas recirculation.7

COFIRING, CCS, OR BOTH?

There are still technical and economic challenges restricting the application of biomass cofiring and CCS as emission reduc-tion solutions. Both CCS and biomass cofiring offer pros and cons and their potential roles globally as carbon abatement tools are not yet certain. Both technologies must reduce the associated costs prior to widespread deployment.

The major costs associated with CCS result from equipment investment, loss of production due to the CCS energy penalty, and transportation and storage of CO2. First-generation CCS technologies are expected to result in efficiency decreases

of eight to 12 percentage points.11 Obviously, significant improvements in reducing the energy penalty would be very helpful for the deployment of the CCS. One potential solution to increase the efficiency (of all plants) is combined heat and power, where over 90% process efficiency is achievable—if a large heat distribution system and relatively continuous heat consumption (or storage) in that system exist.12,13

The costs associated with biomass cofiring are mainly due to the higher prices of biomass fuel in comparison to coal, higher plant investment, and higher O&M costs. The use of biomass increases O&M costs of the cofiring retrofit plant through negative effects on the availability of the boiler (i.e., boiler-related issues cause increased plant downtime) and increased maintenance work and consumables. When considering a retrofit option for biomass, the feasibility of the investment and the willingness to invest are affected also by the remain-ing lifetime of the plant and the annual operating hours.5,14 An indicative comparison on the CAPEX and operating expenses (OPEX) in coal, biomass, and cofired CFB boiler with and with-out CCS is presented in Figure 3.

The costs for CCS depend heavily not only on the characteris-tics of the facility and the operational environment but also on the assumptions related to future operation. From an inves-tor’s point of view, the optimal solution depends on multiple factors, electricity and EU ETS prices being the most domi-nant. As far as capturing biogenic emissions (and achieving negative emissions) from power plants is concerned, the only realistic applications are facilities that cofire biomass with coal and implement CCS. Dedicated biomass-firing plants are not considered to be the optimal sites to apply CCS in the initial phase as these facilities are likely smaller than fossil-fueled facilities and do not currently need to reduce their CO2 emis-sions. When discussing the biomass cofiring option, one must also address questions related to how availability of biomass

FIGURE 3. An indicative comparison of the CAPEX and OPEX in coal, biomass, and cofired CFB boiler with and without CCS*Without CO2 allowances

STRATEGIC ANALYSIS

Fossil withCO2 capture

Fossil Bio/Multi withCO2 capture

Bio/Multi• Agro• Wood

• Efficiency penaltysimilar to fossil

• “Negative” CO2

emissions

• Good plantefficiency

• Zero (biogenic)CO2 emissions

• 8 – 12%-pts eff.penalty in CCS

• Up to 95% CO2

capture rates

• High plantefficiency

• Fossil CO2

emissions

Lowest OPEX*and CAPEX

Higher OPEX*and CAPEX thanwithout capture

Higher OPEX*and CAPEX thanwith fossil fuels

Highest OPEX*and CAPEX


affects pricing and the competition for raw material between different users, such as the forest industry and liquid biofuel producers.

CONCLUSIONS

The possible and predicted high economic value on CO2 emis-sions as well as strict emission standards could provide a foundation for the development and deployment of biomass cofiring and CCS as individual or combined technologies. Both options are applicable for existing and new power plants and the technologies have already been demonstrated. Biomass cofiring is the most efficient means of power generation from biomass, and thus offers a CO2 avoidance cost lower than that for CO2 capture from existing power plants—provided reason-ably priced carbon-neutral biomass is available. However, future policies on legislation, subsidies, and carbon accounting remain the most vital factors for successful biomass cofiring business.

Economically, the difference between biomass cofiring and CCS varies depending on site-specific circumstances. In gen-eral, however, the EU ETS price and electricity prices projected in the near future do not yet make CCS investment feasible. The economic viability of CCS in the EU is heavily dependent on the CO2 allowance price.

There is a path forward for neutral or even negative carbon emissions at power plants that combust coal. For negative net emissions, capturing biogenic emissions is a widely avail-able option; power plants that cofire biomass with coal offer the greatest potential and most straightforward applications. However, the most important factors affecting the deploy-ment of the combined carbon-mitigation technologies include the availability of biomass, coal, and CO2 transportation and storage options as well as the political will (expressed through carbon pricing and recognition of negative emissions) and acceptance of the technologies. In reality, these technologies are already available and nearly ready to be demonstrated and then deployed.

REFERENCES

1. ZEP. (2012). Biomass with CO2 capture and storage (bio-CCS): The way forward for Europe, www.biofuelstp.eu/downloads/bioccsjtf/EBTP-ZEP-Report-Bio-CCS-The-Way-Forward.pdf

2. IEAGHG. (2011, July). Potential for biomass and carbon dioxide capture and storage. Report 2011/06, www.eenews.net/assets/2011/08/04/document_cw_01.pdf

3. Koljonen, T., et al. (2012). Low carbon Finland 2050. VTT clean energy technology strategies for society. Espoo: VTT Technical Research Centre of Finland, www.ashraeasa.org/pdf/VTT%20Low%20Carbon%20Vision.pdf

4. KEMA. (2009, July). Co-firing biomass with coal. Balancing US carbon objectives, energy demand and electricity affordability. White paper. Burlington, MA: KEMA Inc.

5. Kärki, J., Flyktman, M., Hurskainen, M., Helynen, S., & Sipilä, K. (2011). Replacing coal with biomass fuels in combined heat and power plants in Finland. In: M. Savolainen (Ed.), International Nordic Bioenergy 2011—Book of proceedings (pp. 199–206), www.vtt.fi/inf/julkaisut/muut/2011/Finland_Karki.pdf

6. Nevalainen, T., Jäntti, T., & Nuortimo, K. (2012). Advanced CFB technology for large scale biomass firing power plants. Paper presented at Bioenergy from Forest, 29 August, Jyvaskyla, Finland, www.fwc.com/getmedia/227a6ef3-a052-42e4-b81e-ca642124869a/TP_FIRSYS_12_07.pdf.aspx?ext=.pdf

7. Arasto, A., Tsupari, E., Kärki, J., Sormunen, R., Korpinen, T., & Hujanen. S. Feasibility of significant CO2 emission reductions in thermal power plants—Comparison of biomass and CCS. GHGT-12 (submitted 15 September 2014).

8. Tsupari, E., Kärki, J., & Arasto, A. (2011). Feasibility of BIO-CCS in CHP production—A case sudy of biomass cofiring plant in Finland. Presented in Second international Workshop on Biomass & Carbon Capture and Storage, 25-26 October, Cardiff, Wales.

9. Lüschen, A., & Madlener, R. (2013). Economic viability of biomass cofiring in new hard-coal power plants in Germany. Biomass and Bioenergy, 57, 33–47, dx.doi.org/10.1016/j.biombioe.2012.11.017

10. Teir, S., et al. (2011). Hiilidioksidin talteenoton ja varastoinnin (CCS:n) soveltaminen Suomen olosuhteissa. Espoo, VTT. 76 s. + liitt. 3 s. VTT Tiedotteita - Research Notes; 2576 ISBN 978-951-38-7697-5; 978-951-38-7698-2.

11. IEA. (2013). Technology roadmap: Carbon capture and storage, www.iea.org/publications/freepublications/publication/technologyroadmapcarboncaptureandstorage.pdf

12. Davison J. (2007). Performance and costs of power plants with capture and storage of CO2. Energy, 32, 1163–1176.

13. Kärki, J., Tsupari, E., & Arasto, A. (2013). CCS feasibility in improvement in industrial and municipal applications by heat utilisation, Energy Procedia, 37, 2611–2621.

14. Basu, P., Butler, J., & Leon, M.A. (2011). Biomass co-firing options on the emission reduction and electricity generation costs in coal-fired power plants. Renewable Energy, 36(1), 282–288, dx.doi.org/10.1016/j.renene.2010.06.039


“There is a path forward for neutral

or even negative carbon emissions at

power plants that combust coal.”

36

STRATEGIC ANALYSIS

By Christopher LongPrincipal Scientist, Gradient

Peter ValbergPrincipal, Gradient

Although uncommon in developed countries, solid fuels—including wood, charcoal, coal,A dung, and crop residues—are burned domestically by billions of people

across the world for space heating, lighting, and cooking. For example, it is estimated that, as of 2010, approximately 41% of the world’s households (approximately 2.8 billion people) rely mainly on solid fuels for cooking.1 A comprehensive assess-ment of respiratory risks from household air pollution recently concluded that the health of one in three people worldwide is at risk because of exposure to emissions from traditional household solid fuel combustion.2

To provide some perspective on their relative air exposure impacts, we have compared exposure of people to tradi-tional household solid fuel combustion emissions (e.g., smoke from domestic burning of biomass material or coal) to those of coal-fired power plants (CFPPs). We used data from pub-lished papers and reports and tabulated levels of people’s exposure to common air pollutants from these two different combustion sources. The coal-fired power plants used for the

study were based in the U.S. due to the larger amount of air modeling data available, but were older and had more lim-ited emissions controls than modern state-of-the-art plants. As a result, these plants are useful for representing the air exposure impacts of plants that might be built in developing countries today, including those built without international support for meeting high-efficiency, low-emissions standards.

For our comparisons, we focused on air exposure concentra-tions rather than emissions because possible exposure via breathing cannot be characterized based solely on emissions data (e.g., tons per year), but rather needs to be assessed through examining concentrations of pollutants [masses of pollutants per unit volume of air—e.g., micrograms per cubic meter (μg/m3)] that can potentially be inhaled. In addition, we used an alternative metric of exposure, namely intake fraction (iF), to supplement this analysis.

ASSESSMENT OF REPORTED AIR EXPOSURE LEVELS

Traditional Household Solid Fuels Contribute to Complex Indoor Air Pollution

Over the past several decades, numerous studies have inves-tigated the air pollution generated by traditional household solid fuel combustion for space heating, lighting, and cooking in developing countries.1,3 It is now well established that, through-out much of the world, indoor burning of solid fuels (e.g., wood, charcoal, coal, dung, and crop residues) by inefficient, often insufficiently vented, combustion devices (e.g., ovens, stoves,

Evolution of Cleaner Solid Fuel Combustion

A review of available literature has shown that traditional stoves for cooking and heating are a much more inefficient and dangerous means of energy utilization compared to modern electricity services.

“As compared to traditional

household solid fuel combustion

… modern coal-fired power plants

represent a more sophisticated and

cleaner approach to getting the

maximum energy out of solid fuel…”


or fireplaces) leads to highly elevated exposures to household air pollutants. This is due to the poor combustion efficiency of the combustion devices and the elevated nature of the emis-sions; moreover, they are often released directly into living areas.3 Smoke from traditional household solid fuel combustion commonly contains a range of incomplete combustion prod-ucts, including both fine and coarse particulate matter (e.g., PM2.5, PM10), carbon monoxide (CO), nitrogen dioxide (NO2), sulfur dioxide (SO2), and a variety of organic air pollutants (e.g., formaldehyde, 1,3-butadiene, benzene, acetaldehyde, acrolein, phenols, pyrene, benzopyrene, benzo(a)pyrene, dibenzopy-renes, dibenzocarbazoles, and cresols).2 In a typical solid fuel stove, approximately 6–20% of solid fuel mass is converted into toxic emissions, with such factors as the fuel type and moisture content, stove technology, and stove operation influencing the amount and relative composition of the pollution mixture.1

Even though the mixture of pollutants arising from traditional household solid fuel combustion is complex, most measure-ment studies have focused on characterizing breathing-zone exposure levels of two surrogate species in solid fuel smoke, namely PM and CO, which are the main products of incomplete

combustion and are considered to pose the greatest health risks.2 Table 1, adapted from Naeher et al.,3 summarizes indoor air measurements of PM2.5 and CO associated with traditional household solid fuel combustion. As shown in the table, PM2.5 exposure levels have been consistently reported to be in the range of hundreds to thousands of micrograms per cubic meter (μg/m3); likewise, CO exposure levels as high as hun-dreds to greater than 1000 milligrams per cubic meter (mg/m3) have been measured. Consistent with these data, a more recent study of 163 households in two rural Chinese counties reported geometric mean indoor PM2.5 concentrations of 276 μg/m3 (combinations of different plant materials, including wood, tobacco stems, and corncobs), 327 μg/m3 (wood), 144 μg/m3 (smoky coal), and 96 μg/m3 (smokeless coal) for homes using a variety of different fuel types and stove configurations (vented, unvented, portable, fire pit, mixed ventilation stove).4

Air Modeling of CFPP Emissions Predicts Substantially Lower Air Quality Impacts

In comparison to traditional solid fuels, CFPP emissions are associated with far lower ground-level ambient exposure levels

TABLE 1. Summary of indoor PM2.5 and CO breathing zone exposure levels in developing-country households with traditional household solid fuel combustion3

Location Number of Studies

Total Number of Samples

PM2.5 (μg/m3) CO (mg/m3)

meal avg. daily avg. meal avg. daily avg.

Bangladesh 1 53 15–26

Burundi 1 2 42

Ethiopia 1 NA 48

Ghana 1 21 9

Guatemala 7 768 450–27,000 97–1900 2–149 1.2–17

India 13 1009 110–2100 1300–1500 5–216

Kenya 4 199 630–3500 5–60

Malaysia 1 10 3

Mexico 5 191 890 10–22

Mozambique 1 114 48

Nepal 5 127 1700–5700 14–360 14–52

New Guinea 1 9 13–24

Nigeria 1 28 1076

South Africa 1 20 79–180 92

Zambia 1 89 10

Notes: NA = not available. Meal avg. = average concentrations measured during active meal and cooking times, typically between 30 minutes and three hours.

38

of both PM2.5 and CO.B Table 2 provides a summary of model-predicted ground-level PM2.5 and CO concentrations from publicly available studies of the ambient air quality impacts of U.S. CFPPs. We relied on model-predicted concentrations rather than measurement data because air-monitoring data are not specific to power plant emissions and include con-tributions from a variety of other common anthropogenic, natural, and distant air pollution sources. As indicated in Table 2, all but one of the studies we identified reflect modeled air qual-ity impacts for groups of U.S. CFPPs in the same general vicinity; thus, these data encompass air quality impacts higher than what would be the case for a single newer U.S. power plant. Moreover,

the majority of the modeled plants are older CFPPs that lack the clean coal technologies characteristic of newer and retrofitted CFPPs. With respect to PM, these studies generally accounted for both primary PM2.5 emissions and secondary atmospheric forma-tion of sulfate and nitrate particles from gaseous SO2 and NOx emissions, respectively. With respect to CO, we identified just a single modeling study that predicted the CO air quality impacts of emissions from CFPPs (as well as a number of natural gas power plants).5 Most likely because CO emissions from U.S. CFPPs are low and not considered to pose significant air quality problems or public health impacts, CO has not received as much attention as PM2.5 in studies of the air quality impacts of power plants.6

TABLE 2. Model-predicted ground-level PM2.5 and CO concentrations associated with U.S. CFPP emissionsa,b

SourceNumber of Modeled

CFPPsPlant Location(s) Plant Capacity/

Characteristics

Model-Predicted Ground-Level Annual

Average PM2.5 Air Conc. (µg/m3) a

Model-Predicted Ground-Level Annual Average CO Air Conc.

(mg/m3) a

Levy et al. (2000)7

1Salem,

Massachusetts, U.S.

805-MW nameplate capacity; older plant grandfathered under

Clean Air Act

0.2 for maximum po-tential plant emissions, including both primary

and secondary PM2.5

NA

1Somerset,

Massachusetts, U.S.

1611-MW nameplate capacity; older plant grandfathered under

Clean Air Act

0.25 for maximum po-tential plant emissions, including both primary

and secondary PM2.5

NA

Levy et al. (2002)8 9

Illinois, in close proximity to or upwind of the

Chicago area, U.S.

>7500-MW total nameplate capacity;

all older plants grand-fathered under the

Clean Air Act

0.7, including both primary and secondary

PM2.5

NA

Levy et al. (2003)9 7 Georgia, in the

Atlanta area, U.S.

>13,000-MW total nameplate capacity;

all older plants grand-fathered under the

Clean Air Act

0.6–0.9 depending on the air modeling ap-

proach, including both primary and secondary

PM2.5

NA

Perkins et al. (2009)5

3 coal plants/units

(and 18 gas plants/

units)

Bexar County, Texas, in the San Antonio metro-

politan area, U.S.

1425-MW capac-ity for 3 coal plants/

units (and ~2300-MW capacity for 18 gas

plants/units)

0.16 for year 2002 emis-sions, including both

primary and secondary PM2.5

0.00011 for year 2002 emissions

Notes: NA = not available.a As mentioned in the text, model-predicted ground-level annual average PM2.5 and CO air concentrations are generally for groups of older U.S. CFPPs due to the availability of air modeling studies; air concentrations for single U.S. CFPPs, and particularly newer, more advanced CFPPs, would be expected to be lower. On the other hand, air quality impacts of low-efficiency, uncontrolled CFPPs, such as those present in developing countries lacking stringent regulations, may be comparable, if not larger, than those in the table. b Some concentrations are for maximum impacted model receptor locations,8,9 while others are either population-weighted average concentrations7 or county-average impacts.5

STRATEGIC ANALYSIS


The annual average ambient PM2.5 and CO concentrations in Table 2 are far below the comparable daily-average PM2.5 and CO indoor exposure levels associated with traditional household solid fuel combustion in Table 1.C For PM2.5, sev-eral studies7–9 of groups of older, grandfathered U.S. CFPPs predicted annual average concentrations of less than 1 μg/m3 for maximally impacted locations, as compared to daily aver-age PM2.5 exposure levels of hundreds to thousands of μg/m3 inside homes with traditional solid fuel combustion. For CO, the single modeled estimate that we identified for 2002 county-average CO impacts from three CFPPs/units (plus 18 gas-fired power plants/units) in the San Antonio, TX, metro-politan area5 is over 10,000 times lower than the lowest CO exposure levels we found for traditional household solid fuel combustion (Table 1).

INTAKE FRACTION AS AN ALTERNATIVE COMPARISON TOOL

Defining Intake Fraction

The iF is a well-established metric in the exposure assessment and public health fields for quantifying the emission-to-intake relationship, in large part because iFs facilitate comparisons of the exposure implications of various emission sources. Intake fraction can be defined simply as the fraction of material emit-ted into the air from a given source that is actually inhaled; however, Bennett et al.10 provided a more thorough defini-tion of iF as “the integrated incremental intake of a pollutant, summed over all exposed individuals, and occurring over a given exposure time, released from a specified source or sources, per unit of pollutant emitted.” It is generally reported as a unitless value, as expressed in the following equation10:

iF thus sums pollutant intake over two measures—population size and time duration—and incorporates a variety of factors related to the emission scenario and exposure conditions. These factors include chemical properties of the contaminant, emissions locations (e.g., release height, indoor versus out-door, proximity to people), environmental conditions (climate, meteorology, land use), human receptor locations and activi-ties, and population characteristics. Intake fractions can be based on both modeling results and measurements.

Relative Intake Fractions for Traditional Solid Fuel Combustion Versus CFPPs

We identified just a single study11 that reported iFs for both types of PM combustion emissions. Smith (1993) estimated iFs ranging from approximately one to two one-thousandths for PM emissions from traditional solid fuel combustion in biomass cookstoves versus substantially lower iFs of one one-millionth for a U.S. CFPP and 10 one-millionths for a CFPP in a least developed country (LDC) based on the assumption of a greater population density. In other words, these results indi-cate that about one one-thousandth of what is released from traditional household solid fuel burning is inhaled, while only about one one-millionth of what is released from a U.S. CFPP is inhaled.

These differences demonstrate the critical role of the proximity of the emission source to people in determining its exposure potential; whereas CFPP emissions are typically released from tall stacks often far from heavily populated areas, emissions from traditional household solid fuel combustion in develop-ing countries are often released directly into poorly ventilated indoor spaces (e.g., kitchens), where they can remain trapped for extended periods of time in direct proximity of people. Smith12 has subsequently emphasized the concept that the “place makes the poison”.

More recent iF estimates for PM emissions from both tradi-tional household solid fuel combustion and CFPPs confirm that iF differences between these sources span several orders of magnitude.9,13,14 For example, Levy et al.9 estimated a slightly smaller iF for primary PM2.5 emissions from seven older northern Georgia (U.S.) CFPPs (0.0000006), and even smaller iFs for secondary sulfates and nitrates (0.0000002 and 0.00000006). In contrast, Grieshop et al.14 estimated iFs of 0.0013 and 0.00024 for unvented and outdoor-vented cook-stoves, respectively.

CONCLUSIONS

We found that measured PM2.5 and CO concentrations inside homes burning traditional solid fuels are thousands of times greater than even the high-end estimates of ground-level ambient exposure levels from U.S. coal-fired power plant stack emissions. Even if a low-efficiency coal-fired power plant with no emissions controls were employed—a likely scenario in areas where traditional solid fuels are combusted and in the absence of international support for efficiency and environmental upgrades—order-of-magnitude differences would likely be observed compared to traditional solid fuel combustion. Moreover, we saw similar, support-ing results using an alternative comparison approach based on intake fractions. Overall, these conclusions point to

iF =∑people, time

individual pollutant intake (mass, grams)

mass released into the environment (mass, grams)

40

traditional household solid fuel combustion being a signifi-cantly greater source of air pollution exposures of health concern. The basic difference is that coal-fired power plants burn coal much more efficiently and completely—and exhaust their emissions from tall stacks rather than in direct proximity to people. Overall, as compared to tradi-tional household solid fuel combustion, which represents an inefficient, high-emission form of fuel utilization, mod-ern coal-fired power plants (and even older ones with more limited air pollution controls) represent a more sophisti-cated, cleaner approach to getting the maximum energy out of solid fuel with significantly reduced impacts on the air that humans breathe.

NOTES

A. Although coal is used both for traditional household solid fuel combustion and for electricity generation at modern power plants, coal handling and combustion conditions for the two situ-ations are quite different. When used as a traditional household solid fuel, large chunks of often lower-quality coal are directly burned under uncontrolled combustion conditions, such that combustion is inefficient and incomplete. In contrast, modern power plants often burn higher-quality coal, usually pulverized and mixed with air, under efficient and controlled conditions, resulting in nearly complete combustion of coal organics.

B. Actual personal exposures to ambient-derived pollutants can often be significantly lower than ambient (outdoor) air exposure levels. This is largely because people in countries such as the U.S. spend the majority (~90%) of their time indoors where the infiltration process can result in significantly reduced concentra-tions indoors compared to the corresponding ambient levels outdoors.

C. Although expressed for different averaging periods, the annual average PM2.5 and CO concentrations shown in Table 2 (for power plants) should be compared to the daily average PM2.5 and CO concentrations in Table 1 (for traditional household solid fuel combustion), which would occur repeatedly on a daily basis. That is, the daily average PM2.5 and CO concentrations in Table 1 can be assumed to be representative of long-term average (e.g., annual average) exposure levels given the daily occurrence of solid fuel combustion for cooking, heating, and lighting.

ACKNOWLEDGEMENTS

This article was commissioned by Peabody Energy; it reflects the professional opinions of the authors and the writing is solely that of the authors.

REFERENCES

1. Smith, K.R., Bruce, N., Balakrishnan, K., Adair-Rohani, H., Balmes, J., Chafe, Z., … HAP CRA Risk Expert Group. (2014). Millions dead: How do we know and what does it mean? Methods used in the comparative risk assessment of household air pollution. Annual Review of Public Health, 35, 185–206.

2. Gordon, S.B., Bruce, N.G., Grigg, J., Hibberd, P.L., Kurmi, O.P., Lam, K.B., … Martin, W.J., II. (2014). Respiratory risks from household air pollution in low and middle income countries. The Lancet Respiratory Medicine, epub ahead of print.

3. Naeher, L.P., Brauer, M., Lipsett, M., Zelikoff, J.T., Simpson, C.D., Koenig, J.Q., & Smith, K.R. (2007). Woodsmoke health effects: A review. Inhalation Toxicology, 19, 67–106.

4. Hu, W., Downward, G.S., Reiss, B., Xu, J., Bassig, B.A., Hosgood, H.D. III, & Lan, Q. (2014). Personal and indoor PM2.5 exposure from burning solid fuels in vented and unvented stoves in a rural region of China with a high incidence of lung cancer. Environmental Science & Technology, 48, 8456–8464.

5. Perkins, J., Heilbrun, L., Symanski, E., Coker, A., & Eggleston, K. (2009). A study to evaluate the health effects of air pollution in Bexar County with a focus on local coal and gas fired power plants. CPS Energy, www.cpsenergy.com/files/Health_Study_FullReport.pdf

6. United States Environmental Protection Agency (U.S. EPA). (2010). Integrated Science Assessment for Carbon Monoxide. EPA/600/R-09/019F. Research Triangle Park, NC: National Center for Environmental Assessment-RTP Division.

7. Levy, J., Spengler, J.D., Hlinka, D., & Sullivan, D. (2000). Estimated public health impacts of criteria pollutant air emissions from the Salem Harbor and Brayton Point power plants. Boston, MA: Harvard School of Public Health, Dept. of Environmental Health.

8. Levy, J.I., Spengler, J.D., Hlinka, D., Sullivan, D., & Moon, D. (2002). Using CALPUFF to evaluate the impacts of power plant emissions in Illinois: Model sensitivity and implications. Atmospheric Environment, 36, 1063–1075.

9. Levy, J.I., Wilson, A.M., Evans, J.S., & Spengler, J.D. (2003). Estimation of primary and secondary particulate matter intake fractions for power plants in Georgia. Environmental Science & Technology, 37, 5528–5536.

10. Bennett, D.H., McKone, T.E., Evans, J.S., Nazaroff, W.W., Margni, M.D., Jolliet, O., & Smith, K.R. (2002). Defining intake fraction. Environmental Science & Technology, 36, 207A–211A.

11. Smith, K.R. (1993). Fuel combustion, air pollution exposure, and health: The situation in developing countries. Annual Review of Energy and the Environment, 18, 529–566.

12. Smith, K.R. (2002). Place makes the poison – Wesolowski Award Lecture – 1999. Journal of Exposure Analysis and Environmental Epidemiology, 12, 167–171.

13. Evans, J.S., Wolff, S.K., Phonboon, K., Levy, J.I., & Smith, K.R. (2002). Exposure efficiency: An idea whose time has come? Chemosphere, 49, 1075–1091.

14. Grieshop, A.P., Marshall, J.D., & Kandlikar, M. (2011). Health and climate benefits of cookstove replacement options. Energy Policy, 39, 7530–7542.


STRATEGIC ANALYSIS


TECHNOLOGY FRONTIERS

By Jaquelin CochranSenior Energy Analyst,

National Renewable Energy Laboratory (NREL)

Debra LewIndependent Consultant

Nikhil KumarDirector of Energy & Utility Analytics, Intertek

Power systems in the 21st century—with higher penetration of low-carbon energy, smart grids, and other emerging technologies—will favor resources that have low marginal

costs and provide system flexibility (see Figure 1). Such flexibil-ity includes the ability to cycle on and off as well as run at low minimum loads to complement variations in output from high penetration of renewable energy. With a lack of general experi-ence in the industry, questions remain about both the fate of coal-fired power plants in this scenario and whether they can continue to operate cost-effectively if they cycle routinely.

To demonstrate that coal-fired power plants can become flexi-ble resources, we discuss experiences from an actual multi-unit North American coal generating station (CGS).A,1 This flexibil-ity—namely, the ability to cycle on and off and run at below 40% of capacity—requires limited modifications to hardware, but extensive modifications to operational practice. Cycling does damage the plant and impact its life expectancy compared to baseload operations. However, strategic modifications, proac-tive inspections and training programs, and various operational changes to accommodate cycling can minimize the extent of damage and minimize cycling-related maintenance costs.

We have used a case study of this CGS to evaluate how power plants intended to run at baseload can evolve to serve other system needs. The CGS case illustrates the types of changes that may occur in global power systems, especially those with legacy plants. CGS’s experiences challenge conventional wisdom about the limitations of coal-fired power plants and help policymakers better understand how to formulate policy and make investment decisions in the transformation toward power systems in a carbon-constrained world.

A BRIEF HISTORY OF THE CGS PLANT

When it came online in the 1970s, the CGS plant was intended to run at an 80% annual capacity factor. However, the addi-tion of nuclear power soon thereafter displaced coal as the principal source of baseload generation. Consequently, CGS typically ran at 50% annual capacity factor until the early 1990s. To understand the effects of “two-shifting” (i.e., cycling on and off in a day) considerable research was conducted in the 1980s. As a result, plant operations, the steam generator, and supporting equipment were modified.

After a competitive market was introduced in the early 2000s, the CGS plant was operated for longer periods at full plant output—this period was also marked by significant forced out-ages. For example, in 2004, the equivalent forced outage rate (EFOR)—a measure of a plant’s unreliability—was 32%, which represented the accumulated latent damage from the cycling that CGS performed in the 1990s. Typical EFOR for a baseload coal-fired power plant is 6.4%.2

The competitive market created the incentive for CGS units to continue to operate flexibly—for example, that they be able to

Making Coal Flexible: Getting From Baseload to Peaking Plant

FIGURE 1. Simulated dispatch of generation over one week in a high renewable energy scenario (annual load served by 25% wind, 8% solar photovoltaic).Notes: PV = solar photovoltaic; CSP = concentrated solar power; CT = combustion turbine; CC = combined cycleSource: Lew et al., 2013

“Strategic modifications, proactive

inspections and training programs,

and various operational changes to

accommodate cycling can minimize

the extent of damage and minimize

cycling-related maintenance costs.”

100

75

50

25

0Mar 25 Mar 26 Mar 27 Mar 28 Mar 29 Mar 30 Mar 31 Apr 01

CurtailmentWindPVCSPStorageOtherGas CTGas CCHydroGeothermalCoalNuclear

Gene

ratio

n (G

W)

42

two-shift and operate at an output below intended minimum load. Although the two- and sometimes four-shifting created wear and tear and reduced the plant’s cost competiveness, the CGS owners operated the plant in this fashion to compete in the wholesale power market.

EXAMINING THE IMPACT OF CYCLING AT CGS

The CGS coal units were intended to primarily run at full output and start cold only a few times a year. However, each CGS coal-fired unit has experienced an average of 1760 starts, including 523 cold starts throughout its lifetime. The overarching effect of this type of cycling is thermal fatigue. For example, large temperature swings from cold feedwater entering the boiler on start-up and from steam as it is heating create fluctuating

thermal stresses within single components and between dif-ferent components when materials heat at different rates.

Other typical effects of cycling and operating at low loads include:

• Stresses on components and turbine shells resulting from changing pressures

• Wear and tear on auxiliary equipment used only during cycling

• Corrosion caused by oxygen entering the system during start-up and by changes in water quality and chemistry

• Condensation from cooling steam during ramping down and shutting down, which can cause corrosion of parts, water leakage, and an increased need for drainage

These effects (summarized in Table 1) can cause equipment components, particularly in the boiler, to fatigue and fail. In turn, equipment failure leads to increased outages, increased opera-tions and maintenance (O&M) costs, additional wear and tear from the increased O&M, and more extensive and sophisticated training, inspection, and evaluation programs.3 The damage from cycling is not immediate—for example, components may fail and EFOR may rise a few years after significant cycling.

MODIFYING THE PHYSICAL PLANT AND OPERATING PROCEDURES

Physical Modifications

The CGS plant owner made numerous physical modifications to equipment to prevent and address impacts from cycling and low-load operations. These changes have focused on actions that improve drainage and thermal resiliency and reduce


TABLE 1. Specific experiences from cycling at CGS

Problem Impact/Cause

Failure of boiler tubes Caused by cyclic fatigue, corrosion fatigue, and pitting

Cracking in dissimilar metal welds, headers, and valves Due to rapid changes in steam temperature

Cracking of generator rotors Due to movement between the rotor and casing during “barring” (slow turns to keep rotors from being left in one position too long during turning-gear operation)

Oxidation from exposure to air on start-up and draining

Oxides in boiler tubes can dislodge due to thermal changes and lead to damage downstream, such as the turbine blades (see Figure 2)

Corrosion of turbine parts From oxides, but also from wet steam that occurs on start-up, during low-load operations, and during poor plant storage conditions when the plant is dried

Condenser problems Can occur when thin tubes crack from thermal stresses at start-up and shutdown

FIGURE 2. Example of large nick in turbine fin (#96) due to impact with dislodged material formed by oxidation (Debra Lew)


opportunities for corrosion, as described in Table 2. There were no major capital retrofits to allow additional cycling flexibility.

Decisions on whether and when to replace parts or modify com-ponents were made on a case-by-case basis. In other words, the plant owner based such decisions on whether wholesale power market opportunities in the coming year justified the cost of modifications to reduce the forced outage rate.

Operating Procedures

The owner of CGS estimates that once the physical changes were in place, 90% of future cost savings came from modifying operating procedures. For example, establishing procedures and training on boiler ramp rates was especially effective. Controlled ramp rates help minimize thermal fatigue; continual reinforcement of the importance of controlled ramping through training helps ensure that ramp rate procedures are followed.

Another example of effective modifications to operating pro-cedures is high-energy (i.e., high temperature or pressure steam) piping inspections, the value of which is not always appreciated at other coal-fired power plants. The inspection program at CGS covers all the failure mechanisms that can occur (e.g., thermal and corrosion fatigue), and establishes a repair process and a repair program for each failure mecha-nism. The owner employs many similar inspection programs, for example, for the hanger rods that hold the high-energy piping. These examples illustrate that effective operating pro-cedures require an understanding of all components impacted by cycling—not just the major ones. Table 3 describes some of the modifications that were made to CGS’s operating proce-dures to support cycling.

Changes to plant operating procedures were critical to enabling CGS to cycle on and off cost-effectively. Controlling the rise in temperatures during plant start-up and temperature drops on shutdowns as well as having rigorous inspection pro-grams for major and minor components limited the damage

from cycling. Training programs to reinforce the skills needed to monitor the impacts of cycling were also central to the CGS owner’s strategy.

A LOOK AT COSTS AND EMISSIONS

The costs associated with cycling, and modifications made in response, are difficult to distinguish from normal opera-tion efforts. Modifications were made over the course of decades, in response to both cycling and noncycling wear and tear, to achieve EFOR rates that varied highly by unit and year. Extrapolating cost implications to other coal-fired power plants generally from the experiences at CGS is difficult due to variations in age, design, and history of operations. Moreover, decisions on the scope and timing of modifications depend on business case justifications, which are highly market- and context-driven and could vary from year to year.

Studies of coal-fired power plants, such as Kumar et al.,5 evalu-ate cycling costs by calculating operating, maintenance, and repair costs associated with cycling. The plants in this study represent typical operations where coal-fired power plants are operated and maintained according to baseload require-ments. However, the CGS plant owner recognized early on that CGS would be cycling significantly and, therefore, modified operating practices and equipment to minimize the impacts of cycling. Thus, because of the owner’s proactive changes, the costs to mitigate cycling based on EFOR rates at CGS are likely less than those for other plants with similar cycling and EFOR rates whose owners are not as proactive.

Cycling also incurs costs associated with increased emissions rate. The selective catalytic reduction (SCR) system, which con-trols some emissions, must be operated at a minimum load. However, if a power plant needs to operate below this level, the owners may have authority to run the plant without the SCR system, as is the case with CGS. Other emissions impacts occur due to increased fuel use at start-ups, reduced plant efficiency at less than full load, and reduced effectiveness

TABLE 2. Examples of physical modifications to support cycling

Boiler Added a metal overlay to water walls to minimize oxidation, cut back membranes in various areas to reduce start-up stresses, and replaced dissimilar metal welds.

Turbines Added drains, upgraded the lubrication system, modified vacuum pumps and low-pressure crossover bellows, and inspected the non-return valves, which can be damaged during shutdowns.

Generator Rotors

Insulated and epoxied key parts to reduce rotor cracking from rubbing and established continual tests and checks to monitor trends.

CondenserPlugged tubes at the top of the condenser that had been damaged as a result of low-load operation and water impingement, reducing overall efficiency; also installed stainless-steel air removals and retubed the existing brass on several units.

44

of pollution-control equipment when flue gas temperatures at start-up are too low to support the chemical reactions needed.6 Although emissions rates during cycling can be higher than during noncyclic operation, Lew et al.6 showed that the avoided emissions from the added wind and solar far outweigh the impacts of cycling-induced emissions.

CAN THE CGS EXPERIENCE BE REPLICATED?

The CGS plant achieved the flexibility to cycle over several decades; this experience has provided valuable information on impacts, recommended modifications to operations and equipment, and relative costs. However, some of the aspects of CGS that improve the plant’s flexibility might not easily translate to other contexts.

Physical Distinctions

Some of CGS’s original plant designs are conducive to cycling—the owner did not need to conduct major-capital retrofits. For example, CGS’s boiler tubes are horizontal, which facilitates cycling by improving drainage; this reduces corrosion fatigue and the time needed to come back online (see Figure 3). Effective operating practice requires drainage of any residual water in the

boiler to reduce thermal shocking of tubes in the boiler. In con-trast, almost all other boilers in North America are a “pendant design”, which results in water accumulating at the bottom of the U-shape and leading to slow drainage. This design cannot be modified, although a $10–15-million bypass system could be added to improve temperature control and reduce tube failure.

Automation of CGS’s drainage system, absent in most coal-fired power plants, was also critical to reducing failures. Earlier in plants’ projected lifetimes, such major retrofits could be economically feasible.

Operating Distinctions

CGS experiences much higher EFOR rates than typically accommodated in markets where coal-fired power plants run at baseload. The plant owner can manage these high EFOR rates because of the role CGS’s coal-fired units play in its sys-tem operations. The owner found that EFOR rates could be reduced by being highly proactive with inspections and strate-gic operational modifications.

However, a trade-off between maintenance costs and EFOR rates exists. Grid operators may need to change how they

TABLE 3. Example modifications to operating procedures to support cycling

Natural cooling

Accelerated forced cooling for the boiler enabled the owner to quickly shut down the unit to repair a boiler tube and be back online in two days. However, after a year of implementing accelerated forced cooling, the units recorded a noticeable increase in corrosion and cyclic fatigue failures. The shutdown procedures are now to keep the boiler shut for the first four hours (natural cooling).

Monitoring economizer inlet headers

Economizer inlet headers can crack from intermittent additions of cold feedwater to the hot inlet header. The plant owner keeps the temperature difference between the header and water at less than 30°C, below the boiler manufacturer recommendations.4

Pressure part management

The owner established a pressure-part management program, reviewing every pressure component and establishing causes for degradation and failure.

Other changes to boiler operating procedures

These included a program to monitor boiler metal temperature; a tube replacement and inspection strategy; a thermal and cyclic fatigue inspection and repair program; a fly-ash erosion program to reduce tube failures; and inspection programs for expansion joints, dissimilar metal welds, and flow-accelerated corrosion.

Temperature monitoring for turbine parts

The owner established training and monitoring procedures, with associated monitoring equipment, to limit ramp rates and to monitor temperature changes to thick-walled fittings, headers, and the casing to the main steam line.

Water chemistry maintenance

To reduce corrosion, proper water chemistry must be maintained to protect surfaces that oxidize. Water chemistry varies with cycling, so the owner maintains a chemistry staff onsite and established a Chemistry Managed System (following ISO standards).

Overall monitoring programs

The owner compared reports on best practices associated with cycling with CGS’s equipment status and mitigating actions and created an overall plant monitoring program.



operate their systems, and coal-fired power plant operators may require a cultural shift to adapt to higher EFORs. This is particularly true because justifying maintenance costs over EFOR rates could become increasingly difficult if the cost per unit of energy generated increases at low load.

Regulatory Distinctions

Operating at low generation levels could be challenging if plants are required to run environmental controls at all output levels. Operating an SCR system requires a minimum gener-ating level that is frequently higher than the low generating levels at which the CGS plant owner is permitted to operate.

FROM BASELOAD TO PEAKING PLANT

At CGS, the plant owner has achieved what few coal-fired power plant operators have been able to do: modify a plant that was intended to run only at baseload into one that can meet peak demands—cycling on and off up to four times a day to meet morning and afternoon electricity demand. Key to the owner’s success is changing operational practices: moni-toring and managing temperature ramp rates; creating a suite of inspection programs for all impacted equipment (large and small); and continual training to reinforce the skills needed in monitoring and inspections.

The owner’s success in cycling has also benefited from factors specific to CGS. The original plant design, although intended for baseload operation, included features that facilitate cycling. Although the cycling features were an advantage for the unit’s operating regime, additional modifications and procedural changes were required to improve equipment reliability.

Also, the decades-long practice in cycling has increased the owner’s tolerance for rates of forced outages that are higher than those that are typical for plants required for baseload.

The ability of other coal-fired power plant operators to repli-cate CGS’s flexibility will be instrumental in valuing coal in an increasingly low-carbon energy system. Although the CGS unit has certain inherent design features that assist in its operating mode, retrofits and operational modifications to other coal-fired power plants can allow for increased flexible generation across many power systems. Coal-fired power plants can cycle, and if designed and operated appropriately, can provide flexibility, sometimes more significantly than even CGS. There is a cost to cycle and also increased risk of unavailability, but this is true for other types of generation as well.

NOTES

A. For commercial reasons the CGS is not further identified.

ACKNOWLEDGMENTS

This publication was produced under direction of the 21st Century Power Partnership by the National Renewable Energy Laboratory (NREL) under Interagency Agreement DE-AC36-08GO28308 and Task Nos. WFH1.2010 and 2940.5017.

REFERENCES

1. Cochran, A., Lew, D., & Kumar, N. (2013). Flexible coal: Evolution from baseload to peaking plant, NREL Report No. BR-6A20-60575. Golden, CO: National Renewable Energy Laboratory. www.nrel.gov/docs/fy14osti/60575.pdf

2. Vuorinen, A. (2007). Planning of power system reserves, www.optimalpowersystems.com/stuff/planning_of_power_system_reserves.pdf

3. Electric Power Research Institute. (2001). Damage to power plants due to cycling. Product ID 1001507. Palo Alto, CA: EPRI. www.epri.com/abstracts/Pages/ProductAbstract.aspx?ProductId=000000000001001507

4. Babcock & Wilcox. (1994). Economizer inlet header cracking. www.babcock.com/library/pdf/PSB-22.pdf

5. Kumar, N., Besuner, P., Lefton, S., Agan, D., & Hilleman, D. (2012). Power plant cycling costs. NREL/SR-5500-55433. Work performed by Intertek-APTECH, Sunnyvale, California. Golden, CO: NREL. www.nrel.gov/docs/fy12osti/55433.pdf

6. Lew, D., et al. (2013). The Western Wind and Solar Integration Study Phase 2. NREL/TP-5500-55588. Golden, CO: National Renewable Energy Laboratory. www.nrel.gov/docs/fy13osti/55588.pdf

The authors can be reached at [email protected], [email protected], and [email protected]

FIGURE 3. CGS has a horizontal, not pendant, boiler design, which facilitates drainage needed to reduce corrosion fatigue and allow the plant to come online faster. The pendant design more easily allows water accumulation. (Graphic: Steve Lefton, Intertek)

Pendant Design

Gas Flow

Horizontal Design

Gas Flow

46


By Nigel BeanChair of Applied Mathematics,

School of Mathematics, University of Adelaide

Josephine VarneyPh.D. Candidate, University of Adelaide

The recent push to reduce carbon emissions from the electricity sector encompasses common, immediately available approaches such as increasing power plant

efficiency and increasing the deployment of renewables. The opportunity now exists to accomplish these goals simultane-ously through the use of geothermal energy to increase the power output, and decrease the carbon intensity, of thermal power plants. This technology is referred to here as geothermal assisted power generation (GAPG). Basically, GAPG employs hot geothermal fluid to heat the boiler feedwater at a thermal power plant. The steam that would otherwise be taken from the turbines to heat the feedwater is allowed to run through the turbines, thereby generating extra power and increasing plant efficiency. Here we use efficiency to mean “fossil fuel efficiency”, as more power is generated per unit heat (MMBtu) of fossil fuel, because of the addition of the geothermal heat.

Not only would this technology increase the efficiency of exist-ing thermal power plants, most of which are coal fired, it would also assist the development of the immature technology of

utilizing unconventional geothermal resources. As coal-fired power plants rarely exist near conventional (hydrothermal, volcanogenic) geothermal resources, some have drawn the incorrect conclusion that GAPG is of little value or can only be applied in rare cases. However, the development of uncon-ventional (nonhydrothermal, nonvolcanogenic) geothermal resources offers the potential for geothermal energy to be exploited over a much larger geographic range. Therefore, we believe that GAPG should be strongly considered as a means for integrating conventional energy with renewable energy in the most efficient manner possible.

UNCONVENTIONAL GEOTHERMAL RESOURCES

Geothermal energy has been defined as “utilizable heat from the earth”.1 Given that the earth’s temperature increases with depth below the surface, geothermal energy exists everywhere. Further, since it is possible to use geothermal energy to gener-ate power, it has the potential to be a renewable, carbon-free source of baseload electricity. However, while geothermal energy exists everywhere, the cost of extracting this energy does not make it commercially viable everywhere. To be com-mercially viable a geothermal resource must have sufficient temperature and flowrate that can be accessed relatively simply.

Conventional geothermal resources—characterized by depths of <3000 m, high temperature, and highly permeable rock formations—are generally commercially viable, depending on the regional energy market (see Figure 1). Such resources are usually found in volcanic regions, but the last 40 years have seen growing activity in research and development of the unconventional geothermal resources that exist outside the volcanic regions. To date, only one of these resources, at Landau in Germany, has been shown to be commercially viable. However, given the significant promise of the uncon-ventional geothermal resource, work to develop it continues.

Geothermal Assisted Power Generation for Thermal Power Plants

“Up to three times as much power

can be generated per kilogram of

geothermal fluid as can be achieved

in a stand-alone geothermal plant.”

Steam rises as a result of the excess heat of a standalone geothermal plant. GAPG would use geothermal heat more efficiently.


The first step is to find geothermal resources with sufficient temperature and at a depth that can be drilled economically. Unconventional geothermal resources with the potential to be used for electricity generation are divided into two types: deep natural reservoirs (DNRs) and enhanced geothermal systems (EGSs).1 DNRs are systems that make use of deep, naturally occurring aquifers with high permeability. EGS resources have little natural permeability, hence these resources must have their permeability increased via stimulation or fracturing.

The most significant unknown in unconventional geothermal systems is the flowrate per well (or well pair). Unconventional geothermal resources are chosen for their heat and their potential permeability. The degree of permeability of a resource is directly linked to its flowrate. However, when there is insufficient natural flowrate, a reservoir’s permeability can be increased by fracturing. Stimulation technology in a geothermal context is immature, producing “good results some of the time”.1 However, stimulation technology has provided huge productivity improvements in oil and gas wells, so there is hope that similar results will be possible in unconventional geothermal wells. Still, there must be sufficient unconventional

geothermal developments to allow stimulation trials/demon-strations to support the development of this technology.

In the near term, the development of unconventional geo-thermal resources holds significant financial risks, which are largely based on specific geological formations and the need for stimulation. Such risks must be mitigated in some way; from this perspective, GAPG is a major opportunity. Figure 1 shows a simplified means of extracting geothermal energy. Note that actual geothermal developments have many wells, as each producing well can only produce a limited amount of flow. This means that the flow from any geothermal resource increases in a stepwise manner, with each new producing well drilled.

UNDERSTANDING GAPG THROUGH MODELING

GAPG is based on the concept of using high-temperature geothermal fluid to heat the boiler feedwater of a thermal power plant. It was first suggested by Khalifa et al. in 19782 as a replacement for low-pressure feedwater heaters (FWHs). In 2002, Bruhn built on Khalifa’s design,3 making it significantly

HOT VOLCANICS

Underground Water Reservoir

VOLCANIC

POWER

INSULATINGSEDIMENTS

HEAT FROM CENTEROF EARTH

ENHANCED GEOTHERMAL SYSTEMS

POWER

INSULATINGSEDIMENTS

HEAT FROM CENTEROF EARTH

Underground Water Reservoir

SEDIMENTARY

POWER

INSULATINGSEDIMENTS

SANDSTONES OR CARBONATES FRACTURES ENHANCED BY STIMULATION

HOT ROCKSHYDROTHERMAL

VOLCANIC

FIGURE 1. Schematic of geothermal resources

48

more flexible by allowing GAPG to partially replace any of the low-pressure FWHs. After considering the low-temperature geothermal resources most often available near thermal power plants, in 2010, Buchta focused on very low-temper-ature geothermal fluids (30–100°C) and considered applying GAPG to only the first low-pressure FWH.4

Of course, geothermal energy is not the only renewable energy source that can be applied to increasing the efficiency of thermal power plants. Hu et al. investigated both geothermal and solar thermal sources for efficiency gains5 and found that the higher temperatures achievable from solar power makes it possible to consider applying heat to the intermediate- and high-pressure FWHs. Then, more recently, Varney and Bean determined the net-power gain for all feasible geothermal flowrates and, fur-ther, discussed the flowrate and power limits of GAPG.6

Focused research over many years has generally found that GAPG can be retrofitted to any large thermal power station, although the economics are site-specific. It can be used to fully or partially replace the low-, intermediate-, or high-pres-sure FWHs; however, it is most likely to be used to replace only the low-pressure FWHs. Depending on the needs of the indi-vidual plant, GAPG can increase the power generated (power boosting mode) or it can be run to reduce the amount of fos-sil fuel consumed (fuel saving mode). The simplest and most flexible implementation was described by Bruhn and is shown in Figure 2.3 In Bruhn’s implementation of GAPG, feedwater is withdrawn upstream of the first low-pressure FWH and is then heated by the geothermal fluid in the geothermal feed-water heater (GFWH). The geothermally heated feedwater is then returned to the feedwater stream via flows ṁG1, ṁG2, ṁG3,

and/or ṁG4 (depending on the temperature and flowrate of the geothermal fluid).

Given that geothermal fluids are not clean enough to mix with feedwater, GAPG can only be used to replace closed feed-water heaters (i.e., not the deaerator). In order to cool the extra steam coming through the turbine(s), additional con-denser capacity is required, which could be managed by the installation of a new, small condenser.

RESULTS

In our modeling, we retrofitted GAPG to a 500-MW natural-gas-fired, supercritical steam power station, specifically, the Public Service Company of Oklahoma, Riverside Station Unit 1. Although we modeled a gas-fired plant, the analysis could have been applied to a coal-fired power plant and would yield the same results.

One major advantage of GAPG is it’s flexibility: Power can be generated from low geothermal fluid flowrates that otherwise might be of little value in a stand-alone geothermal facility. As these flowrates increase, power generation increases. For example, see Figure 3 which shows the incremental electricity generated as the flowrate of the geothermal fluid is increased. Note that three different temperatures were evaluated (i.e., 150, 175, and 200°C).

Using geothermal heat to boost the efficiency of a thermal power plant increases thermal efficiency above stand-alone geo-thermal plants by 1.7 to 2.9 times, depending on the geothermal

FIGURE 2. Schematic of GAPG

G1 G2 G3 G4 ṁ4ṁ3ṁ2ṁ1

GTh_H

GTh_CSteam take-offs fromlow pressure turbine

Units: FWH - Feedwater heaters,GFHW - Geothermal feedwater heaterStates: F’s, G’s, b’s Flows: ṁ’s, ṅ’sSteam: Condensate: Geothermal Fluid:

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fluid temperature.6 However, there is a limit to the amount of geothermal energy that can be utilized through GAPG at any given thermal power plant—once the appropriate FWHs are totally replaced by geothermal feedwater heaters, no further additional power can be produced. To achieve this maximum power limit, a geothermal resource temperature greater than the outlet of the hottest appropriate FWH (in our modeling the hottest low-pressure FWH was ~160°C) is needed (see Figure 4a). As the geothermal resource temperature increases above ~160°C, the flowrate required to reach this maximum power limit decreases (see Figure 4b). At temperatures less than ~160°C, the maximum power limit cannot be achieved, irrespective of the flowrate (see Figure 4a). Our modeling showed that power could be increased by a maximum of ~6.5% in the modeled 500-MW supercritical plant. To achieve maximum power, a geothermal fluid flowrate of 190–290 kg/s was needed, with lower flow-rates for the higher geothermal fluid temperatures and higher flowrates for the lower geothermal fluid temperatures. Despite this maximum power limit, considering the reduced risk to the geothermal developer and the power producer, it is still likely to be worthwhile to take advantage of GAPG.

UNDERSTANDING THE IMPLICATIONS

Coal-Fired Power Generators

GAPG allows coal-fired power plants to generate more power and reduce their carbon intensity through increased efficiency. Once a geothermal developer brings hot geothermal fluid to the surface, GAPG yields very little risk for the power plant owner. The revenue that can be generated by extra power production will be recognized by the plant operators, as will the capital costs of installing the necessary geothermal feed-water heat exchangers, additional condenser capacity, and extra piping. Hence, power plant operators can decide what they are willing to pay for the hot geothermal fluid in order to make sufficient profits—a site-specific consideration. Finally, if the geothermal fluid stops flowing, for any reason, the power plant can revert to its original operating conditions.

Geothermal Developers

Unquestionably, greater deployment of GAPG has major impli-cations for geothermal developers. GAPG allows them to focus on what they do best, getting hot geothermal fluid from the ground to the surface, and does not require the expertise or capital to produce and sell electricity. Further, the power plant is able to generate up to three times as much power per kilogram of geothermal fluid as a stand-alone geothermal power plant.6 Importantly, GAPG allows the developer to sell whatever hot fluid they are able to get to the surface. This means that they can take small steps—generate some revenue while learning more about the local geothermal resource and enhancing their capa-bility. Later, the flowrate could be increased to further increase the amount of heat provided to the thermal power plant.

COSTS

Looking at the equipment required for a GAPG development, drilling costs clearly are the largest and most significant por-tion of the overall capital cost. Of course, drilling costs vary significantly with geology and local drilling market conditions. For example, it is estimated that, on average, a 1.5-km deep well in the U.S. will cost $2.9 million and a 5-km well will cost

0

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0 50 100 150 200 250 300

Extr

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FIGURE 3. Geothermal fluid flowrate versus power generation

1

2

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50

$10.5 million. However, in Australia, which has a small num-ber of local drilling rigs and had to mobilize some rigs from the U.S., the expected cost for similar wells is $6.6 million and $15.3 million (all estimates are given in U.S. 2014 dollars).1

Further, it is difficult to estimate how many wells are required, because flowrate per well is the other significant unknown in unconventional geothermal developments. The highest flowrate from an unconventional geothermal well has been observed at a site in Landau, Germany, which has a flowrate of 70 kg/s. However, the next highest flowrate per well was recorded at Habanero 1 in Australia, which achieved a maxi-mum flowrate of 40 kg/s. For these reasons, an average cost for a GAPG development cannot accurately be provided. Additionally, as mentioned earlier, stimulation technology, which can potentially increase flowrate, is currently far from certain. Therefore, predicting the total costs to produce a given flowrate at a particular site is currently highly uncertain. However, with knowledge gained through further deployment of GAPG (or other forms of exploration in unconventional geo-thermal resources) this uncertainty can be reduced.

Although accurate costings cannot be provided, it is fair to say that, in general, unconventional geothermal developments (without the integration offered by GAPG) are not commer-cially viable yet. Based on drilling costs from the U.S., it is estimated that flowrates in the vicinity of 80–100 kg/s per well are required for commercial viability.1 However, it is clear that GAPG provides up to three times more power than stand-alone unconventional geothermal developments. As much as geothermal energy development is driven by local markets, including renewable portfolio standards, it is important that GAPG be recognized as a renewable energy even though it is integrated with existing thermal power plants.

Although the economics of GAPG will be uncertain until the technology is deployed, it is certain that GAPG is more eco-nomical than stand-alone geothermal plants. In addition, as greater experience and improved technology make lower drilling costs and higher flowrates possible, unconventional geothermal developments used for GAPG will become an ideal first step toward making unconventional geothermal energy commercially viable on a broad scale—to the future benefit of both geothermal energy developers and the energy consumers who currently rely on electricity from thermal power plants.

LOOKING FORWARD

Unconventional geothermal energy is a relatively immature technology, with high capital costs and large risks, but also

with enormous potential. Geothermal energy is one of the few renewable energies capable of providing baseload power; further, the size of the unconventional resource is potentially “truly vast”.1 For unconventional geothermal energy to prog-ress it must take small steps and GAPG offers one such step.

Additional opportunities may exist for the application of geo-thermal energy at conventional power plants in the future. For instance, low-temperature geothermal fluids are characterized by temperatures in the range of the regeneration tempera-tures of post-combustion amine-based CO2 capture systems. When commercial CCS comes online, GAPG could provide the thermal load needed for CCS, thus allowing the power plant efficiency loss from CCS to be dramatically reduced.

GAPG allows unconventional geothermal developers to con-centrate on the geothermal resource, not power conversion. Accordingly, power conversion can be carried out by expert thermal power plant operators, and up to three times as much power can be generated per kilogram of geothermal fluid as can be achieved in a stand-alone geothermal plant. GAPG offers power plant operators a way to increase power produc-tion and decrease their carbon footprint at essentially no risk. GAPG is potentially a win-win option for both the geothermal developer and the power plant operator.

REFERENCES

1. Australian Renewable Energy Agency. (2014). Looking forward: Barriers, risks and rewards of the Australian Geothermal Sector to 2020 and 2030. Canberra: Commonwealth of Australia.

2. Khalifa. H.E., DiPippo, R., & Kestin, J. (1978). Geothermal preheating in fossil-fired steam power plants. Proceedings of the 13th Intersociety Energy Conversion Engineering Conference, San Diego, California.

3. Bruhn, M. (2002). Hybrid geothermal–fossil electricity generation from low enthalpy geothermal resources: geothermal feedwater preheating in conventional power plants. Energy, 27, 329–346.

4. Buchta J., & Wawszczak, A. (2010). Economical and ecological aspects of renewable energy generation in coal fired power plant supported with geothermal heat. Paper presented at the Fourth IEEE Electrical Power and Energy Conference, 25–27 August, Halifax, Nova Scotia, Canada.

5. Hu, E., Nathan, G.J., Battye, D., Perignon, G., & Nishimura, A. (2010). An efficient method to generate power from low to medium temperature solar and geothermal resources. Paper presented at Chemeca 2010: Engineering at the Edge, 26–29 September, Adelaide, South Australia.

6. Varney, J., & Bean, N. (2013). Using geothermal energy to preheat feedwater in a traditional steam power plant. Proceedings of the 38th Workshop on Geothermal Reservoir Engineering, Stanford University, Stanford, California.




By Han JianguoDeputy General Manager, Shenhua Group Co., Ltd

President, China Shenhua Energy Co., Ltd

Digital mines are based on the innovative application of well-established, advanced information technologies to the areas of geological resource exploration, mine

design and construction, safe and efficient production, operations, and decision-making. Digital mining allows for all aspects of mining to be evaluated simultaneously using digitized displays. The digital mine system can respond to, pro-cess, and utilize data to enable integration of different mining processes so as to achieve unified, centralized management of mining operations. Digital mining incorporates modern mining operations characterized by increased safety, reduced environmental impact, intelligence, and high efficiency.1 In China, Shenhua Group (Shenhua) has led the development and deployment of digital mines. The demonstration of China’s first digital mine successfully came online in the Jinjie Coal Mine of Shenhua’s Shendong Coal Group, Co., Ltd on 27 December 2013, representing a major milestone for Shenhua and China.

THE IMPETUS FOR DIGITAL MINES IN CHINA

China’s government made it clear that the coal industry should increase efforts during the 12th Five-Year Plan period (2011–2015) to develop and deploy an innovative coal system, founded on science and technology, that addresses the needs of coal-producing enterprises, is market oriented, and is based on collaboration between industry, universities, and other research institutions. This transformation in mining is further

supported by recent policies on safer coal production, energy conservation, and emissions reduction.

As the primary source of China’s energy and a raw material for many industries, coal is pivotal to the nation’s economic development. However, coal mining is a complicated opera-tion, often carried out deep underground with many potential risks. These risks can be difficult to detect and even more so to predict. Among other reasons, advanced mining systems, such as those incorporated into digital mines, are important because they can significantly reduce accidents.2

Recently, mining technologies in China have been improved in significant ways: from the use of fully mechanized mining to the application of large, automated equipment, information tech-nologies, and artificial intelligence. Taking advantage of these modern technologies has propelled the development of China’s coal industry—and digital mines are a necessary next step.3

Today, China’s coal industry is facing the reality of a market characterized by slowing demand growth, decreased profits for many coal enterprises, and related problems such as overstaffing, low efficiency, poor safety records, and poor man-agement. These issues are restricting the healthy and steady development of coal enterprises. Thus, digital mines and the associated technologies are needed now more than ever.

ARCHITECTURE AND THE MAJOR COMPONENTS OF A DIGITAL MINE

Shenhua’s digital mine was developed taking into consideration the actual needs of coal producers (both underground and open-pit) in China. Three key challenges had to be addressed: mining information acquisition, transmission, and processing.

Shenhua’s Development of Digital Mines

“Digital mining incorporates modern

mining operations characterized

by increased safety, reduced

environmental impact, intelligence,

and high efficiency.”

The ability to monitor operations from a central location is a key component of the digital mine at Jinjie.

52


Digital Mine Architecture

Shenhua’s digital mine consists of a five-level structure of information standards (i.e., equipment, controls, production execution, operation management, and decision support), which fully incorporate information-based corporate decision-making as well as information-based production management and automated production processes. The complete architec-ture of the digital mine is shown in Figure 1.

The architecture of Shenhua digital mines includes the com-ponents listed in Table 1.

Centralized Platform Design

Two platforms have been developed for Shenhua’s digital mines—the centralized production-monitoring platform and the production execution platform. Within these platforms are 68 subsystems. Data can be freely transferred among these platforms and subsystems.

The centralized production-monitoring platform is primarily used to integrate data and to control the onsite surveillance system and monitoring system; the production execution plat-form mainly provides support to the subsystems of production

and management for data exchanges between production management and control.

The interacting network for underground coal mines is shown in Figure 2. As shown in the figure, information can be exchanged and shared through a network. An interface

TABLE 1. Major components in Shenhua’s digital mine

Digital Mine Area Components Included

Infrastructure Data center, network, admin communication system, dispatching display, and a video-conference system

Centralized Production Monitoring System

Monitoring system: Fully mechanized coal mining face, heading face, hoisting system, main transport, subsidiary transport, power distribution, water supply and sewage, ventilation, coal washery, truck loading, gas extraction, nitrogen injection, grouting, fire control sprinkling, refrigeration and cooling, air compression, boilers, and outsourcing coal monitoringSurveillance system: Safety surveillance and monitoring, personnel and vehicle tracking and positioning, industrial television, communication dispatch, early warning of gas and coal outburst, beam tubes, dust, hydrogeology, roof pressure, microseism of ground pressure, wastewater treatment, waste rock discharge in production, gas inspector patrolling, and an unattended intelligent lamp room system

Production Execution System

Production execution platform, with a 3D exhibition subsystem, production management subsystem, dispatch management subsystem, electromechanical management subsystem, “one ventilation and three prevention” management, safety management subsystem, coal quality management subsystem, design management subsystem, energy conservation and environmental protection management subsystem, central data analysis subsystem, etc.

Operation Management System

Management of planning and overall budget, enterprise resource planning (ERP), supplier relation, customer relation, strategic resource (SRM), costing, system, intrinsic safety, office automation, auditing, science and technology, energy conservation and emission reduction, archives, references, statistics, administration and logistics, coal production supervision, etc.

Decision Support System Operation performance management and enterprise decision support

FIGURE 1. The integrated application architecture of digital mines

L5Decision

support level• Opera�ons

performance management• Enterprise supporton decision-making

L3 Produc�on execu�on level

L4 Opera�on management level

• Centralized intelligent and integrated produc�on management systemL2 Controls level

• Centralized produc�on monitoring and control systemL1 Equipment level

• Smart controllers • Smart instruments • Base sta�ons • Smart cameras

• Enterprise resource planning (ERP)• Strategic resource management (SRM)• Strategic resource management system• Coal produc�on and produc�on control

• Synergized dispatching system of produc�on,transporta�on, and sale


meeting international standards is provided at the network and serial port levels, so that all subsystems can be connected and various software and hardware can be integrated, making the systems connected and interconnected.

Architecture of the IT Infrastructure

The architecture of the IT infrastructure of Shenhua’s digi-tal mines can be divided into three layers, from the lowest upward: network, mine machine room, and the application terminals (see Figure 3).

MAJOR INNOVATIONS FROM SHENHUA’S DEMONSTRATION OF THE DIGITAL MINE

The Jinjie demonstration of Shenhua’s digital mine had several successful aspects. For instance, a software platform for coal mine monitoring was developed after analysis and assessment in the Jinjie demonstration mine. Through use of this system, comprehensive monitoring and multifunctional operation of

the coal mine and operation management through a single display was achieved.

Aided by this coal mine monitoring software platform, the demonstration digital mine operators were able to transition from a conventional top-down management model to more efficient, data-based control of mining, excavating, machining, transporting, and circulating. The use of this software platform changed the dispatch room into a 24-hour command post, accomplishing full data sharing, intelligent linkage, and auto-matic control for mining, excavating, mechanical operating, transportation, and circulating systems by enabling control room operators to have full access to data throughout the mine as well as control of automated equipment and commu-nication with the personnel outside the control room.4

Another important accomplishment during the Jinjie demon-stration related to the GIS-based automated mining model, which allows the memory-based shear cutting of the coal-face to be controlled remotely from the surface. Models and parameters for the slicing and control of the coal cutter were

FIGURE 2. The interacting network for digital mines: underground coal mines

Enterprise service bus (ESB)

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54


based on the geological drilling and the actual data (e.g., min-ing height and fluctuation) of the working face. This system allowed for coal to be cut automatically and the slicing path to be recorded. The system was able to receive input through either the sensors or human intervention. No matter the source, the system recorded any interventions and incorpo-rated that information into subsequent slicing parameters (i.e., a self-correcting model). This process repeated itself automatically, and this technology has been applied to five other fully automated mining faces in Shenhua Shendong Co. on a trial basis.

One notable achievement of the Jinjie demonstration mine related to the transportation of coal on a conveyor whose speed was regulated using laser-based measurements in an intelligent closed loop. The laser-based detection device mon-itors the amount of coal on the belt: When an increase in the quantity of coal was detected, the conveyor sped up imme-diately. This system led to energy savings and more efficient production.

The Jinjie demonstration mine used a 10-GB Ethernet (10-giga) underground high-speed transmission network, allowing the integration of a few sub-networks and allowing real-time transmission of mass data from multiple sources. In addition, a wireless portable hand-held terminal was successfully devel-oped and used to monitor the real-time situations at mobile locations. This underground network was able to satisfy the need to access and transmit 57,000 measured sources of data as compared with the conventional 15,000 measured data points. The transmission network is shown in Figure 4.

By using wireless internet technologies such as 3G, Wi-Fi, and radio frequency underground, users achieved automated data collection in real time using mobile terminals such as cellphones, tablets, and point inspectors, leading to under-ground paperless records to ensure timely and accurate data collection.

IMPACTS AND ACHIEVEMENTS

The Jinjie demonstration of Shenhua’s digital mine provided a large amount of information covering all underground systems, environments, and equipment. This cache of infor-mation helped achieve the complete, accurate, real-time, and automatic collection of data. Based on this, the overall digital mines program established a big data-based production command system, which revolutionized how commands and controls are executed. For example, equipment is controlled by a remote computer rather than by a person. Additionally, controls are now centralized rather than decentralized as was the case in the past.

The construction and application of Shenhua’s digital mines program has been applied at the following sites (in addition to Jinjie): Da Liuta, Yu Jiaoliang, Shi Yitai, Shangwan, Bu Lianta, Baode, Wulan Mulun, Ha Lagou, Cun Caota, Liuta, Jinfengcun Caota, No. 1 mine at Wanli, and Bu Ertai. These 14 applications are reporting substantial, positive impacts to operations, the most important of which are described below.

Increased efficiency and downsized payrolls: The shift from direct onsite control to indirect remote control can reduce the operation personnel underground. For example, a change to centralized control can reduce the underground workforce by 52 production workers. This represents a cost savings of RMB9.2 million (US$1.49 million) and 190,700 labor hours.

Refined production management and reduced equipment downtime: Data sharing within the information systems makes it possible for the equipment and system to operate only as needed. Therefore, minimizing the ineffective operation time of the equipment and maximizing production efficiency can be achieved. Take the main transport belts, for example. It is estimated that the variable speed control technologies can increase the utilization of the underground electromechani-cal equipment by 2%. This translates into a reduced power consumption of 25% and a cost savings of about RMB500,000 (US$80,883) on each belt per year.

Improved productivity, enhanced recovery of resources, and increased utilization of equipment: With the implementa-tion of the digital mines program, energy usage is reduced. Equipment abrasion is also reduced. The output of each coal-face is increased by about 10% and excavation of this mining face is extended by more than 12%. The efficiency of the workforce can be increased by about 16% and the utilization of the equipment by about 5%. In the last three years, coal output increased by 15.09 million tonnes and sales increased by RMB7.873 billion (US$1.285 billion) in the Jinjie, Da Liuta, and Yu Jiaoliang mines alone after they implemented the digi-tal mines approach.

Applica�on terminals

Machineroomfor themines

Datacenter of themining area

Dispatchingdisplay system

System so�ware System so�ware

Servers Servers

BackupsBackups

Opera�ng system

Resource supply management

ViGap

ViGap ViGap

StorageStorage

Network pla�orm

Automa�on network

Informa�on network

Wireless network

Safety facili�es

Virtualiza�on

Administra�vecommunica�on system Video-conference Etc.

FIGURE 3. IT infrastructure architecture of the Jinjie coal mine


Enhanced safety: With the safety management system, acci-dent prevention and control has replaced reactive approaches to safety. The artificial intelligence-based early warning sys-tem has significantly improved the safety-related data and considerably improved the safety of mining operations.

A newly formed GIS-based true three-dimensional emergency rescue system linking the underground with the surface has been created: Potential problems in operation can be remotely moni-tored and diagnosed. Experts can propose effective solutions and provide technical support directly online through consultation.

CONCLUSIONS

The rapid development and mutual integration of IT and automation technology have rejuvenated organizational man-agement, production and decision-making, and technology and production scales of China’s coal industry. The construc-tion and successful operation of Shenhua’s digital mines

program is strategically significant for the industry. It will fur-ther improve production efficiency, reduce costs, and enhance core competiveness for mining. It serves as a cornerstone to the construction of a modern, safe production management system for the coal industry, leading to a modernized coal industry with a highly technical foundation, profitable opera-tions, low energy consumption, reduced pollution, increased safety, and efficient utilization of personnel.

REFERENCES

1. Han, J.G., Yang, H.H., Wang, J.S., & Pan, T. (2012). Research of construction of digital mine of Shenhua Group. Industry and Mine Automation, 2012, 38(3), 11–14. (In Chinese)

2. Lu, X.M., & Yin, H. (2010). Definition, connotations and progress of digital mine. Coal Science and Technology, 38(1), 48–52. (In Chinese)

3. Wu, L.X. (2000). The digital earth, digital China and digital mine. Mine Surveying, 1, 6–9. (In Chinese)

4. Wang, J.S., & Pan, T. (2014). Practical exploration on construction of digital mine. Industry and Mine Automation, 40(3), 32–35. (In Chinese)

10-giga surface switch

Shendong’s C & C08 Switch

10-giga underground switch

10-giga surface switch

10-giga underground switch

10GE backbone circuited network

Substa�on tree and ring networking

Substa�on chain-shaped networking

Explosion-proof camera

FE electrical ports / FE op�cal portFE op�cal port

FE op�cal port

FE op�cal port

Industrial control PLC Locator card

Industrial control PLC

Broadcast terminal

Cellphones

Base sta�on antenna

SMA

Broadcast terminal

10-giga underground switch 10-giga underground switchF

h

ch Central substa�on Central substa�on

Central substa�on

Central substa�onCentral substa�onCentralsubsta�on

Central substa�on

Central substa�on

C

Telecommunica�on network

3G clock server

Base sta�on controller3G core network of Shendong site

FIGURE 4. Transmission network architecture of the mine at Jinjie

56

By Christopher MunningsSenior Research Scientist, CSIRO Energy Flagship

Sarbjit GiddeySenior Research Scientist, CSIRO Energy Flagship

Sukhvinder BadwalCSIRO Fellow, CSIRO Energy Flagship

Energy, particularly electrical power, is one of the most critical components of any modern industrial economy with most economies being based on low-cost abundant

energy supplies. In this regard, coal continues to be the pri-mary energy source of choice for electrical power generation. Coal can be stored easily and converted into electrical power on demand regardless of season or local weather conditions. However, conventional coal-fired power generation can result in high emissions of CO2 and other pollutants. These can be captured or neutralized; however, in some cases this can greatly increase cost.

New coal-based power generation technologies currently being demonstrated and deployed, such as oxy-combustion, supercritical or ultra-supercritical coal-fired power plants, vari-ous gasification technologies, and direct injection coal engines, can lead to incremental or dramatic reductions in emissions. Such technologies are critical as the world progresses to

low-emission power generation. However, further improve-ments to conversion efficiency and emission reductions remain highly desirable. Direct carbon fuel cells (DCFCs) are an emerg-ing technology that has the potential to almost double electric efficiency (i.e., to 65–70%) and halve greenhouse emissions compared with conventional coal-based power plants. Rather than burning coal, these fuel cells electrochemically oxidize it; thus their efficiency is not Carnot cycle limited. (See Figure 1 for a comparison of the efficiency of different coal-to-elec-tricity options.) Furthermore, DCFCs produce two separate exhaust streams, one that is essentially oxygen-depleted air and the second being a concentrated stream of CO2. Thus the energy penalty for CO2 capture is significantly lower (almost zero) compared to post-combustion capture. DCFCs are at an early stage of development, but a number of groups have recently become involved in the development of this tech-nology leading to a range of novel systems and concepts being investigated. In this article we provide a broad overview of the technology. More comprehensive technical information on various systems can be accessed in References 1–3.

WHY FUEL CELLS ARE MORE EFFICIENT THAN COMBUSTION

Fuel cells convert fuels to electricity via electrochemical oxi-dation of fuel, rather than via combustion, to generate heat and pressure that is then converted into electricity through a heat engine, such as a steam or gas turbine. In conventional fuel cells, gaseous (CO, H2, CH4) or liquid (methanol, ethanol) fuels are converted into electrical power. DCFCs operate via the same broad principle; however, the solid high-carbon fuel (such as coal) is consumed to produce electrical power through reactions (1) and (2), respectively occurring at the cathode and anode electrodes of the cell. The two electrodes are kept

Direct Carbon Fuel Cells: An Ultra-Low Emission Technology for Power Generation

FIGURE 1. Average efficiency of coal-based power generation technologies Notes: Brown Coal ST = brown coal steam turbine; Black Coal ST = black coal steam turbine; SC ST = supercritical steam turbine; USC ST = ultra-supercrit-ical steam turbine; IGCC = integrated gasification and combined cycle (gas turbine); DICE = direct injection coal engine; DCFC = direct carbon fuel cell

“Direct carbon fuel cells are an

emerging technology that has the

potential to almost double electric

efficiency and halve greenhouse

emissions…”

0

10

20

30

40

50

60

70

BrownCoal ST

BlackCoal ST

SC ST USC ST IGCC DICE DCFCNet

Pow

er P

lant

Effi

cien

cy (%

)TECHNOLOGY FRONTIERS


separated by an oxygen ion-conducting ceramic membrane (four types of direct carbon fuel cells are shown in Figure 2).

Cathode: O2 + 4e- → 2O2- (1)

Anode: C + 2O2- → CO2 + 4e- (2)

The fuel is housed on the anode side of the membrane with air being used as the oxidant on the cathode side. The oxygen molecules become ionized [reaction (1)], and the oxygen ions flow across the membrane and react with the fuel to produce CO2 [reaction (2)]. The electrons released via this process move through an external load generating an electrical cur-rent. Fuel cells operate similarly to a battery; however, unlike a battery, the fuel cell is continuously “charged” as the fuel is replaced at the anode as it is consumed.

Electrochemical oxidation of fuels to produce electricity is highly efficient because fuel cells contain few moving parts and do not rely on pressure or temperature gradients to operate (again, not Carnot cycle limited). The efficiency of a fuel cell system is defined by four factors: system losses, fuel utilization, electrochemical losses, and the thermodynamic (theoretical) efficiency of the system. The system losses are typically a minor component (approximately 10%) and are largely similar for most high-temperature fuel cells. Solid fuels (such as coal) can be easily separated from the gaseous products (i.e., CO2 in the exhaust) leading to nearly 100% fuel utilization compared to 80–95% for conventional gaseous fuel cells. Electrochemical losses are caused by slow reaction kinet-ics at the electrode/electrolyte interface and transport of ions through electrodes and the electrolyte. These losses are sig-nificantly reduced by operating at high temperature but are still greater for carbon than for conventional gaseous fuels. The thermodynamic efficiency of a DCFC is largely indepen-dent of temperature, and theoretically 100% of the chemical energy in the fuel is available for conversion to electricity. Taking the typical losses into account, practical efficiencies for

coal to electricity of around 65–70% are considered attain-able with the remainder of the energy being lost as waste heat.1 If the waste heat can be utilized (for instance, for coal drying or pyrolysis) then overall efficiencies in the region of 80–90% could be achieved. This is higher than attainable with a gaseous fuel; for comparison, leading MW-scale molten carbonate (FuelCell Energy) and solid oxide fuel cells (SOFC) (Bloom Energy), operating on natural gas, have an electrical efficiency of around 47% and 52%, respectively.

FUEL CELL DESIGNS: KEY CHALLENGES AND TECHNICAL MERITS

DCFC technology is at an early stage of development, with many organizations focusing on the fundamental aspects of the technology.1,3 In general, the key challenge is to strike a balance between cost, performance, and lifetime.

At the core of each proposed fuel cell system is the cell design, which determines all other features. The four most commonly suggested fuel cell designs that can use solid fuels are shown in Figure 2 and compared in Table 1.

The main difference between each of these systems, and com-pared with other conventional fuel cells, is the fuel electrode (anode) and the fuel delivery system. Modifying the fuel elec-trode allows a greater area for the reactions to occur between

Reaction zoneElectrolyte

Anode Cathode

e-e-

e-e-

MO

M

Molten metal

O2 (air)C or CO

CO2

CO2

Molten salt

O2 (air)C or CO

CO2

O2-O2-

Gasification

O2 (air)

CO2

CO

C

Solid state reaction

O2

C or CO

CO2

O2-

O2-CO3

2-

FIGURE 2. Pictorial representation of different DCFC designs under consideration globally

“Solid fuels ... can be easily

separated from the gaseous

products ... leading to nearly

100% fuel utilization...”

58

TABLE 1. Comparison of four common direct carbon fuel cell designs

Descriptor Molten metal Molten carbonate/hybrid with solid oxide* Gasification Solid state

Design principles

“Metal shuffle” mechanism:

Metal is oxidized at the surface of the solid electrolyte.

The metal oxide mixes with molten metal then contacts the fuel.

The fuel reduces the oxide back to metal.

In the molten carbonate system, the molten electrolyte is held between porous electrodes.

In the hybrid system, the electrolyte is a solid oxide with the molten carbonate only in the fuel chamber.

In both cases, fuel mixes with molten carbonate which supplies oxygen to the reaction sites via movement of carbonate ions.

The fuel can be gasified within the anode chamber or gasified externally, then cleaned and fed to a conventional high-temperature solid oxide or molten carbonate fuel cell.

External gasification leads to lower efficiency. Internal gasification requires novel anode materials not used in conventional fuel cells.

Both systems can use porous electrodes.

The anode is a mixed ionic electronic conducting (MIEC) material.

The MIEC material supplies oxide ions and removes electrons, allowing the entire anode surface to be used for fuel oxidation reactions.

Advantages

Potentially simple fuel feed system

Fast fuel oxidation reaction

Could use a wide range of fuels

High tolerance to sulfur impurities

Fuel is fed continuously to the electrode/electrolyte interface.

Could use a wide range of solid fuels

Has the highest electrical efficiency of any technology

Conventional solid oxide or molten carbonate fuel cell can be used.

Waste heat can be used to produce gasification products (CO and H2) to increase system efficiency.

Can consume both solid and gaseous fuels

Solid anode material avoids corrosion and containment issues of molten systems.

Less complex than gasification systems and allows kW-scale deployment before scale-up

Disadvan-tages

Very low tolerance to ash

Tested mainly with high-purity non-solid fuels, e.g., heavy oils, natural gas

Low cell operating voltages reduce efficiency

Short cell life

Difficult to stop the reaction between the molten carbonate and other cell materials

Molten carbonate can speed up the formation of carbon monoxide (CO), which is lost to the exhaust, reducing overall efficiency

Large, expensive plant needed to integrate all components (e.g., gasifier, hot gas cleanup, high-temperature fuel cell, gas turbine, etc.).

Comparably low efficiencies if waste heat from fuel cells is not used for gasification.

Difficult to deliver solid fuel to reaction sites

Slow reaction kinetics for fuel oxidation reaction

Potential electric efficiency

~30%1 up to 80%1 35–58%1,3 65–70%1

*Various other molten salts and mixtures of molten salts have been trialed, including sodium and potassium hydroxides with consumable carbon anodes.1



the solid fuel and the electrode/electrolyte interface. Having a larger reaction area means that more electrons can be pro-duced, and therefore more electrical power can be generated. Conventional fuel cells have porous electrodes, which allow gas to penetrate and react over a large area. As this is not pos-sible with a solid fuel, alternative fuel electrode designs are needed to increase the area available for reaction.

FUEL REQUIREMENTS

The fuel requirements are yet to be fully determined, with only limited studies investigating the effect of impurities and fuel composition on the overall fuel cell performance. There are no defined specifications for an ideal fuel; however, fuel proper-ties which could potentially improve the performance of the fuel cell include high electrical conductivity, low crystallinity, small particle size, friable particles, high surface area, and low ash. DCFCs are less sensitive to other fuel properties that are critical for combustion, such as moisture and thermal content.2

In terms of reactivity with fuel impurities, systems with molten components generally will have significantly more stringent fuel requirements as even small levels (less than 1%) of ash will accumulate within the anode chamber and react with the molten metal or carbonate components, leading to solidification of some components and rapid degradation in cell performance.

If gasification is to be used in conjunction with conventional fuel cells, then ash can be removed during gasification; how-ever, gas cleanup to remove particulates, sulfur, mercury, and phosphorous-based impurities would still be required. If these impurities can be reduced or eliminated via coal cleaning or careful selection of fuel, then it is likely to significantly reduce the overall capital cost of the final gasification DCFC installation.

The direct contact solid state designs fall in-between the exter-nal gasification fuel cell systems and systems with molten components and are more resilient to impurities than conven-tional SOFCs or fuel cells containing molten components. This is because the MIEC anodes are typically a solid ceramic mate-rial, which is far more resistant to chemical attack or poisoning and thus will tolerate a greater level of impurities and ash than molten systems. High levels of ash will still be detrimental to the performance of the fuel cell and will be more difficult to remove from a fuel cell system than a gasifier. Thus ash content of the fuel may need to be reduced by fuel pre-processing prior to its use in a direct-contact solid-state fuel cell. Although high ash contents are generally considered detrimental, not all ash constituents have a negative impact on cell performance: Some impurities contribute to improvement in cell performance. This was well demonstrated by Rady et al., who showed that the presence of brown coal ash led to a 25% increase in power output of the fuel cell.

FUEL CELL POWER PLANTS

One key advantage of high-temperature fuel cells is the greater availability of the waste heat from the system. This, combined with the low-pressure operation and the modular nature of fuel cells, allows far greater flexibility in design of fuel cell plants and leads to greater integration possibilities. Figure 3 provides a schematic overview of an envisaged DCFC power generation module operated on coal. Depending on the tech-nology chosen, 10–30% of the fuels’ energy may be available as high-grade heat (600–800oC) that could be used for fuel drying or pyrolysis, used within a low-pressure steam turbine, or used for the production of syngas. In this way the DCFC can be seen both as a coal-based power production technology and as a key enabler for the production of high-value-added products for export from abundant low-grade fuels, such as Victorian brown coal. Furthermore, since the waste stream from a DCFC is pure CO2, this whole process could conceivably have a very small carbon footprint if CCS is employed. Further reductions in CO2 emission could be realized if waste biomass sources are mixed with conventional fossil fuel carbon sources.

CURRENT STATUS AND FUTURE PROSPECTS FOR COAL-FUELED DCFCS

In general, grid-connected fuel cells are becoming a reality—with a number of commercial systems now available in several markets ranging in size from a few hundred watts to larger scale units in the MW range. All of these systems operate on gaseous fuels. These fuel cell systems offer some benefits in terms of emissions, efficiency, and flexibility of scale, but are essentially an incremental step when compared to advanced combined-cycle gas turbines. DCFCs are, by comparison, in their infancy, but offer a step increase in efficiency over

The 59-MW fuel cell park, South Korea, is indicative of the scale of a direct carbon fuel cell facility (photo courtesy of FuelCell Energy).

60

traditional and emerging solid fuel combustion technologies with the added advantages of low greenhouse gas emissions and the low cost and energy requirements for CCS. This implies the fate of DCFCs is largely dependent on developments in the global energy market. If there is a drive to maintain and grow power production from solid fuels, particularly low-grade solid fuels, DCFC is likely to become a very attractive future tech-nology that could offer a 10–50% increase in efficiency over conventional power generation technologies, that is compat-ible with carbon capture and storage, and that is adaptable in terms of scale of deployment.

ACKNOWLEDGMENTS

The authors acknowledge the support of Brown Coal Innovation Australia (BCIA) for this work and Dr. Aniruddha Kulkarni for the internal review of this document prior to publication.

Coal pre-treatment & pulverization

CO2

recy

cle

Oxygen depleted air

Pure CO2 for sequestration

Ash & other by-products

Air

800oC Fuel cell stack

Thermal output

Material flow

Thermal flowGas flow

FIGURE 3. A schematic of an envisaged DCFC power generation module operated on coal

REFERENCES

1. Giddey, S., Badwal, S.P.S., Kulkarni, A., & Munnings, C. (2012). A comprehensive review of direct carbon fuel cell technology. Progress in Energy and Combustion Science, 38, 360–399.

2. Rady, A.C., Giddey, S., Badwal, S.P.S., Ladewig, B.P., & Bhattacharya, S. (2012). Review of fuels for direct carbon fuel cells. Energy & Fuels, 26, 1471–1488.

3. Gur, T.M. (2013). Critical review of carbon conversion in “carbon fuel cells”. Chemical Reviews, 113, 6179–6206.

4. Giddey, S., Badwal, S.P.S., Kulkarni, A., & Munnings, C. (2014). Performance evaluation of a tubular direct carbon fuel cell operating in a packed bed of carbon. Energy, 68, 538–547.

5. Rady, A.C., Giddey, S., Badwal, S.P.S., Ladewig, B.P., & Bhattacharya, S. (2014). Direct carbon fuel cell operation on brown coal. Applied Energy, 120, 56–64.

The lead author can be reached at [email protected]



By Zheng ChuguangProfessor, State Key Laboratory of Coal Combustion,

Huazhong University of Science and TechnologyDirector, Advanced Coal Technology Consortium,

Clean Energy Research Center

Oxy-fuel technology is characterized by the use of pure oxygen or oxygen-enriched gas mixtures to replace air during combustion of (most often) fossil fuels. After

the fuel is burned, flue gas with a high concentration of CO2 is generated, which facilitates the capture of CO2. First pro-posed by Abraham in 1982, the purpose of the technology was to produce CO2 for enhanced oil recovery (CO2-EOR).1 As concerns related to climate change have intensified, the need to control CO2 emissions (as the principal greenhouse gas) has also gradually increased in prominence. As a technology option with great potential for reducing CO2 emissions, oxy-fuel combustion has become a focus of research worldwide.2

THE STATUS OF INTERNATIONAL OXY-FUEL TECHNOLOGY DEVELOPMENT

Figure 1 shows the development status and capacity of oxy-fuel projects at various research institutions; projects range in scope from laboratory scale to commercial applications. Some projects began as early as the 1980s. The principal research

institutions and companies advancing oxy-fuel technolo-gies include the following: Energy & Environmental Research Center, Argonne National Labs (ANL), Babcock & Wilcox (B&W), Air Products, and Jupiter Oxygen in the U.S.; IHI and Hitachi in Japan; Canmet in Canada; International Flame Research Foundation in the Netherlands; BHP Billiton, Newcastle University, and CS Energy in Australia; CIUDEN in Spain; Alstom in France; Doosan Babcock in the UK; and Vattenfall in Germany. Extensive research, development, and demonstrations are also occurring in China (shown in red in Figure 1), which are discussed in detail in later sections.

Pilot-Scale Demonstrations

Since 2005, oxy-fuel pilot projects have significantly advanced the overall technology. Table 1 lists the pilot projects at the tens of MWe scale that are under construction or have been completed. These include the world’s first 10-MWe oxy-fuel comprehensive process test installation, built by Sweden’s Vattenfall in 2008 in Schwarze Pumpe, Germany. The world’s first 30-MWe oxy-fuel pilot power plant, which also boasted the world’s largest capacity, was completed by Australia’s CS Energy in 2011 in Callide. The 7-MWe oxy-fuel pulverized coal boiler and world’s first 10-MWe oxygen-enriched fluidized bed pilot were completed at CIUDEN’s Technology Development Center in 2012 in Spain. In China, the first 12-MWe oxy-fuel power installation will be completed by the end of 2014.

Large-Scale Demonstrations

Table 2 lists the large-scale oxy-fuel pilot projects being con-ducted globally. In 2003, the U.S. government announced plans to construct a zero-emission plant based on coal gasifica-tion; the project was named FutureGen. After more than seven

Exploring the Status of Oxy-fuel Technology Globally and in China

FIGURE 1. Status of international oxy-fuel project research.3

(Projects conducted in China are shown in red.)

1980 1990 2000 2010 20200.1

1

10

100

1000

FutureGen 168

ENEL 320Shenmu 200

HUST 12

Alstom 1.0HUST 1

Whiterose 426

Endosa 300

Youngdong 100

TOTAL(NG) 10

Callide A 30Vattenfall 10

Renfrew 30Pearl Plant 22

Oxy-coal 13.3

CIUDEN 6.7CIUDEN 10

OHIO 10

B&W 10Jupiter 6.7

JSIM/NEDO(Oil) 4.0

International Comb 11.7

ENEL 1.0

RWE-NPOWER 0.2

PowerGen 0.3

IVD-Stuttgart 0.2

B&W/AL 0.4IHI 0.4

CANMET 0.1

IFRF 1.0

ANL/BHP 0.2

Cap

acity

(MW

e)

Year placed into operation

ANL/EERC 1.0

HUST 0.1

Lab- and pilot-scale (≤1 MWe)Pilot- and demonstration-scale (without CCS)Demonstration-scale (with CCS)

“Following 30 years of development,

oxy-fuel technology has matured

and possesses the fundamental

characteristics necessary for

commercial application.”

62


years, the direction of this project changed. In August 2010, the U.S. Department of Energy launched FutureGen 2.0, which was based on carbon capture from oxy-fuel coal combustion. US$1 billion (the total budget for the project is now $1.3 billion) was allocated for the construction of a 200-MWe (now adjusted to 168-MWe) commercial-scale oxy-fuel power station. The objec-tive is to obtain 90% carbon capture and remove most of the pollutants, including SOx, NOx, Hg, and particulate matter.

The UK power company Drax also announced its White Rose commercial-scale 426-MWe oxy-fuel carbon capture dem-onstration project. The Yorkshire-based project obtained official support from the UK’s Department of Energy & Climate Change in December 2013. A front-end engineering design (FEED) study is currently being conducted.

South Korea is also actively making progress on an oxygen-enriched coal-fired power station demonstration project—the country plans to build a 100-MWe pilot power station by 2015.

In China, several large-scale oxy-fuel projects are currently conducting pre-feasibility or feasibility studies, including the Shenhua Group’s 200-MWe Shenmu power plant, Sunlight Coking’s 350-MWe thermoelectric pilot, China Datang Corporation’s 350-MWe Daqing power plant, and Xinjiang Guanghui Energy’s 170-MWe pilot.

Among the aforementioned industrial-scale installations, a number of key components necessary for the oxy-fuel process have been verified. For instance, major power equip-ment manufacturers such as Alstom, IHI, Doosan Babcock,

TABLE 1. Completed and planned oxy-fuel pilot projects

Name (Location) MWeNew or Retrofit

Construction Began

MainFuel

Electricity Generated

CO2 Capture CCUS CO2

Purity Flue Gas

Purification

Vattenfall (Germany) 10 New 2008 Coal No Yes Yes 99.9% SCR, ESP

Callide (Australia) 30 Retrofit 2010 Coal Yes Yes No FF

Total (France) 10 Retrofit 2009 NG Yes Yes Yes 99.9% FGD

CIUDEN (Spain) 10 New 2010 Coal Yes Yes No SCR, FF

CIUDEN (Spain) 7 New 2010 Coal Yes Yes No SCR, FF

Jamestown/Praxair (U.S.) 50 New 2013 Coal No No

Jupiter Pearl Power Station (U.S.) 22 Retrofit 2009 Coal No No

Babcock & Wilcox (U.S.) 10 Retrofit 2008 Coal No No 70%* SCR, FF

Doosan Babcock (UK) 13 New 2008 Coal No No

HUST (China) 12 New 2011 Coal No Phase 2 Phase 2 80%

Notes: SCR = selective catalytic reducer; ESP = electrostatic precipitator; FF = fabric filter; FGD = flue gas desulfurization; NG = natural gas*Post-drying

Table 2. Large-scale oxy-fuel projects

Country Project Owner/ Power Plant Scale and Parameters Technology

SourceProgress and Planned

Construction Start Time

UK Drax PowerWhite Rose

426 MWe

Ultra-supercriticalAlstom,

Air Products Entering Phase 2, feasibility study

U.S. FutureGen 2.0Ameren and FGA

168 MWe

SubcriticalB&W, NETL, Foster Wheeler,

Air LiquideEntering Phase 2,

feasibility study underway

South Korea Young Dong 100 MWe Doosan Babcock Pre-feasibility study completed;

applying for permit


Hitachi, and B&W have completed evaluation tests on single 10-MWe oxy-fuel swirl burners that can be used in large-scale demonstrations. Alstom has completed verification tests on a 15-MWth oxy-fuel tangential combustion system. Foster Wheeler has completed semi-industrial verification of a 10-MWe oxy-fuel CFB. Gas separation equipment suppliers Air Products, Linde, and Air Liquide have completed evaluation tests of compression/purification systems at the 10–30-MWth level. The success of these tests has laid the foundation for further large-scale projects.

THE CURRENT STATUS OF OXY-FUEL TECHNOLOGY IN CHINA

The foundation for Chinese oxy-fuel combustion research began in the mid-1990s. Huazhong University of Science and Technology (HUST) and Southeast University were the first institutions to focus on the desulfurization mechanisms and combustion properties of oxy-fuel combustion.4 In 2006, HUST obtained the support of the first National High Technology Research and Development Program for carbon emissions re-duction and the first National Key Basic Research Development

Program for carbon emissions reduction, and launched a com-prehensive national system for the research, development, and demonstration of oxy-fuel-based CO2 capture. Table 3 lists the major fundamental oxy-fuel combustion research projects sup-ported by the Chinese government and industry.5

HUST has already carried out much research and development work on basic oxy-fuel combustion, technology development, and pilot projects, which has largely driven oxy-fuel combus-tion technology development in China. Based on progress to date, HUST has developed a roadmap for oxy-fuel technology development in China (see Figure 2).

Laboratory- and Small-Scale Tests

Table 4 provides an overview of the oxy-fuel combustion small test systems (>10 kWth) that China has built or plans to build. Overall, there are two main approaches to oxy-fuel coal combustion (pulverized coal combustion and fluidized bed combustion). To support the development of the overall technology and key components, there has been significant oxy-fuel-related research activity and platform constructions.2

TABLE 3. Overview of fundamental oxy-fuel combustion research projects in China

Project Type Project Focus Organization(s) Dates

National Key Basic Research Development Program

Resource utilization and storage with CO2-EOR HUST, et al. 2006–2010

National Key Basic Research Development Program

Combustion principles and separation technologies for low-cost CO2

HUST, et al. 2011–2015

National High Technology Research and

Development Program

CO2 emission reduction with synergistic pollutant removal for coal combustion HUST 2005–2008

National High Technology Research and

Development Program

O2/CO2 cycle combustion equipment and system optimization HUST, et al. 2009–2011

National Science and Technology Support Program

Key technology and equipment R&D and for 35-MW oxy-fuel carbon capture HUST, DBC, SASE 2011–2014

National Natural Science Fund Key Project

New concepts and methods for CO2 enrichment through oxy-fuel combustion HUST 2011–2014

National Special Project for International Scientific and Technological Cooperation

U.S.-Chinese advanced coal technology cooperation HUST, Tsinghua University, et al. 2012–2014

National Special Project for International Scientific and Technological Cooperation

Cooperative research on large-scale carbon capture and storage

HUST, Institute of Rock and Soil Mechanics, CAS 2011–2013

Shenhua Group major science and technology project

Megatonne coal-fired carbon capture demonstration HUST 2012–2014

Notes: DBC = Dongfang Boiler Group Co., Ltd; SASE = Sichuan Air Separation Equipment Co., Ltd; CAS = Chinese Academy of Sciences

64


In 2006, HUST completed China’s first 300-kWth-test bed for oxy-fuel combustion and pollutant removal, achieving the objective of enriching high concentrations of CO2 (95%) and removing 85% of NOx and 90% of SO2.

In 2011, HUST completed construction of China’s first 3-MWth oxy-fuel whole process test platform in Wuhan (see Figure 3). This platform is currently China’s largest capacity oxy-fuel test platform, with a heat input of 3 MWth and an annual CO2 cap-ture capacity of up to 7000 tonnes. This system first separates oxygen from air, then enriches, compresses, and purifies the CO2 generated during combustion. Thus the testing platform incorporates the comprehensive oxy-fuel combustion process. The system was designed in accordance with industry stan-dards, and therefore possesses the capacity for deployment at increased scale. A number of key technological breakthroughs were achieved during the design, construction, and commis-sioning of the system.

Integrating the advantages and features of a circulating flu-idized bed, Southeast University has conducted systematic studies of CFB oxy-fuel technology.6,7 A CFB oxy-fuel pilot test installation (50 kWth) was constructed, which was the first in China to genuinely achieve flue gas recirculation and the first internationally to be able to achieve wet flue gas circulation. The 2.5-MWth circulating fluidized bed oxy-fuel test system that Southeast University has built in partnership with B&W has been fully constructed and is currently being commissioned.

Industrial Pilots

In May 2011, HUST launched an industrial 12-MWe oxy-fuel pilot project (see Figure 4). The construction of this project was financially supported by China’s Ministry of Science and Technology, Dongfang Boiler Group Co., Ltd. (DBC), Sichuan

Air Separation Equipment Co., Ltd., and Jiuda (Yingcheng) Salt Co., Ltd. The project involved rebuilding a 12-MWe oxy-fuel boiler in the salt company’s power plant. The system uses a swirl combustion system positioned on the front wall and is equipped with a cryogenic air separation system. The design of the boiler and system is compatible with oxy-fuel combus-tion. Evaluation tests can be conducted on air combustion as well as dry and wet circulation oxy-fuel combustion. After con-struction is complete, the pilot is expected to achieve a flue gas CO2 concentration higher than 80% and a CO2 capture rate greater than 90% at a CO2 capture capacity of 100,000 tonnes/year. The captured CO2 can be stored in the mine shafts of the disused salt mine. In addition, some of the CO2 can also be used in the removal of calcium and magnesium during the salt manufacturing process. The project and its commissioning are expected to be completed by the end of 2014. CO2 capture, utilization, and storage (CCUS) will be incorporated during the second phase.

FIGURE 3. 3-MWth oxy-fuel comprehensive process test system (HUST)

FIGURE 2. Roadmap for research and development of oxy-fuel technology in China4

2015–2020

Fundamentalstudy

300 kWth PC pilotBurner development,

data collection, optimization,and thermal design

3 MWth PC pilot7000 tonnes CO2/yr

full chain validation ASU-CPUcoupling FGC and drying

40 MWth plantCommercial-scaleburner, long-term

operation

200–600 MWe≥Million tonnes/yr

CO2-EOR

2013201120051995 2008 2012

50 kWthOxy-CFB pilot

2.5 MWth CFBoxyfuel boiler

In-bed head exchanger

35 MWth plant0.1 million tonnes CO2/yr capture

ASU-CPU-power generationintegration and optimization

2014


Demonstration-Scale Projects

Chinese companies are also actively preparing to launch large-scale oxy-fuel technology demonstration projects. Table 5 provides an overview of such projects.

In March 2012, Shenhua Group announced a project to integrate oxy-fuel combustion and carbon capture at the megatonne scale into a coal-fired power plant. To date more than 70 million RMB (US$11.5 million) has been invested. This

project aims to provide design and technology safeguards for the independent design, construction, and operation of megatonne-scale oxy-fuel projects. HUST, Dongfang Boiler Group Co., Ltd., and Southwest Electric Power Design Institute took part in the research for this project, which was officially launched in November 2012. To date, the project has involved comparing various options for new build and retrofit, techni-cal and economic evaluations, and preliminary research into key equipment such as boilers, burners, and smoke coolers.

Shanxi International Energy Group Ltd. (SIEG) has also announced a cooperative agreement with Air Products, under which Air Products’ exclusive oxy-fuel CO2 purification tech-nology will be applied to SIEG’s 350-MWe oxy-fuel power generation demonstration project. Currently a feasibility study and the conceptual design of the installation are being com-pleted. This project is based at SIEG’s power plant in Taiyuan, Shanxi and will be used to provide purified CO2 emissions for utilization and storage.

On 21 September 2011, China Datang Corporation signed a memorandum of understanding with France’s Alstom, form-ing a long-term strategic partnership to jointly develop CCS pilot projects in China. Under the memorandum, Alstom and China Datang Corporation will collaborate to develop two coal-fired power plant CCS demonstration projects. Of these, the 350-MWe coal-fired power plant located in Daqing will use Alstom’s oxy-fuel technology. A feasibility study is currently being carried out.

FIGURE 4. Picture of 12-MWe semi-industrial oxy-fuel pilot installation (HUST)

TABLE 4. Overview of China’s oxy-fuel combustion small test systems (>10 kWth)

Organization Thermal Power (MWth) Furnace Type, Fuel Completion Year

HUST 0.3 Vertical pulverized, coal 2006HUST 3 Front wall pulverized, coal 2011

Tsinghua University 0.025 Vertical one-dimensional pulverized coal furnace 2008

Zhejiang University 0.020 Fluidized bed, no flue gas circulation, coal 2004Zhejiang University 2 Pulverized coal furnace 2010North China Electric

Power University 0.025 Pressurized bubbling bed, coal 2011

Southeast University 0.050 Fluidized bed, coal 2011Southeast University 2.5 Fluidized bed, coal 2014

Institute of Engineering Thermophysics, Chinese

Academy of Sciences0.100 Fluidized bed, coal 2013

Institute of Engineering Thermophysics, Chinese

Academy of Sciences1 Fluidized bed, coal and semi-coke Under construction

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Xinjiang Guanghui New Energy Co., Ltd. has signed a strategic cooperation agreement with the U.S.-based Jupiter Oxygen Corporation for a carbon capture, energy conservation, and emissions reduction project. Jupiter plans to invest US$200 million in collaborating with Xinjiang Guanghui New Energy Co., Ltd. to build and develop a carbon capture and boiler retrofit project. Through this technical cooperation, Xinjiang Guanghui New Energy is expected to be able to reduce CO2 emissions by about 2.4 million tonnes yearly at its plant that produces 1.2 million tonnes of methanol and 800,000 tonnes of dimethyl ether plant each year.

OUTLOOK

Following 30 years of development, oxy-fuel technology has matured and possesses the fundamental characteristics neces-sary for commercial application. Importantly, it is suitable for existing coal-fired power plants. For China’s coal power-domi-nated energy mix to achieve greenhouse gas emission reduction targets, large-scale demonstrations must be launched as soon as possible, to allow for the greatest likelihood for the com-mercialization of oxy-fuel. At present, China has announced a succession of special CCUS plans. A number of ministries, includ-ing the National Development and Reform Commission, Ministry of Science and Technology, National Energy Administration, Ministry of Environmental Protection, and Ministry of Land and Resources, are promoting numerous strategies, including

demonstration projects, technology research and development, environmental monitoring, storage uses, policies and regula-tions, and international cooperation.

REFERENCES

1. Abraham, B.M. (1982). Coal-oxygen process provides CO2 for enhanced oil recovery. Oil and Gas Journal, 80(11), 68–75.

2. Buhre, B.J.P., Elliott, L.K., Sheng, C.D., Gupta, R.P., & Wall, T.F. (2005). Oxy-fuel combustion technology for coal-fired power generation. Progress in Energy and Combustion Science, 31(4), 283–307.

3. Wall, T., Stanger, R., & Santos, S. (2011). Demonstrations of coal-fired oxy-fuel technology for carbon capture and storage and issues with commercial deployment. International Journal of Greenhouse Gas Control, 5(S1), S5–S15.

4. Zheng, C., Zhao, Y., & Guo, X. (2014). The research and development of oxy-fuel technology in China. Proceedings of the Chinese Society for Electrical Engineering, 34(23), 3856–3864. (In Chinese)

5. Social Development Science and Technology Division, Ministry of Science and Technology of the People’s Republic of China, et al. (2011). Technology development report on carbon capture, utilization and storage (CCUS) in China. (In Chinese)

6. Duan, L.B., Zhao, C.S., Zhou, W., Qu, C.R., & Chen, X.P. (2011). O2/CO2 coal combustion characteristics in a 50 kW(th) circulating fluidized bed. International Journal of Greenhouse Gas Control, 5, 770–776.

7. Zhou, W., Zhao, C.S., Duan, L.B., Liu, D.Y., & Chen, X.P. (2011). CFD modeling of oxy-coal combustion in circulating fluidized bed. International Journal of Greenhouse Gas Control, 5, 1489–1497.

TABLE 5. Demonstration-scale oxy-fuel pilot projects in China

Project Owner/ Power Plant

Scale and Parameters Technology Source Progress and Planned

Construction Start Time

Shenhua GroupShenmu power plant

200 MWe

High voltage HUST, DBC Pre-feasibility study completed; feasibility study currently underway

China Datang CorporationDaqing power plant

350 MWe

Supercritical Alstom Pre-feasibility study completed;construction start date yet to be decided

Shanxi International Energy Group Ltd.Taiyuan Yangguang Thermoelectric

350 MWe

Supercritical B&W, AP Pre-feasibility study completed; construction start date yet to be decided

Xinjiang Guanghui New Energy 170 MWe

High voltage Jupiter Pre-feasibility study underway



GLOBAL NEWS

Movers & Shakers

Mitsubishi Corporation announced the opening of the Caval Ridge Coal Mine in Queensland, Australia. Run by BHP Billiton Mitsubishi Alliance (BMA), Caval Ridge is a new open-cut mine located in the northern Bowen Basin in Cen-tral Queensland that has the capacity to produce 5.5 million tonnes per year of high-quality metallurgical coal for a mine life of about 60 years.

The board of the Rio Tinto Group has extended the tenure of Chief Executive Sam Walsh and Chief Financial Officer Chris Lynch, providing a strong endorsement of their leadership, the Group’s strategy, and its focus on driving shareholder value.

International Outlook

Australia

With the passage of the Emissions Reduction Fund, the Australian government has taken a step toward meeting its greenhouse gas emissions reduction goal of 5% below 2000 levels by 2020. The Emissions Reduction Fund is the center-piece of the Direct Action plan, which replaced the Carbon Pricing Mechanism repealed in mid-2014.

Canada

On 2 October 2014, the Boundary Dam CCS project began operation; the plant is the first and only post-combustion cap-ture facility operating at the scale of about one million tonnes CO2 each year. According to the head of the Global Carbon Capture and Storage Institute, Brad Page, “This trailblazing project clearly demonstrates that carbon capture and stor-age (CCS) is possible on a large scale in the power sector. Importantly, the lessons learned at Boundary Dam will help progress CCS projects internationally as a vital technology to meet our climate change challenge.”

China

The Ministry of Finance and the State Administration of Taxa-tion released a statement that, from 1 December 2014, China

will change its approach to the resource tax on coal. The coun-try will now levy a resource tax based not on quantity, but on price, which will replace the previous quantity-based approach. The resource tax rate will be 2–10%; the exact amount will be determined by the provincial governments within the given range. The statement also noted that the resource tax will be reduced by 30% for coal produced from exhausted coal mines, and by 50% for coal displaced from filling mining.

Europe

The European Council (EC) has adopted several energy targets for 2030: reduce greenhouse gas emissions by 40% compared with 1990 levels; obtain 27% of its energy from renewable sources; and cut energy consumption by 27% compared with projected levels. The final text of the agreement includes a flexibility clause stating that the EC will revisit these targets after the UN climate summit in December 2015. The agree-ment also includes provisions to compensate nations like Poland, which relies on coal for around 90% of its energy.

Germany

At risk of missing its greenhouse gas reduction goal of a 40% reduction in emissions by 2020 compared to 1990, Germany is considering options that include further increas-ing efficiency and reducing the amount of coal-fired power generation in the country.

India

India’s Supreme Court canceled at least 214 coal licenses because they had been distributed without competitive bidding. Coal Minister Piyush Goyal said that the country will auction 74 coal-mining licenses to private companies in the next several months.

International

The U.S. and China announced an agreement to curb green-house gas emissions. For its part, the U.S. agreed to reduce emissions by 26–28% compared to 2005 levels. China com-mitted to peak its emissions by 2030 and also to obtain 20% of its energy from non-fossil sources. Under the deal, efforts on low-carbon energy technology development would also be expanded, including continued funding for the U.S.-China Clean Energy Research Center (CERC). In addition, the U.S. and China have committed to equally fund a commercial-scale (about one million tonnes CO2 per year) CCUS project under which about 1.4 million m3 of freshwater would be produced.

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Conference Name Dates (2015) Location Website

13th Annual Coal Markets Conference 3–6 Feb Hilton Singapore,

Singapore www.coalmarketsasia.com/

2015 Australian Coal Operator’s Conference 11–13 Feb Wollongong,

NSW, Australia www.coalconference.net.au/

World CTX 2015 14–17 AprilBeijing and Yinchuan (Ningxia Autonomous

Region), China

www.chinaexhibition.com/Official_Site/11-4609-World_CTX_2014_Conference_for_Natural_Gas,_Liquid_Fuels_and_Petrochemicals_from_Coal,_

Petcoke_and_Biomass.htmlWorld of Coal Ash 4–7 May Nashville, TN, U.S. www.worldofcoalash.org/Seventh International Con-ference on Clean Coal Technologies

17–21 May Kraków, Poland www.cct2015.org/ibis/CCT2015/home

Clearwater Coal Conference 31 May–4 June Clearwater, FL, U.S. www.coaltechnologies.com/

Key Meetings & Conferences

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

There are several Coaltrans conferences globally each year. To learn more, visit www.coaltrans.com/calendar.aspx

GLOBAL NEWS

Meeting Spotlight

As was highlighted in the Autumn 2014 issue of Cornerstone, coal gasification is growing globally, led by coal conversion projects in China. In this meeting spotlight, two conferences related to coal conversion are highlighted. The Gasification Technologies Council Conference recently concluded and the World CTX Conference will be held early in 2015.

Gasification Technologies Council 2014 Conference

The Gasification Technologies Council (GTC) 2014 Con-ference was held 26–29 October in Washington, DC. This conference included many internationally known speak-ers, most of whom were directly involved with advancing gasification projects. With the rapid upsurge in gasifica-tion projects in China in recent years, many presentations focused on specific projects. These projects highlighted the wide range of potential products from coal gasification from olefins to substitute natural gas to power.

Although biomass and waste gasification projects are usually significantly smaller in size, they are able to offer substantial environmental and/or waste remediation ben-efits; quite a few presentations were focused in these areas.

The 2015 annual GTC conference will be held in Colorado Springs, CO, U.S.

World CTX 2015: Focus on Shale Gas Impact on Coal-to-X Development

The World CTX (Coal-to-X) Conference 2015 will be held in Beijing and Ningxia, China. This year, a focus on shale gas will be added to the usual CTX subjects. In the U.S., the growth of shale gas has placed a damper on coal conver-sion projects. Since shale gas development may well spread, understanding the potential impact of shale gas on coal con-version projects is more necessary than ever. The trifecta of considerations related to the environment, economics, and energy security will impede or advance coal conversion in a changing global energy sector; this will be the focus of the next World CTX conference. The conference website and additional information are provided in the table above.


Corrigendum: Volume 2, Issue 3: Page 12: In the figure showing potential uses for gasification “hydrogen for oil refining” was listed twice. The lower term should have been “substitute natural gas”. Page 27: The caption under the AP Image read, “Nabaj Sarif”, but should have read “Nawaz Sharif”.

Recent Select Publications

Mercury Control for Coal-Derived Gas Streams — Wiley-VCH — This newly published textbook covers technologies for the detection, capture, and regulation of mercury evolved from the combustion or gasification of coal. The information in this textbook is largely based on the successful U.S. Department of Energy Mercury Program and includes contributions from an internation-ally acclaimed group of experts, edited by Evan J. Granite, Henry W. Pennline, and Constance Senior. More informa-tion is available at www.wiley.com/WileyCDA/W i l e y T i t l e / p r o ductCd-3527329498.html

World Energy Outlook 2014 — International Energy Agency — For the first time, the IEA’s WEO will make projec-tions to 2040 throughout the energy sector. Other specific topics covered in WEO 2014 include a look at whether oil output from North America can reduce fluctuations amid abundance, the potential effects of expanding global LNG, the effect of efficiency on regional energy pri-ces, how energy can improve life in sub-Saharan Africa, and much more. WEO 2014 is available for purchase from www.iea.org/w/bookshop/477-World_Energy_Outlook_2014

From the WCA

Looking Into the Future for Coal

The World Coal Association (WCA) and Assocarboni jointly held a workshop in Rome on 18 November, bringing together global energy and environment leaders to discuss the future global role of coal, practical action that can be taken to reduce emissions, and the energy challenges facing policymakers in Europe.

The workshop “Looking into the Future for Coal” featured presentations from representatives from the Australian, Indonesian, and Italian governments. A keynote speech was given by the UNFCCC COP President Marcin Korolec, Poland’s State Secretary for the Environment, responsible for Climate Policy.

The workshop built on the WCA’s Warsaw Communi-qué, developed with the Polish Ministry of Economy and launched alongside COP19 in November 2013. The Commu-niqué outlined practical steps that can be taken to tackle climate change and enable coal to continue to play its vital role as an affordable, abundant, easily accessible source of energy.

Presentations and discussions at the workshop made clear that most people are expecting a deal out of COP21 in Paris in 2015. There was support for the coal industry being an active, constructive stakeholder and for the industry to more fully promote the role of technology in reducing envi-ronmental impacts from coal; this includes high-efficiency, low-emissions (HELE) coal technology and carbon capture, utilization, and storage (CCUS). Participants also agreed that the industry should develop a more compelling narrative about coal, so that the broader community better under-stands the vital role coal plays globally.

Further information is available at www.worldcoal.org

Divestment and the Future Role of Coal

The World Coal Association has published the latest in its series of “Coal Matters” fact sheets. Coal Matters - Divest-ment and the future role of coal looks at divestment campaigns and challenges the arguments being made against the coal industry.

The fact sheet reviews growing energy demand and projec-tions about the future of coal and looks at the role of coal in energy and modern infrastructure. The fact sheet also

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GLOBAL NEWS

shows that markets are already managing any risks associ-ated with fossil fuel investments.

Technology has a huge role to play in reducing environmental impacts from the use of coal. The fact sheet looks at high-efficiency, low-emissions coal technology, carbon capture, utilization, and storage along with actions and investments taken by the coal industry to reduce CO2 emissions.

By definition, divestment requires a change in ownership of assets: Institutes and individuals may sell their shares, but can only do this if other institutes and individuals buy these same shares. In other words, divestment does nothing to affect the demand for or use of fossil fuels.

Divestment campaigns aim to create the very risks they warn of in order to undermine investor confidence and deprive fossil fuel producers of the finance necessary to operate their businesses. However, forecasts show that demand for coal will continue to grow. The priority should therefore be how we access the benefits of coal while mini-mizing environmental impacts. For developing countries in need of energy, divestment campaigns can have serious con-sequences. Divestment will do nothing to address shared global priorities on economic development and reducing GHG emissions and will, instead, hinder efforts to alleviate energy poverty, particularly in developing countries where coal is fueling economic development.

Technology, including efficiency improvements and CCUS, has a vital role to play in ensuring we can meet our future energy and infra-structure needs as cleanly and sustainably as possible. This requires responsible investment decisions and balanced energy policies.

A copy of Coal Matters – Divestment and the future role of coal can be down-loaded from the WCA website: www.worldcoal.org

Meeting of the Minds

On 3 November 2014, the Chairman of the World Coal Association, and Rio Tinto Chief Executive, Energy, Harry Kenyon-Slaney, visited Shenhua Group and met with the Chairman of Shenhua Group, Zhang Yuzhuo. The leaders

discussed the future development of the international coal industry and other related subjects.

Mr. Kenyon-Slaney acknowledged Shenhua Group’s con-tribution to the WCA through the continued support of Cornerstone and the Strategic Research Institute. Later, the WCA Chairman visited the Shenhua Science and Technology Research Institute, the Shendong coal mine, and the Zhun-geer coal mine.

Making Mines Smarter and Safer

Recently Harvard Business Review (HBR) highlighted how smart, connected products are transforming competi-tion and changing industries globally. The mining industry is no different. As part of the study, HBR highlighted how Joy Global, as a leading mining equipment manufacturer, offers the ability to monitor operating conditions, safety parameters, and predict equipment servicing needs in the challenging operating conditions of underground mines. In fact, Joy Global is able to monitor service indicators for fleets of equipment in different mines—even if the equip-ment is spread across multiple countries. For the full case study, visit hbr.org/2014/11/strategic-choices-in-building-the-smart-connected-mine/ar/1


LETTERS

VOLUME 2, ISSUE 2

AN ANALYSIS OF THE INTERDEPENDENCE BETWEEN CHINA’S ECONOMY AND COAL

The authors of this article analyzed the contribution of coal to China’s economy based on several metrics. Much-needed proof was provided regarding the value

coal can provide. China has become the world’s second larg-est economy, continuing to grow at full steam, and is also the largest coal producer and consumer. The country’s economic growth and its reliance on coal are not unrelated as coal has contributed tremendously to China’s development. This arti-cle provides an understanding as to why developing countries continue to rely on coal as a leading energy source. Those that undermine the value of the coal industry may do well to con-sider the information presented in this article.

After an analysis of the correlation between historical eco-nomic data and coal production and consumption, the authors calculated a positive correlation coefficient. The core of their analysis was the coal-dependence index that they defined using four indices, which ultimately explained the interde-pendency of coal and China’s GDP. As we know, coal provides more than 70% of total primary energy consumption and more than 70% of total power output in China. The authors demon-strated how coal is an irreplaceable energy source that helps ensure energy security, maintain social stability, and promote the development of national and local economies.

From a global perspective, the relationship between coal and economics remains strong. Although the global coal indus-try is facing a downward trend, characterized by lower coal prices, I continue to believe that the perspective of the coal industry should be based on the fact that coal consumption will continue to grow, especially in developing countries. Drawing from the data in this article, I hope that the global coal industry will face the future with optimism and extend its work to realize the cleaner utilization of coal resources for the benefit of all.

Zhang Songfeng Researcher

Academy of Macroeconomic Research National Development and Reform Commission

VOLUME 2, ISSUE 3

A COAL-BASED STRATEGY TO REDUCE EUROPE’S DEPENDENCE ON RUSSIAN ENERGY IMPORTS

With Western Europe facing the apparently intractable problem of its dependency on Russian natural gas imports, it is refreshing to read a rational analysis

that reminds us that an increased use of coal could broaden

the region’s options for energy sources. Through the use of carbon capture and sequestration, as well as other clean coal technologies, Western Europe can simultaneously reduce its dependence on natural gas imports, as well as increase the recovery rate from its North Sea oil reserves, and not increase its greenhouse gas emissions. While not neglecting long-run climate concerns, an increased use of new technolo-gies to utilize the ample and widely available sources of coal would enable Europe to respond to its short-term energy security needs while not burdening its economies with exces-sive energy price increases. There are only a limited number of options for energy, and with energy goals that include a reduced reliance on nuclear power and less dependence on Russian natural gas, the answer to Western Europe’s energy problem clearly involves a greater use of coal.

John Jelacic Independent Energy and Economic Analyst

This article is overly ambitious in its assertions of what is possible regarding bringing online coal-fired power plants that are no longer operating in the EU. One example is

the statement that some plants currently idled, such as those in the UK, could be “brought back online relatively quickly”. In many cases such plants are not actually idled, but completely shut down. In some cases these plants have even been partly or fully demolished. Even for those plants still standing, they could not be simply placed back into service. Their opera-tion would be illegal as many of these plants do not have the required environmental controls to operate legally today. In fact, this article does not take into account EU emission regu-lations, including the Industrial Emissions Directive—this will be enforced as of 2016 and will actually result in the closure of additional plants. Generally, the strategy laid out in this article cannot realistically be followed under the current regulatory environment in the UK and greater EU.

Anonymous

Response: The article was based on a dynamic situation regarding the state of coal-fired power plants in the EU; unfor-tunately, some plants have been idled or demolished since the original research was completed. However, the reader brings up a valuable point that the longer European leaders wait to act, the more difficult it will be to reduce reliance on Russian energy supplies. Thus, the door of opportunity is closing and I suggest there should be an immediate moratorium on demol-ishing any coal-fired power plants in Europe. For instance, in the UK, potential power generation sources such as the 1000-MW Ferrybridge plant or the 350-MW Uskmouth plant must be protected.

The research and the article did take into account the envi-ronmental upgrades that would be necessary to bring idled coal-fired plants back online. For example, I noted on p. 46, “It may be necessary to add more SO2 and NOx controls, and

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perhaps other environmental upgrades, to the units.” While considerable investment may be required, adding environmen-tal controls for criteria emissions include applying completely understood, fully commercial technologies already deployed throughout Europe and the world.

Regarding greenhouse gas emissions, the article showed that CTG with CO2-EOR actually resulted in lower greenhouse gas emissions compared to continuing to rely on the leaky and poorly maintained natural gas pipelines from Russia. As well, there may be additional opportunities to reduce greenhouse gas emissions with CCUS from coal-fired power plants when it

is commercial and supported by CO2 prices in the EU ETS.

Finally, it is important to make clear that the article presented an ambitious strategy to increase the energy security of the EU. There may be some regulations that are not compatible with the strategy, but it is worth weighing the value of a carbon-neutral strategy that improves energy security. Regulations can be modified more easily than global energy reserves.

Roger Bezdek President

Management Information Services, Inc.

TO SUBMIT A LETTER TO THE EDITOR, EMAIL [email protected] OR [email protected] (CHINESE).

We’re in the process of planning the editorial schedule for 2015.

We’d appreciate hearing from you regarding what topics you would like us to cover.

We’re looking for any and all feedback from our readers.

Cornerstone aims to be inclusive to all things related to coal and energy, especially those pieces that are focused on scientifically derived solutions for the challenges associated with ever increasing energy demand. Our goal is to include diverse material, such as interviews, letters, op-ed editorials, technical articles, global news, conference listings, etc. If you are interested in contributing or have suggestions about what we should cover, please don’t hesitate to contact the editorial team.

If you have a suggestion, email the editorial team at [email protected] (English) or [email protected] (Chinese)



Author(s) Title Pages

Volume 2, Issue 1, Spring 2014Michael Hightower Reducing Energy’s Water Footprint: Driving a Sustainable Energy Future 4–8

Diego Rodriguez Thirsty Energy: Integrated Energy-Water Planning for a Sustainable Future 9–11

Holly Krutka Exploring Global Energy Challenges: Exclusive Interview with Nobuo Tanaka 12–14Wang Xianzheng Advancing China’s Coal Industry 15–18Aleksandra Tomczak What to Watch in 2014: Policy Developments That Will Shape the Coal Industry 19–25Tianyi Luo, Betsy Otto, Tien Shiao, Andrew Maddocks Identifying the Global Coal Industry’s Water Risks 26–31

Li Zheng, Pan Lingying, Liu Pei, Ma Linwei Assessing Water Issues in China’s Coal Industry 32–36

Rangan Banerjee Coal-Based Electricity Generation in India 37–42Merched Azzi, Paul Feron Considering Emissions From Amine-Based CO2 Capture Before Deployment 43–46Barbara Carney, Erik Shuster Exploring the Possibilities: The NETL Power Plant Water Program 47–51Sean Bushart Advanced Cooling Technologies for Water Savings at Coal-Fired Power Plants 52–57Anne Carpenter Water-Saving FGD Technologies 58–63Chen Yinbiao, Zhang Jianli Supplying Water to Power Plants with Desalination Technology 64–68Daman Walia, Sahika Yurek Moving Coal Up the Value Chain 69–73Nikki Fisher, Thubendran Naidoo Turning a Liability into an Asset 74–77Okty Damayanti Connecting Indonesian Communities to Clean Water 78–79

Volume 2, Issue 2, Summer 2014Anthony Hodge Shifting the Paradigms of Health and Safety in Mining 4–8Milton Catelin Commitment to Safety 9–10

Gregory H. Boyce Modern Energy: The “Golden Thread” That Connects People, Economies, and Progress 11–14

Zhang Kehui Studying the Dominance of Coal in China’s Energy Mix 15–20Jim Spiers Hedging Carbon 21–24Nicholas Newman Advancing the Alleviation of Energy Poverty 25–29Anil Razdan Energy Poverty in India and What’s Needed to Address It 30–35Nikki Fisher Balancing South Africa’s Energy Poverty and Climate Change Commitments 36–38Aleksandra Tomczak Europe Struggles to Pay Its Energy Bill 39–41

Hao Gui Shenhua Group’s Preemptive Risk Control System: An Effective Approach for Coal Mine Safety Management 42–46

Melanie Stutsel Evaluating Safety and Health in Australia’s Mining Sector 47–52

Bruce Watzman CORESafety®: A System to Overcome the Plateau in U.S. Mine Safety and Health Management 53–56

Aaron Leopold Sustainable Charcoal: A Key Component of Total Energy Access? 57–61Xie Heping, Wu Gang, Liu Hong An Analysis of the Interdependence Between China’s Economy and Coal 62–66Yuan Liang Synergetic Technologies for Coal and Gas Extraction in China 67–71Uichiro Yoshimura, Toshiro Matsuda The Global Need for Clean Coal Technologies and J-COAL’s Roadmap to Get There 72–77

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Author(s) Title Pages

Volume 2, Issue 3, Autumn 2014

Alison Kerester Gasification Can Help Meet the World’s Growing Demand for Cleaner Energy and Products 4–12

Laura Miller The Drivers and Status of the Texas Clean Energy Project 13–18

Kyle Aarons Carbon Pollution Standards for New and Existing Power Plants and Their Impact on Carbon Capture and Storage 19–23

A.M. Shah India Re-energized 24–28Ni Weidou, Song Shizhong, Wang Minghua Developing High-Efficiency, Low-Carbon, Clean Coal in China 29–33

Roger Bezdek A Coal-Based Strategy to Reduce Europe’s Dependence on Russian Energy Imports 34–39

Janet Gellici The Reliability and Resilience of the U.S. Existing Coal Fleet 40–45Harry Morehead, Juergen Battke Improving the Case for Gasification 46–49Rob van den Berg, Zhong-Xin Chen, Sze-Hong Chua

The Shell Coal Gasification Process for Reliable Chemicals, Power, and Liquids Production 50–54

Carrie Lalou Distributed Power With Advanced Clean Coal Gasification Technology 55–60Xu Shisen Moving Forward With the Huaneng GreenGen IGCC Demonstration 61–65Rob Jeffrey, Rosemary Falcon, Andrew Kinghorn The Benefits and Challenges Associated With Coal in South Africa 66–70

Volume 2, Issue 4, Winter 2014Stephen Mills The Energy Frontier of Combining Coal and Renewable Energy Systems 4–10

Frank Clemente The Rise of Electricity: Offering Longevity, Improved Living Standards, and a Healthier Planet 11–16

Patrick Falwell, Brad Crabtree Understanding the National Enhanced Oil Recovery Initiative 17–20Benjamin Sporton Developing Country Needs Are Critical to a Global Climate Agreement 21–24

Hans-Wilhelm Schiffer The Flexibility of German Coal-Fired Power Plants Amid Increased Renewables 25–30

Janne Kärki, Antti Arasto Toward Carbon-Negative Power Plants With Biomass Cofiring and CCS 31–35Christopher Long, Peter Valberg Evolution of Cleaner Solid Fuel Combustion 36–40Jaquelin Cochran, Debra Lew, Nikhil Kumar Making Coal Flexible: Getting From Baseload to Peaking Plant 41–45

Nigel Bean, Josephine Varney Geothermal Assisted Power Generation for Thermal Power Plants 46–50Han Jianguo Shenhua’s Development of Digital Mines 51–55Christopher Munnings, Sarbjit Giddey, Sukhvinder Badwal

Direct Carbon Fuel Cells: An Ultra-Low Emission Technology for Power Generation 56–60

Zheng Chuguang Exploring the Status of Oxy-fuel Technology Globally and in China 61–66

www.worldcoal.org twitter.com/worldcoal www.worldcoal.org/extract

www.facebook.com/worldcoalassociation www.youtube.com/worldcoal

Coal Classification Industry Approach to Hazard Classification under the Revised MARPOL Convention and the IMSBC CodeThe International Maritime Organization (IMO) has introduced new environmental and health classification criteria for internationally shipped solid bulk cargoes under the International Convention for the Prevention of Pollution from Ships (MARPOL) and the International Maritime Solid Bulk Cargoes (IMSBC) Code.

The World Coal Association (WCA), together with

ARCHE - a specialist environmental toxicology

consultancy - has prepared a package of reports to

assist coal companies with complying with the new

environmental and health classification requirements.

The package consists of three reports and a summary

document:

Report 1: New Compliance Requirements of the

MARPOL Convention and the IMSBC Code

Report 2: Analysis of Coal Composition, Ecotoxicity

and Human Health Hazards

Report 3: Coal Classification Guidance

The reports are available free of charge to WCA

Members.

The reports are also available to non-WCA Members to

purchase. If you would like information on purchasing

this package of reports, please email the WCA Team at:

[email protected]

You can also get the reports for free if you join the

WCA. Join today and you can get instant access to

this package of reports, along with all the other

benefits of membership. If you would like to discuss

WCA membership options, please get in touch:

[email protected]

World Coal Association

5th Floor, Heddon House 149-151 Regent Street London W1B 4JD, UK

+44 (0) 207 851 0052

www.worldcoal.org [email protected]

WCA Coal Classification Ad 206w x 273h.indd 3 01/07/2014 14:45

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In many countries, coal and renewable energy systems are being deployed at greater percentages and, thus, there is increased interest in how to optimally integrate these systems. In fact, there are a significant number of opportunities.

CORNERSTONE VOLUME 2 ISSUE 4 THE OFFICIAL ......tries, coal is the only economically available bulk...

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