FUELS – HYDROGEN PRODUCTION | Coal Gasification

FUELS – HYDROGEN PRODUCTION | Coal Gasification

Coal Gasification DAJ Rand, CSIRO Energy Technology, Clayton, VIC, Australia RM Dell, Formerly of Atomic Energy Research Establishment, Harwell, UK & ...

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Coal Gasification DAJ Rand, CSIRO Energy Technology, Clayton, VIC, Australia RM Dell, Formerly of Atomic Energy Research Establishment, Harwell, UK & 2009 Elsevier B.V. All rights reserved.

The Role of Hydrogen as a Fuel There is mounting concern over the sustainability of global energy supplies. Among the key drivers are (1) climate change, ocean surface acidification, and air pollution; these imply the need to control and reduce anthropogenic emissions of greenhouse gases, especially emissions from transportation and thermal power stations; (2) the diminishing reserves of oil and natural gas; (3) the need for energy security adapted to each country, such as decreasing the dependence on fossilfuel imports from regions where there is political or economic instability; (4) the expected growth in world population with an ever-increasing expectation of an improved standard-of-living for all, especially in developing and poor nations. The world population is predicted to grow from 6.7 billion today to 9 billion by around 2050, before leveling off at 9–10 billion. Couple this to the energy aspirations of developing countries and it is clear that the demand for energy, in all its forms, will grow inexorably. Where is this energy to come from, and what will be the impact on the environment? Hydrogen is being promoted worldwide as a panacea for energy problems in that it may eventually replace, or at least greatly reduce, the reliance on fossil fuels, while being itself a clean-burning fuel that releases no greenhouse gases into the atmosphere. Although the most abundant element in the universe – the stuff from which stars are made – hydrogen does not occur freely on earth, but is predominantly found in combination with oxygen as water, and with carbon as fossil fuels. Chemical, thermal or electrical energy has to be expended to extract hydrogen from these sources. Hydrogen is therefore not a new form of primary energy, but a vector (or carrier) for storing and transporting energy from any one of a myriad of sources to where it may be utilized. In this respect, it is analogous to electricity, which is also a secondary form of energy. Hydrogen and electricity are complementary: electricity is used for a multitude of applications for which hydrogen is not suitable, whereas hydrogen, unlike electricity, has the attributes of being both a fuel and an energy store. These two energy vectors are, in principle, inter-convertible; electricity may be used to generate hydrogen by the electrolysis of water, while hydrogen may be converted into electricity by means of a fuel cell.

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Specifically, hydrogen has the following key attributes. It can be derived from fossil and nonfossil sources • (renewable or nuclear energy). It can serve as an alternative fuel for internal com• bustion engines. ideal for use in fuel cells to drive electric modes • ofIt istransportation. It is oxidized cleanly to water with no emissions of • greenhouse gases; when obtained from water using renewable energy, the fuel cycle is closed and no pollutants are released in the overall process. The proposal to use hydrogen as a sustainable medium of energy has come to be known as the ‘Hydrogen Economy’; the overall scheme is illustrated conceptually in Figure 1. The upper part of the diagram is generally referred to as the transitional phase, during which hydrogen is produced from fossil fuels. The lower part relates to the long-term, post fossil-fuel age when hydrogen will be manufactured from renewable energy sources and used as a storage medium and as a super-clean fuel, particularly for certain types of fuel cell that are seen as a key enabling technology. Not unexpectedly, the building of a Hydrogen Economy presents great scientific and technological challenges in production, delivery, storage, conversion, and end-use. In addition, there are many policy, regulatory, economic, financial, investment, environmental, and safety questions to be addressed. The world production of hydrogen is around 45–50 Mt per year. This is used principally in petroleum refining, the synthesis of ammonia (for use in fertilizers) and methanol, vegetable oil hydrogenation, and the reduction of metal oxides. Most of this hydrogen is derived from natural gas by steam reforming; the remainder is obtained principally from oil and coal by partial oxidation processes. In all these processes, the carbon component of the fossil fuel ends up as carbon dioxide, which is a key greenhouse gas and has to be separated from the hydrogen and stored indefinitely if it is not to contribute to climate change. By comparison, the preparation of hydrogen by electrolysis of water at present accounts for only B3% of the world output. The transformation of natural gas and liquid hydrocarbon feedstocks into hydrogen is a straightforward catalytic process, but the route from coal requires an initial step of high-temperature gasification. Coal is a more variable commodity than natural gas as regards its composition, structure, and properties. It is

Fuels – Hydrogen Production | Coal Gasification Primary energy

Hydrogen production

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Hydrogen energy

Fossil fuels Coal Oil Natural gas

Nuclear energy

Gasification Energy input

Steam reforming

Carbon sequestration

Thermochemical

Nuclear fission

Renewable energy Electricity for electrolysis

Hydro Solar photovoltaic Wind Geothermal Solar−thermal

Thermolysis Thermochemical

Hydrogen distribution • pipeline • trucking • rail • marine shipping Hydrogen storage • compressed gas • cryogenic liquid • metal hydrides • complex hydrides • chemical hydrides • chemical carriers • nano materials Hydrogen end-use • fuel cells • engines • industrial processes • rocket fuel

Photo-electrochemical Biomass

Gasification Photo-biochemical Fermentation

Figure 1 A sustainable Hydrogen Economy.

also more difficult to extract and handle. The argument for coal as a feedstock for future hydrogen production lies in the prodigious quantities of hydrogen required for a full Hydrogen Economy – far more than may be available from natural gas – coupled with the widespread occurrence of coal measures and the very substantial reserves that are known to exist. Supplies of natural gas are better conserved for the manufacture of chemicals, and for space heating and cooking. Most countries with indigenous coal seams will wish to utilize them, not least because of the security of energy supply that they provide and the favorable impact on trade balances. Coal can be exploited in an environmentally friendly fashion either (1) by combustion followed by capture of the carbon dioxide from the exhaust gases and its indefinite storage (sequestration), or (2) through conversion into hydrogen through gasification – with subsequent sequestration of the accompanying carbon dioxide. The hydrogen can then serve as a clean fuel in gas turbines, fuel cells, or internal combustion engines. The present use of hydrogen for electricity generation through fuel cells is negligible. There is, however, an environmental benefit to be gained that stems from the relative ease of pollution management at a central production facility rather than at dispersed sites. Moreover, in principle, emissions of carbon dioxide are more easily

captured and stored at a single plant than when fossil fuels are deployed in the field.

Coal Production and Reserves It is generally accepted that most deposits of coal are of plant origin and were laid down in geological time, especially during the Carboniferous Period between 345 and 280 million years ago. The first product of decay and consolidation is peat, which has a relatively low carbon content and a high moisture content. Under forces of heat and pressure, peat gradually converts first into bituminous coal and, ultimately, to hard coal (anthracite). Although coal has been widely used as a fuel for centuries (notably, however, King Edward I of England in 1306 banned the burning coal on the grounds of air pollution!), it reached preeminence in the eighteenth century with the invention of the steam engine in Britain and the subsequent launching of the Industrial Revolution. The characteristic physical and chemical properties of coal have long been studied. The diversity of the original plant materials that ultimately formed coal, the variations in the depositional environment and the age of the coal since it was laid down (the ‘rank’ of the coal) have resulted in an exhaustive literature that classifies

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coal by its appearance (macroscopic and microscopic), its chemical composition, the occluded mineral matter, and its physical properties. The various grades include, in terms of increasing carbon content: lignite (or brown coal), soft bituminous coal, and anthracite. Each type of coal is suitable for different applications. The quality of coal is determined by its calorific value, its moisture level, its volatile hydrocarbon content, its ash content and, given present concerns over the adverse effects of emissions on the environment, its sulfur and mercury contents. During coal combustion, sulfur impurities are converted into sulfur dioxide, which in the atmosphere is oxidized to sulfur trioxide and then precipitates as acid rain. As mentioned above, coal is by far the most abundant of the conventional fossil fuels, with proven economicallyrecoverable reserves close to 1012 t worldwide; about a quarter of these are in the USA, with large deposits found in Russia and the other States of the former Soviet Union, the People’s Republic of China, India, and Australia. The total reserves are equivalent to the energy in 3.5  1012 barrels of oil, and represent about 150 years of coal production at present rates. Natural gas is also associated with some of the coal. According to the World Coal Institute, coal provided 26% of global primary energy needs in 2007 through the worldwide mining of 5543 Mt of hard coal and 945 Mt of brown coal (lignite); 41% of the total production was employed in electricity generation. The Energy Information Administration in the USA has projected that by 2030 the consumption of coal will have risen by a further 64%. This forecast, made in 2008, has assumed the absence of national policies and/or binding international agreements that would limit or reduce greenhouse gas emissions. The USA projection is based on the widespread availability of coal (in many countries, it is the only indigenous fossil fuel) and the relatively low cost of the fuel. It should be reiterated that these are the major factors driving the commercial expansion of the coal market; other issues such as pollution, climate change and energy security are more the concerns of governments and politicians, who must provide the legislative framework and financial disincentives (e.g., carbon taxes) to ensure the emergence and growth of clean coal technologies.

Coal-Fired Electricity Plant In the past, coal was employed as a fuel for both stationary and traction steam engines, for ships, for central heating boilers, and for the manufacture of coal gas, coal tar and coal-based chemicals. Most of these markets for coal have declined or disappeared altogether due to the uptake of more convenient petroleum and natural gas. With the advent of refined petroleum, the internal

combustion engine replaced the steam engine. As discussed above, electricity generation is now the main market for coal throughout the world. Coal-fired electricity drives the economies of China and India, and also makes a large contribution to those of key industrial countries such as the USA and Germany. Despite all the associated environmental concerns, there is no doubt that coal will continue to play a leading role in world energy for the foreseeable future. Mankind will simply have to learn to extract the energy from coal without releasing its carbon content to the atmosphere as carbon dioxide. If a full Hydrogen Economy were ultimately to emerge, enormous quantities of hydrogen would be required. Ideally, this would be produced by the electrolysis of water using electricity generated from low-carbon renewable or nuclear sources. In the early years, these energy forms would be inadequate to meet the requirement and, as an interim measure, it would be necessary to convert fossil fuels into hydrogen, with sequestration of carbon dioxide. The direct route to hydrogen from coal is by gasification (as described below), but the problems of filtering and purifying the gas to a standard appropriate for use in fuel cells present a major challenge. An alternative is to use coal for the electrolytic splitting of water. At first sight, it would seem circuitous and nonsensical to use coal to generate electricity, then feed the electricity to an electrolyzer to produce hydrogen, and then to utilize the hydrogen in a fuel cell to generate electricity. When, however, account is taken of (1) the well-established technology of largescale electricity generation in coal-fired plant, (2) subsequent distribution of the electricity through the existing national grid, and (3) the high purity of hydrogen produced by electrolysis, it is not yet clear which route would be the more practical and economic. Indeed, gasification and electrolysis are both technically feasible and the choice may vary from place to place according to circumstances. For these reasons, a description of electricity generation in coal-fired plant now follows. Modern coal-fired power stations are often, although not always, large in size, that is, 1–4 GW output. In a conventional pulverized fuel coal combustion (PFCC) plant, the fuel is first milled to a fine powder and then blown into the combustion chamber of a boiler to raise steam. The burner mixes the pulverized coal in the air suspension with additional preheated combustion air and forces it out of a nozzle similar in action to fuel being atomized by an injector in modern cars. Under operating conditions, there is sufficient heat in the combustion zone to ignite all the incoming fuel. Burners can be designed to accept any type of coal; lignite (brown coal), sub-bituminous, or bituminous coals are generally used, with hard coals (anthracite) reserved for premium applications such as steel making. The

Fuels – Hydrogen Production | Coal Gasification

economics of generating electricity depend very much on the cost of the coal that, in turn, depends on fuel quality, the thickness and the depth of the coal seams, and the distance over which the coal should be transported. Open-cut mining is usually the cheapest. After removing the topsoil, coal (lignite) is simply scooped up with dredgers and deposited on a conveyor belt for direct transfer to the power station. In many countries, the coal reserves, though plentiful, are deep underground in narrow seams and therefore expensive to mine. This is the basic reason why some coal mines have been closed in favor of importing cheaper coal. The United Kingdom, for example, obtains much of its coal from South Africa, Russia, and elsewhere. Moreover, coal from South Africa is low in sulfur content and thus its use reduces atmospheric pollution. A schematic layout of a typical 2-GW PFCC plant is given in Figure 2. The station has four parallel lines, each of which is capable of generating 500 MW; the schematic shows just one of these. Coal is transported on a conveyor belt (14) from a stockpile to a pulverizing mill (16) where it is ground to a fine powder, picked up by a stream of hot air and blown into the boiler system to burn like a gas (each of the four lines has a boiler). The heat produced

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converts extremely pure boiler water into steam in the tubing that forms the boiler walls. The steam leaves the boiler at 841 K and B17 MPa pressure and passes through the high-pressure stage of a steam turbine (11) to turn the blades and shaft at 3000 rpm. The steam returns to the boiler for reheating and then is directed back to the intermediate- and low-pressure stages of the turbine, items (9) and (6), respectively. The turbine shaft is linked to a 500-MW generator (5). The resultant electricity is fed at 23.5 kV to a transformer (4) where it is raised to 400 kV for transmission along the national grid (3). The spent steam from the turbine goes to a condenser (8) where it is cooled (usually by river water) and the pure condensate is pumped back to the boiler for reuse. The warmed water from the condensers passes to large cooling towers (1) where it is sprayed over packing in the base of the tower and cooled by evaporation in the natural updraught of air. The tower is mounted on stilts to allow the air to enter at the base. Before the boiler exhaust gases are discharged from the main chimney stack (27), 99% of the fine dust is removed by electrostatic precipitators (25). Much of the ash from the coal (18) is sold for use in the construction industry. The remainder may serve to fill disused gravel pits that are later restored to agricultural

17

19

21 22

14 1

23 5

6 5

10

9

8 2

3

4

25

15

26

27

11 12 13

16

18

20

24

7 1. Cooling tower 2. Cooling water pump 3. Pylon (termination tower) 4. Unit transformer 5. Generator 6. Low-pressure turbine 7. Boiler feed pump

Key 8. Condensor 9. Intermediate-pressure turbine 10. Steam governor 11. High-pressure turbine 12. Deaerator 13. Feed heater 14. Coal conveyor

Figure 2 Schematic of a 500-MW line in modern, coal-fired, 2-GW power station.

15. Coal hopper 16. Pulverized fuel mill 17. Boiler drum 18. Ash hopper 19. Superheater 20. Forced draught fan 21. Reheater

22. Air intake 23. Economizer 24. Air preheater 25. Precipitator 26. Induced draught fan 27. Chimney stack

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Fuels – Hydrogen Production | Coal Gasification

use. The levels of sulfur dioxide (SO2) and nitrogen oxides (NOx) in the exhaust gases are closely monitored. A 2GW power station produces sufficient electricity to supply the needs of nearly two million people. In the United Kingdom, for example, each power station is granted a licence for the amount of pollutants that may be discharged per year. In order to maximize the quantity of electricity generated and stay within the licence, there is an incentive for the station manager to burn low-sulfur coal. Some power stations have been equipped with flue-gas desulfurization units where the sulfur dioxide is absorbed in limestone (CaCO3) to form calcium sulfate (gypsum, CaSO4), which finds a market as plaster board. (Note that the amount of carbon dioxide produced by the reaction of sulfur dioxide with limestone, namely, CaCO3 þ SO2 þ 12 O2 - CaSO4 þ CO2, is minimal compared with that released from the combustion of coal.) Although this permits the use of coals with higher sulfur content, it is an expensive option in terms of both capital and running costs. Flue-gas desulfurization units have been fitted to the largest coalfired station in Europe, the 3.975-GW plant at Drax in North Yorkshire, UK. This station can handle 10  106 t of coal per year. Over 90% of the world’s coal-fired power stations are of the PFCC type, with the remainder being either circulating fluid-bed combustion or pressurized fluid-bed combustion designs. The PFCC plants generally operate with a thermal efficiency (ratio of electrical output to heat input) in the range of 35–39%. Modern plant using supercritical and ultra-supercritical steam may have efficiencies of 45%, or even higher. A 1% increase in efficiency reduces carbon dioxide emissions by around 2%, which is a significant gain. Some generating stations have been adapted to burn gas as well as coal when this is economically justified, that is, they are ‘dual fuel’ stations. The advantages and disadvantages of using coal to generate electricity are summarized in Table 1. The fact that coal has the highest carbon content of all the fossil fuels is a serious disadvantage, particularly given the concern over climate change caused by greenhouse gases, especially carbon dioxide. What is to be done about it? Attempts are being made to develop practical technology for the capture of carbon dioxide, as well as sulfur dioxide, from the exhaust stacks of power stations. This socalled ‘post-combustion capture’ (discussed later in more detail) is not an easy task as there is no low-cost equivalent to limestone to absorb carbon dioxide. Rather, attempts are focused on the use of liquid amines as sorbents – a technology employed in the steam reforming of natural gas to manufacture hydrogen. The exhaust gases from power stations, however, are not so easy to treat, not least on account of their high volume and throughput. The alternative approach, and a more radical one, is to gasify the coal and remove the carbon, sulfur,

Table 1 Advantages and disadvantages of electricity generation by coal Advantages

Disadvantages

Large reserves of low-cost coal available Well-established industry

Carbon-rich fuel leads to extensive liberation of carbon dioxide High sulfur content of many coals leads to pollution by sulfur dioxide and acid rain

Indigenous fuel source for many countries

and other impurities before combustion; not surprisingly, this is termed ‘pre-combustion capture’ and is also examined in more detail below.

Hydrogen-from-Coal Technologies Coal is generally perceived as being a ‘dirty’ fuel – not only in terms of its handling, but also on account of the volatile matter liberated on burning. Among the products of combustion are aliphatic and aromatic hydrocarbons that include carcinogenic polycyclic compounds, partially oxidized hydrocarbons, toxic gases such as sulfur dioxide and nitrogen oxides, tar, soot, and smoke. After the dreadful urban smogs of the 1940s and early 1950s, notably in London but also in cities elsewhere, clean air legislation was introduced into various countries. In Britain, for example, the burning of bituminous (soft) coal on open fires was banned and householders were required to switch to ‘smokeless fuel’, such as anthracite (hard coal) of much lower volatile content. This legislation, together with the changeover to natural gas for space heating, completely transformed the urban environment. (Note, however, there followed a period when urban air quality again deteriorated as a result of exhaust pollution from the growing number of vehicles, before the introduction of catalytic converters for the clean-up of vehicle exhaust.) As mentioned above, 41% of all coal mined today is used in electricity generation. This includes both lignite and bituminous coals. As higher-grade fuels such as natural gas and petroleum become depleted, it is probable that the world will turn again to its huge reserves of coal as a source of energy. Fortunately, coal need not be a dirty fuel and numerous clean technologies exist, or are being developed, to utilize coal on an industrial scale. These technologies fall broadly into two categories: coal liquefaction and coal gasification. The latter process yields hydrogen which, in principle, can be utilized in either a gas turbine or a fuel cell. Coal Liquefaction Commercial plants for the manufacture of petrol from coal were operated in Germany during World War II and, later,

Fuels – Hydrogen Production | Coal Gasification

in South Africa (the Sasol process). In the 1970s, there was a plant operating at 5000 t coal per day in South Africa for the domestic production of petrol. The conversion process of coal to the so-called ‘syncrude’ requires addition of hydrogen to the coal so as to raise the hydrogen-to-carbon ratio. There are three basic methods (shown schematically in Figure 3), each of which has been investigated on a significant scale to yield, typically, three barrels of petroleum from 1 t of coal. These methods are as follows. Direct hydrogenation at high temperatures (723 K) • and pressures (13–27 MPa) in the presence of a

• •

catalyst. Solvent refining, which involves dissolution of the coal under pressure in a solvent (anthracene oil), followed by separation of the ash and catalytic hydrogenation and hydro-desulfurization of the solution. Conversion of coal into water gas (CO þ H2), followed by the production of liquid hydrocarbons and alcohols by catalytic synthesis in the presence of added hydrogen according to the general equations:

nCO þ ð2n þ 1ÞH2

200 1C

-

nickel; cobalt or thorium catalyst

Cn H2nþ2 þ nH2 O ½I

nCO þ 2nH2 -Cn H2nþ1 OH þ ðn  1ÞH2 O

½II

This catalytic process for making fuels from carbon monoxide and hydrogen was invented in 1923 by Fischer and Tropsch. The resulting hydrocarbon mixture is separated into a higher-boiling fraction for diesel engines and a lower-boiling fraction for petrol engines. The latter fraction contains a high proportion of straight-chain hydrocarbons (alkanes) and has to be reformed (‘cracked’) by catalytic action into branched-chain alkanes for use in motor fuel. The process used at the Sasol plant in South Africa is based on Fischer–Tropsch synthesis. Coal liquefaction has tended to go into abeyance with the discovery of large supplies of petroleum and natural gas (the production of liquid fuels and chemicals from natural gas is economically more attractive than from Coal solution

Pressure Anthracene oil

Coal

H2/catalyst Hydrogenation Hydro-desulfurization

H2/catalyst, 723 K, 13–27 MPa Steam

Water-gas reaction

H2/catalyst Water gas CO + H2

Syncrude

Fischer−Tropsch process

Figure 3 Possible routes for the synthesis of petroleum from coal.

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coal). Nevertheless, when it becomes necessary to place greater demands on coal reserves for primary energy supplies, the above three processes will be available to manufacture gaseous and liquid fuels for use in internal combustion engines. Coal liquefaction is relevant to hydrogen production only insofar as the internal combustion engine is a competitor to the hydrogen fuel cell for transportation applications. The cost targets that the fuel cell will have to meet will be determined in part by the cost of liquid fuels derived from coal. Coal Gasification Gasification is defined as the transformation of solids into combustible gases in the presence of steam and (optionally) air, oxygen, or carbon dioxide; these oxidants combust some of the fuel to provide the necessary heat for the high-temperature (41000 K) endothermic reaction to produce hydrogen. Almost any fossil fuel can be treated in this way to produce hydrogen. The most widely-distributed fossil fuels are the various types (ranks) of coal, but other possibilities exist such as tar sands (now renamed ‘oil sands’), asphalts, heavy oils extracted from shale, refinery residues, and petroleum coke. Biomass, which includes agricultural waste, forestry waste, energy crops and municipal solid waste, may also be processed by gasification technology to produce hydrogen and is discussed in a separate article of this encyclopedia. The gasification of coal has long been practiced. When heated in a restricted supply of air, coal or coke is converted to carbon monoxide that is heavily diluted by nitrogen. This is a low-grade fuel known as ‘producer gas’ and has been employed in industry as a reducing atmosphere. Because of the low calorific value of producer gas, transport costs are an important factor and thus it is mainly manufactured close to where it is needed. During World War II, when petrol was in short supply, some buses in the United Kingdom were converted to operate on producer gas. The bus towed a trailer equipped with a small anthracite or coke oven and the gas was stored in an inflatable bag carried on top of the bus. Conventional petrol engines were employed, although their performance was heavily degraded. When heated coal or coke is reacted with steam alone, the ‘water-gas reaction’ occurs: C þ H2 O-CO þ H2

½III

Water gas found widespread use before World War II in producing hydrogen for the manufacture of ammonia through the Haber process. As mentioned earlier, most hydrogen for this purpose is today obtained from synthesis gas (also known as ‘syngas’), which is made from natural gas by steam reforming; it is a cleaner and cheaper option. The water-gas reaction is highly

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endothermic (heat absorbing) and thus soon ceases unless heat is supplied. Conversely, the combustion of coal or coke in air is highly exothermic (heat evolving). It is therefore usual to pair off the two reactions so as to balance the heat evolved with that absorbed. The two reactions may either be conducted consecutively, in short bursts or, more usually, simultaneously by feeding a mixture of air and steam to the heated bed. The resulting gas is a mixture of carbon monoxide, hydrogen, carbon dioxide, and nitrogen. A gas of higher calorific value can be obtained by using oxygen rather than air, but for many applications this is not affordable. From time to time, proposals have been advanced for the underground gasification of coal as a more efficient and safer alternative to deep mining, but such an approach runs into similar problems, namely, air gives a gas which is too dilute to be useful, while oxygen, prepared by cryogenic fractionation of liquid air, is too expensive to employ. Research is being conducted on membrane processes for gas separation that may prove to be a considerably cheaper option for the preparation of oxygen. The product from the water-gas reaction may be upgraded in terms of hydrogen content by the ‘water-gas shift reaction’. The mixed gases are reacted with steam over a catalyst that converts carbon monoxide to carbon dioxide and increases the amount of hydrogen, that is, CO þ H2 OðgasÞ-CO2 þ H2

½IV

The carbon dioxide is then removed from the gas by scrubbing to leave a mixture of, predominantly, hydrogen and nitrogen; the latter enhances the usefulness of water

gas in the synthesis of ammonia. The water-gas shift reaction may be undertaken in two steps by which the carbon monoxide content is first reduced to o2 vol% at 673 K, and then to o0.2 vol% at 473 K. If ultra-pure hydrogen is required for use in fuel cells, the remaining small quantity of carbon monoxide is selectively oxidized to o0.002 vol% by admitting air at 373 K. The use of excess steam facilitates the water-gas shift reaction and enhances the yield of hydrogen, although at the expense of a reduction in overall thermal efficiency. A conceptual flow sheet for the production of hydrogen by the gasification of coal is shown in Figure 4. By adjusting the fuel, the gases employed (i.e., the steam and air/oxygen mixture) and the operating conditions, it is possible to tailor-make syngas of a desired composition. Until now, the gasification of coal has focused predominantly on chemical synthesis (as discussed above), but there is growing interest in its use for more efficient and cleaner electricity generation (see below) and for hydrogen production for use in fuel cells. Coal gasification plants are being constructed around the world, particularly in China – primarily for the manufacture of chemicals and fertilizers, but also for more efficient generation of electricity. A world survey in 2008 identified 140 operating plants with 420 gasifiers and a total capacity of 58 500 MWth. Of these, approximately half were coal-fired and the remainder were operating with petroleum residues and other fuels. The bulk of the syngas is employed in the manufacture of chemicals and liquid fuels, with much less in electricity production and as gaseous fuels. Worldwide gasification capacity is projected to grow by 70% by 2015. CO2 to sequestration

Coal

CO/H2 Gasification

Gas cleaning

Water-gas shift reaction

O2

CO2/H2

Gas separation

H2 Combined-cycle power generation

H2 Electricity

Air separation unit

Final gas polishing

Air

High-purity hydrogen

Figure 4 Schematic representation of an integrated coal gasification process.

Fuels – Hydrogen Production | Coal Gasification

Gasification Technology The process engineering of coal gasification is quite complex and several large-scale processes have been developed. There are three basic designs of coal gasifier, as follows.

• Entrained-flow. (sometimes also referred to as fixed bed!). • Moving-bed Fluidized-bed. • These technologies are shown schematically in Figure 5 and their main operating features are as follows. Entrained-flow gasifier

Entrained flow is the most aggressive form of gasification, in which pulverized coal and oxidizing gas flow co-currently. Optionally, the pulverized coal may be fed to the gasifier in the form of a slurry with water that then provides the source of the steam required for the reaction. Under operating conditions of high pressure (2–3 MPa) and high temperature (1273–1873 K), almost complete gasification is achieved with little formation of tars or char. Under the extremely turbulent flow, the coal particles experience significant back-mixing, and residence times are measured in seconds. There are at least seven different proprietary technologies for this type of gasifier. Some of these feed coal and air/steam mixtures from the reactor top (as shown in Figure 5) and others from the bottom. Entrained-flow gasification is specifically designed for low-reactivity coals and high coal throughput. Singlepass carbon conversions are in the range of 95–99%. To experience smooth operation, with the removal of the ash as a molten slag, the temperature of the gasifier must lie

Coal slurry

Oxygen

above the coal-ash fusion temperature. Alternatively, it is necessary to add fluxes to lower the melting temperature of the mineral matter in the coal. A problem stemming from the high operating temperature of these gasifiers is that their refractory liners can be susceptible to some of the oxides present in the coal slag (silicon dioxide (SiO2), calcium oxide (CaO), magnetite (Fe2O3)), which can penetrate into the liner and eventually cause cracks. Moving-bed gasifier

Moving-bed gasifiers (also known, perversely, as ‘fixedbed gasifiers’) operate at about 3 MPa and closely resemble a blast furnace. Crushed coal, from which fines have been removed, and fluxes are placed on the top of a descending bed in a refractory-lined vessel. The main requirement of moving-bed gasifiers is good bed permeability to avoid pressure drops and burning in the channels. On moving downward, the coal is gradually heated and contacted with steam and oxygen-enriched air flowing upward counter-currently. Pyrolysis, char gasification, combustion and ash melting occur sequentially. The oldest and best-known gasifier of this type is the Lurgi moving-bed gasifier, although other types have since been developed. The temperature at the top of the bed, where the syngas off-take is located, is typically 723 K, and at the bottom can approach 2273 K, as dictated by the composition of the gas employed. Mineral matter in the coal melts and is tapped as an inert slag. The characteristics of the ash melt influence bed permeability, and fluxes may have to be added to modify aspects of the slag flow. The off-gas contains tars that must be condensed and recycled. The production of tars makes downstream gas-cleaning more complicated than

Coal, fluxes

Syngas

Syngas

Bed of feed Water

Steam Oxygen

Fluidized bed

Coal

Grate

Steam

Syngas

Ash

Air/oxygen Steam Slag Entrained-flow

283

Slag Moving-bed

Fluidized-bed

Figure 5 Schematic representations of entrained-flow, moving-bed and fluidized-bed gasifiers.

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Fuels – Hydrogen Production | Coal Gasification

with other gasification processes. The residence time is between 30 min and 1 h, which places stringent restrictions on the physical and chemical properties of the coal. Long residence times mean that moving-bed gasifiers have a low throughput and hence have limited application in large-scale electricity plants. Fluidized-bed gasifier

A fluidized-bed reactor is a vessel in which fine solids are kept in suspension by an upward-flowing gas such that the whole bed exhibits fluid-like behavior. Finely divided coal is injected into a bed of inert particles that is fluidized by steam and air (or oxygen) at high pressure. Rising oxygen-enriched gas reacts with suspended coal at a temperature of 1223–1373 K and a pressure of 2–3 MPa. High levels of back-mixing give rise to a uniform temperature distribution within the gasifier. This type of reacting system is characterized by high rates of heat and mass transfer (i.e., increased reaction rates) between the solid and the gas. The unusual characteristic of fluidizedbed gasifiers is that the majority of the bed material is not coal but accumulated mineral matter and sorbent (for in situ desulfurization). Operating with a high inventory of inert bed material has two advantages: (1) the coal experiences a high rate of heat transfer on entry; (2) the gasifier can operate at variable load so that the rate of syngas production can be varied at will within wide limits, that is, the gasifier has a high ‘turn-down’ flexibility. In order to avoid ash agglomeration in the fluidized bed, it is necessary to use coals with a higher ash-fusion temperature than the operating temperature of the gasifier. Impurities in the coal, such as iron pyrites and high sodium content (which gives rise to sodium silicates during gasification), can also lead to particle agglomeration. A variant is to use limestone as the inert material of the bed. The sulfur in the coal is oxidized to sulfur dioxide and this reacts with the limestone and further oxygen to form calcium sulfate. Between 90% and 95% of the sulfur dioxide is removed from the exhaust gases. As ash builds up in the bed and the limestone is depleted, both materials are tapped off and further limestone added. The limestone will also absorb any other acid gases released from the coal during gasification. The comparatively low temperature of operation limits the use of fluidized-bed gasifiers to reactive and predominantly low-rank coals such as lignite or brown coal. Most of the units require recycling of entrained fines to achieve 95–98% carbon conversion. To reduce the extent of fines recycling, it has been proposed that the gasifier be linked with a fluidized-bed combustor (i.e., an ‘air-blown gasification cycle’). In this process, the coal is first gasified to 70–80% carbon conversion. The unreacted char is then fed to the combustor where generated heat is used for steam production. The gasifier–combustor combination

would enable the use of low-reactivity coals in an integrated gasification combined-cycle (IGCC) electricity plant (see below). In general, though, the type of gasifier should be matched to the properties of the coal available, especially with respect to its gasifying characteristics and mineral content (ash melting temperature, chemical composition). The three major classes of gasifier in their various modifications can, between them, cope with most types of coal.

Gas Cleaning Gas cleaning is an essential part of the overall gasification technology, both to protect catalysts from poisoning and also to meet the end specification for the syngas, dependant upon whether it is to be used in gas turbines, for chemicals manufacture, or for the pure hydrogen required by low-temperature fuel cells. Compared with the steam reforming of natural gas, gasification of coal yields a syngas that has: (1) higher levels of carbon monoxide, which have to be shifted to carbon dioxide and hydrogen; (2) generally higher levels of impurities, which have to be cleaned from the gas before use. The main contaminants in syngas produced from coal are particulates, sulfur dioxide, nitrogen oxides (NOx), the alkali metals sodium and potassium, and mercury. Minor or trace amounts of ammonia, arsenic, beryllium, cadmium, chromium, hydrogen chloride, hydrogen fluoride, lead, nickel and selenium can also be present. All these species have to be removed to acceptable limits by final gas polishing in order to protect downstream process equipment (in particular, the gas turbines) against fouling, erosion and/ or corrosion, to prevent poisoning of the catalyst used for the shift reaction, and to meet environmental regulations. For low-temperature fuel cells, it is necessary to polish the hydrogen fuel especially well to remove the final traces of impurities and carbon monoxide that can poison the platinum electrocatalyst. At present, barrier ‘candle’ filters are used to remove solid contaminants. The filters have a porous tubular structure and can be classified into two broad designs: (1) ‘ceramic’ filters, which are made from materials such as alumina, silica, and zeolites; (2) ‘metallic’ filters, which are made from nanofibers or wires of alloys, for example, iron aluminide, Incoloy, Monel, Hastelloy, and are protected from corrosion by a ceramic coating. A detailed description of such filters is given in a separate article in this encyclopedia. Conventionally, sulfur is removed from raw syngas by means of low-temperature solvent/adsorption processes, but these are energy-intensive and highly expensive for many applications. A range of high-efficiency sulfurcapture techniques is being developed and include improved physical and chemical sorbents, advanced catalytic processes, and selective separation membranes.

Fuels – Hydrogen Production | Coal Gasification

To avoid degradation of the construction materials used for the gas-treatment unit, and also because of the thermal instability of the solvents, it has been customary to undertake cleaning after the gas has been cooled to below 373 K. This necessitates large heat-exchangers that are costly, and also degrade the overall energy efficiency of the plant. Syngas is required at much higher temperatures and pressures when destined for use in combined-cycle electricity plant. Hence, there are obvious operational advantages to be gained from the development of ‘hot-gas cleaning’ systems. Indeed, such an advance is considered essential if the comparative economics of coal gasification plants are to become attractive. Hot-gas cleaning technologies are in the early demonstration stage with units being evaluated at temperatures above 873 K (which necessitates considerable cooling of the gas) and at pressures up to 2.5 MPa. Calcium-based sorbents (limestone and dolomite) and zinc titanate are the leading candidates for use in the desulfurization of high-temperature fuel gas, but even these have serious limitations that will have to be overcome before they may be regarded as satisfactory.

Combined-Cycle Electricity Generation Combined-cycle gas turbines are widely used for electricity generation from natural gas. The gas is burnt in a high-temperature gas turbine that is coupled to a generator. The exhaust gas from the turbine is used to raise steam, which is then fed to a conventional steam turbine and a further generator. A combined-cycle plant for generating electricity from coal is based on a similar methodology – the IGCC process. The gas leaving the gasifier is an impure mixture of hydrogen and carbon monoxide. Hydrogen sulfide (formed from sulfur impurity in the coal) is removed by absorption in a polyethylene-based solvent. Mineral matter in the coal forms a slag at these high temperatures and is discharged from the base of the gasifier. The cleaned syngas replaces natural gas as fuel for a large gas turbine coupled to a generator. Again, the gas turbine exhaust passes through a heat-exchanger (the ‘heat-recovery steam generator’) to raise high-pressure steam. This is mixed with the steam from the gas cooler and used to operate a conventional steam turbine that generates more electricity. The IGCC process has potential to increase thermal efficiencies to over 50% with correspondingly reduced emissions of carbon dioxide. The scale of the IGCC operation is impressive. Technoeconomic studies have indicated that a large gasifier will have a coal feed in the range of 2000–3000 t per day and will produce syngas at an energy efficiency of 75–80%. On combusting this syngas in an IGCC scheme, the net power generated will lie in the range of 270–420 MWe, with an

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overall thermal efficiency (coal-to-electricity) of 38–45%, although eventual efficiencies of 50% are widely anticipated. This performance is significantly better than that of most conventional coal-fired (PFCC) electricity plants. A 400-MWe plant will emit around 6500 t of carbon dioxide per day. A refinement of the process is to convert the carbon monoxide in the syngas into carbon dioxide and then separate it from the hydrogen, for storage, before the hydrogen is fed to the gas turbine for combustion. This ‘pre-combustion capture’ of carbon dioxide is an example of ‘clean coal’ technology. It is easier than ‘post-combustion capture’ (where the exhaust gases are heavily diluted with nitrogen from the air) and hence the costs of carbon dioxide sequestration will be lower. The exit gas from the gasifier is reacted with additional steam over a suitable catalyst (shift reaction, eqn [IV]) to convert the gas into a mixture of hydrogen and carbon dioxide. The carbon dioxide may then be separated in a form suitable for sequestration (e.g., in geological structures), while the hydrogen is used to fuel the gas turbine. In principle, the hydrogen could be fed to large-scale stationary fuel cell installations, or used to provision a fleet of electric vehicles powered by fuel cells. These possibilities, however, are well into the future. To date, no large-scale IGCC plant with carbon capture has been built, although small-scale trials are thought to be in progress. The ultimate aim is ‘zero-emissions power from coal’. Such plants could also be used for the production of synthetic liquid fuels and chemicals, a so-called ‘polygeneration plant,’ as shown schematically in Figure 6.

Capture of Carbon Dioxide The overall sequestration of carbon dioxide involves the following four steps. of the gas from the emission source. • Capture and compression of the gas. • Dehydration to the storage site. • Transport • Injection into the storage geological reservoir. The capture of carbon dioxide from exhaust gases is taken to be the most difficult part of the overall sequestration activity, and also the most costly. There are three main processes for capturing carbon dioxide from power plants, and then compressing and drying it ready for underground storage, namely: gas scrubbing. • Post-combustion Precombustion decarbonization. • Oxy-fuel combustion. • The options are shown schematically in Figure 7. Note that oxy-fuel combustion is essentially a variant of postcombustion capture; oxygen rather than air is the oxidant

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Fuels – Hydrogen Production | Coal Gasification Fischer–Tropsch synthesis Gas cooling and cleaning

Liquid Liquid fuels fuels and chemicals chemicals and

Shift reactor

CO2 to storage

Syngas CO/H2

CO2/H2 separator

Gasifier

Fuel cells

H2 Contaminants e.g., sulfur

Gaseous constituents constituents

Generator

Air

Gas turbine Steam

Heat recovery steam generator

Coal feedstock Solids

Oxygen

Generator

Steam turbine Combined cycle

Glassy slag

Figure 6 Concept of a poly-generation plant based on the integrated gasification combined-cycle (IGCC) process.

N2 O2 Postcombustion

Coal gas biomass

Power + Heat

CO2 separation

Air Air/O2 steam

Coal biomass Precombustion

CO2 CO2

Power + Heat

Reformer + CO2 separation

Gasification

Gas, oil

N2 O2

Air

Oxy-fuel combustion

Coal gas biomass

CO2

Power + Heat

O2 Air

CO2 compression and dehydration

N2

Air separation

Air/O2 Industrial processes

Coal gas biomass

Process + CO2 separation

Raw material

CO2

Gas, ammonia, steel

Figure 7 Principal routes for managing carbon dioxide emissions from power stations.

and thereby the need to separate carbon dioxide from nitrogen is eliminated. Carbon dioxide is also generated from many large industrial operations (petroleum refineries, ammonia plants, etc.) and is sometimes separated for use in chemical processes or in the food industry.

Current processes for separating carbon dioxide from hydrogen, such as pressure swing adsorption (PSA) and solvent scrubbing, are mature but energy-intensive. A major thrust for reducing the cost and improving the performance of hydrogen and carbon dioxide separation is

Fuels – Hydrogen Production | Coal Gasification

the development of membranes that are selective for hydrogen diffusion. Ideally, membranes capable of operation at high temperatures would be employed to obviate the need for cooling the gas, and thereby save energy and remove the capital cost of extra heat exchangers. Even better would be to integrate the hydrogen separation membrane into the water-gas shift reactor, as shown schematically in Figure 8. Membrane separators are discussed elsewhere in this encyclopedia.

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principle, retro-fitting to existing utilities is possible but there may be practical considerations such as the availability of land. Post-combustion capture has, however, been employed in some chemical manufacturing plants and is being thoroughly investigated by power companies. Many new coal-fired power stations are being built ‘capture ready,’ which implies making provision for future possible adoption of carbon dioxide separation processes. Oxy-Fuel Combustion

Post-Combustion Capture In a conventional combustion process, such as a power station boiler, the carbon dioxide is contained in the exit flue gas. The concentration is generally quite low and ranges from about 4 vol% for a combined-cycle system operating on natural gas to 12–14 vol% for a traditional boiler fired by pulverized coal. The exhaust can be ‘scrubbed’ with an amine solution, typically mono-ethanolamine, which is then heated to release the absorbed carbon dioxide. The low concentration of carbon dioxide in the exit gas means that a huge volume would have to be handled, and this would entail the installation of large and expensive equipment. Also, considerable energy is required to desorb carbon dioxide from the amine solution and subsequently to re-pressurize it. The amine, which is a valuable chemical, can be recycled but soon degrades through the action of high temperature, oxygen, and impurities in the gas; it therefore has to be replaced. This is particularly true for exhaust gases from coal-fired stations that contain sulfur dioxide and other acid impurities. Research is being undertaken to develop more efficient and less expensive processes. Given the drawbacks of the amine route, postcombustion capture has not been demonstrated to be costeffective in most power stations. It has been estimated that the process might well double the capital cost of a combined-cycle operation running on natural gas, as well as reducing the overall plant efficiency and therefore increasing the fuel consumption and the running costs. In

Catalyst in annular space Syngas

Water-gas shift reaction CO + H2O → CO2 + H2

CO2-rich stream

Permeation H2-rich stream

H2

Sweep gas

Membrane tube Reactor shell

Figure 8 Schematic representation of a packed-bed membrane reactor.

The concentration of carbon dioxide in flue gas can be increased greatly by using oxygen instead of air for combustion, either in a boiler or in a gas turbine. The oxygen would be produced by cryogenic air separation which, although expensive, is already employed on a large scale, for example in the steel and glass-making industries. When fuel is burnt in pure oxygen, the flame temperature is excessively high, so some exhaust gas is recycled to the combustor in order to hold the flame temperature similar to that in a normal air-blown boiler. The advantage of oxygen-blown combustion is that the flue gas has a carbon dioxide concentration of B80 vol% compared with 4–14 vol% for air-blown combustion, and therefore separation of the carbon dioxide is relatively simple or even unnecessary. After combustion, the gas stream is first cooled and compressed to remove the water vapor. It may be possible to omit some of the gascleaning equipment that is used in modern coal-burning power stations (such as scrubbers for desulfurization of flue gas), and this would reduce the net cost of carbon dioxide capture. Some sulfur compounds and other impurities would then remain in the carbon dioxide fed to storage, which may be acceptable. A possible downside of omitting the desulfurization stage is that recycled, wet flue gas will contain sulfuric acid that is highly corrosive to the plant. The disadvantage of oxy-fuel combustion is that a large quantity of expensive oxygen is required. Advances in oxygen production processes, such as new and improved membranes that can operate at high temperatures could improve overall plant efficiency and economics. To date, oxy-fuel combustion aimed at power generation has only been demonstrated in test rigs. Nevertheless, there is active interest in the technology within the electricity industry because of its potential for retro-fitting to pulverized coal plants that constitute the majority of the world’s generating capacity. This would have the advantage of improving the generating efficiency and so reducing the carbon emissions. Chemical Looping Combustion This process is a highly speculative alternative to oxyfuel combustion that has been proposed to separate carbon dioxide from nitrogen and excess air. A metal

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oxide (e.g., copper, cobalt, nickel, iron or manganese oxides) serves as an oxygen carrier that transfers oxygen from the air to the fuel. Two reactors in the form of interconnected fluidized beds are employed: (1) a fuel reactor, in which the metal oxide is reduced by reaction with the fuel; (2) an air reactor, in which the reduced metal oxide from the fuel reactor is re-oxidized with air. A schematic of the process is given in Figure 9. The outlet stream from the fuel reactor consists of carbon dioxide and water, while that from the air reactor contains only nitrogen and some unused oxygen. The overall chemical reaction is the same as for normal combustion with the same amount of heat released, but with the important difference that carbon dioxide is inherently separated from nitrogen, so that no extra energy and costly external equipment are required for gas separation. Although the technology is very much in its infancy, particularly with respect to chemical engineering issues, chemical looping combustion offers the same advantages as oxy-fuel combustion, but with the added prospects of higher thermal efficiency and no requirement to extract oxygen from air. Pre-combustion Capture After gasifying the coal, the product syngas is first cleaned and then subjected to the water-gas shift reaction, as described earlier. It is then a mixture of hydrogen and carbon dioxide that has to be separated. This is generally accomplished by PSA, which involves isolating the carbon dioxide and impurity gases by adsorbing them at high pressure (up to 4 MPa) on a suitable adsorbent (e.g., a molecular sieve or activated carbon) in a packed bed. Impurities are selectively adsorbed, while pure hydrogen is withdrawn at high pressure. To allow continuous operation, multi-beds connected in parallel are often used. Once a bed becomes saturated with impurities, the feed is switched automatically to another fresh bed to maintain a continuous flow of hydrogen. Reducing the pressure in a number of discrete steps,

Compression

Combustion

Compressor Air

which releases the adsorbed gases, regenerates spent absorbent. Usually, for existing hydrogen plants, all the desorbed carbon dioxide is vented to the atmosphere, though in principle it is possible to separate it out for storage. Indeed, there are instances where it is pumped underground as a means of facilitating enhanced oil recovery (see below). Pressure swing adsorption yields high-purity hydrogen (up to 99.999%) and recoveries of up to 90% are routinely achieved in industrial plants. The process is highly reliable, flexible, and easy to operate with modest energy requirements. It does, however, suffer from limited capacity and from the requirement to cool the gases to low temperature to effect separation. The product hydrogen is therefore now at low pressure and low temperature, which is not ideal as feedstock for a gas turbine or a high-temperature fuel cell if either system is to operate at maximum efficiency. On the other hand, it would be very suitable for a low-temperature fuel cell. Owing to the modular nature of the PSA process, scalingup can be readily achieved with no loss of efficiency. Industrial units have production capacities that range from 500 to 100 000 N-m3 h1, and typically require up to 12 beds for maximum hydrogen recovery. A photograph of an industrial PSA unit is given in Figure 10. There are numerous ways, other than PSA, of separating hydrogen from carbon dioxide. These include temperature swing adsorption, physical and chemical absorption processes, and cryogenic separation. In the lastmentioned process, carbon dioxide is separated from hydrogen and other gases by cooling and condensation. The technology is used commercially but is energy-intensive and, when water is present, may experience operational problems through the formation of carbon dioxide clathrates and ice that can result in serious blockages of the system. Nevertheless, there is the advantage that, after re-warming under pressure, carbon dioxide is produced in a liquid state that can be easily transported to a disposal site by a tanker. Selective membrane diffusion processes also offer a promising

Expansion Turbine O2 -depleted air (~14% O2)

Air reactor

Metal oxide CO2 + H2O

Metal

Fuel

Fuel reactor Turbine

Cooling and water condensation H2 O

Figure 9 Principle of chemical looping combustion.

CO2 Compression and storage

Fuels – Hydrogen Production | Coal Gasification

Figure 10 Industrial pressure swing adsorption unit.

approach to separating hot gases, as discussed in other contributions to this volume.

Storage of Carbon Dioxide Geological Storage There are a number of possible options for the bulk storage of carbon dioxide, among which deep geological storage is favored now. The most suitable sites are found in sedimentary basins, for example, depleted oil or gas reservoirs, saline formations (aquifers), and deep unmineable coal seams. Oil and gas reservoirs have an important advantage in that they are capped by impermeable rock and are known to have stored oil or gas safely for many millennia. An additional attraction lies in the fact that oil reservoirs are normally abandoned as uneconomic when they contain substantial reserves of petroleum. By injecting high-pressure gas, it is possible to drive out more oil from the pores of the sandstone in which it is held. The process is known as ‘enhanced oil recovery’ and the value of the oil recovered serves to offset the cost of gas storage. This is a well-demonstrated technology that is in use in various places (e.g., USA, Canada). The same procedure is possible with gas reservoirs, although mixing of the natural gas with the injected carbon dioxide limits the scope for further methane recovery. The second preferred option, after enhanced oil recovery, is storage in fully depleted oil or gas reservoirs where there is no prospect for further extraction of fuel. This has the merit of storage in secure locations where leakage is extremely unlikely, although there is no bonus to be obtained. Storage in saline aquifers is the third favored option. The possibility of leakage from these formations over the long term is less certain because they may not have a cap of impermeable rock to hold the gas in place and have not been demonstrated over millennia as secure storage sites. On the contrary, the attraction of aquifers is that

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they are far more numerous than oil and gas reservoirs and are widespread, both on land and under the continental shelf. Access to the latter would be through pipelines from the shore or from off-shore platforms. Obviously, the shorter the pipeline from the capture unit to the store, the less is the capital cost. Also, operations on land are cheaper to conduct than those at sea. Offshore aquifer storage of carbon dioxide is practiced in the North Sea. The natural gas from the Norwegian Sleipner field contains too high a content of carbon dioxide (9 vol%) to be usable so this is separated out (to leave 2.5 vol% in the fuel) and injected into an aquifer at a depth of 800–1000 m below the sea floor. This aquifer is estimated to have a massive storage capacity of 1–10 Gt CO2; the rate of separation and injection is B1 Mt CO2 per annum. An on-shore project is being conducted by In Salah Gas at a field in the Algerian desert. Carbon dioxide is separated from the natural gas and injected under pressure into a brine formation at two kilometer below the surface. Unmineable coal seams are another potential form of geological storage. These are either located at too great a depth to be mined, or are too thin to be economically exploitable. Coal is usually associated with methane. The gas adsorbs on the surface of the micropores in the coal and is confined by water that usually fills the fractures of the host material. Substantial quantities of methane can be adsorbed and are well worth recovering. To desorb the gas, its partial pressure must be reduced to allow both gas and water to move through the coal-bed and up the wells. Methane is a by-product of the process by which plant material is converted into coal and up to 25 m3 may become trapped per ton of coal at the prevailing pressures. A substantial amount of coal-bed methane is retrieved in the USA, whereas in Australia, the vast Queensland coalfields are being actively explored and mapped with a view to gas recovery. Carbon dioxide has great affinity for coal. In general terms, coal can store at least twice the amount of carbon dioxide as methane on a molecular basis. This ratio will vary from coal-to-coal, as well as with the pressure, temperature and physical conditions of storage. In volumetric terms, the ratio of the adsorbed amount of carbon dioxide to that of methane ranges from as low as unity for mature coals such as anthracite, to 10 or more for younger, immature coals such as lignite. It has therefore been suggested that unworkable coal seams might be purged with pressurized carbon dioxide to provide not only a means of driving out and harvesting methane, but also an underground store for the waste gas. The carbon dioxide will flow through the cleat system of the coal, diffuse into its matrix, and then be adsorbed on the inner micropore surfaces to unlock methane. Enhanced coal-bed methane (ECBM) recovery is being undertaken in the San Juan Basin in north-western

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New Mexico, USA. More than 0.1 Mt carbon dioxide have been injected over a 3-year period. In the USA alone, it is claimed that ECBM operations could provide 4.25 Tm3 of technically recoverable methane and a further 0.8 Tm3 of ‘proven reserve’, with the storage of correspondingly large quantities of carbon dioxide. According to the International Energy Agency, the world potential for carbon dioxide storage through ECBM is 100–150 Gt, of which 40 Gt are considered to be viable now. To put this capability into perspective, it is interesting to compare the predictions with the world energy-related emissions of carbon dioxide which, in 2005, amounted to 28.1 Gt carbon dioxide. All projections of methane recovery and the associated storage of carbon dioxide must be treated with caution, however, since the science involved in the uptake of gases by coal is imperfectly understood and complications may arise. There are also safety and environmental issues to be evaluated. Ocean Storage A number of authorities favor deep ocean storage of carbon dioxide, in one form or another. The oceans are believed to contain some 50 times as much carbon as the atmosphere. Moreover, oceans are mainly responsible for the natural sequestration of approximately half of the carbon dioxide that is produced by mankind. Therefore, why not inject the other half for ultimate disposal? Shallow injection of carbon dioxide into an ocean is not an option as it would cause a regional lowering of the pH with almost certain disastrous ecological consequences. Even now, there is grave concern among marine biologists over the acidification of the oceans that has already taken place. Deep injection is a different matter. The density of seawater is almost independent of depth (1.040– 1.045 g cm3), whereas that of liquid carbon dioxide increases with depth. Down to about 2500 m, liquid carbon dioxide is less dense than seawater and tends to float upward. Deeper than 3000 m, the liquid is denser than seawater and sinks to the ocean floor where it accumulates as a lake, over which a solid layer of crystalline hydrates forms as an ice-like combination of carbon dioxide and water. Within its stability range (low temperature, high pressure), solid carbon dioxide-hydrate would inspire greater confidence as a permanent store than dissolved or liquid carbon dioxide. Storage on the ocean floor requires the carbon dioxide to be in liquid form. It could be conveyed to the storage site either by pressurized pipeline or cryogenically by ship. The objections to this form of storage revolve around the unknown ecological impact on marine species that live at these great depths. Also, there is the threat that ocean currents or volcanic activity might lead to dispersal of the crystalline hydrate and progressive

absorption into the ocean water, again lowering the pH with all the anticipated consequences. Recently, an entirely new procedure for ocean disposal has been proposed by scientists working at Harvard and Columbia Universities. They suggest that the gas should be pumped a few 100 m into the porous sediment that covers the deep ocean floor. Under the prevailing conditions, the carbon dioxide would be in liquid form and would soon convert into crystalline hydrate, which would then be locked into the structure of the sediment. It is surmised that the crystalline hydrate would dissolve only very slowly into the ocean over a period of hundreds of years and that no ecological damage would result. This proposition is seen to have material advantages over other methods of sea disposal. The scientists further highlight the fact that the number of ocean sites for containment in porous sediment is virtually unlimited and, therefore, would allow for the storage of all of the world’s captured carbon dioxide indefinitely, with little or no ecological ramifications. Liquid carbon dioxide would be conveyed to the given location by ship or pipeline and then injected into the sea floor by means of the standard technology used in oil extraction. At present, this concept is little more than an interesting proposal; considerable work is required to evaluate the prospects, determine the costs, and provide the necessary reassurance to marine biologists. Meanwhile, it is probable that land-based geological storage will continue to be developed. Institutional Issues Although geological storage of carbon dioxide does appear to be technically feasible, and indeed is being practiced in a few places, its extension to effect the ultimate disposal of most of the global emissions from fossil fuels does raise numerous institutional and safety issues. In economic terms, storage space will have a financial value in an era of emission permits and/or carbon taxes. The worth of a particular facility will depend upon many factors, for example, its location, size, ease of access, integrity. Owners of suitable underground sites, of whatever nature, will be able to charge customers for their services. Already this is the case where storage is in operation. A free market is likely to develop, in which the disposer of the carbon dioxide will negotiate a price with the facility owner. This raises the question of who is the legal owner of each underground site. Most countries have defined mineral rights, but these do not generally extend to great depths where mining is impracticable. For oil and gas exploitation within territorial waters, governments normally invite tenders and sell franchises to the highest bidder. But who owns deep-lying saline aquifers that have no other obvious use? On-shore, are these the property of the landowner? Off-shore, will governments put such storage sites out to tender as with

Fuels – Hydrogen Production | Coal Gasification

oil and gas franchises? Furthermore, who would approve deep ocean storage in international waters? Satisfactory answers have yet to be found. Further legal issues relate to the status of captured carbon dioxide. Is it a waste that, under international treaty, cannot be disposed of at sea? Or is it a ‘resource’ when used, for example, to enhance oil recovery? And do the conventions relating to dumping at sea apply to storage under the sea bed, particularly if the only access is through a pipe from the land? Hence there is much scope for international debate before an agreement can be reached. In the meantime, some new power stations are being built ‘capture ready’ rather than incur the considerable capital costs of building capture units before the ground rules relating to storage have been agreed. It has even been suggested that stored carbon dioxide might be seen as a long-term resource to increase the greenhouse effect during the next ice age! These and many other institutional, legal, and safety matters remain to be resolved before the large-scale storage of carbon dioxide can be adopted, particularly when off-shore or in the deep ocean. For the present, it appears that geological storage in disused oil and gas wells, or saline aquifers, are the most likely possibilities, although storage in ocean bed sediments remains an interesting possibility.

Future Prospects of Coal Gasification With the huge global reserves of coal available as a primary source of energy, nations are now seriously considering the various options for clean coal technology and hydrogen as a fuel. It is recognized that the effective and economic separation of carbon dioxide, both from postcombustion flue gases and from pre-combustion syngas, are key steps in developing clean coal technology as a prelude to the Hydrogen Economy. The problem with capture is that the bulk extraction of carbon dioxide from other gases is costly. Consequently, more research and development is required on novel separation techniques, particularly on membrane technology as applied to the processing of hot, pressurized gases to produce pure hydrogen. Membrane processes for the separation of oxygen from air are also important in the further development of gasification procedures. Commercial coal gasifiers are now well established and there are many different types in operation. The development of the different designs is, in part, a reflection on the variability of coal as a feedstock; it is necessary to match the gasifier employed to the type of coal available. Key issues when specifying a gasifier are: the scale of operations; the desired flexibility of feedstock; the composition of the product syngas; energy efficiency and environmental considerations; reliability

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and maintainability; ash/slag removal arrangements (and possible markets for this by-product); and, of course, capital and running costs. Each of these broad areas breaks down into many detailed considerations that invariably lead to the requirement for improved technology. For instance, technical factors include the following. Procedures adopted for preparation of the coal and • the impact of these on the life of the feed injectors and

• • • •

the performance of the gasifier. Improved feeding systems for high-pressure gasifiers. Robust refractory liners in high-temperature slagging gasifiers and the need for new materials of longer operating life and reduced cost. Better instrumentation and a requirement for on-line monitoring of conditions in the gasifier. Advanced hot gas-cleaning and particulate filtration procedures.

These are mentioned merely as examples of the detailed considerations that have to be given to gasifier selection and design. There are other important issues (beyond the scope of this article) that will determine how rapidly coal gasification is expanded in the electricity supply industry. Chief among these is the fervor with which society addresses the issue of climate change and the level of carbon emission taxes imposed. Another important factor is the long-term future of the electricity supply industry. Will the current practice of centralized generation and long-distance transmission through the grid be continued, or will there be a movement toward more localized generation and distribution? If hydrogen-based fuel cells are to make a significant impact, then the latter model becomes more likely. Also the growth of combined heat and power schemes (co-generation) would make localized generation more probable. These are imponderables at present. What does seem likely is that, in the medium term, all energy prices will continue to rise and consequently there will be a premium on processes with high-energy efficiency and low cost. Finally, there is the question of carbon dioxide sequestration, which must be addressed earnestly. Coal will be deemed unacceptable as a fuel unless sequestration is included. At present though, pending advances in technology, carbon dioxide capture will result in a serious degradation of energy efficiency and increased carbon dioxide emissions, which are equally unacceptable. This is a dilemma that can only be solved by aggressive research and development on gas separation techniques. Experience of geological disposal is limited to just a dozen or so projects, in which gas is injected into oil or gas reservoirs or saline aquifers. Many of the activities are in their early stages and, although so far promising, it will be some time before the results can be fully evaluated. While these and future demonstration projects are

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on-going, there is much to be done in terms of geological mapping, matching large point sources of carbon dioxide to prospective storage sites, and establishing the underlying institutional framework for the long-term monitoring and control of the repositories. Taken in the round, it is clear that society faces massive issues in the large-scale implementation of clean coal technology for the production of electricity and the manufacture of hydrogen to be used in fuel cells. Some of these can be solved by industry alone, but many are contingent upon governments setting the appropriate legislative and financial frameworks within which industry must act. If climate change is to be contained then, according to the climate scientists, there is no time to be lost.

Nomenclature Abbreviations and Acronyms ECBM IGCC PFCC PSA

enhanced coal-bed methane integrated gasification combined cycle pulverized fuel coal combustion pressure swing adsorption

See also: Fuel Cells – Molten Carbonate Fuel Cells: Overview; Fuel Cells – Overview: Introduction; Fuel Cells – Phosphoric Acid Fuel Cells: Systems; Fuel Cells – Proton-Exchange Membrane Fuel Cells: Cells;

Overview Performance and Operational Conditions; Fuel Cells – Solid Oxide Fuel Cells: Systems; Fuels – Hydrogen Production: Autothermal Reforming; Gas Cleaning: Barrier Filters; Gas Cleaning: Membrane Separators; Gas Cleaning: Pressure Swing Adsorption; Natural Gas: Conventional Steam-Reforming.

Further Reading Childress J and Childress R (2004) 2004 World gasification survey: A preliminary evaluation. Proceedings of Gasification Technologies 2004. Washington, DC, USA, 4–6 October. Collot A-G (2003) Prospects for Hydrogen from Coal Report CCC/78. London: International Energy Agency Clean Coal Centre. Dell RM and Rand DAJ (2004) Clean Energy. Cambridge: The Royal Society of Chemistry. Freese B (2003) Coal: A Human History. Chatham: Mackays of Chatham plc. Gasification Technologies Council (2008) Gasification: Refining Clean Energy. Arlington, VA: Gasification Technologies Council. International Energy Agency (2006) Key World Energy Statistics 2006. Paris: International Energy Agency. National Research Council and National Academy of Engineering of the National Academies (2004) The Hydrogen Economy: Opportunities, Costs, Barriers, and R&D needs. Washington, DC: The National Academies Press. Rand DAJ and Dell RM (2008) Hydrogen Energy: Challenges and Prospects. Cambridge: The Royal Society of Chemistry. US Department of Energy (2000) Clean Coal Technology; Topical Report No 20: The Wabash River Coal Gasification Repowering Project, An Update. Washington, DC: US Department of Energy. US Department of Energy (2004) Basic Research Needs for the Hydrogen Economy. Washington, DC: Office of Science, US Department of Energy. World Coal Institute (2004) The Role of Coal as an Energy Source. London: World Coal Institute.