POWER GENERATION FROM FOSSIL RESOURCES

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1 5 POWER GENERATION FROM FOSSIL RESOURCES

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3 5.1 Large-scale electrical generation systems Introduction This chapter describes the various technologies for converting the chemical energy of fossil fuels into electricity. Only large-scale plants (indicatively, P e 100 MW) producing solely electrical energy and powering high-voltage distribution grids will be dealt with here. Other technologies addressed in following chapters are: medium-to-large size plants for the combined production of electrical energy and heat (cogeneration, see Chapter 5.2) and small-scale distributed generation systems interfaced to middle- and low-voltage distribution grids (see Chapter 5.3). Evolution of global demand for electrical energy One constant trend common to all societies and economies is the continuous, progressive increase in demand for electrical energy, in both relative and absolute terms, due to its being the cleanest, most highly valued energy available. Over the last 30 years (Fig. 1), the global demand for electrical energy has increased by over 50% (from less than 10% to more than 15% of the total energy used worldwide) in contrast with the direct exploitation of fuels, which has decreased considerably (for the most part coal, although to some extent, oil) despite the fact that oil products still maintain their dominant role in the field of transportation. The consumption rates shown in Fig. 1 refer to all energy sources (fossil, nuclear, hydroelectric and other renewable sources). The values for fossil fuels refer to the energy content of the raw fuels, before being subjected to any refinement process, and include cogeneration applications. Fig. 2 shows the electricity consumption trends by sector in Mtoe (1 Mtoe 11,630 TWh). Consistent growth has been experienced in all sectors (the average yearly increase in global consumption over the last decade is in the order of 500 TWh/yr). The greatest increases have been in Fig. 1. Evolution of total global energy consumption by source for 1973 and 2003 (IEA, 2005). combustible renewables and waste* 14.3% natural gas 14.6% electricity 9.5% other** 1.7% oil 46.5% coal 13.4% combustible renewables and waste* 14.0% electricity 16.1% natural gas 16.4% other** 3.5% coal 7.4% oil 42.6% * prior to 1994 combustible renewables and waste final consumption has been estimated ** other includes geothermal, solar, wind, heat, etc. VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY 377

4 POWER GENERATION FROM FOSSIL RESOURCES Fig. 2. Evolution of world electricity demand from 1971 to 2003 (IEA, 2005). world electricity demand (Mtoe) 1,200 1, industry transport other sectors residential uses, the service sector, public services and agriculture (indicated as other sectors in Fig. 2), all areas where the trend towards ever-increasing dependence on electricity, a clean, efficient and therefore highly-prized vector, is irreversible. (The portion of electricity demand currently satisfied by cogeneration systems are, instead, not included in Fig. 2.) It is widely held that, barring any unforeseen obstacles, this thirty-year trend will continue, essentially unabated, in coming decades. Therefore, it is anticipated that the demand for new generation capacity will continue at a constant rate of over 100 GW/yr, which will thus have to be met by new installations. The resulting new capacity will be directed, in part, to satisfying the abovementioned increasing global demand for electricity and, in part, to replacing obsolete systems, particularly coal-fired plants (over 60% of the coal-based capacity installed in Europe is over 20 years old, a figure that in the United States reaches 80%). Although a large number of these new plants will be located in developing countries (particularly China and India), significant growth in the number of plants is also foreseen in heavily industrialized areas. For example, Europe, whose installed capacity at the turn of the millennium was in the order of 600 GW, is expected to increase its overall capacity by nearly the same amount by 2030 (i.e. 550 GW). About two-thirds of this is destined to replace obsolete central power stations, while the remaining one-third will go to satisfying the increase in demand of electrical energy. Analogous growth scenarios are also expected in the United States as well. Contribution of fossil fuels to satisfying the demand for electrical energy Fig. 3 shows the breakdown of the energy sources used to meet the global demand for electrical energy and its evolution over time. Although the period considered ( ) includes the boom years of nuclear power (a phenomenon that is not likely to be repeated in the next twenty years), the overall contribution of fossil fuels remained consistently very high; among fossil fuels, the use of natural gas rose substantially, while the role of coal increased only slightly and the consumption of oil products fell sharply. Table 1 shows the breakdown of the energy sources supplying electricity according to geographical area; the overall electrical energy produced amounts to 16,670 TWh and the contribution of fossil fuels is over 60% in all areas, with the exception of South America, where hydroelectric systems play a dominant role. The overall share of fossil fuels is in the order of 11,000 TWh (29.2% from natural gas, 60.4% from coal and 10.4% from oil). Apart from fossil fuels, the only technologies that contribute significantly to current electricity generation are large-scale hydroelectric and nuclear plants; wind, solar and geothermal sources furnish only marginal contributions In the likely scenario of business as usual, the role of fossil fuels is expected to grow even further in coming years; although the use of renewable energy sources is expected to increase greatly, their contribution, in absolute terms, will remain limited. Moreover, it is unlikely that nuclear or hydroelectric technologies will manage to maintain their current share of energy production. The standard energy sources for meeting the world s demand for electricity will continue to be coal and gas. For this reason, a large part of this chapter is dedicated to plants based on these two types of fuels. The dominant technology of the Twentieth century: the external-combustion steam cycle In the Twentieth century, the dominant technology for the production of electrical energy from fossil fuels was the steam power station; its two fundamental features are external combustion and the steam cycle. There are many advantages in combining external combustion with the steam cycle; the most important ones are the following: As combustion is external, the path followed by the fuel and the combustion products is completely isolated from the working fluid. This enables using 378 ENCYCLOPAEDIA OF HYDROCARBONS

5 LARGE-SCALE ELECTRICAL GENERATION SYSTEMS Fig. 3. Breakdown by energy source of global electricity generation (IEA, 2005). world electricity generation (TWh) 18,000 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2,000 other hydro nuclear thermal any type of fuel, even low quality ones, such as coal, orimulsion (an aqueous bitumen emulsion produced in the Orinoco Belt in Venezuela), heavy oil fractions and, in the near future, bituminous schists, without contaminating or compromising the integrity of the surfaces in contact with the working fluid of the power cycle (turbine blades, heat transfer surfaces). As the power cycle consists of a closed loop (the fluid in the cycle always remains the same: water), it is possible to use a fluid that undergoes a phase change, condensing from the gaseous state to the liquid phase when it releases heat, thereby obtaining two important advantages that are precluded in gas cycles and are peculiar to steam cycles. These are, firstly, that heat transfer to the environment takes place through an isothermal process, with the consequent possibility of exploiting only small temperature differences during the entire process of heat exchange between the working fluid and the environment and, secondly, that the working fluid is compressed in the liquid phase; thus, very high operating pressures can be attained with modest energy expenditure. These advantages make the steam thermodynamic cycle a high-quality one. That is, high efficiencies can be achieved, even when operating at relatively modest maximum temperatures; an average steam plant, operating at a maximum temperature in the order of 550 C, can attain net electrical efficiencies (electrical energy/fuel chemical energy) of over 40%. Such efficiency is superior to that obtainable even with today s most modern industrial gas turbine plants which, however, operate at maximum temperatures near 1,400 C and are based on turbines operating under extremely complex fluid dynamic conditions. On the other hand, the combination of external combustion and the steam cycle also involves considerable disadvantages: External combustion calls for heat transfer surfaces operating at temperatures higher than the Table 1. Breakdown (by percent) of electricity generation by energy source and geographical area (data 2003) Energy source Europe North America South America Africa Asia Oceania World Hydroelectric Wind Solar Thermoelectric Geothermal Nuclear Total energy generated per continent in relation to world production VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY 379

6 POWER GENERATION FROM FOSSIL RESOURCES temperature of the working fluid. The high pressures attained by steam require primary heat exchangers made of metal. This limits the maximum possible temperature of the power cycle, thereby reducing the efficiency of the cycle. The current state of the art allows for maximum steam temperatures of about 600 C, in contrast with 540 C in the 1980s and C in the 1990s. The technological and, especially, economic difficulties associated with increasing the maximum temperature to 700 C, for example, seem insurmountable at present (Table 2) given that increasing the temperature calls for tubes with higher thickness to diameter ratios, on the one hand, because of the greater pressure to be withstood, and on the other, because at such high temperatures materials become less resistant. The steam cycle is not suitable for the adoption of very high temperatures, not only because of the technological and economic aspects mentioned above, but because the critical point of water (373 C) is decidedly lower than the temperatures permissible in the current state of the art of metal materials science. Even adopting cycles with various stages of superheating, the fraction of heat transferred to the relatively low-temperature cycle remains high. In principle, this obstacle could be overcome via two different approaches: either by using a different working fluid with a higher critical temperature than water, or by completely abandoning steam cycles in favour of gas cycles, which allow heat to be introduced into the high-temperature cycle without any limitations on pressure. Although neither of the two approaches, which have been under investigation for several decades, appears technologically mature or economically competitive, they could achieve net efficiencies of over 50%. In the first case, current research is focussed on liquid metal/water steam binary cycles (Fig. 4), with Table 2. Comparison of the unit costs of superheater tubing for steam generators operating at 600 C and 700 C Dimensions, mm (inner diameter thickness) T max 600 C T max 700 C Material P91 Alloy A617 A130 Material cost per kg Material cost per metre 1,100 16,600 Ratio of costs per metre for equal gauge 1 24 temperature ( C) potassium cycle steam cycle entropy (kj/kg K) Fig. 4. Schematic representation of the temperature-entropy plot of a potassium-water steam binary cycle. intermediate bleedings from the topping turbine (potassium) to minimize the temperature differences between the two cycles. The second approach focusses on solutions based on high-temperature ceramic exchangers that transfer high-temperature heat to compressed air before it enters the turbine, where it expands. Combustion is initiated and the exhaust fumes are ducted to the ceramic exchanger and then to the steam section. Such solutions (Fig. 5) are termed EFCCs (Externally Fired Combined Cycles). In confirmation of the excellent characteristics of water/steam as the working fluid for medium-to-low temperature thermodynamic cycles, both approaches call for the adoption of a combined cycle: the primary cycle (topping) absorbs high-temperature heat, while a secondary cycle (bottoming) utilizes steam as the working fluid. Emerging alternative technologies: internal combustion power plants Until twenty years ago, internal combustion plants found little application in large fossil fuel fired power stations, the only exception being gas turbines, adopted because of their low cost and their ability to quickly adapt their output to load variations. Thus, they served as backup units to satisfy peak demand and were consequently operated only for short periods (often as little as hundreds or even tens of hours per year). High fuel (often gas-oil) costs and their low efficiencies discouraged their use for energy generation to satisfy base or average loads (mid-merit, see below). With the advent of combined gas/steam cycles and the widespread distribution of natural gas, the picture changed radically, and a significant proportion of world orders for new installations over the last twenty years are based on the use of natural gas in combined cycles. From a conceptual perspective, adopting internal combustion offers important advantages (all linked to 380 ENCYCLOPAEDIA OF HYDROCARBONS

7 LARGE-SCALE ELECTRICAL GENERATION SYSTEMS Fig. 5. Schematic representation of an EFCC (HRSG, Heat Recovery Steam Generator). 120 C HRSG filter 600 C 420 C ceramic heat exchanger 1,250 C 1,400 C electric generator C electric generator 2 combustor fuel steam turbine air compressor gas turbine 600 C the lack of a heat exchanger, given that the working fluid itself undergoes combustion): The walls in contact with the hot fluid are several orders of magnitude smaller than those of the primary exchanger in an external combustion system of equal power, as the pressures they must withstand are far lower; thus, even very expensive materials can be used in their construction without however incurring excessive costs. Cooling mechanisms can be implemented to maintain the surfaces in contact with the working fluid at very low temperatures; for example, in modern gas turbines, the gases enter the turbine at temperatures in the order of 1,400 C, while the temperatures of the superalloys constituting the blades never exceed C. The disadvantages of internal combustion stem from the fact that the working fluids must necessarily be air before combustion and then, following combustion, exhaust gases. As in all gas cycles, this means that isothermal processes are not possible. The stage of heat transfer to the environment, in particular, takes place at constant pressure through the release into the atmosphere of hot gases through a completely irreversible process, which heavily penalizes the thermodynamic quality of the cycle, and therefore its efficiency. Moreover, the internal combustion solution requires the use of clean, high-quality fuels, which generally means higher specific costs. In practice, modern gas turbines call for gaseous fuels (natural or synthetic gas) or suitably purified liquid fuels. The combination of low efficiency and expensive fuel makes simple gas cycle turbines unattractive for base-load electrical generation, despite their being the simplest, most compact and least expensive of all plant designs. Therefore, the best solution to date is represented by the combined cycle, which, as mentioned, involves combining an open upper cycle (costitued by a gas turbine) and a closed lower cycle (made up of a steam cycle that recovers the heat of the turbine exhaust gases), able to exploit the specific advantages of the two different cycles involved. As in open cycles, combined cycles make use of internal combustion, which enables the attainment of high temperatures, while, like a closed steam cycle, they release heat into the environment at low temperatures, for the most part through the isothermal, isobaric process of condensation, while the remaining heat exchange occurs through dispersion into the atmosphere of the products of combustion, by then at temperatures (about C) near that of the environment (Fig. 6). The two cycles are coupled through the transfer of the heat of the turbine exhaust gases to the steam cycle. The heat transfer process is optimized, which signifies that the temperature difference between the medium releasing heat and the medium that receives heat is minimized at all points of the exchange, thanks to the temperature heat input to gas cycle heat from gas cycle to steam cycle gas cycle steam cycle heat released to environment Fig. 6. Temperature-entropy diagram of a combined cycle. ambient temperature entropy VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY 381

8 POWER GENERATION FROM FOSSIL RESOURCES multiple evaporation levels. The result (see Section 5.1.4) is a net electrical efficiency which, in the current state of the art, reaches values of about 58% under nominal conditions. Such levels are unattainable by closed cycles. In the case of clean fuels (liquid or gas), the most logical solution is to carry out combustion in a gas turbine inserted in a combined cycle. The most widespread technique for using low-quality liquid or solid fuels with a gas turbine is gasification (see Section 5.1.5) by means of various system designs integrated with the combined cycle, all known as IGCC (Integrated Gasification Combined Cycles). In the case of solid fuels, an interesting alternative approach (which, however, has yet to produce any meaningful applications to date) is the use of pressurized fluid-bed combustors; the pressurized products of combustion are first cleaned, then allowed to expand in a gas turbine which in a normal combined cycle fed the exhaust gases with a recovery boiler, and the steam cycle may also receive additional heat from coal combustion. Future prospects In the decades to come, a large deal of electricity will continue to be produced by power stations fed with coal and natural gas. Over the last decade, the application of natural gas-fired combined cycle technology has increased considerably, exceeding that of steam-based systems in terms of newly built or contracted plants. This trend is likely to continue throughout most of the world, especially where environmental issues are most keenly felt (Europe, Japan, and the United States, where natural gas is expected to have a predominant role over coal). The prospects in the emerging countries (e.g. China, India) are different; coal will continue to be the energy source of choice for electrical energy generation. Future energy choices, in particular the relative contributions of natural gas and coal to electrical energy production, will be heavily influenced by a number of factors. The price trends of the two fuels, which are difficult to predict, will play a fundamental role in the choices made by energy suppliers; recent years have seen significant fluctuations (Fig. 7) not only in the price of natural gas (traditionally influenced by oil prices), but also in that of coal, the cost of which had previously been held quite stable. Furthermore, it is interesting to compare the specific costs associated with electrical energy generation by two modern plants: a coal-fired steam-electric power station and a natural gas fired combined cycle. For the purposes of the comparison, the following hypotheses have been assumed: Both are state-of-the-art, in terms of both energy performance and pollution-control. Both are base-load power stations, that is, operating for 7,000-8,000 h/yr. The specific costs of the fuels during the lifetime of the plants do not diverge significantly from the average values recorded over the last five years (assumed in the following to be 2.2 /GJ for coal, and 5 /GJ for natural gas). The results reveal a situation of substantial balance, with overall costs (investment operation fuel) in the order of 45 /MWh, although the breakdown of the various contributing items for the two cases is significantly different (Table 3). In brief, while the investment and operation costs account for over 63% of the overall cost in coal-fired plants, for natural gas fired combined cycles the most important factor by far is represented by fuel costs. Therefore, if the specific cost of natural gas were to rise significantly beyond the assumed value, the coal solution would be more Fig. 7. Price of fossil fuels over the last fifteen years. price ( /GJ) natural gas coal heavy fuel year ENCYCLOPAEDIA OF HYDROCARBONS

9 LARGE-SCALE ELECTRICAL GENERATION SYSTEMS Table 3. Percentage contribution of various cost items to the overall cost of the electricity generated by a modern pulverized-coal steam turbine plant and a modern natural gas combined-cycle power station. Item Ultrasupercritical coal dust station Natural-gas combined cycle Capital investment Operations and Maintenance Fuel Total competitive, while the opposite would be true in the event of a return to Twentieth century natural gas prices. With reference to the type of plant, one important determining factor is that the demand for electrical energy varies widely over the course of a year, with demand peaks that are normally more than double the minimum. Even if a portion of the necessary production adjustments to load can be covered by hydroelectric systems or pumping storage systems, a significant number of new fossil fuel fired plants will be required to operate ever more frequently at varying loads, with frequent shut-downs and restarts. Power stations are conventionally grouped into different functional categories on the basis of the equivalent hours of yearly operations (ratio between the energy produced yearly and nominal net power capacity): base-load ( 5,000 h/yr), middle-load (between 2,000 and 5,000 h/yr) and peak-load ( 2,000 h/yr). Coal plants only operate well at base load. For peak-load plants, the best solution is a simple-gas cycle turbine, as they have low capital costs and are highly flexible. Analyses of all reasonable costs scenarios reveal that combined-cycle systems are unbeatable for satisfying middle loads (Fig. 8), while the relative economic competitiveness of natural-gas combined cycles and coal-fired plants for operation as base-load stations depends for the most part on the cost of natural gas, as has already been pointed out above. As far as the evolution of regulations on plant emissions is concerned, following increased interest in environmental issues over the last few decades, electricity suppliers have been forced to meet ever more stringent requirements for toxic emissions; not only have the emissions standards required by law become stricter by the decade, but local situations often impose even tougher limits than general governing regulations. Moreover, the limits set on some power stations under construction are often an order of magnitude lower than those currently required; for example, at the Hekinan plant in Japan (2 1,000 MW) the required specific emissions of NO x and SO x are below 30 and 75 mg/nm 3 respectively (both referred to 6% O 2 molar concentration in the exhaust gases) values that were unthinkable up to only a few years ago. Obviously, such a trend has made plants more expensive and complex to run and has moreover prompted the development and adoption of the cleanest possible fuel natural gas for new plant construction. However, not even natural gas-fired combined cycles are immune to the need to adopt more expensive and complex solutions; although today s most sophisticated premixed flame burners can attain NO x emissions levels below 30 mg/nm 3 (with 15% O 2 ), some regulations (for example, in Japan and California) call for limits that can only be reached by Selective Catalytic Reduction (SCR). The energy costs considered in Table 3 do not take into account the possibility of a carbon tax. If, following concerns over climatic changes, the cost items associated with electrical energy production were to include an expense linked to CO 2 emissions, the relative economic competitiveness of coal and gas described above could change radically (Fig. 9). First of all, a relatively moderate carbon tax would favour natural gas (which discharges substantially lower specific emissions than coal-fired plants) whereas a high carbon tax would instead favour near-zero emission solutions (nuclear power). As far as fossil fuels are concerned, it would be necessary to resort to the capture and subsequent geological storage of the carbon dioxide discharged, a process known as Carbon Capture and Sequestration (CCS), which would be possible for both natural gas and coal plants, although such technology involves significant investment costs and disadvantages in terms of efficiency. yearly operating costs peaking power station (simple cycle gas turbine) combined cycle (low natural gas price) combined cycle (high natural gas price) coal power station yearly equivalent hours of operation Fig. 8. Plot of yearly operating costs-equivalent hours for different types of fossil fuel power stations. VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY 383

10 POWER GENERATION FROM FOSSIL RESOURCES cost of electricity ( /MWh) carbon tax ( /t CO 2 ) natural gas fuelled combined cycle (4 /GJ) natural gas fuelled combined cycle (6 /GJ) USC coal fuelled power station natural gas fuelled combined cycle with CO 2 sequestration (4 /GJ) natural gas fuelled combined cycle with CO 2 sequestration (6 /GJ) IGCC fuelled by coal with CO 2 sequestration wind farm nuclear power station Fig. 9. Effects of a carbon tax on electricity costs for various conversion technologies Steam electric power stations To date, power plants based on the water/steam thermodynamic cycle are the undisputed leaders in the production of electrical energy. They are adaptable to a wide variety of primary energy sources: fossil fuels of various types and qualities, nuclear fuel, renewable sources such as biomass, solar thermal energy, urban solid waste and others. The adaptability of the steam cycle to different fuels stems from the fact that such systems operate in a closed cycle (see above), which protects the machinery s most delicate components (turbine, heat exchangers) from contact with the contaminated products of combustion. Moreover, two important characteristics of steam cycle have been exploited for the adoption of modest technologies. One is the capacity of water steam to take up and give off heat at a constant temperature during a phase change, enabling the achievement of acceptable efficiency levels without the need for high temperatures and the other is that the work output of the expansion phase that generates power is much higher than the work input required to compress water. These two characteristics have been known since the industrial revolution and have determined the feasibility of converting thermal energy into mechanical energy. Although steam technology is well known and widespread today, after more than two centuries it is still undergoing important developments in terms of improving energy-conversion efficiency and reducing polluting emissions that are discussed below. Evolution of the water steam cycle In its simplest form, the steam cycle (Rankine cycle; Fig. 10 A), involves the following four processes: a) an increase in the pressure of the working medium from a low to a high value realized by a pump; b) conversion of water into steam at constant high pressure (isobaric); this is carried out in a heat exchanger (Steam Generator, SG), where the working fluid is heated and evaporated to generate saturated steam; c) expansion, during which pressure falls, producing mechanical work; d) isobaric and isothermal conversion of the water back to the liquid phase, carried out in a heat exchanger (condenser). Heat is absorbed by the working medium in part at varying temperatures, during heating of the liquid up to saturation, and in part at a constant temperature, during evaporation. Such a cycle has numerous drawbacks: The necessary heat is absorbed by the liquid at low temperatures, which is not very efficient. In fact, the higher the temperature at which heat is absorbed, the higher the efficiency of heat input and, vice versa, the lower the temperature at which it is released to the environment, the higher the efficiency of heat output or return. In the case of heat input and return at variable temperatures, the parameter utilized to describe the process is the mean transformation temperature, defined as Dh/Ds (where h and s are the specific enthalpy and entropy of the fluid as it evolves during the cycle). During expansion, the fluid remains within the phase transition curve and thus droplets of liquid are formed, which apart from decreasing cycle efficiency, also create problems in the turbine; as the liquid particles are far more dense than steam, their impacting the turbine blades causes erosion, which drastically reduces the lifetime of the turbine. In practice, it is impossible to reach even relatively high temperatures. Increasing the pump delivery pressure, and thereby the evaporation pressure, would increase the corresponding temperature; however, this would also exacerbate the aforementioned negative effects of droplet formation. The first drawback can be overcome, at least in part, by means of Feed Water Heating (FWH); in order to properly heat the low-temperature fluid (the feed water), a low temperature heat source is used rather than the valuable high-temperature heat produced by combustion of the primary energy source. This low-temperature heat 384 ENCYCLOPAEDIA OF HYDROCARBONS

11 LARGE-SCALE ELECTRICAL GENERATION SYSTEMS source is produced by extracting an appropriate anount of steam from the turbine, theoretically at a pressure corresponding to the temperature to which the liquid is to be heated (actually, it is extracted at a slightly higher temperature to ensure a reasonable DT for heat transfer). Steam condenses in the exchanger (Fig. 10 B), heating the liquid at high pressure, and the condensate is sent to the hot well of the condenser. The regeneration process is shown in Fig. 10B for a single-feed water heater, whereas, in practice, it is usually accomplished by the rather high number (6-10) of feed-water heaters. The technique of SuperHeating (SH) steam is decisive (Fig. 10 C) in increasing the temperature at which heat is introduced into the cycle and, at the same time, in solving the problem of the presence of liquid in the turbine. Although superheated steam increases efficiency by raising the mean temperature at which heat is absorbed by the working fluid, its implementation involves subjecting plant components to very high temperatures. Thus, high temperature materials must be utilized. Repeatedly superheating (RH, ReHeating) steam is the key to obtaining high conversion efficiencies because it allows the adoption of very high evaporation pressures (and therefore even higher T A T B T C saturated cycle regenerative cycle superheated cycle S S S SG SG SG SH Fig. 10. Conceptual schemes for three types of steam cycles. temperature heat input to the cycle), without incurring the serious problems caused by liquid in the turbine. Performance The performance of a thermodynamic cycle (its efficiency, in particular) is determined by the performance of the plant components (turbine, boiler, etc.), as well as the operating parameters and the type of cycle. An analysis of plant components will be taken up later whereas the following will examine the main operating parameters that determine the thermodynamics of the cycle as well as the plant design. Maximum cycle temperature. An increase in the temperature of the steam leaving the superheater and the reheaters yields considerable increases in the efficiency of the cycle, in that, as already stated, it raises the mean temperature at which heat is introduced into the cycle. Moreover, it reduces the likelihood of liquid forming in the turbine by shifting the expansion curve of the steam toward the right (see again Fig. 10C). The steam temperatures obtainable are limited by the heat-resistance of the metal materials used to build the plant components: the superheater and reheater tube banks, the superheated steam collectors, the pipelines connecting the boiler to the turbine, the turbine control valves, the turbine casing and rotary blades (at least in the zones in contact with the high-temperature steam). Adopting particularly sophisticated materials, such as for example, the nickel-based superalloys used for the rotor blades of the gas turbines, is however prohibitive, owing to both the intrinsic cost of the materials and the sophisticated technology needed to manufacture these components. Nowadays, the materials most often used in modern plants are ferrite steels, although austenitic steels are also used to some extent; current research aims to develop the technologies for the widespread adoption of austenitic steels in the near future. The type of material used sets rather rigid limits to the steam temperatures achievable (Table 4); such temperatures vary from 538 C for standard steam-turbine units (with some applications reaching 565 C) to C for the most advanced technologies available. Some noteworthy research programmes aim to extend such limits to 700 C, but industrial applications at such temperatures will probably not be forthcoming until 2020, at the earliest. A rough estimate of the efficiencies that can be expected by adopting different materials, in relation to the maximum practicable temperatures and pressures, reveals that at 540 C and 170 bar pressure, efficiency is 42%, while at 560 C and 250 bar, it is 43-44%, and at 600 C and 300 bar it is 45%, and lastly, at 700 C and 350 bar, it can become as high as 47-48%. Maximum cycle pressure. At any given maximum temperature, increasing the maximum cycle pressure also involves an increase in the mean temperature at VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY 385

12 POWER GENERATION FROM FOSSIL RESOURCES Table 4. Indicative parameter values and net efficiency of steam turbine power stations Parameter Conventional technology Best available technology R&D goals Maximum cycle temperature ( C) Maximum cycle pressure (bar) Number of SH RH or or 1 2 Number of regenerators/feed-temperature ( C) 6-8/ /310 10/340 Net efficiency (percent) which heat is introduced into the cycle and therefore, as mentioned above, higher efficiency. However, the effects of liquid forming in the turbine must be evaluated in that increasing the pressure shifts the expansion curve of the steam to the left; the beneficial effects are therefore only fully realized when adequate superheating is carried out (in terms of the number and of the temperature reached). The ability to operate plants at pressures above the critical pressure of steam (221.2 bar) is based on wellestablished technology, known for decades. Thus, in practice, both subcritical (generally at 170 bar), as well as supercritical systems (usually at bar) are currently in use. Even higher pressures, in the order of 300 bar, have recently been reached (known as USC, Ultra Super Critical) and applied in some of the most advanced power stations. The pressures obtainable are obviously limited by the necessary dimensions of the components involved (steam generator tube banks, collectors and pipelines, tube banks of the hottest regenerators, steam generator tube connections, live steam valves, very high-pressure turbine sections). The thickness, and consequently the bulk and cost, of the components under pressure therefore become a determining factor; it is worthwhile recalling that, given equal diameter, the thickness of a pipeline is directly proportional to the pressure, while the thermodynamic benefits depend on the temperature (the average at which heat is input), which has an approximately logarithmic relation to the pressure. Thus, large increases in pressure are needed to achieve relatively small increases in temperature. Therefore, pressures significantly beyond 350 bar are not to be expected even in future systems. Minimum cycle pressure. Low pressure and consequently low condensation temperatures are accompanied by significantly higher cycle efficiency. The value of the condensation pressure is in fact determined by the availability of coolant at the plant site: indeed, an abundant supply of water for cooling the condenser is one of the main criteria for choosing a site to build a plant. Large power stations are often situated near the sea or other large bodies of water. Whenever possible, very low condensation pressures are adopted. Some Scandinavian plants utilize a nominal condensation pressure of bar (23 C) and achieve very high efficiency values. Moreover, In Italy, in the most advanced Italian plants, given a nominal seawater temperature of 18 C, the pressure is relatively low (0.042 bar, which corresponds to 29.8 C). In general, for any given temperature of the water available as coolant, the difference between the coolant temperature and that of condensation (DT C ) is determined by economic considerations, bearing in mind the increasing costs associated with decreasing DT C, the condenser heat transfer surfaces, circulation pumps, intake and discharge operations, and a larger turbine exhaust section. For central power stations cooled by evaporative towers or dry condensers (see below), the investment costs of heat discharge systems are higher and shift the economic optimum toward higher values of DT C : condensation pressures of or bar are frequent for evaporative towers and dry solutions, respectively, with evident negative consequences for efficiency. Number of regenerators. The advantages of utilizing regenerative systems to heat the feed water have been discussed above. By adopting a large number of regenerators it is possible to use steam at lower pressure to obtain the same heat transfer to the water, as it is likewise possible to obtain feed water at higher temperatures (see Table 4). Number of SH RH. Increasing the number of superheating stages has the same effect as increasing the maximum temperature, with the added benefit that more advanced materials are not needed. However, the investment costs associated with adopting an extra RH are substantially higher in that it involves adopting some crucial high temperature components (tube banks, turbine casing, piping, etc.). Therefore, conversion from a conventional single reheat solution (SH RH) to a 386 ENCYCLOPAEDIA OF HYDROCARBONS

13 LARGE-SCALE ELECTRICAL GENERATION SYSTEMS double reheat (SH RH RH) is not economical. Moreover, it must be borne in mind that increasing the steam temperature makes reheating less effective. Although the double RH technique is well established and has been utilized for many decades, even in the most modern high-tech, high-performance designs, adopting a single reheat cycle is generally deemed optimal from the economic point of view. Modern plant design In the light of what has been said so far, Fig. 11 illustrates the layout of a modern steam power station, specifically, a supercritical plant with double reheat. The station utilizes three low-pressure regenerators and four high-pressure ones, with a deaerator in between. Apart from acting as a regenerative exchanger (mixing water and steam at an intermediate pressure of about 5-7 bar), the deaerator carries out the important function of separating the gases dissolved in water, which occurs due to re-entry of air into the sections at subatmospheric pressures. At high temperatures, the dissolved gases, particularly oxygen, are highly corrosive, and must therefore be removed. This is accomplished by stripping the gases from a steam jet flowing in the direction opposite to that of the feed water in the deaerator. Then the gases are discharged into the atmosphere. Although the steam turbine is mounted on a single shaft, it is divided into different cylinders, between which the low-pressure flow is split (see below); a second turbine drives the main feed pump. Such an arrangement reduces the power requirements of the electrical machinery (and the associated losses), although its main purpose is to simplify the regulation of the flow rate of the circulating water. The upper portion of Fig. 11 shows the components found along the flow of the combustion air and exhaust gases: there are two fans for the circulation of air/fumes (a forced draught fan for the air and an induced draught fan for the exhaust, to maintain the combustion chamber at Fig. 11. Layout of a steam power station. (LP, Low Pressure; HP, High Pressure; IP, Intermediate Pressure; VHP, Very High Pressure). EXHAUST HANDLING line/limestone stack air FGD ammonia injection gypsum ESP FF SCR high dust final heat exchange air pre-heater POWER CYCLE crossover, 3 bar 580 C, 26 bar turbopump 580 C, 90 bar 580 C, 300 bar SH LP LP IP HP VHP RH1 RH2 leakages 0.05 bar condenser leakages 315 C deaeretor low pressure pre-heater condensate extraction pump feed turbopump HP pre-heaters pulverized coal VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY 387

14 POWER GENERATION FROM FOSSIL RESOURCES atmospheric pressure); the regenerative exchanger, which heats the combustion air by drawing heat from the exhaust gases; and lastly, the pollution control devices (nitrogen oxide Selective Catalytic Reduction, SCR; particulate matter Electro Static Precipitator, ESP; sulphur oxides Flue Gas Desulphuration, FGD) which will be addressed in more detail below. The diagram does not, however, include some of the many other auxiliary systems that make up a complete power station, such as, for example: the condenser cooling water circulation system, often with evaporative cooling towers; coal treatment system, which includes, pulverizing, conveying, etc.; makeup-water demineralization; the systems for the treatment of reagents and by-products of pollution control systems, as well as others, whose description is beyond the aims of this chapter. The steam turbine In water/steam plants, the fundamental component is the steam turbine. This is where the expansion of steam converts enthalpy into mechanical work. Large steam turbines are made up of a large number of axial flow stages grouped together in sections. It should be recalled that each stage includes a fixed blade (the stator or nozzle) and a mobile one (the rotor). Stages are classified into two types, impulse or reaction, depending on the arrangement of the blades and how the energy is extracted from them. An impulse stage is defined as one in which the entire expansion takes place in the stators; thus, the pressure is the same both upstream and downstream of the rotor (i.e. there is no pressure drop across the stage). In a reaction stage, instead, the pressure difference is split between the stator and the rotor. The main advantage of impulse-stage solutions lies in their ability to handle a larger enthalpy drop at equal peripheral velocities than reaction stages. On the other hand, reaction stages yield higher efficiencies. The characteristics of such axial-flow stages are determined by several dimensionless parameters: V ex V ex V N ex S w ; D S D/ ; VR 144 Dh is 3/4 Dh1/4 is V in where N S is the specific speed; D S the specific diameter; VR the ratio of volumetric expansion; Dh is is the isentropic enthalpy drop per unit mass; V ex and V in are the flow rates at outlet and inlet for the isentropic expansion respectively; w is the angular velocity of rotation and D the mean blade diameter (from base to tip). Given a certain speed of rotation, which in large units is dictated by direct coupling with the alternator (3,000 rpms for 50 Hz grids and 3,600 rpms for 60 Hz grids), and given a maximum admissible peripheral velocity (u w D/2), which depends upon the maximum centrifugal force sustainable by the constituent materials of the blades and wheels on which the blades are mounted (stress proportional to u 2 ), the maximum enthalpy drop, Dh is, achievable in a stage is proportional to u 2 /2 through a proportionality coefficient, K is, known as the load coefficient, which can vary only within rather narrow limits, from 2 to 5, for proper fluiddynamic sizing of the stage. With metal materials and current technology, the maximum enthalpy drop attainable by any stage is in the order of kj/kg, in contrast to an overall drop in enthalpy in the order of 1,500 kj/kg over the whole expansion. This would indicate the need to use at least ten stages, although in reality a much greater number is necessary due, for the most part, to the enormous volume change during the expansion of steam, which increases by about 3,000 times from entry to exit. In this repect: Parameter VR cannot reasonably exceed a value of for any single stage, in order not to cause wide variations in speed and, above all, to keep the operation within the subsonic field (the shock phenomena associated with supersonic flows penalizes efficiency). The need to maintain the specific diameter within an optimal range of values to achieve good efficiency calls for using smaller diameters for lower flow rates, which at equal rotational speed w would provide for smaller enthalpy drops and therefore the need for more stages, the high-pressure sections. The same conclusions can be reached by analysing the specific speed, a particularly important parameter because it significantly influences stage efficiency; at a low value of N S the blade height is small in comparison to the stage diameter. Such an arrangement involves high losses due to secondary flows (created at the casing and hub surfaces) and leakage through the clearance between the rotating blades and the housing. Instead, a high N S means that the blades are excessively long relative to their diameter, with the consequence that the difference in circumferential velocity between the blade root and its tip does not allow for adopting optimal velocity triangles along the entire radial extension of the blade. In fact, it is impossible to size all stages of a steam turbine (from first to last) with near optimal N S values (between 0.15 and 0.35 to attain high efficiencies). The flow rate is much higher than the value that would correspond to such a range. It should moreover be noted that the mass flow of steam turbines used in traditional plants actually decreases as expansion progresses, because of bleeding from the regenerative feed water system (the mass flow in the last stage is usually 55-60% of the first). In steam turbines for combined cycles, instead, the opposite occurs because steam produced at lower pressures is introduced, and this complicates the 388 ENCYCLOPAEDIA OF HYDROCARBONS

15 LARGE-SCALE ELECTRICAL GENERATION SYSTEMS problems consequent to variations in flow rate. In conclusion, steam turbines not only require many stages (30-40 and more), but the medium or low pressure steam flow must be split over two to four (sometimes even six) separate turbines in parallel, mounted on the same shaft (flow splitting). The basic technology for large-scale steam turbines was developed during the 1960s, when units with power capacities of MW e were successfully built. Over the last decade, significant progress has been made in blade design, following a better understanding of the causes of energy loss in the various mechanical components. Such advances have come mostly from the field of computational fluid dynamics and numerical methods, which have thrown further light on the state of mechanical and thermal stress in the blades. Advances in steam turbine design have come from three major developments: increased height of the low-pressure blades; the use of high-reaction mixed stages, even in the high and medium pressure sections; and the ever more widespread application of 3D-profile blades. As far as the first improvement is concerned, a good example of the technological progress made is the development of a 1,219 mm (48 ) steel blade mounted on a base 1,880 mm in diameter, with a tip-to-base diameter ratio of nearly 2.3 (Fig. 12). The outlet area is about 12 m 2, which consequently reduces the outflow speed and the associated discharge kinetic energy losses. With regard to the second advancement, an interesting fact is that even those manufacturers most committed to impulse designs are progressively adopting high-reaction solutions, despite the higher number of stages involved (about twice as many: typically, the K is defined above decreases from 4 to 2 in the transition from a fully impulse stage to a 50% mixed reaction stage). Thus, the most advanced, recent systems can attain very high adiabatic efficiencies: as high as 94-95%, in the high and medium pressure sections. Steam generators A general overview of steam generators is not presented here, but the following addresses some specific points relevant to the generators in large supercritical power stations, very different in both size and design from other types of industrial generators. The steam generator (also known simply as a boiler) is where combustion takes place. The heat released by combustion is transferred from the combustion products to the working medium of the thermodynamic cycle; that is, liquid water is heated, evaporated (also at supercritical pressure), then superheated (either SH and 1 or 2 RH, see above). Fig. 13 shows the general layout of a large generator. In the combustion chamber (lower left in Fig. 13), the Fig. 12. Rotor blade of the final stage of a steam turbine (courtesy of Gepower). fuel is channelled to the burners by specialized fuel delivery systems (a pneumatic system in the case of powdered coal). The combustion air from windboxes is forced by a fan through a regenerative heat exchanger for preheating (see below), and then enters to react with the fuel in the combustion chamber, where the flame can reach temperatures of over 2,000 C. The heat of combustion radiates onto the walls of the chamber, which are lined with the pipelines through which the steam flows while changing phase. The numerous tubes that make up the so-called evaporator (even in supercritical systems, although no true evaporation with two different phases actually takes place), are arranged in such a way as to isolate the hottest areas from the external environment, through the so-called membrane walls (piping joined through welded plates). The heat transfer coefficient of the steam within the tubes is very high and must be so in order to maintain the metal walls at a temperature near that of the steam itself (about 400 C, a temperature that even rather economical carbon steels can withstand), despite the presence of very high temperature gases. When the gases leave the combustion chamber (upper portion in Fig. 13) they are at more moderate temperatures (about 1,000 C) and flow to the superheaters. The various heat exchangers are not inserted counter current, but are arranged so as to limit the temperature of the pipeline walls. The exchangers making up the SH and RHs (two RHs in Fig. 13) are arranged in such as way as to minimize the need for VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY 389

16 POWER GENERATION FROM FOSSIL RESOURCES final super-heater platen super-heater IP 3 SH 1 (walls) LP 3 economizer evaporator Fig. 13. Schematic diagram of a large-scale supercritical steam generator. IP 2 LP 2 IP 1 LP 1 materials able to withstand the very high temperatures (and therefore particularly expensive) in the areas of the maximum steam temperature. Each SH/RH is divided into at least two exchangers, between which is inserted a desuperheater, where some water is injected into the line in order to allow for precise control of the final temperature of the superheated steam, thereby avoiding any conditions approaching the critical resistance of the materials. Subsequently, the exhaust gases, by now at relatively low temperature ( C), undergo final cooling to about 350 C in the economizer, which is an exchanger that heats the feed water from its state at inflow to the generator (as it exits the regenerative preheaters) to near evaporation conditions. At this point, the gases can no longer release heat to the fluid (water/steam) but are subsequently cooled in a regenerative exchanger where they release heat to the combustion air, thereby falling to a final temperature of about C (cooling to lower temperatures should be avoided because an acid condensate would form due to the presence of sulphur in the fuel). These exchangers (not shown in Fig. 13) are often Ljungstrom air preheaters, which consist of a central rotating metallic matrix through which the gas flows. The hot exhaust gas flows over the central rotor, transferring some of its heat to the element, which rotates quite slowly to allow optimum heat transfer first from the hot exhaust gases to the element, then as it rotates, from the element to the cooler air in the environment. The water/steam circulation in the evaporative section of a steam generator is necessarily of the forced type (once-through) in supercritical generators, in which the liquid and steam phases do not coexist; water is channelled through numerous pipes arranged in parallel, at the end of which evaporation is complete. The steam is then collected in a collector and piped to the SH. Such a simple arrangement, however, has the serious drawback that, if an adequate supply of liquid does not reach all pipes simultaneously, temperature peaks, which are difficult to control, can easily occur in the pipe walls. If a single pipe is not thoroughly cooled by the water undergoing evaporation, it can easily reach intolerably high temperatures (with a consequently disastrous fracture), due to the extremely high temperature of the gases in the combustion chamber. Such a risk can be eliminated (or at least drastically reduced) only by generating steam at more moderate pressures, or in any event below the critical value. To this end, two different design approaches have been adopted. Firetube boilers, in which the hot exhaust gases flow within pipes immersed in a pool of boiling water. Such an arrangement is however incompatible with high pressures and is thus absolutely impractical in steam generators of power plants, although it has found widespread application in the generation of industrial steam at pressures in the order of bar. Water-tube boilers, in which the water reaches a cylindrical container (drum) where it coexists with steam. The hot working medium (water) passes through a descending tube (downcomer) to a lower collector, and then rises again, to the drum through boiler tubes (Fig. 14). The evaporated part of the fluid is collected in the upper area of the dome, which thus releases saturated steam. Such a solution avoids the risk of localized superheating. The outflow steam is clearly saturated under all operating conditions (barring any unwished-for transport of droplets, which is minimized by special separators), and thus regulates superheater operations. As the system is based on the density difference between liquid water and steam, it is applicable only to two-phase systems, which excludes not only supercritical processes, but also those too near the critical pressure (never exceeding 170 bar). Circulation may be left to a 390 ENCYCLOPAEDIA OF HYDROCARBONS

17 LARGE-SCALE ELECTRICAL GENERATION SYSTEMS gas saturated steam to super-heater feed water from economizer downcomer (water) pollution control (see below); significant developments in this field include modified burners, improved air-flow control mechanisms, integration with removal devices (SCR and others), and superheater materials able to withstand steam temperatures of over 600 C. Also worth mentioning are some interesting projects for rationalizing the overall lay-out of boilers, which call for modifying the traditional dual-pass arrangement shown in Fig. 13 to a tower (or single pass) or even a highly innovative horizontal layout. evaporator pipes (water-steam mixture) Fig. 14. Circulation in a water-tube boiler. passive process, although in some cases a circulation pump is used. The efficiency of a steam generator (h SG ) is the ratio between the heat actually transferred to the fluid to be heated and the heat released by the fuel (heating value, usually the Lower Heating Value, LHV). The value of h SG can be evaluated indirectly (and also experimentally) as the complement of 1 of the sum of all heat losses. Losses stem from various causes: incomplete heat recovery from exhaust gases; release of still hot combustion products into the environment; defective thermal isolation of the generator walls (inappropriately called radiation losses); discharge of unburnt fuel, which signals incomplete exploitation of the chemical energy in the fuel; the release of other substances at high temperature, for example, coal ash collected at the bottom of the boiler. Quantitatively, the first type of loss mentioned is by far the most significant. In order to achieve high efficiencies, the temperature of the exhaust gases must be kept as low as possible (for example, by using a Ljungstrom exchanger). Moreover, a proper mass ratio between air and fuel must be used. This ratio must be above the stoicheiometric value in order to avoid any significant amounts of unburnt fuel, which, apart from reducing efficiency, includes quite hazardous toxic substances (carbon monoxide, unburnt hydrocarbons). However, an excess of air results in greater heat loss via the release of gases into the environment, in that it increases the mass flow rate; optimal control of the quantity of air relative to the fuel is therefore a crucial factor in steam generator performance, in both energy and environmental terms. The large steam generators used in thermoelectric plants can reach efficiencies in the order of %. In terms of technological developments, over the last few decades designers have concentrated their efforts on Condensers Condensers must discharge into the environment a great deal of heat per unit time, equal to or even slightly greater than the electrical power of the plant. This calls for large fluid flow rates to absorb heat from the condensing steam. There are only are three possible alternatives for such fluid: river or seawater, air from the atmosphere, or a stream of water cooled by air flow from the atmospheric air. The devices used in the three cases are. Water heat exchangers, in which water from a natural body of water (or even water cooled via a waterair heat exchanger) makes the steam condense. In the case of an open circuit (river or sea water), the water is withdrawn from and then returned to the reservoir at a higher temperature by circulation pumps. Air heat exchangers or condensers cooled directly by atmospheric air via convection heat transfer; these are known as dry exchangers to differentiate them from wet evaporative towers. Evaporative towers, which utilize a semi-closed circuit to cool the water heated by exchangers like those described above. The transfer of heat from the water in the evaporative tower to the atmosphere involves an exchange of mass. In principle, the first solution the water-steam exchanger is the most efficient and economic one; therefore it is also the one most frequently used in large plants. In fact, water possesses much better thermal exchange properties than air (at equal flow velocities and diameters, the convective heat transfer coefficient of water is 500 times that of air) and therefore allows the construction of relatively small, inexpensive exchangers. The technical and economic optimization of such exchangers, therefore, leads to solutions with a limited temperature difference between the water and the condensate, as has already been underlined when describing the influence of the pressure of condensation on cycle performance. From the perspective of construction, the design solution most often utilized is the shell and tube exchanger. Therefore, considering the relatively low investment costs (which favour adopting solutions with small DT and low condensation pressures), the smaller seasonal temperature variations VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY 391

18 POWER GENERATION FROM FOSSIL RESOURCES of water compared to air, and the rather low power requirements needed to circulate water, it is understandable that open circuit condensation yields the best performance. There are nevertheless some significant limitations to the use of such open circuit solutions. First of all, the water must be drawn from natural sources such as rivers, lakes or seas. Accordingly, plants must be constructed near such a body of water, which often means in natural areas with scenic value. This seriously limits the availability of sites, especially in densely populated areas. Moreover, returning the water to its environment involves issues of thermal pollution, which have often been neglected in plant design (especially in older plants). These problems limit the areas suitable for constructing new plants. In fact, the combined effects of two electrical power stations in the same area may easily exceed locally imposed limits; environmental studies and associations have long stressed the damage caused by discharging hot water into natural settings, including disturbances to ecosystems. Thus, governing legislative limits to plant hot water discharge must be carefully taken into account at the design stage. Faced with such limitations and the often onerous search for sites with large quantities of water, the technical solution of dry heat exchangers has received renewed interest. However, such solutions involve a considerable amount of effort in terms of plant design, costs and performance. The reasons lie in the aforementioned low thermal exchange capacity of air (therefore the need for large exchange surfaces), as well as the power required by the fans. The enormous volumetric capacity of air calls for large flow areas (a 600 MW e unit needs about 50,000 m 3 /s of air; at a speed of 2.5 m/s, this corresponds to a cross-section of 20,000 m 2, the surface area of three football fields), with consequent problems of space. However, the most serious obstacles to the use of dry exchangers is the need to keep them air-tight (the re-entry of air causes a pressure increase in the turbine discharge), and the formation of ice (with possible tube rupture). Despite these difficulties, a wide range of air condensers is commercially available, most of which adopt modular hut solutions, with forced draft to the exchanger, which is made up of banks of finned, vertically arranged tubes. Dry heat exchangers are widely used in the steam section of combined cycle plants, which have lower heat discharge requirements than steam cycles. Steam cycles, however, more often employ evaporative towers, which have the advantage of very low (although non-zero) water consumption in comparison to open systems, thereby offering considerable savings over dry solutions. Evaporative towers (Fig. 15) are direct contact air-water heat exchangers in which the two fluids are not separated by any physical barrier (pipe), but can also interact to exchange mass. Thus, a part, albeit a small one, of the water evaporates to bring the air to saturation. The two fluids flow in opposite directions (countercurrent flow) and therefore, in the process of heat exchange, the air is heated by contact with the warmer water, which at the same time progressively increases the quantity of water that can be absorbed by the air through evaporation. The hot water therefore cools to some extent because it relinquishes a significant amount of heat to the air, but especially because the phase transition releases the latent heat of evaporation. The lower temperature limit for the cooled water is that of the ambient air under conditions corresponding to the wet bulb temperature. In a dry exchanger, on the other hand, this lower limit is the dry bulb temperature, which is significantly higher than the wet bulb temperature under summer conditions of maximum load. Evaporative towers are thus able to ensure lower condensation temperatures than dry systems, especially under more demanding operating conditions. An evaporative tower consumes far less water than open systems; 1 kg of water in a tower removes 2,500 kj (corresponding to the heat of water evaporation 2,500 kj/kg), compared to about 30 kj/kg for open systems. Actually, water consumption turns out to be somewhat higher (about double), because it is necessary not only to make up for the evaporated water lost to the atmosphere, but also that lost in the so-called blowdown which is necessary to maintain acceptably hot water air basin Fig. 15. Schematic illustration of a natural air-circulation evaporative cooling tower used in large-scale power stations (Hamon). drift eliminators water distribution exchange surface air cooled water 392 ENCYCLOPAEDIA OF HYDROCARBONS

19 LARGE-SCALE ELECTRICAL GENERATION SYSTEMS low concentrations of solid substances in the water circulation (calcium and other salts). The air flow necessary is quite limited in comparison to dry systems, because the enthalpy change of humid air is increased by the contribution of the latent heat associated to the difference in the quantity of steam at inlet and outlet. Moreover, the smaller volume of air in the flow occupies less space and therefore, in principle, involves lower energy consumption to drive any fans that may be needed. Evaporative towers, however, are not free of problems. The major drawbacks are the proliferation of bacteria in the damp hot environment, particularly Legionella pneumophila, which poses a serious health hazard and the formation of so-called plumes (clouds of condensation forming from the water contained in the outflow of damp air as it comes in contact with the colder outside air). This phenomenon, undesirable for both aesthetic reasons and the consequent fall of water droplets to the ground, can be effectively avoided by using various techniques (for example, by mixing it with atmospheric air heated in a dry section of the tower) which, however, significantly increase investment costs. Pollution control Gaseous pollutant emissions and their control are of fundamental importance in operating fossil fuel burning plants. Nowadays, energy efficiency and low cost per kwh produced alone are not enough to guarantee the success of an investment in the field of electrical energy production; environmental impact must be a primary consideration in plant design and operations. This holds for all fuels, but especially coal, which is generally considered highly polluting. This, however, is not entirely true. The environmental impact of even dirty fuels, such as coal, can be contained to within acceptable limits, if, that is, so-called Best Available Technology (BAT) is adopted. Due consideration must therefore be given to such technologies in the plant design. The principal pollutants present in the combustion products of coal plants are nitrogen oxides, generally indicated as NO x (nitrogen monoxide, NO, being the predominant form released at the time of combustion, and nitrogen dioxide, NO 2, into which the nitrogen oxides are converted in the atmosphere), sulphur oxides (SO 2 and, in a much smaller proportion, SO 3 ) and particulate matter (PMs, all the residual solid particles, whose chemical composition and grain size vary widely). The emissions of such pollutants (taken to be NO 2 for the NO x and SO 2 for the sulphur oxides) are generally expressed in mg/nm 3 in dry gases with 6% O 2 (3% for liquid or gaseous fuels). European regulation 2001/80/CE, which goes into effect on January 1st 2008, sets the reference emissions values for a large coal plant at 200 mg/nm 3 for NO 2 and SO 2, and 30 mg/nm 3 for particulates. To appreciate exactly how restrictive such values are, it should be enough to consider that meeting the SO 2 limit of 200 mg/nm 3 in the absence of any exhaust purification systems would require using coal with a sulphur content below about 0.1% (a rare quality indeed) or, alternatively, coal with 1% sulphur content and a desulphurization system able to capture at least 90% of the SO 2 present in the exhaust gases (commercial coals have a sulphur content varying from 0.5 to 4%). It must also be borne in mind that local emissions limits are often even more restrictive, especially for nitrogen oxides. Pollutants can be controlled by adopting two methods: primary methods, which try to prevent pollutant formation, and secondary methods, by which the toxic compounds are removed from the exhaust gases. No economically feasible primary technologies exist for particulate matter or sulphur oxides. Thus, only their removal will be examined here, while for nitrogen oxides both approaches can be, or rather must be, used in conjunction. Low NO emissions combustors Combustion produces NO through two fundamental mechanisms: Molecular nitrogen (N 2 ) contained in the air undergoes thermal dissociation and subsequent oxidation (that is, favoured by high temperatures, and accordingly termed thermal NO). Nitrogen present in the fuel, not as molecular nitrogen but chemically bound in the form of cyano- and amino-compounds, at a high temperature, give rise to nitrogen compounds such as NH 3 and HCN, and subsequently, NO (termed fuel-bound NO). A fuel such as coal contains considerable quantities of nitrogen. The production of the two types of N, thermal and fuel-bound, are comparable, their relative amounts depending on the composition of the fuel. Although the production of both is strongly influenced by the flame temperature, the fuel-bound fraction is produced at temperatures far below those present in the combustion chamber, so its formation is extremely difficult to avoid. As far as thermal NO is concerned, the three main reactions involved are (extending Zel dovich s mechanism): O N 2 NO N N O 2 NO O N OH NO H The first two reactions are reversible, while the third is shifted almost completely to the right. The NO concentration in the combustion products is consistently quite different from the equilibrium concentration. The strategies for obtaining acceptable NO x emissions by VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY 393

20 POWER GENERATION FROM FOSSIL RESOURCES limiting its formation during combustion can be summed up as follows: Reducing the residence times - hardly a feasible approach in steam generators and combustion chambers (even of gas turbines). Reducing the N 2 concentration also negligible for air-fed combustion, since the nitrogen concentration in combustion chambers is, in any event, extremely high. Reducing the concentration of O 2 in the proximity of the flame - which is possible with a rich mixture. As this involves high emissions of CO and other unburnt by-products, it must be followed by strong dilution with air to eliminate such by-products and bring combustion to completion. Known as staged combustion, this is one of the main approaches being pursued in low emissions combustors. Decreasing the equilibrium temperature of the flame by adding to the fuel or combustion air an inert component that does not react and therefore dilutes the flame, reducing its temperature. Water or steam are used as inert components. However, their addition causes a drastic decrease in the performance of the boiler (lower boiler efficiency). This technique is known as Exhaust Gas Recirculation (EGR). Although it is an effective way to reduce NO x, it however involves an increase in the flow of circulating boiler gas (combustion air recirculated gas) and, as a result, increased dimensions of the exchange surfaces and higher cost. Therefore, only moderate recirculation ratios can be used, which alone are generally insufficient to guarantee sizeable emissions reduction. Another way to reduce the flame temperature consists of carrying out combustion under non-stoicheiometric conditions, either via a lean mixture (the excess air does not participate in the combustion and thus acts as an inert compound, thereby reducing the efficiency and increasing the dimensions of the boiler), or, on the other hand, using an excess of fuel, which has been dealt with in the previous point (reduced O 2 concentration). All told, staged combustion is currently the most promising technology for reducing NO x during combustion, and this is implemented by combining two of the approaches suggested by the Zel dovich formulation. One of the techniques successfully applied to accomplish this is afterburning : combustion initially takes place under conditions very near stoicheiometric proportions, which produces less NO x than normal combustion with a somewhat lean mixture. Subsequently, additional fuel (typically 10% of the total) is injected, so as to create a reducing atmosphere that consumes the previously formed and still chemically active NO, converting it into N 2 (afterburning). This second combustion is however accompanied by the production of a great deal of unburnt fuel (mostly CO), which is subsequently oxidized by further injection of air (OverFire Air, OFA). In practice, the temperature peak of normal lean combustion is not reached at any point in the chamber. Thus, the effects of the lower peak temperature are combined with the effect of chemical reduction in the afterburning zone, which acts to reduce fuel-bound NO. This mechanism is repeated on a smaller scale in low emissions burners that go through the same sequence of staged combustion, applying it to the flame itself: a secondary jet of fuel is injected into the central zone of the flame (carried out in approximately stoicheiometric proportions). This supplies the reducing effect, and is followed by an injection of secondary air through the burner s outermost ring for the final oxidation. These combined measures are generally not enough to guarantee NO x emissions within levels required by the strictest regulations (especially with coal, due to the contribution of fuel-bound NO), although they can achieve pollutant reductions of 50 to 70% over conventional burners. Therefore, the most highly ecocompatible plants (the only type allowed for new construction in the European Union) combine the measures described above with additional systems for removing NO x from the exhaust gases. NO x removal NO x is eliminated directly from the combustion products of the steam generator by SCR; the process is carried out by injecting a reducing agent that drives the reduction reaction in an oxygen rich environment such as the exhaust gases. In fact, when CO must be removed (which happens very rarely), no extra reagents need be added, since the oxygen necessary for conversion of CO into CO 2 is already present in the gases; all that is needed is a catalyst to accelerate the reactions. This reducing agent is usually ammonia which, in the presence of a suitable catalyst, undergoes the following reactions: 4NO 4NH 3 O 2 4N 2 6H 2 O 6NO 2 8NH 3 7N 2 12H 2 O In practice, the reaction is catalysed by sprinkling ammonia either on a ceramic honeycomb matrix or, more frequently, on an appropriately corrugated metal matrix, which serve the purpose of offering an extensive surface over which the exhaust can come into contact with the metals covering it. These carry out the function of catalyst (usually, vanadium pentoxide, V 2 O 5 or tungsten trioxide, WO 3 ). The reactions takes place with the maximum efficiency in a gas temperature range of about C, although with suitably refined 394 ENCYCLOPAEDIA OF HYDROCARBONS

21 LARGE-SCALE ELECTRICAL GENERATION SYSTEMS catalysts it is possible to broaden this operating range. In large steam plants with coal boilers, the required temperature is compatible with the gas discharge from the economizer. The use of pure ammonia as the reducing agent poses significant problems in storing and transporting such an extremely toxic and inflammable reagent, which moreover must be kept at pressures of over bar for it to remain liquid at ambient temperature. One possible solution is to make use of a hydrated solution, NH 4 OH, which is liquid at ambient pressure. However, NH 4 OH must be made to evaporate for the injection, which involves the consumption of energy. Another possible solution utilizes urea, (NH 2 ) 2 CO, which is transported as a solid and is then diluted in water. Although urea is safer, it is far more expensive and therefore better suited for use in relatively small systems (for example, cogeneration plants). Regardless of the catalyst used, the operating principles underlying SCR remain the same. The fundamental requirements and drawbacks of SCR operations are: The conversion efficiency (percentage of NO x converted to nitrogen) depends on: the catalyst; the geometry and surface area of the catalyser; correct, uniform feeding of the ammonia; and the operating temperature, which must remain within a rather narrow range. The attainable efficiency is generally between 85 and 90%; higher values involve higher costs. Their use involves gas pressure losses, due to the presence of the base metal catalyst, whose dimensions must be limited to avoid increasing power consumption by the fans. A certain amount of ammonia is not converted in the reaction and is therefore released with the exhaust gases. This phenomenon, called ammonia-slip, must be kept to a minimum for obvious problems of toxicity and to avoid subsequent reactions of the NH 3, which can form substances that clog the catalyst (see below). Catalysts have limited lifespans. This is a crucial factor that depends on numerous operating parameters: erosion due to the presence of gases and the particulate matter contained therein; contamination by particular elements, such as arsenic or vanadium in the ashes of heavy fuels; and plugging, which may be obstruction or even only partial covering of the catalyst by dust, ash or other unwanted reaction products. SCR operations are thus hampered by the presence of dust and sulphur oxides. Bearing in mind that other systems are adopted simultaneously to eliminate such pollutants (see below), there are three possible SCR configurations for application in power plant exhaust systems: High dust. In such systems a large amount of dust is allowed to pass through the SCR. Therefore, the ducts used must not only be wider, but they must be periodically cleaned with air or steam jets. Moreover, as SO 2 is still present in the exhaust, the SCR is subject to the formation of ammonium sulphates, and its useful lifespan is thus decidedly shorter than the other two alternatives. Consequently, the catalyst must be replaced rather frequently (3-5 years), which clearly involves significant costs. Nevertheless, this is currently by far the most widely adopted technology. Low dust. In this case a high temperature electrostatic precipitator is adopted to reduce the particulate matter fed into the SCR, thereby improving operating conditions. However, problems remain at the level of the precipator. Tail end. Filtering and desulphurization are carried out at low temperatures (which also avoids the aforementioned problems associated with the presence of SO 2 ) and the gases are then brought to about 350 C before they reach the SCR. Although most of the large quantity of heat necessary for this process is obtained from regeneration, a certain external contribution is necessary to make up the difference in temperature between the two gas flows, an essential condition for operating the recuperative exchanger. Although this is the best configuration in terms of the various gas treatment components, such a solution involves large-size heat exchangers and additional energy consumption, and therefore higher costs than the high dust solution. The considerable investment and operating costs of SCRs have led to proposals for utilizing Selective Non Catalytic Reduction (SNCR), which is far more economical, although not nearly as efficient. Such systems call for injecting ammonia into the exhaust flow, in the absence of any catalyst, thereby eliminating the associated costs and operating problems described above. However, in order for the reactions to attain sufficient kinetics, the gas temperature must be about C, at which the additional reaction: 4NH 3 5O 2 4NO 6H 2 O begins to become significant, with disastrous consequences on NO reduction. Still higher temperatures (for example, 1,000 C) may even lead to an increase in NO. Therefore, even under optimum conditions, SNCRs are characterized by a removal efficiency of 40-60%, which is generally insufficient in environmental terms for the most demanding applications. Sulphur removal The removal of SO 2 (produced by the combustion of the sulphur contained in the fuel) is of VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY 395

22 POWER GENERATION FROM FOSSIL RESOURCES considerable importance, especially in those cases where no economically feasible primary methods of reduction are available, as in pulverized (or powdered) coal-fired boilers. In this case, it is worth recalling that primary SO 2 reduction can be achieved in fluid bed combustors (at C) by adding a limestone-based sorbent material to the fluid bed itself (a sorbent is a substance that, when injected into the exhaust gases, reacts with pollutants, sorbing them through either absorption). Fluid bed technology now includes significant applications for particular fuels (biomass, fuels derived from waste, lignite), although its adoption is less widespread with high quality coal, as it is more expensive and does not offer any meaningful advantages over powdered coal-fired boilers. Numerous technologies are currently available for removing sulphur, one of which, wet scrubbers, is used in at least 90% of all applications. All the various techniques adopt a sorbent material able to react with SO 2 or derivative chemical compounds. Such sorbents are sodium, magnesium or, more frequently, calcium compounds. In wet scrubbers, in particular, the exhaust fumes are made to come into contact with aqueous calcium carbonate solutions at the lowest temperatures possible (ambient) to favour the absorption reactions, which can be summed up as follows: SO 2 H 2 O H 2 SO 3 CaCO 3 H 2 SO 3 CaSO 3 CO 2 H 2 O CaSO 3 2H 2 O 1/2O 2 CaSO 4 2H 2 O In most cases, contact between the gas and the water/calcium carbonate solution is guaranteed by spraying the solution onto various types of filler materials. What is produced is gypsum, or hydrated calcium sulphate (CaSO 4 2H 2 O). The third reaction is important in order to obtain a good quality commercial product, to maintain the aqueous mixture sufficiently fluid and homogeneous, and to facilitate the subsequent separation of water and gypsum. The reaction requires an ample supply of oxygen, which is usually achieved by blowing air onto the scrubber bottom. Wet scrubbing is a well established, proven technology, which involves significant capital investments (although no more than other technologies). However, it offers the critical advantage of high removal efficiency, up to 92-95%, an essential feature to enable the use of high sulphur-content coal. Such efficiency, however, is heavily influenced by the relative proportions of sorbent material and sulphur present (Ca/S ratio), which must be greater than unity ( ) in order to achieve the greatest efficiency. An alternative solution is the dry scrubber,in which the solution is much denser and the water is made to evaporate on contact with the fumes. The correct operation of this process requires, rather than calcium carbonate, calcium hydroxide, which is more reactive, but more expensive. The main reactions are: Ca(OH) 2 SO 2 CaSO 3 H 2 O CaSO 3 2H 2 O 1/2O 2 CaSO 4 2H 2 O The powder containing the reacted sorbent and gypsum is recovered from the scrubber by electrostatic precipitators or sleeve filters (see below). Often it is preferable to use an electrostatic precipitator, even before the dry scrubber, in order to recover the ashes separately and reduce the solid load to the scrubber. The gypsum produced is not of commercial quality, and therefore, despite lower investment costs, dry technology suffers from two significant disadvantages (the need for calcium hydroxide instead of carbonate and a non-reusable by-product), as well as lower, although still quite high overall, efficiency (85-90%). It has therefore achieved less success than wet technology. A last system worthy of mention is the injection of sorbent material into the boiler. The system is relatively simple, although not particularly efficient (50-70%), mainly due to the brief contact times. The temperature range for maximum reactivity is also narrow, about C for the reaction: CaO SO 2 1/2O 2 CaSO 4 similar to what occurs in fluid beds (which, however, have longer residence times). The CaO is produced by decomposition of the CaCO 3 (calcination) at high temperatures (about 1,000 C). This system is rarely adopted in new designs, although it is still of some relevance in existing plants. Removing particulate matter Particulate pollution is formed from the solid particles contained in the exhaust gases. It includes both inorganic particles from the ashes contained in the fuel, as well as organic carbon residues due to incomplete combustion. As these latter are negligible in quantity in comparison to the former, at least under optimal operating conditions. The following refers to the removal of the light ashes, so-called fly-ash, transported by the fumes, bearing in mind that a portion of the ash settles on the bottom of the combustion chamber (bottom ash) and is therefore more easily removed. Two standard technologies are currently in use for the treatment of large volumes of exhaust gases: Electrostatic precipitators (ESP), whose function involves the formation of an electric field, on the application of a voltage difference of about kv DC enough to ionize the gas. As the negative ions move, they impart a negative charge to the solid particles, which thus also migrate to the positive electrode, where they lose their charge, fall (or are 396 ENCYCLOPAEDIA OF HYDROCARBONS

23 LARGE-SCALE ELECTRICAL GENERATION SYSTEMS removed by simple mechanical systems) and are collected in a hopper. The positive electrode is thus called the collection electrode and is made up of metal plates, while the negative one is called the discharge electrode and is usually made of steel wire. ESPs normally operate at temperatures below 200 C (fitted before the air preheater), but some models have operating temperatures in the order of C. ESPs are very efficient at removing rather coarse particles (over 99.9%), such as PM10 (Particular Matter 10, with an average size of less than 10 mm), but less so for smaller particle diameters (for example, 95% for PM1). The investment costs are relatively high, although this is somewhat compensated for by their low maintenance costs and high reliability. Moreover, as the gases lose little of their pressure, energy consumption is low. ESPs are therefore the most widespread systems on the market. Fabric Filters (FF) are simply bags made of various types of textiles (some quite sophisticated, such as fibreglass-reinforced Teflon), arranged in frames (called the baghouse ) that enable the filter to be cleaned either by shaking or blowing air through it against the normal direction of flow. They offer an important advantage over ESPs: they allow the efficient removal of even very fine particles (for example, over 99.5% even for PM1). The operating temperature depends on the type of fabric, although it is generally below 150 C. Excessive humidity can make the ashes sticky, which hinders cleaning. The associated investment costs are less than, or equal to, those for an ESP, while the operating costs are greater due to the limited lifespan of the filter and higher gas pressure losses. They are also not as reliable as ESPs. Despite these drawbacks, today FFs are considered the best of the available standard technologies because of their high efficiency in removing fine particulate matter. Removing heavy metals and mercury The combustion of coal produces some particles of metallic origin. Although their concentrations may be extremely low (in the order of a few parts per million), some are highly toxic. Of these health hazards, many (such as As, B, Cd, Cr, Cu, Mo, Ni, Pb, Se, V and Zn) are discharged as solids and are thus removed by standard ESPs or FFs, together with the less hazardous metal particulates (Al, Ca, Fe, Mg and Si). Instead, the removal of Cl, F and Hg compounds, which are removed only partially, if at all, by ESPs is a greater problem because they are present in various chemical forms, for the most part as gases. The halogen gases, predominantly HCl and HF, are captured with considerable efficiency by wet desulphurizers. The removal of mercury is a particularly important and delicate process, as its compounds are especially toxic. Mercury is found in various forms in exhaust gases: elemental (Hg 0, the most critical in terms of removal), oxidized (HgO) and bound to Cl or S (HgCl 2, HgS, and HgSO 4 ). ESPs remove these latter compounds efficiently, while wet scrubbers significantly reduce the oxidized mercury content. Thus, about 90% of the mercury is eliminated from emissions by the systems fitted for desulphurization and particulate removal. In the event that this is not enough (although the European Union currently has no regulations governing mercury emissions), it is necessary to resort to other, more specific techniques, such as active carbon bed filters, injecting active carbon before the ESP, or adsorption on sulphur-impregnated zeolites or alumina. Given the enormous quantities of gas to be treated and the extremely low concentrations of mercury (in the order of mg/m 3 ), such systems involve considerable costs (associated with the consumption and regeneration of active carbon and the zeolites). Thus, to date, they have been adopted only on a limited industrial scale Gas turbines A gas turbine is a heat engine that produces power by means of a thermodynamic cycle in which the working medium (commonly called the working fluid) is a gas. The behaviour of the working fluid approximates that of a perfect gas, which follows the state equation pv nrt, where p is the pressure, V the volume of the gas, n the number of moles of gas, R the gas constant (8,314 J/mol K) and T the thermodynamic, or absolute temperature. The ideal, reversible cycle (known as the Joule or Brayton cycle) is made up of two adiabatic isentropic and two isobaric transformations. The first two are carried out by a compressor and a turbine where the gas exchanges work without exchanging heat; the other two transformations are performed by two heat exchangers where the gas transfers heat without performing work. A real cycle (Fig. 16) differs from the ideal one not only in that the four transformations must necessarily include irreversible processes (increases in entropy in the compressor and turbine, losses during the transfer of heat), but also because the working fluid, which is the gas carrying out the thermodynamic cycle, is itself transformed by internal combustion via the following sequence. The compressor takes in air and compresses it up to the maximum cycle pressure (1-2). Fuel is then injected into the compressed air and is oxidized, which generates heat Q 1, thereby raising the temperature of the gas and modifying its composition (2-3). The products of combustion expand in the turbine until they reach VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY 397

24 POWER GENERATION FROM FOSSIL RESOURCES Fig. 16. Real internal combustion open gas cycle in a gas turbine: W t, work produced by turbine; W c, work absorbed by compressor (Lozza, 2006). temperature real expansion line, accounting for coolant mixing non-isentropic compression 2 is leakages 2 thermal losses combustor pressure drop cooling flow 4 is non-isentropic expansion p 3 p exhaust pressure drop p 2 ambient p 0 pressure P 1 exhaust gases discharge 2 3 W t -W c 0 1 cooling flow inlet pressure drop 1 4 specific entropy ambient pressure, when they are discharged into the atmosphere (3-4). The last transformation necessary to close the cycle, that is, the transfer of heat Q 2 to the environment, occurs in the atmosphere outside the plant. Internal combustion Apart from involving internal combustion, the gas turbine cycle also differs from the steam cycle in that it is open. That is, it is in communication with the external environment both by introducing ambient air into the cycle at the compressor intake and by discharging combustion products at the turbine outlet. The combined features of internal combustion and of an open cycle enable operation in the complete absence of heat exchange devices, since heat Q 1 is generated by the working fluid itself, and heat Q 2 is transferred to the environment by direct contact between the exhaust gases and the atmosphere. Thus, the entire system is made up of only three components: the compressor, the combustor and the turbine (expander). The absence of heat exchange devices gives some advantages: reduced size, weight and cost. Indeed, compact, lightweight, cost-effective gas turbines have become the undisputed leaders in aeronautical propulsion in the post-war period. The maximum temperature of the thermodynamic cycle is the critical determinant of gas turbine performance. Specifically, the higher the temperature at which gas is fed into the turbine expander, the better the efficiency. The incentive to raise this temperature is so strong that complicated cooled systems have already been in widespread use since the 1960s. In such systems, the turbine sections exposed to the highest temperature gases are cooled using relatively cold air bled from the compressor and introduced into the blades, whence it is discharged into the main flow of the exhaust gases (Fig. 17). In this way, the materials of the turbine (nickel-based superalloys ) are maintained within the temperature limits necessary to guarantee adequate mechanical resistance. The two expansion curves shown in Fig. 16 show how this cooling of the hottest parts of the turbine affect the expansion of the gases (which is no longer adiabatic) and thereby the performance of the thermodynamic cycle. Due mostly to the requirements of aviation applications, which have determined the development compressor combustor main flow cooling flows turbine stages Fig. 17. Schematic diagram of a gas turbine cooled with air drawn from the compressor (Lozza, 2006). 398 ENCYCLOPAEDIA OF HYDROCARBONS

25 LARGE-SCALE ELECTRICAL GENERATION SYSTEMS and success of gas turbines, the compressor and turbine are usually mounted on the same shaft, with the combustor between them, to form an extremely compact, light-weight assembly, easily transportable for land applications as well. The net power output available to drive the load is the difference between the power generated by the turbine and that absorbed by the compressor. Like all internal combustion systems, in which the combustion products flow through the components generating the actual work, gas turbines are subject to limitations on the type of fuels that can be used: as the combustion products flow through sophisticated (and costly) components, such as the cooled turbine sections, such limitations are extremely strict, since even minimal contamination by solid particles or corrosive mixtures (alkaline metals, vanadium, sulphur, salts, etc.) can be disastrous for the integrity of the machinery. In practice, the only fuels that can be used for applications requiring high reliability are natural gas (or, with suitable precautions, diesel oil) for land-based applications, and kerosene for aeronautical applications. Thermodynamic cycle The characteristics, and therefore performance, of a gas turbine are determined by two factors, as explained in the following. Unlike the Carnot cycle, in which the heat exchange takes place with the working fluid at constant temperature, in the Joule cycle, both the heat, Q 1, input to the cycle, and the heat, Q 2, released to the outside are transferred at variable temperatures (see again Fig. 16). Recalling that, by the Carnot theorem, a cycle operating under a given temperature differential attains maximum efficiency when heat is fed into and released from the cycle at a constant temperature (respectively, the maximum and minimum temperature), it follows that the efficiency achievable from the Joule cycle is always lower than that of a Carnot cycle working under the same temperature differential. On the other hand, internal combustion transfers heat to the working fluid (gas) of the thermodynamic cycle without the mediation of any exchange surface. This makes it possible to overcome the problems posed by the constituent materials of the components for heat input (acceptable stress, thermal stress, creep, and corrosion). Thus, turbines can be operated at much higher gas temperatures than those achievable in external combustion cycles, specifically the steam cycle. The first factor limits the thermodynamic performance of the gas turbine cycle; at relatively low maximum cycle temperatures ( C), and equal minimum (ambient) temperatures, a gas turbine cannot equal the efficiency of a steam cycle. Indeed, through condensation the steam cycle can give off heat, Q 2, at a constant temperature very close to that of the environment while evaporation, moreover, allows the input of most of the heat, Q 1, at a constant temperature, although this value cannot exceed the critical temperature of water (373 C). The second factor, on the other hand, allows for very high maximum operating temperatures (unattainable with external combustion cycles), which compensates to a large degree for the handicap of variable-temperature heat exchange, and thereby enables gas turbines to attain efficiencies similar to those of steam cycles. Modern commercial gas turbines today operate with maximum cycle temperatures close to 1,400 C, providing efficiency of 41-42% in aeronautical applications analogous to those of supercritical steam systems with maximum cycle temperatures of C. Thus, in a way, raising the maximum temperature from C to 1,400 C is the price that the gas turbine must pay to compensate for the poor quality of the Joule cycle. Cycle parameters The ideal Joule cycle is completely defined by the characteristics of the working fluid, the maximum and minimum temperatures (i.e. Turbine Inlet Temperature, TIT and the compressor inlet temperature) and the compression ratio b (ratio between compressor outlet and inlet pressures). In order to define a real cycle, however, additional parameters are needed; these regard the quality of the components and of the real processes involved: the efficiency of the turbine, pressure losses, heat losses, leakage, cooling mechanisms, etc. Although all these technical parameters have a highly significant impact on performance, here the discussion will be limited to the thermodynamic parameters of an ideal standard cycle. In the case of an internal combustion gas turbine, a number of factors are fixed a priori: The working fluids - atmospheric air for the compressor, the combustion products for the turbine; the characteristics of the combustion products (particularly, the variations in specific heat as a function of temperature) vary very little with the type of fuel or the air-to-fuel ratio, and the effects of such variations on performance are modest to the point of being, in practice, negligible. The minimum pressure and temperature, which are necessarily those of the atmosphere, whence the air feeds the compressor and into which the turbine exhaust gases are discharged (although this is not strictly true, as the air for the compressor is sometimes first cooled in order to increase power output, especially in the summertime). The thermodynamic characteristics of the cycle can thus be determined by the only two remaining VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY 399

26 POWER GENERATION FROM FOSSIL RESOURCES parameters: the maximum Turbine Inlet Temperature (TIT) and the compression ratio b, the choice of which is at the discretion of the designer. In order to illustrate the effects of the design criteria chosen, it is particularly useful to analyse the behaviour of the two main performance indices of a gas turbine: the specific power (i.e. the work per unit mass of air that flows into the compressor) or in other words, the power output per unit air flow, and efficiency, which is the ratio between the net work and the heat released by the fuel. As the size, weight and costs of a gas turbine are linked to the volume of air that flows into the compressor, the specific power, in turn, determines three important indicators of system performance: the power output per unit volume, the power output per unit weight, and the specific investment costs (cost per unit power output). With increasing specific power, the first two indicators increase, while the third decreases. It thus follows that it is attractive to achieve the greatest specific power possible. For a given power output, specific power determines investment costs and, hence, fixed costs, while efficiency, which determines fuel consumption, is the basic factor in variable (operating) costs. Compression ratio Fig. 18 shows the curve of efficiency, h, as a function of the specific power output, w, with varying compression ratio, b, for three values of the maximum TIT. The parameters of turbine efficiency, pressure losses, materials characteristics, cooling efficiency, etc. are all considered constant and correspond to those of the most advanced, large power output industrial gas turbines. Beyond a certain value of the compression ratio, the curves are interrupted, because the temperature of the air bled from the compressor to cool the turbine net electrical efficiency (%) b 45 b 45 b 33 b 40 b 30 b 47 b 47 b 40 b 30 b 25 b 30 b 20 b 20 b 20 b 16 b 16 b 16 b 12 b 12 b 12 TIT 1,000 C b 8 TIT 1,200 C b 4 b 4 b 4 b 8 TIT 1,400 C b specific power (kj/kg) Fig. 18. Efficiency of a gas turbine as a function of specific power at varying compression ratios and for three different values of TIT. becomes so high that it becomes impossible to maintain the hottest portions of the turbine at temperatures sustainable by their constituent materials (the most critical components are the stator and the rotor of the first stage of the turbine, which receive the gas at the maximum temperature). As the compression ratio changes, the point values of the performance of the gas turbine describe a curve in the plane (w, h). Such curves determine the maximum values of both specific power and efficiency. Since, by increasing b, such values follow the curve in a counter clockwise direction, the compression ratio yielding the maximum specific power is always lower than that corresponding to the maximum efficiency. The point corresponding to the maximum specific power (moderate compression ratio) is particularly relevant to applications for which the most important consideration is either containing investment costs (peak demand power stations, whose operating times do not exceed a few hundred hours per year), or achieving high power output (military aircraft propulsion). As illustrated in the following in more detail, the value of b that maximizes specific power is generally very close to the value that maximizes the efficiency of a combined cycle. Hence, the point of maximum specific power is also of particular interest to all combined-cycle applications. The value corresponding to the highest efficiency (very near the limit value beyond which cooling of the turbine begins to fail) is most relevant to applications for which fuel consumption is a primary concern (central power plants that must operate thousand of hours a year or commercial aircraft propulsion). The values of b which maximize work or efficiency vary with TIT and turbine efficiency: the higher the TIT, or the higher the efficiencies of both compressor and turbine, and the higher are the values of b that maximize w and h. In the current state of the art (TIT 1,350-1,400 C, with efficiencies of compressor and turbine stages approaching 90%), the compression ratio maximizing the specific power falls in the range of about 16 to 20, while the value maximizing efficiency is over 40. This explains why so-called heavy-duty industrial machinery designed to operate in combined cycles or in peak load plants adopt compression ratios of 16-18, while the propulsion systems of large commercial aircraft, as well as large-scale plants (40 50 MW e ), derived from aeronautical applications and designed for continuous operations, utilize compression ratios of Turbine input temperature As Fig. 18 shows, specific power increases significantly with increasing TIT. In the absence of cooling, this would moreover be accompanied by a considerable increase in efficiency. However, 400 ENCYCLOPAEDIA OF HYDROCARBONS

27 LARGE-SCALE ELECTRICAL GENERATION SYSTEMS Fig. 19. Efficiency and specific power as a function of TIT with a compression ratio of 20 for three typical gas turbines. net electrical efficiency (%) adiabatic turbine advanced cooling technology reference case b 20 specific power (kj/kg) advanced cooling technology adiabatic turbine reference case b ,000 1,200 1,400 1,600 TIT ( C) ,000 1,200 1,400 1,600 TIT ( C) collecting the relatively cool air from the compressor and using it to keep the temperature of the hot parts of the turbine within acceptable limits involves losses that offset, in part or in whole, the thermodynamic advantages of the higher TIT. Fig. 19 illustrates the effects of TIT on the efficiency and the specific power of a gas turbine operating with a constant compression ratio of 20 (the case in point refers to the same turbine efficiency values, pressure losses, materials characteristics, cooling, etc. as in Fig. 18). While increasing the TIT always raises specific power, efficiency is limited by a maximum TIT value beyond which the thermodynamic benefits consequent to any further rise in temperature are completely offset by the losses consequent to cooling. The TIT value at which the efficiency curve of a cooled system levels out depends on the quality of both its components and materials (where by quality we mean components that yield the highest turbine efficiencies, the most effective cooling, materials that can withstand the highest temperatures, etc.). The higher the quality, the higher is the limit value of TIT up to which the efficiency continues to rise, and, consequently, the higher is the corresponding efficiency and specific power. In the absence of cooling, a design achievable through the use of ceramic materials able to operate at extremely high TIT, efficiency rises continuously. Fig. 19 highlights the strong incentive to adopt as high a TIT value as possible, at least as long as any increase in such value yields a corresponding increase in efficiency. The drive towards increasing TIT values, however, is limited by the resistance of the constituent materials of the combustor and the first stages of the turbine. In a machine such as the gas turbine that works under stationary conditions, in the absence of cooling, the materials in contact with the expanding gases are brought to approximately the same temperature as the gases themselves. As a result, further increasing the temperature of the gases flowing into the turbine is possible only if such an increase is compatible with the properties of the materials making up the most highly stressed machine parts, in particular, the rotor blades, which are subjected to tremendous centrifugal forces. Late Twentieth century advances in materials science and manufacturing techniques for individual turbine components (lost wax casting, directional crystal solidification, single crystal blades, etc.) have led to an increase of about 200 C in the operating temperatures of some of the most critical components (combustor walls, first-stage turbine stator and rotor blades). Nevertheless, the temperatures sustainable by the materials available today (about 900 C for heavy-duty, industrial turbines, and nearly 1,100 C for aviation turbines) are still insufficient to achieve the performance required by the market. Thus, TIT values well over current material limits have been adopted by recourse to the technique of cooling the hottest turbine parts with the relatively cool air drawn from the compressor. Fig. 20 shows the evolution of TIT in the latter half of the Twentieth century, over which period its value rose on average by about 12.5 C per year; about one third of this increase can be attributed to materials improvements, while the remainder is due to the adoption of ever more sophisticated and efficient techniques for cooling the blades. In current cooling systems, the air drawn from the compressor traverses an intricate network of channels that pass through the turbine shaft to reach the stator and rotor blades. The blades themselves have finely corrugated channels within their interiors to maximize heat exchange with the coolant as it flows through. Finally, through tiny VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY 401

28 POWER GENERATION FROM FOSSIL RESOURCES TIT ( C) 1,600 1,500 1,400 1,300 1,200 1,100 1, Pratt & Whitney aero engines General Electric heavy-duty Rolls Royce aero engines ABB/Alstom heavy-duty trend: 12.5 C/year MHI heavy-duty Siemens heavy-duty year Fig. 20. The evolution over time of turbine inlet temperatures for industrial and aviation gas turbines. perforations in the most critical blade zones, the coolant is discharged into the gas flow in contact with the external surface with the aim of creating a relatively cool surface coat (film cooling). As further protection for the metallic walls, the surface of the blades is coated with a thin layer of materials (zirconium oxides), which are particularly resistant to high temperatures and corrosion (thermal barrier coating). In modern gas turbines the expansion process is accompanied for the most part by a drop in entropy; the decrease in entropy consequent to the heat absorbed by the intense flow of coolant air discharged into the gas exceeds the increase in entropy due to the irreversibility of the expansion. In this case, the coolant flow represents a significant portion of the overall outflow from the turbine. This trend towards continuously increasing TIT is likely to continue in the future because, as can be seen in Fig. 19, technological improvements are shifting the conditions of maximum efficiency towards ever higher temperatures. The performance currently achievable, even using exceedingly sophisticated technologies and materials are, however, still limited; even by adopting high compression ratios (over 80) and TITs of 1,500 C, thanks to ceramic materials that do not require cooling, the best that can be expected would be no more than 50% efficiency. Such a relatively modest value is dictated by the inherent limitations of the gas cycle (heat input and heat release at variable temperature). Industrial production: commercial models From the point of view of design and implementation, land-based gas turbines can be classified into two categories depending on their origins: heavy-duty, or industrial turbines that have been designed and developed exclusively for land applications, mainly for the generation of electrical energy, and aeroderivative turbines, that is, models based on designs originally developed for aircraft propulsion, which have been adapted for land applications after some relatively minor modifications. Heavy-duty turbines are characterized by a more basic design, as size and weight constraints are not as important as the economy of construction and operation. The vast majority are single-shaft models, with compression ratios near the value maximizing specific power (see again Fig. 18). The reasons underlying such design choices are: In order to contain investment costs, it is preferable to give priority to maximizing specific power output. Moderate b values enable limiting the number of stages, thus making a single-shaft design, decidedly simpler and more economical than multiple shaft designs, quite acceptable. For land applications, the high temperature of the gases discharged from the turbine at moderate b (for the most recent designs, about 600 C) is particularly well-suited to feeding a steam recovery plant, and thereby to application in high-efficiency, combined gas-steam cycles. In fact, the value of b maximizing the specific power output of the gas turbine is very close to the value maximizing the efficiency of a combined cycle. Fig. 21 shows a scale model of an industrial gas turbine for electrical power generation. The cutaway illustrates its structure and the working fluid flow; atmospheric air enters from the right and proceeds leftwards along the direction of the axis of rotation through 17 compressor stages. It is then fed to the combustor, made up of various burners arranged in a circle whose axis is inclined with respect to the axis of Fig. 21. Scale model of an industrial gas turbine for electric power generation (courtesy of the Author). 402 ENCYCLOPAEDIA OF HYDROCARBONS