Natural Gas- Fuel for the 21st Century

by Vaclav Smil

  Central gas-fired power plants—supplied by a pipeline from a nearby field or located next to LNG regasification terminals and converting typically 33–35% (for the older stations) and 35–38% (for post-1990 projects) of gas to electricity—remain important in several countries, most notably in Japan which has the largest group of such high-capacity (>2 GW) stations originally built to replace coal- and oil-fired plants and to improve air quality in the country’s densely populated coastal conurbations. Nearly 20 of these LNG-based high-capacity stations, located on reclaimed land adjacent to receiving terminals, are easily identifiable by their tall boilers and generator halls and chimneys and gas storage tanks. Japan’s largest gas-fired station is 5.04 GW Futtsu in Chiba prefecture, across the Tōkyō Bay from the capital (see Fig. 5.7). The second largest station, 4–8 GW Kawagoe, is in Mie Prefecture east of Ōsaka.

  Other East Asian LNG importers with large gas-fired stations include China, Taiwan, and South Korea, while Russia, Australia, and Malaysia rely on power plants burning inexpensive domestic gas. With 5.597 GW of installed capacity, Russia’s Surgut-2, in West-Central Siberia (Khanty-Mansiysk region), was the world’s largest gas-fired station in 2014, while New York’s 2.48 GW Ravenswood station, burning natural gas, fuel oil, and kerosene illustrates the compact nature of such large facilities as it occupies a rectangular lot of just 12 ha just south of the Roosevelt Island Bridge on the East River in Queens. But in the United States, smaller-capacity gas turbines have been dominant for decades: in 2012, gas-fired boilers producing steam for large turbogenerators accounted for less than 20% of the US gas-fired generating capacity, nearly 30% of it was in simple cycle gas turbines and 52% on combined cycle gas turbines (CCGTs), and hence in the rest of this section I will describe the rise and the performance of these remarkable machines.

  4.2.1 Gas Turbines

  The quest for combustion turbines goes back to the end of the eighteenth century, to John Barber’s patent that outlined an essentially correct principle but had no chance to be transformed into a working machine. Doing that remained a challenged for generations to come. Only in 1903, Aegidius Elling’s six-stage turbine with a centrifugal compressor generated a bit of net power, and between 1903 and 1906, the best prototypes of centrifugal turbines built by the Société des Turbo-moteurs reached a net efficiency of less than 3%, far inferior compared to the best steam engines of the day. At the same time, Brown Boveri, a pioneer of steam turbine manufacturing, worked on its first gas turbine prototype (Smil, 2006).

  The first practical advances came only during WWI. GE’s new turbine research department, established in 1917 by Sanford Moss (whose first gas turbine design went back to 1895), developed a turbo supercharger driven by hot exhaust gases from reciprocating Liberty engines that powered America’s wartime planes. More proposals and patents for turbojet engines followed during the 1920s, but the only practical application was a small gas turbine designed by Hans Holzwarth and built by Brown Boveri for a German steel mill. Real commercial breakthroughs began only during the 1930s, helped by advances in materials and by greater market opportunities; at the same time, dedication and persistence of two young engineers, Frank Whittle in the United Kingdom and Hans Joachim Pabst von Ohain in Germany, led to the first turbines (jet engines) suitable for flight (Smil, 2010a).

  The first stationary gas turbine with utility-scale capacity was a machine built in 1939 by Brown Boveri for the municipal electricity-generating station in Neuchâtel (Alstom, 2007). Its rated capacity was 15.4 MW, but because its compressor consumed almost 75% of the generated power and because all exhaust heat was vented, the actual available capacity was no higher than 4 MW, resulting in a poor efficiency of just over 17%. Remarkably, the turbine decommissioned only in 2002, after 63 years of operation. Post-WWII development of gas turbines was slow: except for the US natural gas was not readily available, utility markets everywhere were dominated by coal-fueled steam turbines or hydroturbines, and inexpensive exports of the Middle Eastern oil offered a new fuel alternative for electricity generation. Combustion of fuel oil in large boilers became an important component of electricity in coal-deficient countries as well as in Japan whose economy began its rapid expansion.

  In the United States, both Westinghouse and GE introduced their first gas turbines for electricity generation (with capacities of <1.5 MW) in 1949, and a decade later, the aggregate capacity of American gas turbines was just 240 MW, less than a single large machine delivers today. In 1960, the highest turbine rating reached 20 MW, and the total installed capacity rose to 840 MW in 1965; before that year ended, an unexpected event ushered in a new era of rapid gas turbine expansion. On Tuesday of November 9, 1965, the Northeastern United States—extending from New Jersey to New Hampshire, and also parts of Canada’s Ontario, overall an area of more than 200,000 km2—suffered a power blackout, with about 30 million people losing electricity for up to 13 hours (USFPC [US Federal Power Commission], 1965).

  Utilities had realized that rapidly deployable gas turbines would have made a critical difference. Although a turbine has to be started by external means (a small motor will do), its output can reach full load in minutes compared to hours for steam turbine. American utilities installed 8 GW of new gas turbine capacity in just 3 years after 1965 and expanded aggregate gas turbine power more than 30-fold in a decade to nearly 45 GW in 1975. This rapid expansion ended due to the rising prices of natural gas (a consequence of OPEC’s quintupling of oil prices in 1973 and 1974) and declining demand of electricity (after years of rapid expansion).

  Growth had resumed after hydrocarbon prices fell in the mid-1980s, and by 1990, the US utilities installed almost half of their new capacity in gas turbines, and the orders for new gas turbines have surpassed the worldwide orders for steam turbines (Valenti, 1991). No less importantly, this quantitative growth was accompanied by impressive qualitative improvements. Gas turbines are among the most reliable modern machines: when properly maintained, stationary turbines require overhaul after no less than 25,000 hours of operation (i.e., 2.85 years of nonstop operation). This reliability makes them also a preferred choice in continuous industrial applications: oil and gas industry uses them to drive pumps and compressors in processing plants, refineries, and pipeline pumping stations.

  And they are also very efficient. As already noted, in 1939, Brown Boveri’s first turbine had an efficiency of only about 17%; three decades later, efficiencies came close to 30%; in 1976, GE’s largest (100 MW) turbine rated about 32%; and by the year 2000, gas turbines reached thermal efficiencies of just above 40%. Plants using the best steam turbines and the best simple cycle gas turbines had thus a very similar performance, but gas turbines could do much better as a part combined cycle. The early machines had low capacity (<10 MW), and their exhaust gas had temperature below 750°C, a combination that did not allow to do more than use the waste heat for preheating air for a boiler or heating boiler feedwater.

  Larger units (50 MW in 1970, 100 MW by the mid-1980s, 200 MW by the mid-1990s) and higher firing and hence higher exhaust temperatures (the former ones getting above 1,000°C by the late 1960s and reaching 1,250°C by 1990; the latter ones rising from less than 400°C in the early 1950s to as much as 600°C in the latest machines) provided an unprecedented opportunity to either raise the efficiency of electricity generation or to maximize the overall efficiency of a gas turbine-based system used for cogeneration, that is, for combined production of electricity and heat (space or processing) for industrial or household uses.

  4.2.2 CCGTs

  Predesigned combined cycle plants entered the market during the late 1960s and the early 1970s under the names Steam and Gas (STAG by GE) or Gas und Dampf (GUD by Siemens) and Power and Combined Efficiency (PCE by Westinghouse), and eventually, the technique became generally known as CCGT. After a relatively rapid maturation, CCGT became the most common choice for both adding new capacity and repowering older plants (Balling, Termuehlen, and Baumgart
ner, 2002; Rao, 2012). This logical arrangement couples a gas turbine with a steam turbine: gases leaving a gas turbine are hot enough to raise steam (in an attached heat recovery steam generator) whose expansion runs a coupled steam turbine. Efficiency of this combined cycle is calculated by summing up the specific efficiencies of the two turbines and then subtracting their product: 42% efficiency for a gas turbine and 32% efficiency for a steam turbine yield a combined efficiency of just over 60%.

  That has been the state of the art, but future improvements, up to 68–69%, might be possible with further combinations (adding solid oxide fuel cells or solar photovoltaics). Maximum CCGT capacities have now reached the level of midsize (400–600 MW) steam turbogenerators in large central power plants. Siemens introduced the world’s largest machine in 2007: its SGT5-8000H rated 340 MW and powered 530 MW combined cycle plant with an efficiency of 60%, and it has since increased the maximum simple cycle capacity to 375 MW in simple and 570 MW in combined cycle (Siemens, 2014). GE’s two latest models, 9HA 01 and 9HA 02 (introduced, respectively, in 2011 and 2014), are the current record holders with 397 and 470 MW in simple cycle, and the larger machine helps to deliver 710 MW gross and 701 MW net in combined cycle (GE, 2014a; Figure 4.3).

  Figure 4.3 GE gas turbine.

  Reproduced courtesy of General Electric Company.

  Cogeneration (also known as combined heat and power (CHP)) does not convert waste heat into electricity but uses it directly for processing in adjacent industrial plants or, more often, to heat water for numerous industrial uses (particularly in food and textile industries) or for space heating, such as centralized heating plants (in the past fueled by coal or by fuel oil, now also by waste biomass). Besides higher overall efficiency, cogeneration has the advantage of reduced air pollution and enhanced local and general security of supply. CHP has been fairly common in urban areas of Europe and Japan and now is also widely used in China’s rapidly growing cities. In Europe, cogeneration now produces more than 10% of all electricity, with natural gas being the dominant fuel in most countries using CHP, particularly in the Netherlands, Spain, Italy, Germany, and the United Kingdom (COGEN Europe, 2014).

  A particularly interesting case of cogeneration has been its use in Dutch greenhouses that now cover more than 60 km2 of the country. The practice began in 1987, it saves up to 30% on total energy costs, and the combustion of natural gas provides not only light and heat for the country’s extensive greenhouses but a part of the generated CO2 that is used to enrich the enclosed atmosphere to at least 1,000 ppm (compared to the global ambient atmosphere average of 400 ppm in 2014). This practice results in faster growth and higher yields of peppers and tomatoes, the two dominant products of Dutch greenhouse farming (Wageningen UR, 2014).

  A new option for natural gas-based electricity generation became available with the introduction of less massive aeroderivative turbines, jet engines modified for stationary application (Smil, 2010a; Langston, 2013). GE’s first design (LM6000 with rated capacity of 40.7 MW and efficiency of 40%) was based on a long-serving CF6 engine used to power Boeing 747 and 767 as well as several Airbus models (GE, 2014a). By 2013, GE offered models rated from 16.4 to 105.8 MW in both 50 and 60 Hz series (GE Power & Water, 2013). The other two large jet engine makers, Rolls Royce and Pratt & Whitney (P&W), offer their lines of aeroderivative gas turbines—the former’s line based on its widely deployed Trent series of jet engines and the latter’s on JT8D engine which powered first Boeing 727 and 737 planes during the 1960s. P&W has also developed packaged gas turbine designs that come fully assembled on trailers and that can start generating electricity in less than a month after reaching their location.

  P&W’s FT8 27 MW gas turbine is mounted on a steel base, comes packaged with its ancillary support systems, directly drives the generator package, fits on just two trailers, and it is ready to generate only 8 hours after arriving at a site (PW Power Systems, 2014).The turbine, its control trailer, access roads, fuel and electricity connections, and a safety perimeter buffer occupy only 600 m2, while a 60 MW SwiftPac on concrete foundations needs 700 m2, and it generates just 3 weeks after delivery. Compactness of gas turbines makes it easy to site them within the boundaries of existing central power plants, obviating often contentious approval process for new locations. For example, siting of the original Didcot-A 2 GW coal-fired station completed in Oxfordshire in 1968 met a great deal of local opposition, but gas turbines of Didcot-B, 1.36 GW gas turbine station completed in 1997, are virtually hidden within the Didcot-A site where it takes up less than 10% of the original station’s area (Smil, 2015).

  Ubiquity of gas turbines is attested by their rising numbers and by their share of newly installed capacities. In 2013, there were more than 26,000 gas turbines worldwide, working as simple cycle machines, as CCGTs, and in CHP system, with North America having nearly a third of the total and Asia a fifth (Platts, 2014). In 2012, the United States had 121 GW installed in gas turbines, or about 15% of all fossil fueled and 11% of all net summer capacity, but they generated only 3% of all electricity. That very low share is easily explained by their use during the times of peak power demand: during off-peak hours, their capacity factors are usually just 1–3%, while during the peak hours (in the United States now between 1 and 5 p.m.), they go above 10%, and in the Northeast (Northeast Power Coordinating Council, where the peak is extended from 10 a.m. to 20 p.m.) and in Texas (with more pointed peak centered on 3 p.m.), they rise above 25% (USEIA, 2014f).

  The peaking role of gas turbines is also discernible in total seasonal natural gas consumption: in 2013, gas used in July and August (to meet peak air conditioning demand) was 40% higher than gas used in January and February. Not surprisingly, new generating capacities in the United States have been dominated by gas turbines. In 2013, just over 50% (about 6.9 GW out of the total of 13.5 GW) of new capacity was in gas turbines, almost equally split between simple cycle and combined cycle arrangements; and in terms of total generating capacity in 2012, nearly a third was installed in natural gas-fueled gas turbines (20% in CCGTs), compared to 41% in steam turbines (including 29% in coal-fired plants and almost 8% in natural gas-fired stations), about 7.5% in hydroturbines and 5.5% in wind turbines (USEIA, 2013a).

  Because of the rising demand and high price of high-quality materials used to make them, gas turbines have been getting more expensive to install, but CCGT still generates electricity far more cheaply than any other commonly deployed method. USEIA (2014g) projects the following levelized costs of new electricity generation for the entire systems entering operation by 2019 (with all values in $(2012)/MWh): about $95 for conventional coal, $96 for advanced nuclear (a highly arguable value), $103 for biomass, $80 for onshore wind (and $204 for offshore turbines), and $130 for solar PV—compared to $66 for conventional natural gas combined cycle and $64 for an advanced version of CCGT.

  No other stationary prime movers combine so many advantages as do modern natural gas-fueled turbines: they have the most compact size and hence the smallest footprint of all electricity generators and hence can be easily installed within the boundaries of existing thermal power plants or industrial establishments; they can be inexpensively transported to those sites by trucks, barges, or ships; they are exceptionally reliable and relatively easy to maintain; their service is almost instantly available: they can reach full load within a few minutes and hence are perfect for covering peak load or other sudden fluctuations in demand; because they are air cooled, they (unlike steam turbogenerators) do not require any arrangements for water cooling; they are relatively quiet as silencers keep their noise below 60 dBA at the distance of 100; and in combined cycle arrangements, they have unrivaled efficiencies and hence also the lowest specific CO2 emissions.

  4.3 NATURAL GAS AS A RAW MATERIAL

  All fossil fuels have been used not only as sources of heat and light but also as raw materials, most importantly as feedstock in chemical industries providing essential elements or
compounds required for subsequent syntheses or processing. Because it is a mixture of the lightest alkanes, natural gas has an inherent advantage as a feedstock for chemical syntheses. During the combustion, all alkanes contribute to the release of heat, but natural gas is not used as feedstock either in its raw form or after processing (when its composition becomes more uniform), but its constituents are separated and used for specific applications.

  Methane is the most important input for the synthesis of ammonia (NH3), for the production of hydrogen (for hydrocracking and hydrodesulfurization) and methanol (CH3OH) and its derivates. Ethane (C2H6), the lightest of natural gas liquids, is converted into ethylene (C2H4, ethene) whose polymerizations yield the largest and the most valuable chain of synthetic products. Similarly, propane (C3H8, also used as portable fuel, most commonly for home heating, small stoves, and barbeques) is turned into propylene (C3H6, propene), the second most important compound to be polymerized after ethylene. Butane (C4H10) yields butylene (C4H8, butene), the basis for synthetic rubber, but it is also blended with gasoline and mixed with propane and is sold as LPG.

  But the first major use of natural gas as a raw material was in the production of carbon black. Carbon black is a powdery or granular form of virtually pure (at least 97%) elemental carbon (unlike black carbon, or soot, which contains <60% C). Industrial use of carbon black is dominated by rubber industry, in the United States about 70% of the total as a reinforcing filler in tires, 10% in other automotive goods (belts, hoses), and 10% into molded and extruded rubber products; the remainder is used as a pigment in printing inks (now ubiquitously in photocopiers and laser print cartridges) and coating resins and films (ICBA [International Carbon Black Association], 2014).