by Vaclav Smil
Free-living methanogens were eventually joined by archaea that are residing in the digestive tract (in enlarged hindgut compartments) of four arthropod orders, in millipedes, termites, cockroaches, and scarab beetles (Brune, 2010), with the tropical termites being the most common invertebrate CH4 emitters. Although most vertebrates also emit CH4 (it comes from intestinal anaerobic protozoa that harbor endosymbiotic methanogens), their contributions appear to have a bimodal distribution and are not determined by diet. Only a few animals are intermediate methane producers, while less than half of the studied taxa (including insectivorous bats and herbivorous pandas) produce almost no CH4, while primates belong to the group of high emitters, as do elephants, horses, and crocodiles.
But by far the largest contribution comes from ruminant species, from cattle, sheep, and goats (Hackstein and van Alen, 2010). Soil-dwelling methanotrophs and atmospheric oxidation that produces H2O and CO2 have been methane’s major biospheric sinks, and in the absence of any anthropogenic emissions, atmospheric concentrations of CH4 would have remained in a fairly stable disequilibrium. These emissions began millennia before we began to exploit natural gas as a fuel: atmospheric concentration of CH4 began to rise first with the expansion of wet-field (rice) cropping in Asia (Ruddiman, 2005; Figure 1.1).
Figure 1.1 Methanogens in rice fields (here in terraced plantings in China’s Yunnan) are a large source of CH4.
Reproduced from http://upload.wikimedia.org/wikipedia/commons/7/70/Terrace_field_yunnan_china_denoised.jpg. © Wikipedia Commons.
Existence of inflammable gas emanating from wetlands and bubbling up from lake bottoms was known for centuries, and the phenomenon was noted by such famous eighteenth-century investigators of natural processes as Benjamin Franklin, Joseph Priestley, and Alessandro Volta. In 1777, after observing gas bubbles in Lago di Maggiore, Alessandro Volta published Lettere sull’ Aria inflammabile native delle Paludi, a slim book about “native inflammable air of marshlands” (Volta, 1777). Two years later, Volta isolated methane, the simplest hydrocarbon molecule and the first in the series of compounds following the general formula of CnH2n+2. When in 1866 August Wilhelm von Hofmann proposed a systematic nomenclature of hydrocarbons, that series became known as alkanes (alkenes are CnH2n; alkines are CnH2n−2).
The second compound in the alkane series is ethane (C2H6), and the third one is propane (C3H8). The fossil fuel that became known as natural gas and that is present in different formations in the topmost layers of the Earth’s crust is usually a mixture of these three simplest alkanes, with methane always dominant (sometimes more than 95% by weight) and only exceptionally with less than 75% of the total mass (Speight, 2007). C2H6 makes up mostly between 2 and 7% and C3H8 typically just 0.1–1.3%. Heavier homologs—mainly butane (C4H10) and pentane (C5H12)—are also often present. All C2–C5 compounds (and sometimes even traces of heavier homologs) are classed as natural gas liquids (NGL), while propane and butane are often combined and marketed (in pressurized containers) as liquid petroleum gases (LPG).
Most natural gases also contain small amounts of CO2, H2S, nitrogen, helium, and water vapor, but their composition becomes more uniform before they are sent from production sites to customers. In order to prevent condensation and corrosion in pipelines, gas processing plants remove all heavier alkanes: these compounds liquefy once they reach the surface and are marketed separately as NGL, mostly as valuable feedstocks for petrochemical industry, some also as portable fuels. Natural gas processing also removes H2S, CO2, and water vapor and (if they are present) N2 and He (for details, see Chapter 3).
1.1 METHANE’S ADVANTAGES AND DRAWBACKS
No energy source is perfect when judged by multiple criteria that fully appraise its value and its impacts. For fuels, the list must include not only energy density, transportability, storability, and combustion efficiency but also convenience, cleanliness, and flexibility of use; contribution to the generation of greenhouse gases; and reliability and durability of supply. When compared to its three principal fuel alternatives—wood, coal, and liquids derived from crude oil—natural gas scores poorly only on the first criterion: at ambient pressure and temperature, its specific density, and hence its energy density, is obviously lower than that of solids or liquids. On all other criteria, natural gas scores no less than very good, and on most of them, it is excellent or superior.
Specific density of methane is 0.718 kg/m3 (0.718 g/l) at 0°C and 0.656 g/l at 25°C or about 55% of air’s density (1.184 kg/m3 at 25°C). Specific densities of common liquid fuels are almost exactly, 1,000 times higher, with gasoline at 745 kg/m3 and diesel fuel at 840 kg/m3, while coal densities of bituminous coals range from 1,200 to 1,400 kg/m3. Only when methane is liquefied (by lowering its temperature to −162°C) does its specific density reach the same order of magnitude as in liquid fuels (428 kg/m3), and it is equal to specific density of many (particularly coniferous) wood species, including firs, cedars, spruces, and pines.
Energy density can refer to the lower heating value (LHV) or higher heating value (HHV); the former rate assumes that the latent heat of vaporization of water produced during the combustion is not recovered, and hence it is lower than HHV that accounts for the latent heat of water vaporization. Volumetric values for methane are 37.7 MJ/m3 for HHV and 33.9 MJ/m3 for LHV (10% difference), while the actual HHVs for natural gases range between 33.3 MJ/m3 for the Dutch gas from Groningen to about 42 MJ/m3 for the Algerian gas from Hasi R’Mel. Again, these values are three orders of magnitude lower than the volumetric energy density of liquid fuels: gasoline’s HHV is 35 GJ/m3 and diesel oil rates nearly 36.5 GJ/m3. Liquefied natural gas (50 MJ/kg and 0.428 kg/l) has volumetric energy density of about 21.4 GJ/m3 or roughly 600 times the value for typical natural gas containing 35–36 MJ/m3.
Methane’s low energy density is no obstacle to high-volume, low-cost, long-distance terrestrial transport. There is, of course, substantial initial capital cost of pipeline construction (including a requisite number of compression stations), and energy needed to power reciprocating engines, gas turbines, or electric motors is the main operating expenditure. But as long as the lines and the compressors are properly engineered, there is no practical limit to distances that can be spanned: multiple lines bring natural gas from supergiant fields of Western Siberia to Western Europe, more than 5000 km to the west. Main trunk of China’s West–East pipeline from Khorgas (Xinjiang) to Guangzhou is over 4,800 km long, and eight major branches add up to the total length of 9,100 km (China.org, 2014). Moreover, pipelines transport gas at very low cost per unit of delivered energy and can do so on scales an order of magnitude higher than the transmission of electricity where technical consideration limit the maxima to 2–3 GW for single lines, while gas pipelines can have capacities of 10–25 GW (IGU, 2012).
Undersea pipelines are now a proven technical option in shallow waters: two parallel 1,224 km long lines of the Nord Stream project built between 2010 and 2012 between Russia and Germany (from Vyborg, just north of Sankt Petersburg to Lubmin near Greifswald in Mecklenburg-Vorpommern) to transport 55 Gm3/year were laid deliberately in the Baltic seabed in order to avoid crossing Ukraine or Belarus before reaching the EU (Nord Stream, 2014). Crossing deep seas is another matter: low energy density of natural gas precludes any possibility of shipborne exports at atmospheric pressure, and the only economic option for intercontinental shipments is to liquefy the gas and carry it in insulated containers on purpose-built tankers; this technique, still much more expensive than pipeline transportation, will be appraised in detail in Chapter 5. Methane’s low energy density is also a disadvantage when using the fuel in road vehicles, and once again, the only way to make these uses economical is by compression or liquefaction of the gas (for details, see Chapter 7).
Low energy density would be a challenge if the only storage option would be as uncompressed gas in aboveground tanks: even a giant tank with 100 m in diameter and 100 m tall (containing about 785,000 m3 or
roughly 28 TJ) would store gas for heating only 500 homes during a typical midcontinental Canadian winter. Obviously, volumes of accessible stores must be many orders of magnitude higher, high enough to carry large midlatitude cities through long winters. The easiest, and the most common, choice is to store the fuel by injecting it into depleted natural gas reservoirs; other options are storage in aquifers (in porous, permeable rocks) and (on a much smaller scale but with almost perfect sealing) in salt caverns.
High combustion efficiency is the result of high temperatures achievable when burning the gas in large boilers and, better yet, in gas turbines. Gas turbines are now the single most efficient fuel convertors on the market and that high performance can be further boosted by combining them with steam turbines. When exiting a gas turbine, the exhaust has temperature of 480–600°C, and it can be used to vaporize water, and the resulting steam runs an attached steam turbine (Kehlhofer, Rukes, and Hannemann, 2009). Such combined cycle generation (CCG, or combined cycle power plants, CCPP) can achieve overall efficiency of about 60%, the rate unsurpassed by any other mode of fuel combustion (Figure 1.2). And modern natural gas-fired furnaces used to heat North America’s houses leave almost no room for improvement as they convert 95–97% of incoming gas to heat that is forced by a fan through ducting and floor registers into rooms.
Figure 1.2 Combined cycle gas turbine: energy flow and a model of GE installation.
Reproduced courtesy of General Electric Company.
Little needs to be said about the convenience of use. The only chore an occupant has to do in houses heated by natural gas is to set a thermostat to desired levels (with programmable thermostats, this can be done accurately with specific day/night or weekday/weekend variations)—and make sure that the furnace is checked and cleaned once a year. Electronic ignition, now standard on furnaces as well as on cooking stoves, has eliminated wasteful pilot lights, and auto reignition makes the switching a one-step operation (turning a knob to desired intensity) instead (as is the case with standard electronic ignition) of turning a knob to on position (to open a gas valve), waiting a second for ignition, and then turning a knob to a preferred flame intensity.
Combination of these desirable attributes—safe and reliable delivery by pipelines from fields and voluminous storages, automatic dispensation of the fuel by electronically controlled furnaces, effortless control of temperature settings for furnaces and stoves, and low environmental impact—means that natural gas is an excellent source of energy for densely populated cities that will house most of the world’s population in the twenty-first century. As Ausubel (2003, 2) put it, “the strongly preferred configuration for very dense spatial consumption of energy is a grid that can be fed and bled continuously at variable rates”—and besides electricity, natural gas is the only energy source that can be distributed by such a grid and used directly in that way.
As for the cleanliness of use, electricity is the only competitor at the point of final consumption. Combustion of pure methane, or a mixture of methane and ethane, produces only water and carbon dioxide . There are no emissions of acidifying sulfur oxides (as already noted, H2S is stripped from natural gas before it is sent through pipelines), while heating houses with coal or fuel oil generates often fairly high emissions of SO2. Moreover, coal combustion produces high concentrations of particulate matter (diameters of <10 µm, PM10), and the smallest particles (diameter <2.5 µm, PM2.5) are also fairly abundant when burning heavier liquids, while combustion of natural gas emits only a small fraction of the finest particulate matter compared to the burning of solid or liquid fuels.
Similarly, natural gas is a superior choice when generating electricity in large power plants. Coal burning in large central stations remains a globally dominant way of thermal electricity generation, and even with appropriate modern air pollution controls (electrostatic precipitators to capture more than 99% of fly ash produced by the combustion of finely pulverized coal in boilers; flue gas desulfurization to remove more than 80% of SO2 produced by oxidation of coal’s organic and inorganic sulfur), to generate a unit of electricity, it releases five to six times more PM2.5 and PM10 and in many cases more than 1,000 times as much SO2 as does the combustion of natural gas (TNO, 2007).
No other form of energy has a higher flexibility of use than electricity: commercial flying is the only common final conversion that it cannot support, as it can be used for heating, lighting, cooking, and refrigeration; for supplying processing heat in many industries, powering all electronic gadgets and all stationary machinery; for propelling vehicles, trains, and ships; and for producing metals (electric arc furnaces and electrochemical processes). Natural gas shares the flying limitation with electricity—but otherwise, the fuel is remarkably flexible as its common uses range from household space heating and cooking to peak electricity generation and from powering compressors in nitrogen fertilizer plants to propelling LNG tankers (for details, see Chapter 4).
Because climate change and the future extent of global warming have become major concerns of public policy, contribution to the generation of greenhouse gases has emerged as a key criterion to assess desirability of fuels. On this score, natural gas remains unsurpassed as its combustion generates less CO2 per unit of useful energy than does the burning of coal, liquid fuels, or common biofuels (wood, charcoal, crop residues). In terms of kg CO2/GJ, the descending rates are approximately 110 for solid biofuels, 95 for coal, 77 for heavy fuel oil, 75 for diesel, 70 for gasoline, and 56 for natural gas (Climate Registry, 2013). Moreover, high-temperature coal combustion in large power stations also produces much higher volumes of the other two most important greenhouse gases: more than 10 times as much CH4 and more than 20 times as much N2O per unit of generated electricity (details in Chapter 7).
Reliability of supply is perhaps best demonstrated by the fact that inhabitants of large northern cities hardly ever think about having their gas supply interrupted because such experiences are exceedingly rare. There may be a temporary problem with a distribution line bringing the gas to a house, and there are rare—and in a great majority of cases perfectly preventable—explosions. A widely reported explosion that leveled two apartment buildings, killed 7, and injured more than 60 in New York’s East Harlem on March 12, 2014, is a good illustration of such an avoidable accident. Several residents said that they “smelled gas in the area for several days” (Slattery and Hutchinson, 2014). That unmistakable smell is butanethiol (butyl mercaptan, C4H10S) that is added to odorless natural gas in order to detect even tiny leaks by smell (humans can detect as little as 10 parts per billion of the skunk-like odor).
Nor are there any great uncertainties about the reliability of international gas supply. The most notable case of interrupted supply took place in January 2009 when Gazprom cut off all flows of Russian gas to Ukraine (also affecting the deliveries to more than half a dozen European countries whose gas must flow through the Ukrainian lines) due to the unpaid accumulated debt for previous deliveries (Daly, 2009). The flow was restored after 13 days, but by March 2014, new Ukrainian debts threatened a reprise of 2009, although Gazprom maintained that the EU consumers west of the Ukraine would not be affected. Another threat of export interruption (following Russia’s annexation of Crimea and fighting in the Eastern Ukraine) was averted by a deal conclude in late October 2014. But this unique, albeit recurrent, threat is not a reflection of general natural gas trading practices, rather an exception due to an unsettled nature of Russia’s relations with its neighbors in the post-Soviet era.
Durability of supply is, of course, the function of resources in place and of our technical and managerial capabilities to translate their substantial part into economically recoverable commodities—and natural gas ranks high on all of these accounts. Natural gas is present in abundance in the topmost crust in several formations, but until recently, only three kinds of gaseous hydrocarbons dominated commercial production. They are natural gases associated with crude oils, a very common occurrence in nearly all of th
e world’s major oil reservoirs; these gases may be present in separate layers in a reservoir containing oil and gas, they may accumulate on top of oil as gas caps, or they may be (another common occurrence) dissolved in crude oil. Usual cutoff for associated gas is when a gas/oil ratio is less than 20,000 ft3 per barrel (in SI units about 350 m3 of gas per 100 l of oil).
In contrast, nonassociated natural gas comes from gas fields, that is, from hydrocarbon reservoirs whose gas/oil ratio exceeds the rate noted in the preceding paragraph. The two common categories of nonassociated natural gas are wet (also called rich) gas that is extracted from reservoirs where methane dominates but where heavier alkanes (NGL) account for a substantial share of hydrocarbon mixtures, while dry natural gas comes from reservoirs where prolonged heat processing produced gas mixtures containing more than 90% or even more than 95% of methane and only small amounts of ethane and other alkanes.
These three conventional resources continue to dominate global extraction of natural gas, but some countries and regions are now producing increasing quantities of gaseous fuel from coal beds and from shales, while extraction of gas from methane hydrates still awaits additional technical advances before becoming commercial. All resource totals are always only temporary best estimates, but in this instance, their magnitude guarantees generations of future use: the best recent assessments of recoverable resources indicate that the global peak of natural gas extraction is most likely no closer than around 2050 or perhaps even after 2070. Another reassuring perspective shows that during the past three decades (between 1982 and 2012), the world gas consumption rose 2.3-fold, but the global reserve/production ratio has remained fairly constant, fluctuating within a narrowband of 55–65 years and not signaling any imminent radical shifts.
