by Vaclav Smil
Ethylene is also the starting material for the production of PVC, the second most common plastic worldwide. Catalytic reaction of ethylene and chlorine (released by electrolysis of NaCl) produces ethylene dichloride whose cracking results on vinyl chloride monomer that is turned into white PVC powder by polymerization. Although the global PVC output is lower than the PE production, the material is even more ubiquitous: wire insulation, sewage pipes, virtually every disposable item in a hospital (tubing, bags, containers, trays, basins, gloves), window frames, house siding, toys, and credit cards to name just a few common categories. But unlike PE, PVC has been often seen as a health hazard and a major environmental risk (Smil, 2013a).
The third in the trio of dominant plastics is PP produced since the mid-1950s by cracking propane and then by polymerizing propylene (C3H6, propene). PP is flammable and gets degraded by UV radiation, but it has many ubiquitous uses (above all various food containers, bottles, garbage cans, and pipes) that overlap with PE, but its combination of low density, fairly good strength, high melting point and resistance to acids and solvents makes it a preferred material for high-temperature uses (most commonly many items in hospitals that require sterilization) and heavy-duty applications (industrial pipes, container lids). PP is also used for carpets and outdoor fabrics and in several countries (including Canada) for new, more durable banknotes.
Oxidative catalytic dehydrogenation of butane produces butadiene whose polymerization yields synthetic rubber: polybutadiene is highly resistant to wear, and that makes it an excellent candidate for the production of vehicle tires, and it is also used as a coating in electronics and in making a variety of elastic items. Polybutadiene rubber is highly elastic, it is often blended with natural rubber, and it now accounts for about a quarter of the global output of synthetic rubber. The most common (and the most affordable) kind of synthetic rubber is a copolymer of styrene and butadiene, while polyisoprene rubber shares the chemical structure with natural rubber but lacks its other ingredients and hence does not equal its quality.
Pentane is in a different category of raw materials than are the three lighter alkanes: rather than getting transformed by catalytic reactions into another compound, it is used a blowing agent in the production of expanded polystyrene (PS), a superior insulation material made of 90–95% of PS and 5–10% of pentane. PS beads are first expanded roughly 40 times by a small amount of steam-heated pentane; then the PS is cooled down and kept for up to 2 days in a holding tank before its reheating achieves the final expansion producing a material made up of as much as 98% of air. Pentane is also used as a blowing agent in making polyurethane foams.
4.3.3 Gas-to-Liquid Conversions
Industrial gas-to-liquid (GTL) conversions have followed two main pathways: methanol synthesis producing an alcohol and Fischer–Tropsch (F–T) synthesis producing synthetic crude oil (Olah, Goeppert, and Prakash, 2006; de Klerk, 2012; Brown, 2013). They both start with synthetic gas (syngas) made by catalytic steam reforming of a carbon-rich feedstock, solid, liquid, or gaseous. The starting raw material can be biomass, and until the 1920s, all commercial production of methanol was wood based; hence, its common name is wood alcohol. F–T production of gasoline by Nazi Germany was based on brown coal, and South Africa’s production of gasoline and diesel (starting in 1955 in Sasolburg) was based on hard coal. Natural gas has become a dominant feedstock in the United States and in the Middle East because of its abundance and low cost.
Methanol (CH3OH, methyl alcohol) is produced directly from synthetic gas (a mixture of H2, CO, and CO2) whose production from methane has been already described earlier in this chapter when dealing with ammonia. Subsequently, an exothermic catalytic reaction combines the gases to make methanol: . About 30% of global methanol production (roughly 50 Mt in 2013) is used to make formaldehyde (widely used in wood, pharmaceuticals, and automotive industries), and another 30% goes for making acetic acid (mainly for adhesives and paints), methyl chloride (for silicones), and dimethyl terephthalate used for recyclable plastic bottles (Methanex, 2014). Production of methyl tertiary butyl ether (MTBE, added to gasoline to prevent knocking and raise octane rating) used to be a large consumer of methanol but the compound was outlawed in the United States. The most important energy use is for fuel blending: adding methanol to gasolines claimed about 12% of the total output in 2013 and the use is expanding strongly. I will return to this use in Chapter 7.
Production of methanol is the simplest GTL conversion: a much more complex procedure can turn the simplest alkane to high-purity liquid hydrocarbons, including gasoline, kerosene, and diesel fuel. These conversions are using F–T process first commercialized in Germany (Weil, 1949; Schwerin, 1991). Franz Fischer, Hans Tropsch, and Helmut Pichler developed the process between 1923 and 1926, and IG Farben built a prototype plant in 1926. F–T process starts with the splitting of CO and results in the formation of liquid hydrocarbons, mostly alkanes—(2n + 1) H2 + n CO → CnH(2n + 2) + n H2O—but it also produces some alkenes and oxygenated hydrocarbons. Iron- and cobalt-based catalytic reactions produce liquids that have no sulfur and heavy metals (hence their combustion produces very little air pollution) and that can be hydrocracked into a variety of fuels (LPG, gasoline, jet fuel, naphtha, diesel) and lubricants, waxes, and white oils.
During WWII, Germany’s coal-based GTL reached, in 1943, as much as 124,000 barrels per day (bpd), but then the allied bombing reduced the output to just 3,000 bpd by the fall of 1944 (Schwerin, 1991). The synthesis was abandoned after WWII as imports of inexpensive Middle Eastern and then Russian crude oil made such ventures uneconomical. Several small American plants built after WWII were closed by 1953, but in 1955, South Africa’s Sasol began to produce hydrocarbons using large domestic coal deposits, first to lower dependence on imports and then to maintain domestic supply when the country’s imports were embargoed due to its apartheid policies (Sasol, 2014). In 1997, PetroSA Mossel Bay plant, using natural gas from fields some 120 km offshore, became the world’s first GTL using a process developed by Sasol for its planned ventures in Qatar and Nigeria. Sasol’s first overseas plant, Oryx GTL in Qatar (daily capacity of 33,700 barrels of liquids), began to operate in 2007, and the company has several plans for facilities in North America.
Among large oil and gas companies, Shell has been the one most committed to the development of large-scale GTL (Shell, 2014). Since the 1970s, it has amassed more than 3,500 patents for all stages of the process, and it used its experience from its first GTL plant in Bintulu in Malaysia (which began to operate in 1993 with a current daily capacity of 14,700 barrels) to build the world’s largest project in Ras Laffan Industrial City in Qatar: Pearl GTL entered full production by the end of 2012, and Shell is the operator of the plant developed under a production and sharing agreement with Qatar Petroleum. Pearl GTL uses natural gas from the world’s largest gas field (North Dome): 22 wells produce maximum of 1.6 billion cuft/day to be converted, by proprietary Shell Middle Distillate Synthesis, into 140,000 barrels of virtually sulfur-free, highly biodegradable, and nearly odorless products (gas oil, kerosene, naphtha, and paraffins) and 120,000 barrels of natural gas liquids and ethane (Shell, 2014; Figure 4.5).
Figure 4.5 Qatar Shell Pearl GTL.
Reproduced with permission from Photographic Services, Shell International Limited.
Pearl GTL was to be profitable at oil prices between $50 and 70/barrel, but after it began to operate, prices were fluctuating at around $100/barrel making its operation quite rewarding—but this has not resulted in a worldwide stampede to build more large GTL projects: high capital cost of these facilities is a key deterrent. In the late 1990s, the capital cost for GTL plants was estimated to be as low as $20,000/bpd, Shell’s Pearl GTL costs $140,000/bpd, and Nigerian Escravos (Sasol–Chevron) is estimated at $180,000/bpd (de Klerk, 2012). Escravos was designed to eliminate large-scale flaring of natural gas in the Niger Delta by setting up a 33,000 bpd GTL facility (processing 325 Mcf/day) based on the Oryx exp
erience as a collaboration of Sasol, Chevron, and the Nigerian National Petroleum Corporation.
But the project’s completion has been postponed several times before the start-up in mid 2014 (Chevron, 2014), and its cost (close to $10 billion) is roughly eight times of a similarly sized Oryx which required $1.2 billion (Sasol, 2014). And (a development not anticipated even just a decade ago) petrochemical producers in the Gulf countries are now experiencing regional shortages of natural gas and are forced to use liquid feedstocks (Horncastle et al., 2012). In any case, perhaps the best way to illustrate how far the GTL projects have to go in order to make a real difference to the global liquid fuel supply is to note that the aggregate capacity of all GLT projects operating in 2014 (<400,000 bpd) was equal to less than 0.5% of the global liquid hydrocarbon extraction.
The ultimate goal of natural gas conversion is to commercialize new methods that would transform methane into cheap feedstocks. Perhaps the most publicized laboratory demonstration achieved selective conversion of methane to methanol at temperatures around 200°C using platinum bipyrimidine complexes as catalysts (Periana et al., 1998). Solid catalysts would be preferable (Palkovits et al., 2009), but as is often the case with laboratory demonstrations, scaling up this pathway as the basis of commercial production is another matter (Service, 2014). Other intriguing proposals envision enzymatic bioconversion of methane to liquid fuels (Conrado and Gonzalez, 2014) and direct, nonoxidative conversion of methane to ethylene, aromatics, and hydrogen (Guo et al., 2014). Again, challenges inherent in scaling such processes to produce millions of tons of feedstocks a year remain immense.
5
Exports and Emergence of Global Trade
Coal exports are well documented already in medieval Europe, starting with the English sales during the fourteenth century: before its end, dozens of boats were engaged in regular shipment of the fuel from Newcastle to European ports on the coasts between northern France and Denmark (Daemen, 2004). Crude oil was traded internationally almost from the very beginning of its commercial extraction, and so were the numerous refined oil products, including such important nonfuel items as lubricating oils, waxes, and asphalt. By the end of the nineteenth century, the two largest oil producers, Russia and the United States, were also the largest exporters of petroleum products, mainly to Western Europe.
By 1950, even before large-scale oil imports to Europe and Japan, 27% of the world’s crude oil production was internationally traded, and that share rose to 36% by 1960 and to nearly 55% by 1974, just after the OPEC’s action had quintupled the world oil price (UNO [United Nations Organization], 1976). In contrast, large-scale international trade in natural gas was nonexistent or very limited as long as only a few countries were substantial producers (recall that even as recently as 1970, there were only five countries, the United States, Canada, Netherlands, Romania, and the USSR, producing annually more than 20 Gm3 of natural gas), and once the supply had expanded, development of substantial gas trade required first major capital investments in transcontinental pipelines (for trade within North America or Europe) and then in expensive infrastructures to liquefy, transport, and regasify gas (for imports from other continents).
But once these two processes got underway, the progress was relatively rapid. In 1950, the international gas trade amounted to a small fraction of 1% of the extracted fuel, and even by 1960, the only major export stream was the western Canadian gas (about 2.6 Gm3) going to the US Midwest. But by the century’s end, nearly 21% of all extracted natural gas was sold abroad, and by 2012, 31% of all marketed natural gas was traded internationally (21% by pipelines, 10% by liquefied natural gas (LNG) tankers), compared to 64% of crude oil and about 16% of bituminous coal (WCA (World Coal Association, 2014). As a share of the total output, natural gas is thus now traded about twice as much as coal and about half as much as crude oil, but a better comparison is in terms of energy equivalents: in 2012, natural gas export reached about 36 EJ, while crude oil exports were 3.2 times larger at 115 EJ and coal exports were about 31 EJ, or 15% lower than the international gas sales.
Compared to crude oil (and even more so to the sales of refined oil products), the natural gas trade has been also much less diversified. Virtually every one of the world’s roughly 200 countries (including major crude oil producers) is importing some refined oil products, and 16 countries are major crude exporters (shipping more than a million barrels a day): Saudi Arabia, Russia, the UAE, Kuwait, Nigeria, Iraq, Iran, Qatar, Angola, Venezuela, Norway, Canada, Algeria, Kazakhstan, Libya, and Algeria. In addition, 20 other countries sell more than 100,000 barrels of crude a day (CIA, 2014). In contrast, the total number of natural gas importers remained limited until the 1960s when the Dutch and Algerian gas began to reach the European market and widened further after 1973 when the first Soviet gas exports reached both East and West Germany, while the number of exporters began to increase only during the 1990s with the expansion of LNG trade.
In 2012, dozen countries were major natural gas exporters by pipeline led by Russia and followed (in volume order) by Norway, Canada, and the Netherlands. These four countries accounted for 61% of all exports by pipeline. The next four largest exporters were Turkmenistan, Algeria, Qatar, and Bolivia. When the exports of natural gas (petroleum gases in the terminology of the Standard International Trade Classification, item 3414) are expressed as the shares of total foreign earnings, the countries that were most dependent on such sales in the year 2010 were Bolivia (41%), Turkmenistan (40%), Algeria (20%), Norway (16%), and Russia with nearly 9% (Hausmann et al., 2013). As I will detail later in this chapter, the trade in LNG was slow to expand, but its total volume has reached about 50% of the amount exported through pipelines (330 Gm3 compared to 705 Gm3 in 2012) with 18 LNG-exporting countries led by Qatar (accounting for nearly a third of the total 2012 volume), with Malaysia the distant second (<10% of all LNG trade) followed by Australia, Nigeria, and Indonesia (each on the order of 8% of the global total).
In this chapter, I will look in some detail at the two major continental natural gas markets: at North America with its now rapidly changing supply and demand with imports accounting for about 18% of the global total and at the world’s largest, and increasingly interconnected and integrated, market that links the giant fields of Asia (Siberian Russia, Central Asia, and the Middle East) with the importers in Europe and the Far East and that involves about 75% of global natural gas pipeline trade. The chapter’s last segment will be devoted to the slow evolution of LNG industry and to the assessment of its current state and near-term prospects: will it become a truly global endeavor akin to the trade in crude oil and refined oil products (with scores of importers) or will its importance remain limited to only a few regions?
5.1 NORTH AMERICAN NATURAL GAS SYSTEM
Origins of North American natural gas trade go back to the 1890s. Canada began exporting natural gas from Welland, Ontario, in 1891 to Buffalo in Upstate New York (at that time a major US industrial center), and in 1897 a pipeline under the Detroit River brought gas from the Essex field to Detroit, Michigan, and also to Toledo, Ohio. Declining output of the Essex field soon led the Ontario government to prohibit exports of both gas and electricity. Canada had actually become a small-scale importer of the US gas, and the situation changed only when major post-WWII hydrocarbon discoveries in the Western Canada Sedimentary Basin (in Alberta and British Columbia) transformed Canada into a major crude oil and natural gas exporter, with all of the gas going to the United States.
In 2012, Canada had just over 1% of the world’s proved gas reserves, but until 2011, it was the world’s third largest producer of natural gas (behind the United States and Russia), and only in 2012, it was surpassed (by <3%) by Iran, the country with the world’s largest (just over 18% of the total) conventional gas reserves. Three factors explain the great disparity between Canada’s modest natural gas endowment and its large annual gas extraction: domestic needs for heating, with Canada averaging recently 3,500–4,500 heating deg
ree days, compared to 2,000–2,500 in the United States (CGA [Canadian Gas Association], 2014); energy-intensive categories of industrial production (petrochemicals, synthetic fertilizers, ferrous and color metallurgy); and the country’s proximity to the huge US market that has for decades guaranteed a rising demand for gas imports.
As a result, Canada has been sending large shares of its gas extraction—30% in 1980, 38% in 1990, 49% in 2000, 41% in 2010, and 51% in 2013—to the United States, making it the world’s second largest gas exporter (after Russia) until 1980 when it was surpassed by Norway and the third largest exporter until 2009 when it was surpassed by Qatari shipments of LNG. Canada has been the source of all but a small fraction of natural gas imported to the United States. Imports from Mexico have been small and sporadic (up to 2.9 Gm3 in the early 1980s, none later in the decade, and no more than 1.5 Gm3/year since the year 2000), and imports of LNG (started in 1985) remained below 5 Gm3 until the year 2000 and peaked at almost 22 Gm3 in 2007.
This means that Canada supplied 99.5% of all imports in 1975, 94% in 2000, 82% in 2007, and, once again, 97% in 2013. Shares of Canada’s natural gas in the overall US consumption were just over 5% in 1975, 15% in 2000, and 16% in 2007 with, naturally, much higher contributions in main import markets in the Pacific Northwest (Seattle), the Midwest (Minneapolis, Milwaukee and Chicago), and the Northeast (Boston). And a comparison in absolute terms shows even better the magnitude of that trade: when Canada’s natural gas exports peaked at 107 Gm3 in 2007, they were larger than the total gas production of all but six leading countries, and their volume was larger than the current natural gas production of Saudi Arabia.
