by Vaclav Smil
Foundations for mass-scale pipeline construction were set by the widespread adoption of inexpensive steelmaking (Bessemer) process during the 1860s (Smil, 2004) and by the invention of seamless steel pipes by Reinhard and Max Mannesmann at their father’s metal factory in Remscheid (Koch, 1965). In 1885, they introduced the pierce rolling process, and a few years later came pilger rolling, a concurrent lengthening of a pipe and reduction of its diameter and wall thickness. More than a century later, the Mannesmann process still dominates pipe production, but the company lost its independence; in 1999, it was taken over by Vodafone, and in the year 2000, Mannesmannröhren-Werke became a part of the Salzgitter Group (Salzgitter Mannesmann, 2014).
In 1872, a wrought-iron line of more than 80 km brought gas to Titusville, PA, and by 1886, Pittsburgh was receiving natural gas from nearby fields through wrought- and cast-iron pipes with diameters of up to 60 cm. But long-distance natural gas pipelines remained uncommon. The earliest one of these was a nearly 200 km long line from central Indiana to Chicago, completed in 1891, and the first gas export line (20 cm diameter) from Essex County, Ontario, to Detroit, crossing the Detroit River from Windsor in 1895, was less than 40 km long. Between 1906 (the first year for which the nationwide statistics are available for the US gas extraction) and the end of WWI, American gas production grew by about 85%, while much, or most, of the associated gas continued to be vented or flared. In 1920, the ratio of wasted/used gas in the United States was 0.83, but in 1930 it rose to 1.47.
Discoveries of natural gas in Texas, Arkansas, Oklahoma, and other Great Plains states during the 1920s (most notably of the giant Hugoton gas field in 1922) and the need to connect them with large Midwestern cities stimulated such pipelining innovations as electric resistance welding, electric flash welding of seams (greatly improving seam strength), and large-diameter (up to 60 cm) seamless pipes made in 12 m lengths, double the previous standard. The country’s first long-distance (nearly 1,600 km, 60 cm diameter) pipeline between Texas and Chicago was completed after just 1 year of construction in 1931, followed by a line from the Texas Panhandle to Michigan (Castaneda, 2004).
3.2.1 Modern Pipelines
The first post-1945 gas deliveries from Texas to the Northeast used the two famous oil pipelines, Big Inch and Little Inch (both just over 2000 km long), that were built in 1942 and 1943 in order to bring crude oil and refined products to Philadelphia and New York (TETCO, 2000). The lines were decommissioned in November 1945; in 1947, they were bought from the US government by the Texas Eastern Transmission Corporation and converted to carry natural gas, first under low production pressure and later with a nearly 10-fold capacity under compression. In 1953, the Gulf gas reached New England. Concatenation of technical advances—in metallurgy, pipe making, trenching, welding, pipe protection, pipe laying and better compressors—came together after WWII to begin a new era of long-distance, large-diameter, high-throughput natural gas pipelines. The first postwar decade saw the beginning of a generation of rapid pipe laying made possible by fully mechanized trenching, by the adoption of double submerged arc processes for making longitudinal seams in 1948, and by the introduction of high-strength pipes.
Pipeline longevity was enhanced by standard coating (with coal tar or asphalt enamel, done during the installation) and by cathodic (galvanic) protection against corrosion, either passively by using sacrificial anodes or by more effective impressed current systems with anodes connected to a direct current source. These measures were largely or totally absent before WWII, but when properly applied, cathodic protection (especially when incorporating deep well ground anodes) can keep pipe’s original wall thickness and strength almost indefinitely (AGA, 2006). Pipeline safety was further enhanced by the introduction of radiographic inspection of welds and (starting in the 1960s) by using smart “pigs” (instead of simple low-resolution caliper deformation tools) for internal pipe inspection. The latest pigs are equipped with high-resolution magnetic flux sensors and ultrasonic tools that make it possible to locate precisely any pipe anomalies and hence limit the required dig area.
Brush-bearing devices were used to clean pipelines for many years, and the first monitoring tools were smart pigs equipped with electronic sensors to check the thickness and integrity of pipe walls. And the 1960s also saw the introduction of plastic pipe coatings before installation, and the now standard fusion bond epoxy coatings can withstand construction activities and have a very long durability (AGA, 2006). New liquid coatings have made it much easier to recoat, repair, and rehabilitate aging pipelines and extend their lifespan at costs that are substantially lower than pipe replacement (Alliston, Banach, and Dzatko, 2002). Perhaps the most remarkable advance in construction has been a more common use of trenchless installations using guided directional drilling to go under rivers, roads, and built-up surfaces.
Advances were also made in pushing the gas through the lines. Periodic compression of transported gas is necessary in order to compensate for friction and elevation differences that would eventually slow the speed of the moving gas (between 5 and 12 m/s, which is commonly about 30 km/h) and reduce its pressure. Depending on terrain and volumes of the gas, compressor stations are spaced every 60–110 km (Figure 3.8). The world’s longest export pipeline that carries the West Siberian natural gas to Europe has 41 compressor stations along its nearly 4500 km route, one every 110 km. Unless closed down by accidents, for periodic testing of the station’s emergency shutdown system or for a major overhaul, these stations operate year-round. They rely on separators and scrubbers to remove any solid or liquids, and as the repressurization warms the gas, it may have to be cooled before reentering the pipeline. Exhaust silencers are used to reduce the noise generated by compressors, and backup generators are available to supply electricity in emergency.
Figure 3.8 US compressor stations.
The first prime movers installed at American compressor stations during the 1930s were spark engines with horizontal cylinders, and nearly all of them were later (between 1950 and 1970) replaced by integral units, that is, by reciprocating engines sharing the same crankshaft with compressors. These large units, expensive to operate but highly efficient, are still common at the US compressor stations, but gas turbines (both aeroderivative and industrial stationary designs with capacities of up to 15 MW) have been the best choice for all major pipelines since the 1960s (for more on these reliable machines, see Chapter 4). Introduction of reliable and efficient gas turbines has largely eliminated the need for electricity or liquid fuels (previously the dominant choice to power compressors) as these compact machines could be powered simply by diverting a small volume of the transported gas. Compressor stations on long-distance pipelines consume typically 2–3% of the gas pushed through a line (in comparison, resistance losses for high-voltage electricity transmission are 6–7%).
Environmental impact of natural gas pipelines is limited. Their mechanized construction requires access by heavy trenching and pipe-laying machinery and claims 15–30 m wide corridors. After the lines are buried (at least 1.5 m below the surface), right-of-way strips must be maintained to allow access for possible repairs. These strips range from 10 to 30 m, but the land can be grazed by cattle or use for annual crops, and Canada even allows planting of trees less than 1.8 m tall as long as they are at least 1 m away from the line. Permafrost precludes the burial of pipelines in the Arctic, and the lines must be placed on well-anchored steel support and equipped with expansion joints in order to compensate large seasonal temperature differences.
The two main factors determining the transportation costs are the pipeline’s capacity and length. For example, doubling the distance from 2,000 to 4,000 km will roughly double the operating cost per unit of delivered energy, while doubling the annual capacity from 5 to 10 Gm3 will cut the cost by about 30%, and quadrupling it to 20 Gm3 will cut the shipping cost in half (Messner and Babies, 2012). Where there is a choice between a pipeline and LNG, delivery pipelines are less costly
for distances of up to 3,000 km for 60–70 cm diameter lines and up to 5,000 km for 140 cm diameter lines.
Given the longevity of well-built and well-maintained pipelines, it is not surprising that so many large US natural gas transmission lines date to the period of rapid post-WWII expansion, to the 1950s and 1960s. In 2012, the United States had 477,500 km of onshore natural gas transmission lines, of which 48% were built between 1950 and 1970 (with the aggregate length roughly split between the two decades) and 35% were older than 50 years (PHMSA [Pipeline & Hazardous Materials Safety Administration], 2014a). Safety of older pipelines is an obvious concern, but analysis of oil pipeline incidents by Kiefner and Trench (2001) showed that the number of years a pipeline has been in service is an unreliable indicator of its condition: what matters more are the techniques and methods used in a pipeline’s construction. That is why Kiefner and Rosenfeld (2012, 30) concluded that “a well-maintained and periodically assessed pipeline can safely transport natural gas indefinitely because the time-dependent degradation threats can be neutralized with timely integrity assessments followed by appropriate repair responses.”
Leaks in trunk lines and in distribution networks should be always limited to less than 1% of the transported volume: pipeline losses do not only increase the cost of delivery but are also source of a powerful greenhouse gas (for details, see Chapter 7). Unfortunately, we cannot make safety comparisons for natural gas pipelines with other modes of land transportation: pipeline transport of oil is roughly 40 times safer than in rail tanks and 100 times safer than by road tankers, but, obviously, such comparisons do not really apply to natural gas—LPG shipped by railroads in tank cars are not a directly comparable fuel category, and although both compressed natural gas and LNG can be distributed by trucks, there is no large-scale transport of these fuels in any modern economy.
Comprehensive US statistics allow us to trace the frequency of all significant and serious pipeline incidents as well as the ensuing injuries, fatalities, and property damage. The number of serious incidents (those involving a fatality or hospitalization) for transmission pipelines has declined between 1994 and 2013, and both fatalities (averaging 2/year during 20 years) and injuries (averaging 10/year) have remained low with only 2 years (2000 and 2010) having accidents with, respectively, 15 and 10 deaths (PHMSA, 2014b). Serious incidents affecting distribution lines are, as expected, more common, often caused by severed line during construction or by house fires: the total number of incidents has been about six times higher than for transmission lines, and 20-year averages were 53 injuries and 14 fatalities a year but with all of these indicators showing clearly declining trends.
The long-term annual average of all fatalities (16 a year) translates into accidental mortality of 0.005/100,000, and putting that risks in perspectives is best done by comparing it with such common fatalities and injuries as falls and car accidents: in 2012, falls in the United States caused 13.4 million consulted injuries, and transportation accidents injured 3.6 million people (CDC [Centers for Disease Control], 2014), and in 2010, 26,000 died as a result of falls (8.4/100,000), and car accidents killed 33,500, with a mortality rate of 10.9/100,000 (Murphy, Xu, and Kochanek, 2013; CDC, 2014). This means that it is roughly 2,000 times more likely to die as a result of fall or car accident than as a result of an incident involving a natural gas transmission or distribution line.
To complete the description of the entire US natural gas transportation system, I should also note that in 2012 the country had 17,000 km of onshore gathering lines, as well as 7,800 km of transmission and 9,800 km of gathering lines offshore. The entire network is made up of more than 200 pipeline systems with 5,000 reception points, 1,400 interconnection points, and more than 1,100 delivery points and is connected to national natural gas transmission systems of Canada and Mexico (Figure 3.9). There are also nearly 40 market centers (most of them in place since the 1990s) along major lines in the United States and Canada that provide gas shippers and marketers with access (both receipt and delivery) to two or more pipeline systems, as well as transportation between the centers and requisite administrative services (Tobin, 2003).
Figure 3.9 US pipeline network.
The United States also has nearly 19 natural gas multiline hubs: 12 in Texas and Louisiana, two in Illinois, and one each in California, New Mexico, Colorado, Wyoming, and Pennsylvania. Henry Hub, named after Henry hamlet near Erath in southern Louisiana (and owned by Sabine Pipe Line, Chevron’s subsidiary), sits at the interconnection of nine major interstate pipelines, and it has been the centralized point for natural gas futures trading in the United States (Sabine Pipe Line, 2014). Henry Hub natural gas prices are expressed in US$ per million Btu (abbreviated as MMBtu; as already noted, unlike in the International System of Units where M stand for million, in the US usage, M is 1000 and million is MM). Henry Hub has been the primary standard for the US natural gas spot (wholesale) price, and before 2009, it had seen recurrent short-lived sudden peaks: in December 2000 to $8.9, in October 2005 to $13.42, and in June 2008 to $12.69 (USEIA, 2014c). Since March 2010, their monthly mean stayed below $5 except for unusually cold February of 2014 (monthly mean $6.00, day peak of $8.15 on February 10, 2014), with the bottom at $1.95 in April 2012.
During the late 1990s, the Henry Hub price was actually slightly more expensive than the EU mean price and only about 15–25% cheaper than Japan’s LNG imports. Until mid-2008, wholesale natural gas prices in the United States were only slightly lower than in Europe and about 20% lower than in Japan (EC [European Commission], 2014). The subsequent fall of American wholesale price, driven primarily by rapid shale gas extraction, led to a great decoupling. In spring 2010, the British spot price (which, too, fell since late 2008) was still similar to the declining US rate, but German spot price was double the US rate, and the Japanese LNG imports averaged nearly three times as much. These differences had widened by 2013 when Henry Hub price averaged $3.71/MMBtu, UK (Heren NBP index) price was $10.63, German imports were $10.72 (nearly three times the Henry Hub price), and Japanese LNG imports cost $16.17/MMBtu or 4.35 times the Henry Hub price (BP [British Petroleum], 2014a).
Decoupling of historically closely related crude oil and natural gas prices also took off in 2008: between 1991 and 2008, oil-to-natural gas price ratio (dollars per unit of gross energy content) fluctuated between one and two, but the subsequent rapid rise brought it briefly to more than eight during 2012. When a comparison is done with price averages for 2013—natural gas at $3.73/MMBtu at Henry Hub and West Texas crude oil at $97.98/barrel at Cushing, OK—crude oil supplies about 60 MJ/$ compared to roughly 280 MJ/$ for natural gas, a 4.7-fold difference that makes natural gas a great bargain for all uses where it can displace refined oil products.
Maps of American natural gas lines show their highest (indeed the world’s highest) concentration in the coastal region along the Gulf of Mexico from the southernmost Texas the easternmost Louisiana; in southern Arkansas and northern Louisiana; and in Oklahoma. Relatively dense networks are in Kansas, Iowa, Illinois and Wisconsin in the Midwest, Ohio, Pennsylvania and upstate New York in the East, and Colorado, southern Arizona and California in the West. Columbia Gas Transmission Company (serving the Northeast) has the highest annual capacity (86 Gm3) among the country’s large interstate natural gas systems, but the Northern Natural Gas Company (78 Gm3, with service area extending from Texas to Illinois) has longer main lines (25,400 vs. 16,600 km). Texas Eastern Transmission (66 Gm3, 14,700 km of main lines) comes third, bringing the Gulf of Mexico gas to the Northeast. I will describe the world’s longest natural gas pipelines in Europe and Asia in Chapter 5 when dealing with the emergence of large-scale international gas trade.
3.2.2 Storing Natural Gas
Storage of natural gas is an essential component of the production and distribution system. As the seasonal demand for natural gas rises, the only way to meet it by direct pipeline deliveries would be to raise their daily rates to levels that would be multiple
s of low-season demand, obviously an uneconomical (and also impractical) solution. And even in warm climates (where gas is not used for seasonal heating), it is necessary to cope with daily (weekdays–weekend) and intraday fluctuations caused by household demand for cooking and, much more so, by the requirements of industrial consumers. Storages required for these fluctuations are tiny fractions of volumes needed to assure adequate gas supply during winter months in more northerly latitudes (Canada, parts of the United States and the EU) where seasonal residential and commercial heating may account for as much as 90% of a city’s annual gas consumption.
With rising shares of electricity generated by natural gas (see the next chapter), the demand for highly responsive storage has been increasing in all areas of all affluent countries where more natural gas is used to produce power during the peak consumption hours (often spiking to record levels due to air conditioning demand during prolonged hot spells), a practice that entails large, and often relatively rapid, fluctuations of gas supply. And adequate storages must be also in place in order to ensure uninterrupted supply in the case of upstream pipeline accidents or other breakdowns that would cut off the incoming gas for hours or days. And storage in the United States, the world’s largest gas producer with fluctuating prices, is also done for profit: banking the gas at times of low prices and selling it once demand picks up.
Natural gas is not a perishable commodity, but storing it, and being able to release it on demand and in variable volumes, requires a number of specific conditions. Storing gas in a depleted oil and gas reservoir is the most obvious, hence the oldest, option used for the first time near Weland (not far from Niagara Falls in Ontario) in 1915, and it is still the most common choice. Once the gas was extracted, porous underground formations remain intact, their extent and properties have become well known over the years or decades of exploitation, and the infrastructure needed to operate the storage (wells, pipes) is already in place, a combination that makes the old reservoirs (as long as they are near major consumption centers) also the least expensive natural gas storages to set up and to operate. While the porosity of a depleted reservoir limits the volume of gas that can be stored, its permeability can be increased by using shaped charges and controlled explosions in order to raise the speed of gas injection and withdrawal.
