Power Density

by Vaclav Smil

  Pipelines are not only the least expensive mode of transporting oil on land but also the safest. The United States pioneered their use starting in the 1870s but the longest post-World War II American lines, from the Gulf of Mexico to the East Coast, were eventually eclipsed by pipelines carrying oil from western Siberia's supergiant Samotlor oil field to Western Europe, a distance of about 4,500 km. The United States has an extensive network of both crude oil pipelines carrying oil from major oil basins (with diameters of up to 1.2 m) and from tanker ports and product pipelines moving refined fuels (above all gasoline and kerosene, with diameters of up to 1.05 m) to major consumption centers. Pipeline construction claims corridors 15-30 m wide (needed for trenching, pipe delivery, and the operation of pipe-laying machinery) and ROW strips for operation; on US federal lands they are normally up to 15 m for buried pipelines and 19.2 m for elevated pipelines, but the extremes can range from only about 10 m to more than 30 m.

  These strips are kept clear of major vegetation and any major obstructions to ensure access for monitoring, maintenance, and effecting needed repairs. The danger of accidental encroachment at major lines can be prevented, or at least minimized, by aerial or satellite monitoring, by burying fiber cable above the pipelines, or by placing infrasonic seismic sensors (Chastain 2009). Pumping stations, placed at roughly 100-km intervals, need 10-20 ha. The latest statistics show about 80,000 km of crude oil lines and 140,000 km of product lines, and a total transported mass of roughly 1.675 Gt (BTS 2013). Assuming (perhaps a bit conservatively) an average ROW of 15 m, those figures imply an average nationwide throughput power density of 675 W/m2.

  America's longest pipeline is the Trans-Alaska Pipeline System, owned and operated by the Alyeska Pipeline Service Company and linking the North Slope with Anchorage. The line is 1,288 km long (with about 700 km built aboveground through the permafrost territory), and its ROW is about 20 m. Its peak throughput, in 1988, was just over 100 Mt of crude oil, but by 2012 the rate was down to just over 30 Mt/year (Alyeska Pipeline 2013; fig. 4.7). These performances translate to throughput power densities of about 5,300 W/m2 and 1,500 W/m2, respectively. Many oil pipelines of moderate to low capacity will have throughput power densities of less than 500 W/m2.

  Figure 4.7

  Trans-Alaska Pipeline. © Robert Harding World Imagery/Corbis.

  Tanker loading facilities make rather limited onshore claims, mainly for necessary storage tanks; the transfer operations are often located entirely offshore in order to accommodate larger ships with a deeper draft: the most famous examples are the Saudi Ras Tanura and the Iraqi Faw facilities. As a result, the throughput power densities of the largest crude oil-loading facilities are in excess of 105 W/m2. Refineries are also inherently highthroughput facilities, but those with large capacities claim substantial blocks of usually coastal land. Their densely packed assemblies of columns, piping, and arrays of storage tanks are designed to process annually 104-107 t of crude oil in a single facility that has often seen gradual expansion into the surrounding areas.

  Figure 4.8

  ExxonMobil giant Baytown refinery, Texas. © Smiley N.Pool/Dallas Morning News/ Corbis.

  The world's largest refineries process in excess of 500,000 bpd, that is, at least 25 Mt of crude oil a year with an annual throughput of 33.3 GW. These complexes are readily identifiable on satellite images, and the only uncertainty in calculating their throughput power densities concerns whether to include the often extensive areas within the facilities that have been abandoned or that are held in reserve for future expansion. Centro Refinador Paraguana in Falcon, Venezuela, has the world's largest capacity (940,000 bpd), but in 2013 it was actually processing only 588,000 bpd, and it occupies about 500 ha; that translates to an average throughput power density of almost 8,000 W/m2.

  The second largest facility, Ulsan in South Korea, has a capacity of 817,000 bpd and a throughput power density of nearly 5,000 W/m2. The ExxonMobil giant refinery in Baytown, Texas, America's largest, covers 9.7 km2 and has a capacity of 560,640 bpd, and hence a power density of about 3,900 W/m2 (ExxonMobil 2013a; fig. 4.8). Exxon's Baton Rouge refinery in Louisiana, the second largest in the United States, occupies 392 ha along the eastern shore of the Mississippi and 840 ha when its tank farm is included; with 500,000 bpd, those claims translate respectively to 8,600 and 4,000 W/m2 (ExxonMobil 2007). The Yanbu' refinery on the Red Sea in Saudi Arabia, which produces fuel for the domestic market, occupies 165 ha and processes 225,000 bpd, resulting in a power density of roughly 9,200 W/m2 (Saudi Aramco 2013). The largest refinery in the Middle East, the Saudi Ras Tanura, with a capacity of 550,000 bpd and an area of roughly 500 ha, has a power density of nearly 7,500 W/m2, but small facilities will rate well below 1,000 W/m2.

  Natural Gas, Pipelines, and Liquefied Natural Gas

  Natural gas is usually a mixture of the three lightest homologs of the alkane series, methane (CH4), ethane (C2H6), and propane (C3H8). American analyses show the following ranges of the three gases: 73%-95% for CH4, 1.85.1% for C2H6, and 0.1%-1.5% C3H3. Some of the heavier alkanes, mostly butane and pentane, may be also present and are separated out as natural gas liquids before gas enters a pipeline. Raw natural gases have energy densities between 30 and 45 MJ/m3; pure CH4 contains 35.5 MJ/m3, or less than 1/1,000 of crude oil's volumetric energy density. The marketed production of natural gas is appreciably lower than its gross withdrawals, and US data show the reasons for the difference: the extraction loss is about 4%, the removal of nonhydrocarbon gases reduces the volume by about 3%, and less than 1% of the aggregate flow is vented, but nearly 12% is used for field repressurization, leaving the final dry gas production at about 80% of initial withdrawals (USEIA 2013c).

  The low energy density of methane limits the total amount of energy stored in gas reservoirs, but the formations with thick gas-bearing strata have storage densities comparable to those of the world's largest oil fields. The South Pars-North Dome field, shared by Iran and Qatar, is the world's largest store of hydrocarbons: on top of its 51 Tm3 of natural gas (about 35 Tm3 are considered recoverable) it also contained originally nearly 8 Gm3 of natural gas condensates (Esrafili-Dizaji et al. 2013). This translates (assuming that energy density of 1 m3 of condensate equals that of 1 m3 of crude oil) to about 2.1 ZJ of energy, and, with the field's area of 9,700 km2, it implies a storage density of about 215 GJ/m2. Europe's largest onshore natural gas field is the Dutch Groningen in the north near the German border (NAM 2009). The field (discovered in 1959, producing since 1963) had an original gas volume of 2.8 Tm3, with the 100-m-thick reservoir rock underlying about 900 km2 of countryside, implying a storage energy density of about 110 GJ/m2.

  The west Siberian Urengoy gas field is the world's second largest supergiant gas field, but its initial content of as much as 8.25 Tm3 is only about 15%, and its recoverable volume (of about 6.3 Tm3) is less than 20% of the South Pars-North Dome storage (Grace and Hart 1990). The field underlies about 4,700 km2 of thick Siberian permafrost that turns into summer swamps and lakes, implying an initial storage density of just over 60 GJ/m2. Yamburg field, north of the Arctic Circle in Siberia's Tyumen region, comes third: with a recoverable share of 3.9 Tm3 and the reservoir underlying about 8,500 km2 of tundra, its initial storage density was roughly 35 GJ/m2. Hugoton, America's largest natural gas field, is an elongated formation that extends from southwestern Kansas through Oklahoma to Texas; originally it contained 2.3 Tm3, or about 20% less than Groningen, but its large area of nearly 22,000 km2 reduces its storage density to less than 4 GJ/m2 (Dubois 2010).

  Natural gas also comes from three other major sources. The most common one is associated gas whose flows accompany the crude oil extraction (wet gas). This gas is dissolved in the crude oil, and after it reaches the surface, the heavier alkanes are separated as natural gas liquids before further processing and marketing. For decades, large volumes of associated gas produced at remote oil fields without access to gas pipelines were simply vented or burned off (flared). This wasteful practice is sti
ll common in giant western Siberian oil fields: they also yield large volumes of associated gas, and a large share of these flows continues to be flared (Roland 2010). This environmentally damaging practice has been greatly reduced since the 1970s, but the total amount flared globally is still unacceptably high. In 2010 it was estimated at 134 Gm3 (mostly in Russia, Nigeria, and Iran), equivalent to almost 20% of the US gas use (GGFR 2013).

  The world's largest oil field, the Saudi al-Ghawar, is also an excellent example of a reservoir containing both liquid and gaseous hydrocarbons: besides producing annually about 250 Mt (10.5 EJ) of oil, it also yields about 21 Gm3 (750 PJ) of associated natural gas (Alsharhan and Kendall 1986; Sorkhabi 2010). And in 1971, 20 years after the reservoir began producing crude oil, a large pool of nonassociated gas was discovered below the oilbearing layers at a depth of 3-4.3 km; this deep reservoir now produces annually about 40 Gm' (1.4 EJ) of nonassociated gas. North America's latest addition to large formations producing both oil and gas is the Williston Basin (Bakken shale) in North Dakota, where oil extraction by horizontal drilling and fracturing has been accompanied by so much natural gas that, in the absence of adequate pipeline capacity, large volumes of it had to be flared: by the end of 2011 more than one-third of all gas produced in North Dakota was flared or not marketed (USEIA 2011b).

  The third large source of natural gas is coal beds, and China and the United States, the largest coal mining nations, are also the largest producers of gas from this source. The latest addition is natural gas released by horizontal drilling and hydraulic fractioning from shales: gas-bearing shales underlie large areas on all continents, but so far only the United States has developed this resource on a large scale (Maugeri 2013). US statistics show the relative importance of these four principal gas sources: in 2011, 43% of gross withdrawals came from natural gas wells, 21% from oil wells, 6% from coal bed wells, and 30% from shale gas wells, whose output was lower than that of coal bed wells as recently as 2007 (USEIA 2014c).

  Power Densities of Gas Production and Delivery

  As with oil extraction, both well densities and the areas of well sites required for natural gas extraction vary, but, not surprisingly, they closely resemble each other. In conventional US natural gas fields, the typical density is one well per 256 ha, that is, 0.4 wells/km2, but the rate is significantly higher in shale or tight gas formations: in the Barnett shale it was 1.1-1.5 wells/km2 in the beginning, and later permits allowing in-fill wells have resulted in up to 6 wells/km2 (NYSDEC 2011). Future spacing will be less dense as multiple horizontal wells are drilled from a single well pad. For example, in the Marcellus shale, which stretches from West Virginia to New York, a standard vertical well may be exposed to no more than 15 m of the reservoir while a lateral bore of a horizontal well can reach 600-2,000 m within the targeted formation (Arthur and Cornue 2010). This means that a producer can develop one square mile of subterranean resources with 16 vertical wells (with 40-acre spacing), or as few as four horizontal wells drilled from a single pad.

  In Pennsylvania's Marcellus shale, a typical multiwell pad for drilling and fracturing is 1.6.-2.0 ha, which, after a partial restoration, may be as little as 0.4 ha; in New York State a new multiwell pad set up for horizontal drilling and fracturing is 1.4 ha, and that is reduced to 0.6 ha after the required partial reclamation, slightly smaller than a soccer field at 0.7 ha (NYSDEC 2011). The production of natural gas from shales shows the same rapid hyperbolic decline as does the extraction of crude oil (Sandrea 2012). Wells in the Marcellus shale, the most extensive gas-bearing formation in the United States, produce at an initial rate of 120,000 m3/day, followed by an early decline of 75%, while in the Barnett shale in Texas the initial flow is less than 60,000 m3/day, followed by a 70% decline.

  The first-year flow in Pennsylvania may be in excess of 10 Mm3 (average of almost 6 Mm3); the next year the mean is down to less than 2 Mm3, and that flow is halved in the third year (Harper and Kostelnik 2012; King 2013). The highest first-year flows (with a 0.5-ha pad) imply an extraction power density in excess of 2,000 W/m2, while the third-year flow is down to just above 200 W/m2. In western states the initial sizes of well pad sites average nearly 1.6 ha, but over the life of production that is reduced to less than 0.6 ha (Buto, Kenney, and Gerner 2010). These states, as well as the gasproducing areas of Oklahoma, Texas, and California, have hundreds of thousands of old stripper wells whose production is only 100,000-200,000 m3/year, and even with a small well site area of 0.5 ha, their extraction power densities would be less than 50 W/m2 (USEIA 2012).

  Typical new productive wells have extraction power densities two orders of magnitude higher. In Alberta, wells claim 1.5-15 ha (average of 3 ha), and with an average annual output of about 50 Mm3 Qordaan, Keith, and Stelfox 2009), this means an extraction power density of about 1,850 W/m2. Dividing Alberta's 2012 province-wide statistics on natural gas output (100 Gm') by the 1,622 connected wells (Alberta Energy 2013) yields an average productivity of nearly 62 Mm3/well, and a typical power density for well sites of 3 ha would be about 2,300 W/m2. And power densities can be another order of magnitude higher in supergiant fields.

  The Groningen field is one of the best examples of minimal and unobtrusive gas recovery. The extraction is concentrated in 29 production clusters remotely controlled from the central control room in Sappemeer; each cluster has 8-12 wells arranged in a strip and adjoined by associated treatment plants (comprising several identical units), an electricity supply, and a control building (Royal Dutch Shell 2009). Clusters are very similar in size, with almost 7 ha taken by wells and 4 ha by other facilities, and the total area claimed by 20 clusters is about 310 ha. With the annual 2010-2020 production capped at 43.6 Gm3, this puts the field's power density of extraction at about 16,000 W/m2.

  Gathering lines (low pressure, small diameter) take gas from individual wellheads to processing facilities to strip CO2, H2O, and also H2S. The processing of natural gas has minimal land requirements, with power densities ranging mostly between 50,000 and 70,000 W/m2. Purified gas is sent through high-pressure, large-diameter (0.5-1.05 m) transmission (trunk or interstate) lines. US statistics show the difference in the aggregate length of three categories of gas pipelines (PHMSA 2013). In 2012 the country had about 16,800 km of onshore gathering lines and 477,500 km of transmission lines. Compressor stations take up about 2 ha at intervals of 65-150 km, and they have slightly lower throughput power densities, on the order of 20,000 W/m2. Distribution lines (very low pressure, diameters of just 1.25-5 cm, also as plastic tubing) take gas to individual users, and their length of more than 3.2 Gm far surpasses the combined extent of all other pipelines.

  An average throughput power density for US natural gas pipelines can be calculated from detailed information about individual US systems (USEIA 2007). The Northern Natural Gas Company, which serves states from Texas to Illinois, is the country's longest interstate natural gas pipeline system, with about 25,400 km of trunk lines and an annual capacity of 78 Gm3; with an average ROW of 15 m, this implies a throughput power density of about 230 W/m2. Texas Eastern Transmission (14,700 km, carrying 66 Gm3 from the Gulf of Mexico to the Northeast) rates about 330 W/m2. Columbia Gas Transmission Company, which serves the Northeast (16,600 km), has the highest annual capacity (86 Gm3) and a throughput power density of about 380 W/m2. Algonquin Gas Transmission in New England (1,800 km and 24 Gm3) rates about 1,000 W/m2.

  Liquefied Natural Gas

  Increasing volumes of the fuel are traded in the form of liquefied natural gas (LNG). Gasification entails cooling the gas to - 162°C and reducing its volume to about 1/600th of the gaseous state; this is done in several independent units (trains) that are typically about 300 m long (Linde 2010). LNG is stored in superinsulated containers before it is transferred (via articulated pipes) to isothermal tanks on LNG tankers, the largest of which, the Q-Max ships of Qatar, carry 266,000 m3 of gas (Qatargas 2013). With 22.2 GJ/m3 of LNG, that equals almost 6 PJ of floating energy storage. Regasification takes place in se
awater vaporizers. Most of the recently commissioned terminals have liquefaction capacities of 4-5 Mt/year, and most of the new receiving terminals rate between 3 and 5 Mt/year (IGU 2012).

  By the end of 2013 more than 40 liquefaction terminals were in operation or under construction in 19 countries, while nearly 30 countries had more than 90 regasification terminals, with the largest number (24) in Japan (Global LNG 2013). Both the gasification and regasification terminals have relatively small land claims (typically 30-120 ha), and, as with oil tankers, actual LNG loading and offloading are often done offshore. A liquefaction capacity of 3 Mt/year and an area of 80 ha would translate to a throughput power density of 6,400 W/m2 The Norwegian Snohvit LNG plant, Europe's first world-scale LNG project, located on Melkoya island near Hammerfest, has an annual capacity of 4.3 Mt LNG, and its compact modular design occupies only about 70 ha (Nilsen 2012); that (with 53.6 GJ/t LNG) implies a processing power density of about 10,000 W/m2. The first three liquefaction trains at Ras Laffan, the world's largest LNG exporting facility, have an annual capacity of 10 Mt and claim 3.7 km2 (Qatargas 2013), resulting in throughput power density of about 4,600 W/m2.

  Regasification plants have power densities as high, or even considerably higher. America's largest receiving LNG terminal, Cheniere Energy's terminal on the Sabine Pass River in Louisiana, has a capacity of 19.5 Mt/year and a maximum power density of about 8,300 W/m2. Japan is the world's largest importer of LNG, with more than 30 regasification terminals. Higashi Niigata on the coast of the Sea of Japan (annual capacity of 8.45 Mt, area of 30 ha) has a power density of nearly 48,000 W/m2. The Himeji and Himeji Joint LNG terminals have a combined capacity of 12.67 Mt/year on 60 ha of landfill on the northern shore of Seto Inland Sea; this yields a throughput power density of nearly 36,000 W/m2. Tokyo Bay's Futtsu terminal, the world's largest regasification facility, supplies fuel for the world's second largest gas-fired electricity-generating plant, the 4.534-GW Futtsu station (TEPCO 2012). With an annual capacity of 19.95 Mt and an area of just 5 ha (ten storage tanks holding up to 1.1 Mm3), the terminal's throughput power density is about 60,000 W/m2.