by Vaclav Smil
Most of the oil in the Earth's crust is not in liquid form but is interspersed in sands or shales, and the storage density of these nonconventional oil resources rivals that of the richest classical fields. This is hardly surprising, as the shares of oil in these rocks are low (commonly less than 10%) but the oil-bearing strata can be very thick. The world's largest concentration of oil interspersed in shales is in the Green River formation, which underlies parts of Colorado, Utah, and Wyoming; the oil-bearing layers there are up to 150 m thick. The Piceance Basin in Colorado holds the world's largest deposit of shale oil: there are roughly 210 Gt of oil locked in the rock under its roughly 18,200 km2 (Johnson et al. 2010), which prorates to nearly 500 GJ/m2 of energy originally in place. That is more than twice the density in the world's richest field producing liquid oil, but the technical challenges and costs (and ultimately the low net energy returns) of extracting oil from Colorado shale are far greater than those associated with getting oil from giant oil fields where the oil initially flows under natural pressure.
Power Densities of Oil Production
Extraction densities depend on the richness of exploited reservoirs, methods of oil recovery (free-flowing wells, artificial lift aided by water flooding or injection of gases), the density of wells, and their productivity. Crowded spacing of oil wells was common in the early decades of oil era (fig. 4.4); now the spacing is carefully planned to optimize the output, which similarly is deliberately controlled either to extend the production span of an oil field or to match the available pipeline capacity. The temporary oil yield of some the world's most famous oil well gushers was astounding (SJVG 2010). The earliest gushers were in the Baku oil fields: Bibi Eibat, drilled on September 27, 1886, flowed at 84,000 barrels per day (bpd), which amounts to (at 5.8 GJ/barrel) to a daily rate of about 5.6 GW.
Figure 4.4
High density of producing oil wells in the Spindeltop field near Beaumont, Texas. Bettmann/CORBIS.
Starting on October 15, 1927, the Baba Gurgur oil field near Kirkuk, Iraq, spewed 95,000 bpd for eight and one-half days (6.4 GW). The famous Spindletop, near Beaumont, Texas, produced 100,000 bpd on January 10, 1901 (6.7 GW), while the recorded maximum is for Cerro Azul No. 4 well near Tampico, Veracruz, Mexico, which blew on February 16, 1916; when it was capped, three days later, its February 19 flow was 260,858 bpd, or 17.5 GW. For comparison, BP's Macondo well, which spilled nearly 700,000 t of oil into the waters of the Gulf of Mexico between April 20 and July 15, 2010, had a maximum flow of about 62,000 bpd, or 4.2 GW.
And all of these gigawatt-sized blow-outs spewed from pipes whose area was no more than 0.02 m2! Even if we were to prorate such flows across a large drill site of 2 ha (200 x 100 m), we would get power densities on the order of 105 W/m2 (300,000 W/m2 for a 6-GW gusher). No other power densities of energy extraction are even remotely close to these extraordinary releases of accumulated stores of high-energy-density fossil fuels. But all of them are necessarily short-lived, lasting only for hours or days, and the output of every naturally pressurized well will decline, usually following a fairly predictable course. Secondary recovery methods will help, but they will claim more land for new injection wells, as well as for the delivery of water or gases.
Perhaps the most representative examination of land claimed by conventional crude oil production comes from the data set of 301 California oil fields covering some 3,000 km2 and containing at least 58,000 production wells, 22,000 shut-in wells, and 25,000 injection wells, at an average density of 31 wells/km2 (Yeh et al. 2010). Calculations of land disturbed per well were based on satellite image analysis of three fields and resulted in the range of 0.33-1.8 ha/well, with an average of 1.1 ha/well, and that rate included not only the cleared or occupied area surrounding a well but also all access roads and other facilities found in each image. The authors used the identical approach to assess land claims of Alberta's conventional oil fields, whose much lower density of only 0.3-2.5 wells/km2 translated into larger land claims, ranging from 1.6 to 7.1 ha/well and an average of 3.3 ha/well (Yeh et al. 2010).
Satellite images of sufficiently high resolution (showing objects smaller than 5 m) indicate that in the world's most productive fields, the extent of land disturbance per well is closer to the just noted Californian mean rather than to the Albertan average. Saudis have not been forthcoming with detailed information about the development and production of the world's largest supergiant oil field, but we know that al-Ghawar has about 3,400 wells that dot its elongated (along the NNE-SSW axis) shape in the eastern Arabian desert between Fazran and Haradh (Afifi 2004), and that these wells typically are rectangular areas of 100-150 m (1.5 ha) graded in sand (Google Earth 2014). The field also has many water injection wells-with water brought by pipelines from the Persian Gulf-as water flooding has become increasingly necessary to keep up its productivity. Samotlor's wells, dotting the western Siberian forest and wetlands, claim mostly between 0.5 and 2 ha.
A detailed study of land disturbance associated with oil and gas development in the Upper Colorado Basin found that the lifetime average pad size in Utah, Colorado, and Wyoming was 1.04 ha (Buto, Kenney, and Gerner 2010). But considerably more land could be disturbed if there is a need to build new long access roads and to clear land for larger storage yards. As for the oil well densities, their maxima are prescribed in many jurisdictions. For example, in the East Texas field, rules require a minimum distance of 200 m between adjacent wells, which translates to a maximum of 25 wells/km2; the West Texas field also has more than 20 wells/km2. Oklahoma assigns 16 ha as the area drained by shallower wells and 32 ha for deeper wells (implying densities of respectively 6.25 and 3.12 wells/km2), while some smaller fields in the United States have more than 50, others less than 5 wells/km2.
Lack of accurate information makes it impossible to offer reliable calculations of peak and short-term extraction densities for the world's largest supergiant oil fields. Assuming that al-Ghawar's output peaked at 250 Mt/year, its maximum extraction power density would have been only on the order of 150 W/m2 when that output is prorated over the entire footprint (2,200 km2) of the reservoir, but it rises to about 5,000 W/m2 when only areas disturbed by wells and roads are considered. Most of al-Burqan's 350 wells (famously set on fire by Saddam Hussain's retreating army in 1991) have areas of about 1 ha, but the total reservoir area is given either as 500 km2 or as much as 820 km2 (with two smaller associated formations included), and the field's peak output was either 120 or 140 Mt/year in 1971 or 1972 (Sorkhabi 2012). Consequently, the field's maximum operating power density was as much as 370 W/m2 (prorated over the reservoir's area), and more than 20,000 W/m2 when only areas disturbed by wells and roads are considered.
But in order to convert land claims to truly representative power densities of oil extraction we need to know the long-term productivities of the oil wells. All natural well flows decline with time, and hence the power densities for the early years of extraction will be substantially higher than in later years or decades. Again, no accurate rates can be offered for the largest Middle Eastern reservoirs because the total mass of their ultimately recoverable oil and the complete duration of their exploitation are uncertain. For example, the total for al-Burqan is as low as 6 Gt and as high as 10.5 Gt, and the field is still producing at about half its peak rate nearly 70 years after the beginning of its exploitation.
The best way to gauge long-term power densities is to look at the history of those American oil fields that have been exploited for many generations. For example, the power density of production from the California oil wells studied by Yeh and co-workers (2010) averaged about 2,500 W/m2 for the cumulative 1919-2005 output but only about 1,700 W/m2 for the 2005 extraction, while the historical (1958-2007) power density for Alberta oil wells was roughly 1,100 W/m2, with the marginal rate for 2007 declining to about 640 W/m2. Data for the evolution of the West Texas Wasson oil field near the New Mexico border (Smith 2013) illustrate this process of gradual decline in greater detail.
The
field's first well, drilled in 1936, had a short-term-production power density of about 1,500 W/m2. By 1938, 201 flowing wells (assuming 1 ha/well) averaged about 250 W/m2, and the field's peak output in 1948 prorated, with 1,588 wells, to about 320 W/m2. The field is clearly outlined by its fairly regularly spaced wells (fig. 4.5): many are in an almost perfectly regular square grid pattern and occupy usually no more than 2,500 m2 (0.25 ha), which means that by 1992, the field's 2,242 wells (and their service roads) claimed only some 900 ha, with the addition of several associated gathering and processing facilities raising the total to about 1,000 ha. The power density of the field's cumulative output over 56 years of extraction would have been about 600 W/m2.
US data illustrate changing productivities on a national scale. The average productivity of US oil wells rose from 13 bpd in 1955 to a peak of 18.5 bpd in 1972, and since that time has declined to 10.8 bpd in 2000 and 10.6 bpd in 2011 (USEIA 2012). The decrease would have been much higher without the extensive use of secondary recovery, now a standard practice in all aging oil fields that relies on injections of water or gases to boost oil flow (SPE 1999). In contrast, directional and horizontal drilling make it possible to reach larger volumes of oil-bearing layers from a single well and thus spare the land and boost the average power densities of extraction. But these innovations, even when combined with new, highly productive discoveries, could not prevent the global decline of productivity, and hence worldwide reductions in the power densities of oil extraction.
Figure 4.5
West Texas Wasson oil field. NASA Earth Observatory.
Oil & Gas Journal has been publishing annual global reviews listing the numbers of producing wells and average production rates for oil-producing nations as well as for major oil fields. In 1972, the last year of inexpensive oil (in the fall of 1973 came the first of OPEC's large price increases, which quintupled the cost of a barrel), Saudi Arabia had only 627 wells, and their output, even when assuming land claim of 2 ha/well, prorated to about 40,000 W/m2, while average power densities for the entire Middle Eastern oil extraction were nearly 25,000 W/m2, and the worldwide mean (excluding the USSR) was around 500 W/m2. This low global figure was largely the result of the low productivity of many thousands of old and older US wells: even if a land claim of just 1 ha/well is assumed, the US mean in 2012 was only 125 W/m2. Clearly, J.E.Mielke's contemporaneous estimates of land claims by the US onshore oil extraction-3.03-6.9 acre-year/1012 Btu, that is, 1.2-2.8 ha/PJ or 1,100-2,600 W/m2 (Mielke 1977)-referred to well sites occupied by highly productive new wells.
Oil & Gas Journal data for the year 2012 show that the power densities of oil extraction had fallen everywhere, with the means (even when assuming just 1 ha/well) at about 23,000 W/m2 for Saudi Arabia, less than 9,000 W/m2 for the Middle East, and about 100 W/m2 for the United States, with the global mean, including all of the world's countries, at about 650 W/m2 (Oil & Gas Journal 2012). The power densities of oil extraction thus range between 102 W/m2 for old, or older, oil provinces outside the Middle East (some of them, including Azerbaijan, California, and parts of Texas, have been exploited for more than a century) to 104 W/m2 for the most productive fields on the Arabian Peninsula. The decline of average power densities has been unmistakable, and although this trend has been slowed down by secondary recovery, it clearly illustrates the maturity, even advanced age, of many of the world's major oil fields.
Unconventional Oil Production
Declining oil well productivities in conventional fields do not signify any imminent exhaustion of liquid hydrocarbons because vast volumes of oil are locked in solid rocks, sands, shales, and tars. Some of these vast kerogen resources can be now tapped by modern extraction methods. Recent increases in US crude oil production have been mostly attributable to crude oil from shales extracted by a combination of horizontal drilling and hydraulic fracturing (American Petroleum Institute 2009; USEIA 2011c). The Bakken shale, part of the Williston Basin, located mostly in North Dakota and Saskatchewan, has been the fastest-developing new oil development in the United States, with more than 5,000 new wells drilled in the five years starting in 2009 (Patterson 2013). New Bakken well sites average 2 ha, and subsequent reclamation reduces that to about 0.8 ha for production that draws on a subsurface area of 512 ha of oil-bearing shales; in contrast, conventional vertical drilling would claim 4-20 times the surface area.
But while properly managed conventional wells can maintain a fairly steady or a slowly declining output for many years, production from fractured horizontal wells is characterized by rapid, hyperbolic declines. For example, during their first year of production the wells in North Dakota's Bakken oil field could produce as much as 2,000 bpd, which was followed by 65%-80% declines in subsequent years (Sandrea 2012). A typical Bakken well yields 900 bpd during the first year, less than half that much in the second year, only 65 bpd during the fifth year, and 40 bpd during the tenth year (Likvern 2013). As a result (when assuming an average well area of 1.5 ha), the cumulative power densities of its oil extraction would be about 4,000 W/m2 in the first year, roughly 1,600 W/m2 for the first five years, about 900 W/m2 for the first decade of its output, and less than 400 W/m2 for three decades, although many wells will not be in operation that long. The rates would be significantly reduced if new access roads, needed not only to bring in the drilling equipment but also for regular deliveries of fracking liquids, were taken into account.
There is no commercial recovery of oil from the American Green River shales, but Alberta's oil sands already provide nearly 60% of Canada's oil extraction. The three principal formations-Athabasca-Wabiskaw, Cold Lake, and Peace River-cover a total of about 140,000 km2, with 10.6 ZJ (1.75 trillion barrels) of oil in place (Hein 2013); this translates to a storage energy density of about 75 GJ/m2. There are two important and distinct ways of exploiting oil sands: surface mining and in situ recovery (fig. 4.6). Surface mining entails the removal of overburden (peat, clay, sand), the excavation of relatively oil-rich sand strata, the transportation of these minerals in giant trucks for oil extraction (using hot water and NaOH), and the ensuing creation of large tailing ponds that now cover 176 km2 and contain mixtures of water, sand, clay, and residual oil left over after processing (CAPP 2013). Separated bitumen (with densities in excess of 1 t/m3, compared to less than 0.95 t/m3 for conventionally produced oil) is first sent for upgrading and then to a refinery (Gray 2001).
Only a tiny share of Alberta oil locked in sands can be extracted by surface mining, and it is expected that eventually some 98% of aggregate production will come from in situ recovery. The first process of this kind was cyclic steam stimulation (CSS), with periods of injecting hot pressurized steam (300°C, 11 MPa) into well bores followed by periods of months to three years of soaking to loosen the bitumen and then pump out the bitumen-water mixture from the wells used for steam injection, with recovery rates of 25%-35%. The most rewarding in situ recovery technique is steam-assisted gravity drainage (SAGD), whereby the oil in place is softened by steam injected into a horizontal well (500-800 m long) and drains through slots to a gathering well placed 5 m below the steam conduit. This method can recover up to 60% of oil in place, but it is both energy - and water-intensive; after separation, water is reused and oil is piped for upgrading.
Figure 4.6
Alberta oil sands. Top: Surface mining of bitumen. © Ashley Cooper/Corbis. Bottom: In situ recovery. © Brett Gundlock/Corbis.
The power densities for surface mining (with annual energy yields ranging between 0.61 and 1.2 PJ/ha) range from 1,900 to 3,700 W/m2 (mean, about 2,900 W/m2). For in situ recovery (with annual yields of 2.2-5.2 PJ/ ha) they are substantially higher, between 7,000 and 16,000 W/m2, with a mean of about 10,500 W/m2 (Yeh et al. 2010). But all of these density calculations exclude land claimed by natural gas production that is needed to heat water for the extraction of bitumen from excavated sands, to produce steam for in situ recovery, and to provide energy for the upgrading of bitumen. These three requirements average respectively 70, 2
20, and 50 m3 of natural gas per cubic meter of upgraded oil, and the inclusion of all of these upstream land claims lowers the typical power density of oil produced by surface mining to about 2,300 W/m2, and that from in situ extraction and upgrading to less than 3,200 W/m2 (Jordaan, Keith, and Stelfox 2009; Yeh et al. 2010).
Pipelines and Refineries
Gathering pipelines take oil from individual wells to field storage tanks or to processing facilities. They are relatively short, with small diameters (typically just 5-20 cm); their limited throughputs restrict their power densities; and their ROWs are minimal in compact and highly productive fields, whereas in old fields with a large number of stripper wells (marginal wells approaching the end of their extractive span) their network may be relatively extensive. Canada has about 250,000 km of such lines, roughly 3,800 km for every million tonnes of conventional oil production (CEPA 2013). In contrast, the United States has no more than 65,000 km of gathering pipelines, located mostly in Texas, Oklahoma, Louisiana, and Wyoming (Pipeline 101 2013).
Crude oil is often processed before it enters a pipeline. Processing separates oil from natural gas, and in the fields using water flooding the two liquids must be separated to prevent pipeline corrosion. Some crudes also require desalting and at least a partial removal of H2S (sweetening) and stabilization before sent into a pipeline. Many fields also have on-site storage tanks of limited capacities. Crude oil is transported by every kind of commercial carrier (with the obvious exception of aircraft): it is often trucked or transported by rail cars and loaded on barges for river transport, but the two leading means of its long-distance delivery are pipelines on land (as well as from offshore fields) and large tankers on the oceans.
