Unconventional oil production But 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 but they are, necessarily, more expensive to exploit than the reservoirs of liquid oil. Recent increases of US crude oil production have been mostly attributable to crude oil from shales extracted by a combination of horizontal drilling and hydraulic fracturing (USEIA 2011a; API 2009). Bakken shale (part of the Williston Basin, mostly in North Dakota and Saskatchewan) has been the fastest developing new oil development in the US, with more than 5,000 new wells drilled in 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 subsurface area of 512 ha of oil-bearing shales; in contrast, conventional vertical drilling would claim 4-20 times the surface area.
But while 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 wells in North Dakota’s Bakken oil field could produce as much as 2,000 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 10th year (Likvern 2013). As a result (when assuming average well area of 1.5 ha) 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 operated for so long. The rates would be significantly reduced when adding new access roads (to bring not only the drilling equipment but also for regular deliveries of fracking liquids).
While there is no commercial recovery of American Green River shales, 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 translate to 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. Surface mining entails the removal of overburden (peat, clay, sand), excavation of relatively oil-rich sand strata, transportation of these minerals (by giant trucks) for oil extraction (using hot water and NaOH), and ensuing creation of large tailing ponds that now cover 176 km2 and contain the mixture of water, sand, clay and residual oil that is left over after processing (CAPP 2013). Before it goes into refineries the 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 (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 (3000C, 11 MPa) into well bores followed by periods of months to three years of soaking to loosens 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 way of in situ recovery is done by 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 natural gas- and water-intensive; after separation water is reused and oil is piped for upgrading.
Power densities for oil sands surface mining (with annual energy yields ranging between 0.61-1.2 PJ/ha) range from 1,900 to 3,700 W/m2 (mean about 2,900 W/m2) and for in situ recovery (annual yields of 2.2-5.2 PJ/ha) they are substantially higher at between 7,000-16,000 W/m2 and the mean of about 10,500 W/m2 (Yeh et al. 2010). But all of these densities exclude land claims by natural gas production that is needed to heat water for the extraction of bitumen from excavated sands, to produce steam that is injected into oil-bearing shales for in situ recovery and to provide energy for the upgrading of bitumen to oil suitable for refining. Inclusions of these claims lowers the overall power densities. These three requirements average, respectively, 70, 220 and 50 m3 of natural gas per m3 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 (Yeh et al. 2010; Jordaan, Keith and Stelfox 2009).
Pipelines and refineries Gathering pipelines take oil from individual wells to field storage tanks or to processing facilities. They are relatively short and their small diameters (typically just 5-20 cm) and hence limited throughputs restrict their power densities; on the other hand, their rights-of-way (ROW) are minimal and most of their land claims are included in the totals for well sites and associated infrastructure. In compact and highly productive fields is minimal, in old fields with a large number of stripper wells (marginal wells approaching the end of their extractive span) their network is relatively extensive. Canada has about 250,000 km of such lines, or roughly 3,800 km for every million tonnes of conventional oil production (CEPA 2013). In contrast, the estimate for the US is no more than 65,000 km of gathering pipelines located mostly in Texas, Oklahoma, Louisiana and Wyoming (Pipeline 101.com 2013).
Crude oil is often processed before leaving an oil field in a pipeline. Processing operations at individual wellheads or gathering sites separate oil from natural gas, and in all fields using water flooding the two liquids must be separated in order 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.
Pipelines are not only the least expensive mode of transporting oil on land but also the safest. US pioneered their use starting in the 1870s but the longest post-WW II American lines (from the Gulf of Mexico to the East Coast) were eventually eclipsed by pipelines carrying oil from the Western Siberia’s supergiant Samotlor field to Western Europe, distance of about 4,500 km. US has an extensive network of both crude oil pipelines carrying oil from major oil basins (diameters up to 1.2 m) and from tanker ports and product pipelines moving refined fuels (above all gasoline and kerosene, diameters up to 1.05 m) to major consumption centers. Pipeline construction commonly claims corridors of 15-30 m wide (needed for trenching, pipe delivery and the operation of pipe-laying machinery) but ROW strips for operation may be narrower: on the US federal lands they are normally up to 15 m for buried 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 in order to assure access for monitoring, maintenance and needed repairs. Dangers of accidental encroachments at major lines can be prevented, or at least minimized, by aerial or satellite monitoring, by burying fiber cable above the pipelines or by infrasonic seismic sensors (Chastain 2009). Pumping stations, placed at roughly 100 km intervals, need 10-20 ha. The correct magnitude of the aggregate ROW claim of US intercity crude and product lines is easy to calculate. The latest statistics show about 80,000 km of crude oil lines and 140,000 km of product lines and the total transported mass of roughly 1.675 Gt (BTS 2013). Assuming (perhaps a bit conservatively) average ROW of 15 m those figures imply average nationwide throughput power density of 675 W/m2.
As expected, many major trunk lines will operate with higher rates, many smaller lines will be well below that mean. America’s longest pipeline is the Trans Alaska line operated by Alyeska Pipeline Service Company and linking the North Slope with Anchorage. The line is 1,288 km long (with about 700 km build above ground through the permafrost territory), its right-of-way is about 20 m, and 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 2013). These performances translate, respectively, to throughput power densities of about 5,300 and 1,500 W/m2. Many oil pipelines of moderate to low capacity will have throughput power densities less than 500 W/m2.
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 deeper draft: the most famous examples are the Saudi Rās Tanūra and the Iraqi Faw. As a result throughput power densities of the largest crude oil loading facilities are in excess of 105 W/m2. Refineries are also inherently high-throughput facilities but, inevitably, they claim large 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 expansion into the surrounding areas over its decades of service.
The world’s largest refineries process in excess of 500,000 bpd, that is at least 25 Mt of crude a year and annual throughput of 33.3 GW. These complexes are readily identifiable on Google Earth, and the only uncertainty in calculating their throughput power densities concern the inclusion of often extensive areas within the facilities that have been abandoned or that are held in reserve for future expansion. Centro Refinador Paraguaná in Falcón, Venezuela has the world’s largest capacity (940,000 bpd) but in 2013 it was actually processing only 588,000 bpd and occupies about 500 ha; that translates to average throughput power density of almost 8,000 W/m2.
The second largest facility, Ulsan in South Korea, has capacity of 817,000 bpd and throughput power density of nearly 5,000 W/m2 and ExxonMobil giant Baytown, TX refinery, America’s largest, covers 9.7 km2 and has capacity of 560,640 bpd and hence power density of about 3,900 W/m2 (ExxonMobil 2013). Exxon’s Baton Rouge refinery in Louisiana (the second largest in the US) 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 2008). Saudi Yanbu’ refinery on the Red Sea, producing fuel for the domestic market, occupies 165 ha and it processes 225,000 bpd, resulting in power density of roughly 9,200 W/m2 (Saudi Aramco 2013). The largest refinery in the Middle East, Saudi Rās Tanūra (capacity of 550,000 bpd and area of roughly 500 ha) has power density of nearly 7,500 W/m2, but small facilities may have power densities well below 1,000 W/m2.
Natural gas, pipelines and LNG
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 to 95 % for CH4, 13-3 % for C2H6, and 0.1-1.3% C3H8 from just 0.1-1.3 %. Some of the heavier alkanes (mostly butane and pentane) may be also present and they are separated as natural gas liquids before gas enters a pipeline. Raw natural gases have energy densities between 30-45 MJ/m3, pure CH4 contains 35.5 MJ/m3 or less than 1/1000 of crude oil’s volumetric energy density. Marketed production of natural gas is appreciably lower than its gross withdrawals and the US data show the reasons for the difference: extraction loss is about 4%, removal of non-hydrocarbon gases reduce the volume by about 3%, less than 1% of the aggregate flow is vented but nearly 12% are used for field repressurization, leaving the final dry gas production at about 80% of initial withdrawals (USEIA 2013a).
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 oilfields. South Pars-North Dome field, shared by Iran and Qatar, is not only the world’s largest gas field but also the world’s largest sore 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 (energy density of 1 m3 of condensate = 1 m3 of crude oil) to about 2.1 ZJ of energy and, with the field’s area of 9,700 km2, it implies 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 was discovered in 1959 and it has been producing since 1963; its original gas volume was 2.8 Tm3 with the 100-m thick reservoir rock underlying about 900 km2 of countryside, implying storage energy density of about 110 GJ/m2.
West Siberian Urengoy, 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 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 initial storage density of just over 60 GJ/m2. Yamburg field, north of the Arctic Circle in Siberia’s Tuymen region, comes third: its initial gas content is about the same as in Urengoy but recoverable share is much lower at 3.9 Tm3; with 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 (nearly 22,000 km2) reduces its storage density to less than 4 GJ/m2 (Dubois 2008).
Large gas reservoirs containing mixtures of the lightest alkanes (dry gas) are now the largest contributor to global gas production but the fuel also comes from three other major sources. The most common one of these is associated gas whose flows accompany crude oil extraction (wet gas). This gas is dissolved in crude oil and after reaching surface 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 burnt off (flared). This wasteful practice is still common in giant Western Siberian oil fields: they also yield large volumes on associated gas but, for a variety of reasons, an unacceptably large of these flow continue to be flared (Røland 2010). Overall, this environmentally damaging practice has been greatly reduced since the 1970s but the total flared globally is still unacceptably high: in 2010 it was estimated at 134 Gm3 (mostly in Russia, Nigeria and Iran), an equivalent of almost 20% of the US gas consumption (GGFR 2013).
The world’s largest oil field, Saudi al-Ghawār, 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 (Sorkhabi 2010; Alsharhan and Kendall 1986). And in 1971, 30 years after the reservoir began producing crude oil, a large pool of non-associated gas was discovered below the oil-bearing layers at depth of 3-4.3 km and this deep reservoir now produces annually about 40 Gm3 (1.4 EJ) of non-associated 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 are coal beds and China and the US, the largest coal-mining nations, are also the largest producer of this gas. 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 US has developed this resource on a large commercial scale (Maugeri 2013). The US statistics show the relative importance of these four principal gas sources: in 2011 43% of gross gas withdrawals came from gas wells, 21% from oil wells, 6% from coalbed wells and 30% from shale gas wells whose output was lower than coalbed gas as recently as 2007 (USEIA 2014).
Power densities of gas production and delivery As with the oil extraction, both well densities and areas of well sites required for natural gas extraction vary but, not surprisingly, they closely resemble each other. In conventional US natural gas fields 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 formation: in Barnett shale it has been 1.1-1.5 wells/km2 in the beginning and later permits allowed in-fill wells have resulted in up to 6 wells/km2 (New York State Department of Environmental Conservation 2009). Future spacing will be less dense as multiple horizontal wells drilled from a single well pad will become the norm. For example, in Marcellus shale (stretching 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 well pad.
In Pennsylvania’s Marcellus shale a typical multi-well pad for drilling and fracturing is 1.6.-2.0 ha and after a partial restoration it may be as little as 0.4 ha; in New York state a new multi-well 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). Production of natural gas from shales shows the same rapid hyperbolic decline as does the extraction of crude oil (Sandreas 2012). Wells in Marcellus shale, the most extensive gas-bearing formation in the US, have initial rate of 120,000 m3/day followed by early decline of 75% while in Barnett shale in Texas the initial flow is less than 60,000 m3/day followed by 70% decline.
The first year flow in Pennsylvania may be in excess of 10 Mm3 and the average has been almost 6 Mm3; by the second 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 0.5 ha pad) imply extraction power density in excess of 2,000 W/m2, the third year flow is down to just above 200 W/m2. In the western states initial sizes of well pad sites average nearly 1.6 ha but over the life of production this is reduced to less than 0.6 ha (Buto, Kenney and Gerner 2010). These states, as well as long-established gas-producing 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 if 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 well areas range over an order of magnitude, from 1.5-15 ha (average of 3 ha), and Jordaan, Keith and Stelfox (2009) assumed average annual output of about 50 Mm3; this yield means extraction power density of about 1,850 W/m2. Dividing Alberta’s 2012 province-wide statistics of natural gas output (100 Gm3) by 1,622 connected wells (Alberta Energy 2013) yields average productivity of nearly 62 Mm3/well and 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.
Groningen field is one of the best examples of minimal and unobtrusive gas recovery. The extraction is concentrated in 29 production clusters, each one with 8-12 wells arranged in a strip and adjoined by associated treatment plants (several identical units), electricity supply and a control building (Royal Dutch Shell 2009). There is no permanent personnel on these sites as the clusters are controlled from the central control room in Sappemeer. Clusters are very similar in size, with almost 7 ha taken by wells and 4 ha by other facilities, and hence the total area claimed by 20 clusters is about 310 ha. With the recent annual output of about 128 Gm3 this translates to extraction power density of nearly 46,000 W/m2.
Gathering lines (low pressure, small diameter) take gas from individual wellheads to processing facilities to strip CO2, H2O and also H2S. Processing of natural gas has minimal land requirements: such facilities have throughput power densities ranging mostly between 50,000-70,000 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 required to push the gas through high-capacity trunk lines take up about 2 ha at the intervals of every 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 kinds of pipelines.
Average throughput power density for the US natural gas pipelines can be calculated from detailed information about individual US systems (USEIA 2007). Northern Natural Gas Company (serving states from Texas to Illinois) is the country’s longest interstate natural gas pipeline system with about 25,400 km of trunk lines and with annual capacity of 78 Gm3; with average ROW of 15 m this implies 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 330 W/m2. Columbia Gas Transmission Company serving the Northeast (16,600 km) has the highest annual capacity (86 Gm3) and throughput power density of about 380 W/m2. Algonquin Gas Transmission in New England (1,800 km and 24 Gm3) has throughput power density of 1,000 W/m2.