Natural Gas- Fuel for the 21st Century
Page 16
In the year 2000, Oman became LNG exporter and Greece and Puerto Rico became the latest new importers; by 2003, as the US domestic gas production kept declining, all of the country’s regasification terminals were in operation for the first time since 1981, and in 2004, the first offshore terminal was approved near Port Pelican, Texas. Ranks of LNG exporters were enlarged by Egypt (2004) and Norway and Equatorial Guinea (2007), while Portugal and Dominican Republic (2003), India (2004), and Mexico and China (2006) became the new importers. Most importantly, declining output and rising prices of the US natural gas pointed to an increasing need for large-scale LNG imports, demand that was to be satisfied not only by existing exporters but by the development of Russia’s largest offshore field, Shtokman in the Barents Sea. And China’s rising energy demand and extraordinarily high air pollution levels in the country’s major cities indicated that the world’s fastest growing economy will need many more LNG contracts than those already concluded with Australia and Indonesia.
In 2008, LNG shipments reached 25% of all natural gas, and the total annual export capacity had more than doubled during the first decade of the twenty-first century (from 100 Mt in 2000 to about 220 Mt in 2009) as maximum train sizes had more than doubled during the same time and as, after decades of stagnations, new class of large LNG tankers entered service, bringing obvious economic advantages but requiring solution of many technical challenges because of changes on loading, unloading, and vapor handling (Cho et al., 2005). Large aluminum spheres (Kvaerner–Moss shells) covered with insulation and placed inside steel tanks attached to the vessel’s hull were the standard (and space-wasting and cumbersome) choice for more than three decades.
New membrane design uses thin stainless steel to make insulated tanks that fit the vessel’s inner hull. Qatargas took advantage of this innovation by ordering 45 new large vessels belonging to Q-Flex (210,000 m3) and to Q-Max (266,000 m3) class (Qatargas, 2014b). This capacity growth meant that, after decades of no or slow growth, the volume of the largest LNG tankers had finally increased enough to compete with capacities that have been standard for large crude oil tankers since the late 1920s. But LNG tankers are still more expensive to build than oil tankers: 125,000–138,000 m3 LNG tanker cost nearly twice as much (about $200 million) than a 250,000 dwt (VLCC) oil tanker that could be had for $120 million (IMO [International Maritime Organization], 2008). And because crude oil has 60% higher energy density than LNG (roughly 36 MJ/l vs. 22 MJ/l), large oil tankers carry four to five time as much energy per shipment.
But even as the LNG exports were rising and a strong consensus saw further rapid expansion of facilities, fleets, and capacities, two unexpected developments intervened and affected the pace of anticipated developments. The worst post-WWII economic downturn (2008–2010) reduced energy demand and affected future development of all major infrastructural projects, while hydraulic fracking (in 2005 a production method appreciated only by a relatively small number of experts and by 2010 one of the most widely publicize innovations in modern US history) became a major, and rising, contributor to America’s natural gas (as well as crude oil) supply. The sudden emergence of fracking has led to three remarkable developments: to an impressive decline in North American gas prices, to an unprecedented decoupling of US oil and gas prices, and not just to cancellation of LNG imports plans but to plans for US LNG exports.
This is then where the global LNG industry stands half a century after its tentative British beginning (GLNGI [Global LNG Info], 2014; GIIGNL [International Group of Liquefied Gas Importers], 2014; IGU, 2014; BRS [Barry Rogliano Salles], 2014). By the middle of 2014, there were 27 LNG plants with 86 liquefaction trains in operation in 17 countries (Angola became the latest exporter in 2013), with 11 plants under construction and 22 in planning stages (Figure 5.6). Ras Laffan in Qatar was the world’s largest LNG-exporting facility with annual capacity of 10 Mt (Qatargas, 2014a), and Qatar (with nearly a third of the total shipped volume) remained the leading exporter. Global trade reached 236.8 Mt in 2013 (slightly less than the record of 241.5 Mt in 2011) with just over 60% of all imported gas consumed in Asia–Pacific region, with Europe far behind (at about 33 Mt). About 77 Mt, or a third of all exported LNG, were traded on the spot and short-term market, with Nigeria and Qatar dominating the spot trade. Most of the contracts are still for long-term deliveries, with oil-linked prices at roughly $12/million BTU in Europe and $15 in Japan. LNG fleet consisted of 357 tankers with combined capacity of 54 Mm3, and nearly 100 new vessels were on order.
Figure 5.6 Australian Karratha LNG terminal for gas exports to Asia.
© Corbis.
Importance of LNG sales for the exporting countries is best illustrated by looking at the shares of LNG sale in their annual export earnings. Here are, in descending order, the ten top nations with the ordering based on the Standard International Trade Classification (export of item 3413: liquefied hydrocarbons) and calculated for the year 2010 by Hausmann et al. (2013) as a part of the Harvard–MIT economic complexity project: Qatar, 42%; Trinidad and Tobago, 34%; Algeria, 15%; Yemen, 15%; Oman, 14%; Egypt, 9.8%; Nigeria, 8.5%; Indonesia, 5.7%; Malaysia, 4.9%; and the United Arab Emirates, 4.4%. But several oil-exporting countries are more dependent on a single commodity than Qatar is on LNG: crude oil accounts for 89% of Azeri export earnings, and the other high shares are 86% for Nigeria, 76% for Saudi Arabia, and 67% for Kuwait.
In 2013, 29 countries were LNG importers and they had 104 regasification terminals. Three new importers were added in 2013: Israel, Singapore, and, remarkably, Malaysia, the world’s second largest exporter (sales of 24.7 Mt in 2013, imports of 1.6 Mt). Regasification capacity reached a new record at 688 Mt/year which means that its utilization rate declined to just 34% in 2013, and floating regasification expanded to nine countries with a total capacity of more than 44 Mt. Japan, the largest importer, had the largest number of regasification plants (24), with Tōkyō Bay’s Futtsu terminal, the world’s largest, able to receive 19.95 Mt/year, most of it to power the world’s second largest (4.5 GW) gas-fired electricity-generating plant (TEPCO [Tokyo Electric Power Company], 2013; Figure 5.7). Papua New Guinea has become Japan’s latest source of LNG in May 2014, and the country’s massive $19 billion project (taking gas from Southern Highlands and Western Provinces) will also supply China and Taiwan (PNG LNG, 2014).
Figure 5.7 Futtsu LNG terminal.
© Corbis.
LNG facilities have always made fairly small land claims, mostly just 30–120 ha. 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 first three liquefaction trains at Ras Laffan (annual capacity of 10 Mt) claim 3.7 km2 (Qatargas, 2014a), operating with a throughput power density of about 4,600 W/m2. New modular designs are even more compact: 4.3 Mt Norwegian Snøhvit on Melkøya island near Hammerfest (4.3 Mt/year) occupies only about 70 ha and operates with processing power density of about 10,000 W/m2 (Nilsen, 2012; see Fig. 8.4). Regasification plants have similar or even higher power densities. America’s largest receiving LNG terminal, Cheniere’s Sabine Pass in Louisiana, has a maximum throughput power density of about 8,300 W/m2, Higashi–Niigata on the coast of the Sea of Japan (30 ha, 8.45 Mt/year) reaches nearly 48,000 W/m2, and Tōkyō Bay’s Futtsu terminal, the world’s largest regasification plant (just 5 ha and 19.95 Mt/year), has a throughput power density of about 60,000 W/m2.
6
Diversification of Sources
Although the term nonconventional gas resources will be used for decades to come, extraction of some of those resources has become quite routine in the United States where nonconventional gas (shale gas, gas from tight sands, and coal-bed methane (CBM)) accounted for just 18% of the total output in 1990, over 60% by 2005, and 73% by 2012 (USEIA [US Energy Information Administration], 2014i). But the United States and, to a lesser extent, Canada are two great exception, and in most gas-producing countries, nonconventional ga
s sources are still only of marginal importance. These resources belong to four distinct formations: natural gas held tightly in shales (often also in sandstones), methane in coal beds, gas in high-pressure aquifers, and methane hydrates (clathrates) in the Arctic and in much larger undersea deposits.
The quest for difficult-to-extract natural gas is not new, and one of the methods that was not just proposed, but actually tried several times in the United States, is truly incredible (an adjective used with restraint). A more fitting label would be irrational, but its proponents (and there were many) in the US government were convinced that it would work: they thought that explosions of nuclear devices will increase the effective drainage volume and enable economic production of natural gas from tight sands. These experiments, part of the Plowshare Program, were characteristic of the era when many thought of nuclear energy as an effective enabler that could be deployed for many commercial tasks (US Congress, 1973; Kaufman, 2013).
The first test, Operation Gasbuggy in New Mexico on December 10, 1967, detonated a 29 kt device (Hiroshima bomb was about 12.5 kt of TNT equivalent) just 1,270 m below the surface, and a month after the detonation, a well was drilled into the resulting rubble chimney, and about 5.7 Mm3 of gas was withdrawn and flared at the site. In energy terms, about 120 TJ was released by a nuclear explosion in order to withdraw about 200 TJ of natural gas, a net energy return (1.7-fold) only if one disregards all the energy needed to produce the explosive nuclear device. The second test, Project Rulison in Colorado on September 10, 1969, exploded a 40 kt device, and during the third test, in 1973 in Rio Blanco County in Colorado, three 33 kt nuclear devices were detonated almost simultaneously in low-permeability sandstones 1.75–2 km below ground.
The fourth test, Wagon Wheel in Wyoming, never took place: it would have detonated five devices of 100 kt each at depths of 2.7–3.5 km, producing a rubble chimney more than 800 m tall and 300 m in diameter and releasing at least 35 times more energy than the energy of expected natural gas extraction (Noble, 1972). If successful, the US Atomic Energy Commission and El Paso had plans for full-scale production that would have included as many as 40–50 detonations every year! Reading this four decades later has only increased the sense on incredulity: how could these frequent detonations be ever justified in net energy terms, and how could regular detonation of powerful nuclear bombs underneath the grassland, fields, and forests of the American West be accepted by the public as routine means of producing gas used for heating and cooking? The experiments produced results far below expectations, and the project was abandoned.
But more promising techniques were under development when the nuclear route was abandoned. In his review of unconventional natural gas resources, Mankin (1983) noted that the process known as massive hydraulic fracturing (creation of vertical fractures extending from the wellbore into the reservoir) received a great deal of attention by the oil and gas industry (as well as federal research funding) but that it remained too expensive to recover gas from tight sands unless the producers receive subsidies or granted special incentives. He was no less pessimistic about natural gas from organic-rich shales, a challenge that cannot be easily overcome by hydraulic fracturing due to the problems with fracture propagation, recovery of fracturing fluid, and rapid decline of gas extraction.
His conclusion (published almost exactly 25 years before the large increases of oil and gas produced by hydraulic fracturing) is worth quoting in full:
In any case, it is reasonable to assume that any increased development of natural gas from Devonian shales will be confined to meet local or regional needs because of the low rates of production per well.
(Mankin, 1983, 35)
On the other hand, he was convinced that “the magnitude of the resource base and the long-range future for natural gas are factors that will lead ultimately to substantial development. In all likelihood, such development will not materialize until the early part of the 21st century” (Mankin, 1983, 42). That was a much better appraisal as large-scale development of shale gas released by horizontal drilling and hydraulic fractioning actually came in the second half of the very first decade of a new century.
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; Zuckerman, 2013; Gold, 2014; Figure 6.1). Tracing the evolution of what is often called natural gas revolution, assessing the current state of hydraulic fracturing (commonly called fracking), and looking into the immediate future of shale gas will take up most of this chapter. The rest of it is devoted to advances and prospects for commercial recovery of other nonconventional gas resources: CBM, tight gas, and gas hydrates. China and the United States, the largest coal-mining nations, have also the largest resources of coal-bed gas, while tight gas (in formations with minimal permeability) is more widely distributed, and a large share of methane hydrates is offshore, deep under the seabed. But, before starting this systematic coverage with a more detailed focus on shale gas, I should first stress that the production of natural gas from nonconventional sources can be seen as a part of a larger progression of extracting mineral resources.
Figure 6.1 Global shale deposits.
The sequence starts with tapping the resources that are easiest to find and easiest to produce with limited technical capabilities of early developmental stages; in the case of natural gas, the fuel itself was not initially even the object of search as it came associated with the eagerly sought-after crude oil and its production required only the separation of liquid and gaseous hydrocarbons. Later decades of deliberate quest for natural gas used the accumulating experience of oil exploration and extraction to bring large fields of nonassociated gas to the market; in many cases, that required not only higher capital investment in developing fields in extreme environments (Arctic, hot deserts, offshore) but also construction of long pipelines to bring the fuel to major consuming areas thousands of kilometers away.
As the most accessible and inexpensively produced reserves of mineral resources decline, the attention shifts to abundant deposits of lower quality or to remaining high-quality deposits whose recovery demands advanced techniques and rising production costs. Quality decline has been evident in the case of many common metals (as many extracted ores now have metal content an order of magnitude lower than in the early decades of the modern industrial era). Nonconventional gas resources yield the fuel of the same quality but their extraction is much more challenging and hence is highly dependent on relevant technical advances.
6.1 SHALE GAS
Assessments of shale gas resources and technically recoverable reserves and descriptions and reviews of basic operating procedures (involving horizontal drilling and high-volume hydraulic fracturing (HVHF)), regulatory frameworks, and common environmental impacts are readily available (USDOE [US Department of Energy], 2009; NETL, 2013; Speight, 2013). And yet writing about shale gas in concise and comprehensive way has become rather challenging, particularly when trying to give a balanced assessment of the US developments. Some controversial aspects of this development are only part of this challenge; the main hurdle is simply the cumulative amount of constantly increasing information, claims, and counterclaims brought forth by perhaps the most remarkable, and most consequential, expansion of resource extraction in modern history. Its progress has been so remarkable because it has been so sudden: for those in the know, it was not entirely unexpected, but even lifelong participants in the US oil and gas industry were surprised by the swift takeoff of the practice that led them to see it as revolutionary in nature.
In 2003, two experienced petroleum geologists published an assessment of North American natural gas supply that had a single perfunctory reference to shale gas (listing it among potential opportunities together with deep drilling, CBM, tight gas, and hydrates) and concluded that the days of cheap gas are history and that additional LNG facilities are needed for increased imports but because they cannot be built rapidly in signific
ant numbers “rationing of available gas by the market mechanism of higher prices seems the only option” (Youngquist and Duncan, 2003, 229). In just 6 years, the United States, thanks to horizontal drilling and hydraulic fracturing, regained its global primacy in natural gas output, and many projections saw the country as a major LNG exporter even before 2020.
But this rapid shift was preceded by (mostly unappreciated) long technical gestation as individual components of new extraction technique made their gradual progress before they were combined in a mature and commercially rewarding process. During the early decades of drilling, it was difficult to keep straight course with deep wells, and deviated wellbores were fairly common. Deliberate directional drilling, able to exploit larger reservoir volume from a single well site, was the next step, and the first short horizontal well was drilled in Texas in 1929 (USEIA, 1993). Their high cost and absence of equipment most suitable to this task delayed the commercial adoption of horizontal drilling until the 1970s. More than 300 horizontal wells were drilled in North America during the 1980s, more than 3,000 during the next decade when the introduction of rotary steerable drilling motors introduced enabled to drill fairly easily even 90° bends and to follow undulating seams. Moreover, these motors can be mounted at the end of small-diameter (2.5–11.25 cm) coiled tubing, dispensing with rigid steel drill pipes while reaching a depth of up to 4 km.
Hydraulic fracturing had its distant precursor in oil well “shooting” done first during the early decades of the US oil expansion with nitroglycerine in order to increase to shatter the oil-bearing rocks and boost the liquid flow (Montgomery and Smith, 2010). Nonexplosive fluids were used for the first time during the 1930s to increase productivity through acid etching, but the first experiment with hydraulic fracking came only in 1947 in Kansas when Standard Oil of Indiana used pressurized fluid to create fractures and fluid-borne propping agents to hold them open in order to release previously unobtainable hydrocarbons.