Cheap, plentiful energy has long been a precondition of the industrial age. In recent years though, conventional reserves of fossil fuels such as oil and gas have been steadily dwindling. With renewables not yet sufficiently developed to end dependence on these resources, the world faced a stark choice: either return to more hazardous and more polluting sources such as nuclear and coal, or accept dramatically higher energy prices and the constraints on economic activity.
In the past five years, however, a quiet revolution has taken place. In the US, after decades of deindustrialisation, firms are retooling in energy-intensive industries like steel and chemicals. Growth has returned, carbon emissions have declined and the price of gas has fallen from highs of over $13 per million British thermal units (MB tu) in mid-2008, to as low as $1.82 in April 2012. The reason for this radical transformation is shale gas, and its potential as a new source of cheap and abundant energy is prompting interest worldwide.
EXPLAINING SHALE: Shale gas is part of the family of “unconventional” hydrocarbons, and “shale” refers to the geological material in which shale gas and associated (“tight”) oil is formed. It typically lies much deeper than the so-called conventional reservoirs of oil and gas that have until now provided the majority of the world’s supply. Shale is actually the source rock for those conventional deposits. It is the layer at which organic material many millions of years old is transformed under immense pressure into hydrocarbons.
In conventional deposits, those hydrocarbons have seeped back toward the surface, passing through layers of semi-porous, permeable rock before becoming trapped beneath a seal of non-porous rock. It is in these “traps” that reservoirs of oil and gas can accumulate under enormous pressure, enabling a single vertical well to tap huge quantities of hydrocarbons.
By contrast, deeper-lying shale consists of rocks, which are much less permeable. Hence, the oil and gas held in these formations is less concentrated, and locked more tightly within the rock itself. For this reason, very little exploitation has taken place. Wells must be dug deeper to access such formations and low permeability of the rocks means very little oil or gas is released from any single well. Establishing how to economically extract hydrocarbons given such constraints has, until recently, proved elusive to petroleum engineers.
NEW TECHNOLOGIES: Matters changed in the 1980s, when George P Mitchell pioneered the combination of two techniques for extracting gas from shale: horizontal drilling and hydraulic fracturing (“fracking”).
By drilling a well over a mile deep and then turning the bore sideways, Mitchell’s rigs were able to penetrate deep within a shale formation. If a solution of water (with various chemicals added to make it more “slippery”) is pumped down the well, the resulting pressure will fracture the rock bed and release the gas (and, in some formations, oil) trapped within it.
Perfecting the technique took Mitchell 10 years, $6m and a good deal of government assistance, yet it helped transform his business, Mitchell Energy, into a Fortune 500 company. It has also transformed the outlook for the US domestic upstream gas sector (known as the E&P industry). While conventional gas production has been declining since 2006 from 18trn cu feet (tcf) per year, to 12.3 tcf in 2011), output from shale wells has sky-rocketed, reaching 8.5 tcf in 2011, from less than 1 tcf as recently as 2005.
Shale wells now make up around 30% of domestic gas production in the US, and shale exploitation has helped push gas output up to 28.5 tcf per year as of 2011 – higher even than the boom years of the early 1970s. The impact of shale most likely resulted in the US passing Russia in 2011 to become the world’s number one gas producer. Liquids released from fracking process have led to a major increase in US oil production, with around 800,000 barrels per day (bpd) being added since 2005 with tight oil exploitation.
INCENTIVES: The rapid development of the US shale market can be attributed to a number of factors. Benjamin Gage, an analyst at US-based gas consultancy PFC Energy, told OBG, “Given the region’s substantial E&P legacy, both the pipeline infrastructure and service expertise were already in place.” This legacy is found both upstream and downstream. Upstream, the US is home to over 1700 drilling rigs – more than the rest of the world combined. (By comparison, Europe has fewer than 130 rigs, most incapable of horizontal drilling).
This abundance of rigs was the product of a relatively mature market in conventional oil and gas exploration, characterised by a large number of low-producing wells typically serviced by smaller companies. This decentralised production model was ideal for exploiting shale, which follows a “manufacturing” process: rather than striking big on a single well, production requires the continuous drilling of many small wells.
Downstream, infrastructure for processing, storing, transporting and marketing the gas was also in place, enabling producers to scale up production rapidly without having to worry about bottlenecks or having to flare excess production. The success of the downstream sector in servicing early shale plays in areas such as Ohio, Pennsylvania and New York has been underlined by the difficulties being faced by E&P companies attempting to exploit more remote formations such as the Bakken Field in North Dakota, where an absence of infrastructure has resulted in flaring of up to 35% of production. The second advantage was a highly developed, wellintegrated wholesale market. The federal government also provided incentives for E&P between 1980 and 2000, such as the section 29 tax credit for unconventional gas, which encouraged exploratory drilling methods such as those pioneered by Mitchell.
The final incentive is, perhaps, the most important. The majority of shale exploration thus far in the US has been carried out on non-federal land as rights to belowsurface minerals reside with the land owner (rather than the federal government), giving individuals an incentive to allow prospecting on their property in return for royalties. “Private land owners or government landowning bodies sell the drilling rights to their land based on a certain return of the production revenue. Land owners are consequently keen to see drilling rigs move to their leases,” Gage told OBG.
ENVIRONMENTAL IMPACT: The rapid expansion of shale in the US has not been without controversy. Environmental concerns over extraction procedures fall into three categories: increased seismic activity; contamination of the water table; and the harmful effects of the chemicals used in the fracking process.
In some areas of shale gas production there has been a dramatic increase in small-scale seismic activity ( usually between 3 to 5 on the Richter scale). In 2010 more than 600 minor earthquakes were recorded in Arkansas (home to the Fayetteville formation) – almost as many in a single year as for the previous century. In the UK, two earthquakes were recorded in 2011 near test wells in Lancashire, prompting a nationwide moratorium on drilling. In the UK case the company responsible for the wells, Caudrilla, admitted the tremors were probably caused by fracking. In the US, however, demonstrating a link has proved to be a matter of some contention.
Oklahoma (home to the Caney and Woodford formations) experienced its strongest recorded earthquake in 2011, a magnitude 5.7 quake.
According to a report produced by the University of Oklahoma, Columbia University and the US Geological Survey, the Oklahoma quake was “likely caused by fluid injection”, with disposal of fracking waste water having taken place as close as 250 metres to the quake site. A Congress-commissioned report by the US National Research Council released in June 2012 came to a similar conclusion: the injection of waste water increases the likelihood of seismic activity.
CONTAMINATION: There have been a number of instances of seepage within wells, usually caused by corrosion or breakage of the steel well shafts. The water table can become contaminated by both gases (or liquids) released through the fracking process, as well as chemicals contained in the fracking liquid. Contamination can also result from well blowouts.
The fracking process also results in the production of waste water of up to 13.6m litres per well. Owing to an exemption in the 2005 US Safe Drinking Water Act, shale companies were spared from federal disclosure of the composition of fracking fluids, having argued such information constitutes a trade secret. A cocktail of toxic chemicals such as 2-butoxyethanol and acetone has frequently been recorded in water tests near fracking sites, leading to several fines for contamination being levied. A report by the US Environmental Protection Agency in December 2011 officially linked fracking to water contamination for the first time, prompting some states to introduce mandatory disclosure of the chemical content. The UK government, for example, has mandated that all chemicals used in fracking must be approved by the Environment Agency.
SUSTAINABILITY:Some have questioned the economic sustainability of shale, suggesting that the US market bears all the hallmarks of a classic asset bubble.
Arthur Berman, a petroleum geologist and energy sector consultant, has drawn attention to three issues: the true size of shale reserves; the profitability of the production model; and the dynamics driving production. It is popularly believed that shale gas is sufficiently abundant in the US to satisfy demand for a century.
Measuring shale gas reserves is a complex procedure, and involves distinguishing between “proven” reserves (those which are 90% probable and can be profitably extracted), and “unproven” reserves (those which may exist, but are not certain to be technically recoverable).
Unproven reserves are further sub-divided into “probable” (50% probability of production), “possible” (10% probability) and “speculative”.
The “100 year” claim for US shale reserves originated in a 2011 report by the Potential Gas Committee (PGC), which obtained its estimate of 2170 tcf by adding all four reserve categories. Based on current US domestic demand of around 24 tcf per year, this would equate to a 95-year supply. However, proven reserves of shale in the US are only 273 tcf. In 2011, the US Energy Information Agency (EIA) suggested that the Marcellus shale formation (an extensive block extending across the Appalachian Basin) might have held a “technically recoverable resource base” of about 400 tcf. Less than a year later the US Geological Survey slashed that estimate by 80%, stating reserves of only 43 tcf at 95% probability. The EIA has stated that the US may once again become a net gas importer by 2035, based on a conservative reading of its own figures.
MARGIN OF ERROR: Given the novelty of fracking, the data upon which estimated ultimate recovery (EUR) models are built contain a high margin of error. Early estimates have varied, yet they typically advertised EURs of anywhere from 2.5bn cu feet (bcf) per well, to as high as 10 or 15 bcf for “monster wells”.
The difficulty in predicting EUR has to do with accurately modelling the rate of decline in production for a well. Early estimates suggested horizontally drilled, fracked wells could have a viable production window of between 40 and 65 years, with half of a well’s production coming between years 20 and 65. More recent data suggest most value is to be had from a shale well within the first five years, with negligible value after 20 years. In practice, the rate of decline in many wells has also proved disappointing: often as much as two-thirds in the first six months, and 80% over the first year.
The US Geological Survey (USGS) updated its data in September 2012 to reduce predicted EUR for the various shale “plays” in operation in the US. For all US shale plays ( just under 36,000 producing wells) USGS data showed average EUR was anticipated to be only 0.64 bcf. A review of data taken from longer-standing wells, reported in TheNew York Times, showed that less than 10% had recovered their costs within seven years.
The profitability of the current production model is contentious. Critics say shale is unprofitable and on an average, annualised basis, has been since 2008. In Berman’s opinion, real estate speculation drives the industry: flipping leases for potential plays to inflate value. “It seems fairly clear at this time that the land is the play, and not the gas,” Berman wrote on the industry website The Oil Drum. “The extremely high prices for land in all of these plays has produced a commodity market more attractive than the natural gas produced.”
POTENTIAL: Berman’s criticisms relate primarily to the structure of the market driving US shale, rather than the viability of shale itself. With gas retailing at less than $3 per MB tu, it is hard to see how individual wells can be profitable, and it is likely that some destruction of capital is taking place in the current market. Yet with greater discipline on the supply side, a price of $5-6 MB tu could easily be achieved, while the associated liquids found in some formations add to revenues, selling at higher crude-indexed prices. Based on current trends the International Energy Agency (IEA) expects the US to become the world’s largest oil producer by 2017, thanks largely to tight oil released by fracking.
Two questions remain: what impact is US shale likely to have on wider energy markets? And what potential is there for shale production beyond the US?
It is easy to exaggerate the potential impact of shale. Gas remains a limited market, where fundamentals tend to be driven by local conditions, and long-term contracts and pipelines predominate. While wholesale prices in Europe ($12/MBtu) and Japan ($16/MB tu) suggest that US shale gas could find a ready market ( particularly once current expansion of the Panama Canal is complete), the cost of liquefaction and transportation means limits the potential for arbitrage. Aside from a plant in Alaska, there are no facilities for liquefying gas in the US. The first one is likely to be Cheniere Energy in 2015. Early forward contracts signed for its 800-bcf-per-year Sabine Pass terminal are based on Henry Hub prices plus a 15% mark-up and liquefaction fees of $2.15 per MBtu – equivalent to around $10 per MB tu once other costs are included. Such prices may prove attractive in some markets; yet with annual demand for gas in the EU standing at around 20 tcf, such levels of supply are unlikely to have a major bearing on prices. Qatar, for example, already produces around 3.7 tcf of liquefied natural gas (LNG) per year, which has not significantly affected prices. Total global LNG production in 2011 was 11.5 tcf, around 10% of all gas.
NEW HORIZONS: Many other players are examining the cost of shale gas. The Polish government announced in 2012 that reserves were likely to be 85% lower than early US estimates, reaching only 27 tcf. Parts of Western Europe are set against shale development, due to environmental costs and the absence of any “buy-in” for those likely to be affected. France has some of the largest shale reserves in Europe, but banned fracking in 2011, while Germany has proven more pragmatic: limited fracking has taken place since 2009 and current estimates suggest there could be as much as 25 to 80 tcf of reserves. China, which may have reserves of 1275 tcf, hopes to produce 3.5 tcf of shale gas per year by 2020. Perhaps the best short-term prospect for shale and unconventional gas is Australia, where coalbed methane is already being used as the feedstock for an LNG project. Nations with an established E&P industry are well-placed for short-term shale development, but long lead times mean it will to be some years before the true impact of shale is felt beyond the US.
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