Cheap, plentiful energy has long been a precondition of the industrial age. In recent years, however, conventional reserves of fossil fuels have been steadily dwindling. With renewables not yet sufficiently developed to end our dependence on these resources, the world seemed to face a stark choice: return to more hazardous and polluting sources such as nuclear and coal, or accept dramatically higher energy prices, and the consequent constraint on economic activity. In the past five years though, a quiet revolution has taken place. In the US, after decades of deindustrialisation, companies are once more retooling in energy-intensive industries such as 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 (mmbtu) 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. WHAT IS SHALE?: Shale gas is part of the family of “unconventional” hydrocarbons, which also includes tight gas, tar sands and biofuels. Shale refers to the geological material in which shale gas and associated (“tight”) oil is formed. It typically lies much deeper than conventional reservoirs of oil and gas. 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 into hydrocarbons.
In conventional deposits, those hydrocarbons have seeped back toward the surface through layers of semiporous, permeable rock before becoming trapped beneath a seal of non-porous rock. It is in such 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 in these formations is less concentrated, and locked much more tightly within the rock. For this reason, little exploitation has taken place. Wells must generally be dug much deeper to access such formations, and the 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 such a 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, and him into a billionaire. 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 steadily declining since 2006 (from 18trn cu feet [tcf] per year, to 12.3 tcf in 2011), production from shale wells has rocketed, reaching 8.5 tcf in 2011, up from less than 1 tcf in 2005.
Shale wells now make up around 30% of domestic gas production in the US, and shale exploitation has helped push total gas production up to 28.5 tcf per year – higher even than the boom years of the early 1970s.
The impact of shale helped push the US past Russia in 2011 to become the world’s number one gas producer. At the same time, liquids released from the fracking process have also led to a major increase in US oil production, with around 800,000 barrels per day (bpd) being added since 2005 through tight oil exploitation.
This latter category, sometimes referred to as shale oil, should not be confused with oil shale (or kerosene), a solid mix of organic compounds which must be heated to be transformed into oil. There is as yet no proven technology for economically extracting oil from such formations while keeping the shale itself in place.
INCENTIVES: The rapid development of the US shale market can be attributed to a number of separate yet mutually reinforcing factors, not all of them necessarily exportable. 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. Europe has under 130 rigs, and barely any of these are capable of drilling horizontally. This abundance of rigs was the product of a relatively mature market in conventional oil and gas exploration, characterised by a large number of lowproducing wells typically serviced by smaller companies. This decentralised production model was ideal for exploiting shale, which follows a process whereby, 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 already in place. This enabled 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 Ohio, Pennsylvania and New York has been underlined by the difficulties currently being faced by E&P companies attempting to exploit more remote formations such as the Bakken in North Dakota. There, an absence of pre-existing infrastructure has resulted in flaring of up to 35% of production – enough gas to power all the households in Washington, DC and Chicago combined.
The second advantage was a highly developed, wellintegrated wholesale market. The federal government also provided incentives for the E&P industry from 1980-2000, such as the section 29 tax credit for unconventional gas, which encouraged exploratory drilling methods such as those pioneered by Mitchell. The final incentive may have proved the most important, however. The majority of shale exploration so far in the US has been carried out on non-federal land. This is because rights to below-surface minerals in the US reside with the land owner (rather than the central government), giving individuals an incentive to allow prospecting on their land in return for royalties. “Private land owners or government land-owning 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 said.
ENVIRONMENTAL IMPACT: The rapid expansion of shale in the US has not been without controversy, with environmental concerns being raised over extraction procedures. These concerns fall into three broad categories: increased seismic activity; contamination of the water table through seepage; and the possible 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 3-5 on the Richter scale). In 2010 over 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, prompting a nationwide moratorium on drilling. In the UK case the company responsible for the wells, Caudrilla, admitted that the tremors were probably caused by fracking. In the US, demonstrating a link has proved contentious. Oklahoma (home to the Caney and Woodford formations) experienced its strongest recorded earthquake in 2011, a magnitude 5.7 quake. According to a report by the University of Oklahoma, Columbia University, and the US Geological Survey (USGS), the quake was “likely caused by fluid injection”, with disposal of fracking waste water having taken place 250 metres from the quake site. A US National Research Council report 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 in wells, usually caused by corrosion or breakage of the steel well shafts. In this way, the water table can become contaminated by gases or liquids released through the fracking process, and chemicals in the fracking liquid itself. Contamination can also result from well blowouts. Regardless of seepage the fracking process results in the production of waste water of up to 3m gallons per well, the content of which has become a matter of concern. 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. As a result, a cocktail of toxic chemicals has been recorded in water tests near fracking sites, leading to several fines for contamination being levied on the industry. 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 of fracking fluid. Loopholes remain, however, while in other cases the damage has already been done. Other countries seem to have learned the lesson that a proper regulatory framework for fracking is vital to maintain public confidence. 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 current US market bears all the hallmarks of a classic asset bubble. Arthur Berman, a petroleum geologist and energy consultant, has drawn attention to three issues concerning the industry: 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 the next century. In fact, as with other fossil fuels, measuring shale gas reserves is highly complex, and involves distinguishing between “proven” reserves (those which are 90% probable and can be profitably extracted in the current market), and “unproven” reserves (those which may exist, but are not certain to be recoverable). Unproven reserves are further subdivided into “probable” (50% probability of production), “possible” (10% probability) and finally “speculative”.
The “100 year” claim for US shale reserves originated in a 2011 report by the Potential Gas Committee (PGC), a body which obtained its total estimate of 2170 tcf by adding together all four reserve categories. Based on current US domestic demand of around 24 tcf per year, this would indeed equate to a 95-year supply. However, total proven reserves of shale in the US are only 273 tcf. Grand early claims regarding shale formations have also been liable to sharp revision. In 2011, for example, the US Energy Information Agency (EIA) suggested that the Marcellus shale might hold a “technically recoverable resource base” of about 400 tcf. Less than a year later the USGS slashed that estimate by 80%, stating reserves of 43 tcf at 95% probability. In contrast to the PGC, the EIA has stated that the US may again become a net gas importer by 2035, based on a conservative reading of its own figures.
MARGIN OF ERROR: The reserve picture is further complicated by Berman’s second argument: that the current production model for shale is based on inaccurate modelling and is inherently unprofitable. This is perhaps the most contentious issue of the current shale boom, as it concerns the estimated ultimate recovery (EUR) of a given shale well – that is, the total amount of gas a well can produce over its lifetime.
Given the relative novelty of fracking, the data upon which EUR models are built still contain a relatively high margin of error. Early estimates have varied, yet they typically advertised EURs ranging from 2.5bn cu feet (bcf) per well to as high as 10 or 15 bcf for “monster wells”. A large part of the difficulty in predicting EUR has to do with accurately modelling the rate of decline in production for a well. Again, early estimates suggested horizontally drilled, fracked wells could have a viable production window of around 40-65 years, with half of a well’s production coming between years 20 and 65. More recent data suggest that most value is to be had from a shale well within the first five years, with only 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.
For this reason the USGS updated its data in September 2012 to substantially reduce predicted EUR for the various shale plays in operation in the US. For all US shale plays (a total of just under 36,000 producing wells) USGS data showed average EUR was anticipated to be only 0.64 bcf. In a similar vein, a review of data taken from longer-standing wells and reported in The New York Times showed that less than 10% had recovered their costs within seven years.
While the industry has become more accurate in targeting the most productive areas, the underlying profitability of the production model remains contentious.
It is on this issue that the detractors’ final argument rests: shale is unprofitable, and on an average, annualised basis has been since 2008. The dynamics driving the industry must therefore lie elsewhere. In Berman’s opinion, that is real estate speculation: “flipping” leases for potential plays to inflate their value. “It seems fairly clear at this time that the land is the play, and not the gas,” Berman wrote recently on The Oil Drum website. “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 mmbtu, 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 mmbtu could be achieved, while the associated liquids found in some formations add to revenues, selling at higher crude-indexed prices. Indeed, based on current trends the International Energy Agency (IEA) expects the US to become the world’s largest oil producer by 2017, thanks to tight oil released through fracking.
Two questions remain. What impact will US shale 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 mmbtu) and Japan ($16 mmbtu) suggest US shale gas could find a ready market, the cost of liquefaction and transportation means the potential for arbitrage is limited. Aside from one plant in Alaska there are currently no facilities for liquefying gas in the US. First out of the traps is likely to be Cheniere Energy in 2015. Early forward contracts signed for its 800-bcf-per-annum Sabine Pass terminal are based on Henry Hub prices plus a 15% mark-up and liquefaction fees of $2.15 mmbtu – equivalent to $10 mmbtu once other costs are included. Such prices may prove attractive in some markets; yet with annual demand for gas in the EU standing at 20 tcf, such levels of supply are unlikely to have a major bearing on prices. Qatar, for example, already produces 3.7 tcf of LNG per year, which has not significantly affected prices. Indeed, total global LNG production in 2011 was only 11.5 tcf, or 10% of all gas.
BENCHMARK: Based on these fundamentals it seems unlikely that the US Henry Hub will become the new benchmark for European and East Asian gas. Rather, crude oil looks set to continue as the benchmark for long-term gas contracts, while in Europe increasing production from Norwegian wells – which in 2012 grew by 16%, or 600 bcf – should prove a more significant determinant of prices. Where arbitrage is taking place, the shift has been toward spot pricing or hub-indexing based on the British National Balancing Point, or even away from gas and toward coal. Moreover, given that Europe is, if anything, currently oversupplied with gas, creating a stronger internal market could have a much bigger impact on pricing than shale ever could.
US shale may have a more significant knock-on effect on global oil markets. As mentioned, the IEA expects the US to become the world’s largest oil producer by 2017, with 11.1m bpd. This would make the US more or less self-sufficient, and free up Middle Eastern oil for export to Asia. As a result, the IEA anticipates that by 2035 up to 90% of Middle East oil will be flowing to Asia, significantly altering the pattern of world trade, and likely contributing to a reconfiguration of geopolitics. Will an energy self-sufficient US be more insular? Will China and India seek greater influence in the Gulf as their energy dependency grows? Whatever the answers, US shale production will play a significant role.
NEW HORIZONS: Turning to the second big question – is there potential for shale to be developed beyond the US? The geological and economic challenges will be significant. 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 the potential environmental costs and the absence of any buy-in for those likely to be affected (the state lays claim to anything under the surface in the “Old World”). France has large potential shale reserves, but banned fracking in 2011. Germany has proved more pragmatic: limited fracking has been taking place since 2009, while there are estimated to be 25-80 tcf of reserves.
China, which may have the world’s largest shale reserves if US EIA estimates of 1275 tcf are correct, hopes to produce 3.5 tcf of shale gas per year by 2020. However, its deposits are trickier than those in the US: they are more deeply buried, and are located in waterscarce regions. Auctions for shale plays have produced mixed results, with the profile of bidders suggesting land speculation is a key motivation. Even if China succeeds in its plans, gas is still only set to make up 10% of the country’s energy mix by 2020, from 4% currently. Perhaps the best prospect for unconventional gas in the short term is Australia, where coal-bed methane is already being used as the feedstock for an LNG project. In 2013 Linc Energy claimed that Australia’s Arckaringa Basin could hold 103bn-233bn barrels of tight oil. A strong domestic mineral industry and proximity to Asian markets could prove major advantages.
The viability of shale has been proven. How far its potential benefits will extend beyond America, and how rapidly, will depend on countries finding the right mix of regulatory structures and market incentives – both to attract the huge investment in infrastructure necessary, and to keep public opinion onside. Those with an existing E&P industry will be at an advantage in this, yet long lead times mean it is still likely to be some years before the true impact of shale is felt beyond the US.
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