In a clearing in a cornfield in the Eagle Ford region of south Texas, the rig drilling the Sisti A3 well for ConocoPhillips looks very similar to the ones that have been working in the state’s shale reserves for more than a decade. But a mile or two below the surface, the way the wells operate has changed radically.
Since 2012, Conoco has doubled the volume of ceramic proppant – a sand-like material – it uses for hydraulic fracturing. Mixed with water and pumped into wells at high pressure, the proppant forces open the cracks in the rocks where oil and gas is trapped. Using more proppant has increased the output of each well by 30 per cent – giving a healthy boost to Conoco’s bottom line. Now its engineers are examining ways to double the amount of proppant again.
This kind of experimentation has made Eagle Ford and other shale formations, including Bakken in North Dakota and Permian Basin in west Texas, the oil industry’s equivalents of Silicon Valley.
The shale boom is not a one-off event but a permanent revolution, with companies constantly pushing back the frontiers of the technology to cut costs and improve well productivity.
“We are a gigantic innovation machine,” says Greg Leveille, Conoco’s general manager for unconventional resources such as shale. “We put a lot of effort into trying to find the optimal combination of fracturing techniques.”
Horizontal drilling, which opens up layers of resource-bearing shale, and hydraulic fracturing, or “fracking”, has raised US crude output by more than 65 per cent in the past six years, helped by historically high oil prices that have made the techniques commercially viable.
The big question now is how much longer the US shale industry’s growth spurt will last.
Few issues are more significant for the future of the world economy. Threats to global crude supplies have risen this year, with turmoil in Iraq, mounting tensions between Russia and the west, and unrest in other oil-producing countries such as Libya. Yet prices have fallen, with internationally traded Brent crude dropping from about $108 per barrel at the start of the year to about $102 today.
In large part, that has been a result of booming US production. Between 2011 and 2013, the US raised its output by 2.2m b/d, more than the entire increase in global demand.
While the immediate outlook for global oil supplies is benign, longer-term prospects are more troubling. If emerging economies – above all China – continue to grow, their demand for oil will rise as well. A few countries, including Canada, Brazil and Mexico, have realistic prospects of increasing their production to meet that demand. But there is still a great burden of expectation riding on the US.
As Per Magnus Nysveen of Rystad, a consultancy in Norway, puts it, the US is taking on the role of “swing producer” that was once played by Saudi Arabia and other members of Opec, the oil producers’ cartel: raising production at a time of high prices to stabilise the market.
If US oil production stops rising or worse, begins to fall, it could send prices soaring.
David Hughes, a geologist and one of the leading shale sceptics, believes that is likely to happen in the next two years.
Shale wells, he points out, are fundamentally different from conventional wells in that their production drops off much more quickly. If no new wells are drilled there, the big Ghawar field in Saudi Arabia would lose about 5 per cent of its production every year, he says. Bakken would lose about 45 per cent.
Production in North Dakota is growing – it broke through 1m b/d in April – because there are so many new wells being drilled there. But Bakken needs 1,400 new wells a year just to keep production stable. The higher production rises, the more new wells are needed to maintain it.
The problem is exacerbated by the wide variation in the quality of shale reserves. The Eagle Ford shale, for example, covers 32 counties but just six of those account for 89 per cent of its oil production, says Mr Hughes, founder of Global Sustainability Research, a consulting company.
He argues that as the “sweet spots” with the best reserves are fully exploited, companies will be pushed towards the less productive rocks that yield lower returns. Eventually, drilling will become unprofitable and activity will slump, sending production into decline.
“The price of oil will have to be a lot higher to make drilling in those less productive counties economic,” Mr Hughes says.
The exploration and production companies that pioneered the shale revolution and still generally lead it today take a more upbeat view. Conoco says its successful experiments with proppant volumes, as well as changes in well design, have had spectacular results in terms of production and its expectations. In April 2013, the company predicted it would reach 150,000 b/d of production in the Eagle Ford by 2017. By the first quarter of this year, it had already exceeded that, with production of 160,000 b/d. In April it raised the estimate of its ultimately recoverable resources in the area by 40 per cent, from 1.8bn barrels to 2.5bn. It added that it expected to increase that figure further in the future.
Don Hrap, Conoco’s president for the Americas, says he has never seen a field like the Eagle Ford. “It just keeps surprising to the upside.”
Other shale companies have similar stories. Continental Resources, which has the largest acreage of drilling rights in the Bakken, is one of the leaders in experimenting with “downspacing”, fitting in more wells per square mile in the hope of recovering more oil from the most productive areas, all at a lower cost.
It has been running pilots of multiple wells in a honeycomb arrangement, with up to eight horizontal wells in an area that would previously have held no more than four, and three more sets of eight below them in a deeper formation called Three Forks.
Warren Henry, the company’s head of investor relations, describes the region as like a “layer cake”, with sometimes as many as five separate oil-bearing areas stacked one on top of the other.
As those layers are developed, he says, production in the Bakken is likely to double to 2m b/d in the next five to eight years. “This is Saudi Arabia in the 1950s,” he says. “Although we’ve been there for the past six years, we’re just barely getting started.”
EOG Resources, which has grown rapidly in recent years to become the largest oil producer in the “lower 48” US states, is also experimenting with packing wells in more tightly together. In 2012 each of its wells in Eagle Ford was on an average of 65 acres; today, they are on 40 acres. The reduced space does not appear to have hurt their productivity. EOG says it expected to receive 450,000 barrels from each of its Eagle Ford wells in 2012 and it anticipates the same from its new wells today.
As it became more confident in its ability to fit wells closer together, EOG in February raised the estimate of its potential reserves in Eagle Ford even more sharply than Conoco, announcing a 45 per cent increase from 2.2bn to 3.2bn barrels.
ExxonMobil and Chevron, America’s two large international oil companies, were late to the party but are also now building up their shale operations. Exxon told analysts last month that it was having “tremendous success” in Bakken, where it made a series of acquisitions. In the past two years, it has cut the cost of its wells by 25 per cent and raised their initial production by almost 60 per cent.
Although the shale oil boom has until now been concentrated in Eagle Ford and Bakken, companies have been sounding increasingly optimistic about other areas, particularly the Permian Basin, another region where different oil-bearing formations with names such as Bone Spring and Wolfcamp, are stacked alongside and on top of one another. Pioneer Natural Resources, one of the most active companies in the area, said in May that the estimate of the total recoverable resources of the Spraberry/Wolfcamp formation had been raised from 50bn barrels to 75bn, making it by far the largest oilfield discovered in the US.
Positive statements are to be expected from companies that need supportive investors. Critics of the industry have sometimes described shale as a Ponzi scheme dependent on a constant inflow of fresh capital to prevent a collapse.
“There is certainly a shale oil bubble in the sense that companies have greatly outspent their cash flow to increase their production,” says Bill Powers, an independent energy analyst and private investor.
However, the financial health of the shale companies is improving strongly, and as a group they are becoming less reliant on infusions of new financing. Their upbeat assessments of technical progress are also borne out by official data. The US government’s Energy Information Administration has started publishing drilling productivity statistics, which show rising output from new wells per working rig in Eagle Ford, Bakken, Permian and the Niobrara formation of Colorado.
The US shale industry is still young. Successful horizontal shale wells were first drilled for gas in 2002, and for oil in 2008. So there is still great uncertainty over how the reserves will perform in the long term. EOG and Continental have yet to reveal fully how their experiments with more closely packed wells in Bakken have worked, and the detailed results expected at Continental’s presentation to investors and analysts next month will be watched closely.
Phani Gadde of Wood Mackenzie, a consultancy, argues that that is a good reason for optimism about future production.
“The shale industry is just starting out; it is not even a teenager yet,” he says “Best practice in terms of how to maximise production has not been nailed down yet. So there is still plenty of room for growth.”
No oil boom can last for ever. The time will come when Eagle Ford and Bakken are in decline, as the North Sea and the North Slope of Alaska are today. The breakneck pace of US production growth will become increasingly difficult to sustain, if only because the industry is working from a higher base.
As Mr Hughes warns, when the decline comes it could be rapid. But the oil business is engaged in a never-ending battle between recalcitrant resources and the industry’s creativity in working out how to extract them – and for now human ingenuity appears to be winning.
Production: A football kickabout among friends
Of all the influences on US oil production, the most significant in the short term will be the price of crude.
Philip Verleger, an energy economist, argues that in 2015 there is likely to be a growing surplus of oil on world markets created by rising production in the US, Canada and a few other countries. The result will be falling prices.
“My guess is we’re going to be in a period of significantly lower prices,” he says. “Maybe not as low as $50 per barrel. But certainly enough to slow down the whole push towards shale development.”
Flows from shale wells decline quickly so the industry needs to drill thousands more every year for total output to grow. If drilling becomes uneconomic, the effects show through quickly in overall production.
Per Magnus Nysveen of Rystad, a consultancy, says about 10 per cent of the rigs working in the Eagle Ford shale formation in Texas and the Bakken in North Dakota will not be economic with global oil prices below $100 a barrel; not much lower than today’s $102.
A 10 per cent drop in drilling will not stop production rising in those areas, he says, but it will cause a significant slowdown in growth.
However, the more severely affected developments might be large, expensive conventional projects such as offshore fields in the Arctic or the Canadian oil sands.
Mr Verleger draws an analogy with games of football. Shale is like a kickabout among friends: if it starts raining, everyone goes inside but as soon it stops they can restart quickly. Big conventional projects are more like World Cup fixtures: it takes a lot for them to be called off but once they are cancelled it takes a long time to get them going again.
Shale production is likely to drop off more quickly, but it will probably recover faster as well.
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