Pump jacks are seen in the Midway Sunset oilfield
© REUTERS

If you really want to understand hydraulic fracturing, it is not enough to read about it or watch it on video; you have to feel it.

As the mixture of water, sand and chemicals is pumped into a well to crack the rock and release the trapped oil and gas, there is a palpable sense of the power involved, the pipes and pumps tensed and vibrating slightly as they control the intense pressures required.

A typical fracturing – “fracking” – operation will use about a dozen pumps, each with as much horsepower as three Formula One racing cars, each mounted on the back of an 18-wheeler truck.

When they are pumping, they can raise the pressure in the well to the same level as on the seabed in 30,000 feet of water; deeper than almost any ocean on earth.

The capabilities and costs of those pumps, made by companies such as Weir Group of the UK and Gardner Denver of the US, are crucial factors for the North American shale revolution.

High-pressure pumping, combined with horizontal drilling to send wells a mile or more laterally away from the rig to open seams of oil and gas, has made possible production from reserves that were long known about but previously not financially viable as sources of production.

The techniques were first applied to natural gas, but in the past five years, as the price of gas slumped, they have been increasingly used to extract oil.

The result has been a surge in US crude production, which has risen more than 50 per cent in the past five years.

A question hangs over the US oil boom, however, in terms of its production costs. The effort required to squeeze the oil out of the rock, from which it will not naturally flow easily, means that shale production is relatively high cost, compared with the traditionally cheap-to-extract reserves of the Middle East.

The smaller and midsized US independent companies that have led the charge into shale oil, including Continental Resources, EOG Resources, Whiting Petroleum and Hess, have nevertheless been able to expand their production very rapidly, thanks to high crude prices of about $100 per barrel, and a steep decline in their costs.

In part, those falling costs have reflected the companies learning more about what is still a very new activity. They are making remarkable technical advances, such as pushing the horizontal distance travelled by wells from one mile to two or more, and using a rig on a single site to drill multiple wells, rather than disassembling it and moving it to a different location every time.

That technical progress has meant that EOG, for example, says that it has been able to cut the average time it takes to drill a well in the Eagle Ford shale of Texas from 15 days in 2011 to less than 10 days in 2013.

On top of those productivity improvements, however, there has also been a very significant boost from overcapacity in the service industries.

In 2010-11, there was heavy investment in new pressure pumping capacity, as the leading fracking service companies such as Schlumberger, Halliburton, Baker Hughes and FTS International (formerly Frac Tech Services), positioned themselves for the boom they could see coming.

“Those were the gold rush years,” says Keith Cochrane, chief executive of Weir.

“Then in early 2012, it became very clear we had started to see a dramatic shift . . . We had a much more challenging environment for the supply chain, as the industry sought to adjust.”

While oil drilling boomed, drilling for gas slumped as prices hit a 10-year low. Equipment for drilling and fracking was shifted across from gas to oil but not enough to pick up all of the slack in the service industries.

PacWest, a consultancy, says that capacity utilisation for pressure pumping equipment dropped to just 74 per cent at the end of last year. As a result, prices for pumping services dropped an estimated 22 per cent between the first quarter of 2012 and the third quarter of 2013.

It was a rough time for service companies. Schlumberger’s North American operating profits fell 10 per cent last year, Halliburton’s by 26 per cent and Baker Hughes’ by 34 per cent. For producers, though, it was wonderful.

Now, however, prices have started to stabilise. Some of the excess capacity has been used up by the attrition of old equipment, and by being moved to new shale prospects now opening overseas. As the services companies report quarterly earnings over the coming week, they are expected to show better results and improving prospects for their North American operations.

The outlook depends in large part on what happens to gas production. Mr Cochrane suggests a catalyst could be the start of exports of liquefied natural gas from the first US projects set to come on stream over the next few years, which could lift prices and revive gas drilling. Gas producers’ gain, however, would be oil producers’ pain.

Christopher Robart of PacWest says: “Assuming that the price of oil stays strong, and the gas price strengthens too, then we will definitely start to see some competition for that capacity picking up, and that will be helpful to service prices.”

Analysts at Sanford Bernstein have argued that as the benefit of the service industry’s overcapacity goes away, and producers’ costs are falling more slowly, they will also face deteriorating productivity from their new wells, because they have drilled the best locations first.

The result could be higher costs per barrel, and a US shale oil industry that will be able to continue to grow only if crude prices rise higher.

It is possible that the US shale oil can continue to thrive only if shale gas continues to struggle.

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