The Shale Gas Revolution

Shale is the world’s most common sedimentary rock, made from fossilized mud or clay. Like coal, it was long known to contain natural gas, but it would take the combination of evolving knowledge of how the gas is stored in the rock and horizontal drilling technology to make it possible to extract.

“In shale gas, effectively what you are doing is you’re creating a reservoir,” explains Mike Dawson, president of the Canadian Society for Unconventional Gas. The secret to doing that is a process known as multi-stage fracture stimulation. The rock is extremely “tight” as fossil fuel beds go, which poses a problem of how to break it to release the gas locked inside. Using newly available horizontal drilling equipment, companies like Mitchell Energy (which was acquired by Devon Energy Corporation in 2002) succeeded in drilling down to the shale layer, then turning along its horizon for hundreds or even thousands of metres. But existing methods of “fraccing” – forcing water, sand and/or chemicals down the hole at high pressure to break the rock – were insufficiently powerful. The breakthrough in the Barnett between 2002 and 2004 was a technique of concentrating the charge into a single segment of the well bore’s horizontal leg at a time, each 100 to 200 metres in length.

EnCana Corporation was in on the Barnett play in 2003 and is today producing 153 million cubic feet a day there, says Mike Graham, president of the company’s Canadian foothills division. EnCana has since taken what it learned there and adapted it to its land in the Haynesville Shale in Louisiana and Horn River, near Fort Nelson. “We’d actually discovered the Horn River basin in B.C. in about 2003 or 2004. And we weren’t really sure what we had so we got a lot of help out of our U.S. people. It took technology to really get these shales to work.”

One thing that quickly distinguishes a new shale gas well is the huge concentration of pumper trucks – as many as 20 to 30 – clustered on-site to generate sufficient “horsepower” to fracture the shale. “You need to inject a tremendous amount of fluid and a tremendous amount of sand,” measured by the tonne, Graham explains. “We used to think 10- or 20-tonne fracs were big fracs. Now we’re putting 1,000-, 2,000-tonne fracs as just a normal course of business.” From drilling to completion, a single well can cost $10 million (compared to maybe $2 million for a vertical well), though EnCana’s experience with resource plays is that costs typically drop 20% to 40% in the first few years.

“We really have to get a manufacturing style going,” Graham says.

When Arc Resources Ltd. bought Star Oil & Gas in 2003, it acquired a property in the Montney play in northeastern B.C. known as Dawson. The idea then was to drill a vertical well down to a soapstone layer (finer in grain than true shale but similar in its characteristics and extraction methods), blast it with a 120-tonne frac and produce a million to 1.5 million cubic feet of gas a day. Two years later, with the Barnett play taking off, Arc began drilling horizontal wells, expecting to save money; each well bore would generate four times the production and four times the reserves for perhaps three times the costs, the company reasoned. The experience proved different.

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