Alaska Shale: Oil makes a grab for shale crown

Lower 48 shale game started out as gas play, but low gas prices, new technology have firms chasing higher value oil, natural gas liquids

Eric Lidji

For Petroleum News

The potential for a shale oil boom on the North Slope of Alaska is based on slightly different market factors than the current rush on similar formations across the Lower 48.

The interest in oil-bearing source rocks on the North Slope is based in part of infrastructure. The lack of a natural gas pipeline makes oil the only sure bet in northern Alaska, while declining throughput on the trans-Alaska oil pipeline is creating an incentive — and a public need — for producers to find new volumes of oil.

In the Lower 48, though, recent interest in shale oil is about prices. When shale gas exploration exploded in 2008, oil topped $150 a barrel and natural gas topped $13 per thousand cubic feet, but today oil is $100 a barrel and natural gas is less than $4 per mcf.

Oil has always been more valuable than gas, but technological constraints kept companies from pursuing it until Petrohawk cracked the code in the Eagle Ford in 2008.

The recent shift became clear as companies released their annual reports this year.

Chesapeake Energy, which calls itself “America’s Champion of Natural Gas,” doubled its oil production in 2010 and said it didn’t plan to transition away from oil even if natural gas prices improve in the next few years. “We can drill a natural gas well and receive around $4 per unit of production or we can drill an oil well and receive around $15 per unit of production,” CEO Aubrey McClendon told investors in late February.

Range Resources recently sold its Barnett Shale properties in North Texas to focus on Appalachia, where three stacked shale plays — the Marcellus, Upper Devonian and Utica — create economies of scale by offering liquids-rich shale gas formations.

After watching gas volumes drop except at liquids-rich plays like the Granite Wash tight sands in Oklahoma, MarkWest Energy Partners, a midstream company, wants to connect liquids operations from Pennsylvania through Kentucky and down to Gulf Coast markets.

The major service companies see the writing on the wall, too. “With natural gas price forecasts from the Energy Information Agency for 2011 slipping by nearly a third compared to initial projections made at the beginning of the year, an increasing portion of the drilling and completion activity in shale reservoirs has shifted to liquid and condensate-rich plays in North America,” Schlumberger wrote in year-end filings.

Baker Hughes noted that recent spending on shale gas is based on temporary market oddities: hedging leftover from times of higher prices, the need to drill wells to meet lease terms, joint venture capital coming from overseas companies looking to gain technical know-how and experience and boosts from associated liquids production.

Cracking the nut

Because oil molecules are sticky and larger than gas molecules, engineers thought the process wouldn’t work to squeeze oil out fast enough to make it economical. But drillers learned how to increase the number of cracks in the rock and use different chemicals to free up oil at low cost.

“We’ve completely transformed the natural gas industry, and I wouldn’t be surprised if we transform the oil business in the next few years too,” McClendon said.

Petroleum engineers first used the method to unlock oil from source rock in 2007 from the Bakken Shale, a 25,000-square-mile formation under North Dakota and Montana.

A huge increase in interest followed a 2008 U.S. Geologic Survey study suggesting that the Bakken contained 3 billion to 4.3 billion barrels of oil, a 25-fold increase over the previous USGS estimate, made in 1995.

That increase is the result of one word: recoverable. Improvements in technology between 1995 and 2008 made it possible for companies to first extract natural gas and the, in 2007, begin to extract liquids.

On to the Eagle Ford shale

Liquid production doubled in the Barnett between 2005 and 2009, nearly quadrupled in the Marcellus between 2008 and 2009, and increased eight-fold in the Woodford shale of Oklahoma between 2007 and 2009.

In just this past year liquids production in the Bakken rose 50 percent to 458,000 barrels a day, according to Bentek Energy, an energy analysis firm.

In the Eagle Ford shale of South Texas, oil production jumped from 300,000 barrels in 2009 to nearly 2.6 million barrels in 2010 and condensate production jumped from some 500,000 barrels in 2009 to nearly 3.3 million barrels in 2010, according to the Railroad Commission of Texas, the main permitting and statistical agency in the state. Those increases dwarf the not-too-shabby four-fold jump in natural gas production last year.

The Eagle Ford is still just a kid. Petrohawk began developing the gas potential of the formation in 2008, but it and others have since focused on the liquids-rich northeast end of the 400-mile long formation starting from the Mexican border up into East Texas.

The Eagle Ford is attractive because its rocks, buried 4,000 to 12,000 feet underground, are up to 70 percent carbonate shale, making them very brittle and easy to fracture.

That combined with rising oil prices is drawing producers to the region. The Railroad Commission of Texas issued 33 drilling permits in 2008, 94 in 2009 and 1,229 in 2010.

That activity is expected to increase and to keep favoring oil. A February 2011 industry-funded forecast by the University of Texas San Antonio expects companies to drill nearly 5,000 new wells in the Eagle Ford over the next decade, nearly 75 percent of them for oil.

The producers stalking the Eagle Ford include some of the biggest players in Alaska, like Anadarko Petroleum, ConocoPhillips, Marathon Oil and Pioneer Natural Resources.

While that means Alaska is competing with South Texas for exploration dollars, it also means those companies are learning about similar geology — the Eagle Ford is thought to be the closest analog to the Shublik and Kingak, the North Slope’s major source rocks.