AD Main Menu

Great Bear betting big on Alaska's shale oil

Kay Cashman

Can Alaska join the shale oil boom sweeping the Lower 48, making states like North Dakota contenders for the largest producer in the country?

One company, Great Bear Petroleum, bet $8 million in Alaska's latest North Slope lease sale that it can.

In a sale last fall, the newly formed independent, which only plans to do business in Alaska, grabbed more than 500,000 acres containing a chunk of the geologic "kitchen" that produced 100 billion barrels of oil that flowed into major North Slope reservoirs.

In a presentation to the Alaska Legislature's Senate Resources Committee on Feb. 26, Ed Duncan, Great Bear Petroleum president and chief operating officer, amazed legislators with his description of the company's plans.

Among the most startling:

• If Alaska needs 1 million barrels of oil a day in the trans-Alaska oil pipeline, Great Bear can deliver it and more by stepping up the pace of drilling. The company says it expects production up to 600,000 barrels a day from just two of its three shale "plays."

• Alaska has three of the most prolific source rocks in the world. Individually they are superior to the Eagle Ford shale in Texas, currently considered the hottest conventional oil play in the world.

• Great Bear plans three 15-year development phases. In each phase, 3,000 wells will be drilled from the same one-acre pads, at an average of 200 wells a year, requiring at least 20 drilling rigs working year-round. The cost for drilling, excluding pipelines, facilities, roads and other infrastructure is $2 billion a year, about $10 million a well.

• If production begins in 2013, as planned, Great Bear projects oil production from its acreage at 200,000 barrels a day by 2020, 350,000 by 2035, 450,000 by 2041, peaking at 600,000 in 2056, with sustained production of 450,000 until 2074.

• This volume of production, Duncan said, especially if other shale developers grab hundreds of thousands of acres still available in these same areas, might eventually necessitate a pipeline to replace TAPS, or a sister line.

• Great Bear's longer-term North Slope gas development strategy might include exporting liquefied natural gas.

• Great Bear is not looking for investors or partners, except for a possible shared seismic shoot next winter across the North Slope from the border of ANWR to the far western edge of the National Petroleum Reserve-Alaska, out into the Beaufort and Chukchi seas.

Duncan told the committee that Great Bear's analysis indicates that 20 percent of the oil from its leases had migrated north to known fields, leaving 80 percent to be tapped with improved technology.

"The percentage of hydrocarbon recovered is a moving target," he said. "Two years ago it was probably 3 to 4 percent. Now it's 5 to 6 percent, and it's improving. Technology in this particular field is moving at a spectacular pace."

MATCHING GEOLOGY WITH TECHNOLOGY

Duncan is a former project supervisor and geologist with Sohio's (now BP Alaska's) exploration group. From 1982 to the late 1980s, he was in charge of everything on- and offshore between the Colville River and the Canadian border. His job was to match the geology of an area or prospect with advances in technology that might make it economical.

Duncan said the challenge of producing oil and gas from Great Bear's leases has little to do with the geology. "The challenge for the play is: Is it operationally doable on the Slope," he told the Petroleum News. The answer, he said, is yes.

"There's always a chance the rocks just won't perform the way we want them to. We don't expect that. That's way outside our prediction range of outcomes. Also, there's a chance the rocks will perform well beyond what we might imagine," Duncan said.

The technology and geology are a perfect match, he says, or will be as soon as his associates have tweaked their well design.

"We have some technical uncertainties to address -- that's one of the reason we want to do our core holes soon," Duncan said, referring to drilling tentatively scheduled for late fall.

"We need to design our fracs (hydraulic fracturing). Our first four planned full production test wells have large R&D research elements in them. We'll perfect a method very quickly in the first few wells, then we go into factory drilling, and the costs go down at that point.

"That's the operational model that has been developed in the Lower 48," he said, explaining that he expects the wells to be roughly 9,000 to 11,000 feet deep, with 4,000- to 6,000-foot horizontal drilling.

"We'll drill down to the source rock and then run the laterals along the source rock strata and using state-of-the-art rock fracturing techniques to cause oil to flow direct from the sources."

MULTIPLE PHASES

In phases one and two, Great Bear will target the deepest and oldest of the three source rocks, the Shublik formation. In the process, the company will drill past the Kingak shale, and the youngest and shallowest rock, the Hue shale.

"The richest source rock on the North Slope and one of the richest source rocks in North America -- in fact, one of the richest source rocks in the world -- is the Shublik formation," Duncan told legislators. "Its regional extent, its quality, is extraordinary. And that is our primary target.

"But, again, I can't emphasize enough; we believe that the Kingak and the Hue individually could supply an unconventional resource development on their own. The fact that we have three on the North Slope provides ... an extraordinary opportunity. You don't get that in south Texas, you don't get this in the Bakken and you really don't get that in the Marcellus."

Decker and Duncan address water issues

But even if geology is not a challenge as it is in conventional oil and gas plays, there are technical challenges associated with producing oil and gas from shale. One of those challenges is water.

The hydraulic fracturing critical to making source rock permeable enough to release hydrocarbons requires large quantities of water. Of most concern to the public is any potential for water supply contamination. That has caused considerable controversy for shale oil developments in the Lower 48.

A few days before Duncan spoke in Juneau, State petroleum geologist Paul Decker addressed that concern in another legislative hearing.

"Are there environmental risks?" he asked legislators. "Well, I think we have all heard some of the stories from the Lower 48 plays where they have done fracking," Decker said. "There is the possibility that shallow aquifers could be contaminated if great care isn't taken to ensure that those fractures don't extend up into that fresh water aquifer, but this is something that is clearly avoidable with good engineering, good geologic practice.

"Responsible operators can certainly avoid this, particularly on the North Slope. I had asked you to try and envision the base of the permafrost where the fresh water aquifers need to be protected. That is essentially a mile or 6,000 feet or so above our zones of interest for fracking, so I think we can really avoid this kind of environmental risk."

Duncan talked about advancing technology in regard to water use, as well as known water sources on the North Slope.

"Fortunately the technology evolving today allows for the recycling of frac water, so that reduces water needs significantly. Additionally we talked to the water folks at DNR in Fairbanks . . . and with virtually every service provider that's going to be involved in this play.

"We believe there are adequate water resources on the North Slope, both from the Sag River, for example, as well as surface water. But more importantly, as this play develops we may see accessing subsurface water; some of the brackish aquifers, not suitable for drinking water.

"These water resources may be perfectly adequate for making up our frac fluids and that could definitely change the balance of surface water use in this program. It's a challenge. We know that. And we're working on it."

ALASKA CHALLENGES

Duncan addressed the challenge of oil development in Alaska by pulling out a slide with data comparing the ability to execute projects here compared to other petroleum provinces, including all the major oil producing countries. Alaska ranked 129 out of 141, in large part because of federal "impediments" to on and offshore projects.

Great Bear's project, he said, had to make sense for all stakeholders, including the people of the North Slope, the state of Alaska, the environment and wildlife, and his company.

GREAT BEAR'S VISION

"The easy conventional oil on the North Slope has been found. . . . As with every other basin in North America, the future is unconventional -- oil and gas. . . . It's unconventional resource plays that are going to drive the energy economy of this country and this state going forward for a very long time," he said.

"Our company aims to be the leading unconventional oil and gas producer in Alaska. Our leasing is focused very heavily on good science. We're reasonably proximal to infrastructure. We bracket the pipeline. We see every reason to believe these rocks will produce at commercial rates. We believe that effective and efficient development of our resource base from our leasehold alone provides a growing and stable forecast-able energy and economic future for the State of Alaska for the next 50-plus years, effectively, in the near term, reversing the state's oil decline," Duncan said.


By KAY CASHMAN
Petroleum News