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Alaska Shale: Why Alaska sees hope in source rocks State petroleum geologist tells lawmakers that North Slope source rocks resemble some of the hottest shale plays in North America Eric Lidji For Petroleum News
The State of Alaska is “cautiously optimistic” about oil development from source rocks.
“Optimistic” because the geology of the Alaska North Slope resembles the hot Eagle Ford shale formation in South Texas, and Great Bear Petroleum’s leases are “well positioned” to develop that geology, a Division of Oil and Gas petroleum geologist recently told state lawmakers. “Cautiously” because developing source rocks is an entirely new concept in Alaska that will require a lot of equipment, crews and water, and some trial and error.
“If these production pilots and exploration success do occur then full-scale development, if it were to occur, could be quite a whirlwind,” Paul Decker said on Feb. 23. “But, you know, things remain to be seen. But at this point I think we’re cautiously optimistic.”
The play Great Bear is proposing to develop at its new 537,500-acre North Slope lease position is so new for Alaska that it doesn’t even have an agreed upon name, but Decker is calling it “source-reservoired oil,” meaning that the source rock is also the reservoir, because the rocks are so tight that they hold onto the oil they generate like a traditional geologic trap.
What makes for good rocks? The North Slope is home to three “prolific” source rock intervals that are candidates for development: the Shublik, the Kingak and the GRZ/Hue shale system, from deepest to shallowest. These source rocks exist some 8,000 to 13,000 feet underground.
The factors that make source rocks good candidates for development include the organic chemistry — the ingredients for making oil, elements like carbon and hydrogen — and the thermal maturity — the underground heat needed to turn those elements into oil.
For source rocks to become the “kitchen” where oil and gas gets “cooked,” they must be deep enough for the heat of the earth to reach the proper temperatures. Shallow rocks are too cool, or “immature,” and won’t generate oil and gas for ages, but in the hotter depths below those immature rocks are usually an “oil window” and a deeper “gas window.”
The tectonic history is also important, because natural fracturing can make recovery easier and needs to be well understood in order to design, drill, and complete the wells most effectively.
Clues in Texas and N. Dakota Trying to analyze the source rocks on the North Slope, the most comparable basins are the Eagle Ford shale in Texas and the Bakken shale in North Dakota. On average, North Slope source rocks aren’t as organically rich as the Bakken or the best parts of the Eagle Ford, but they are generally thicker. The Shublik rocks appear to be brittle like the Eagle Ford and the Bakken, but typical Shublik-sourced oil is somewhat heavier. The Kingak and GRZ/Hue appear to be less brittle than the Eagle Ford and Bakken, but are known to generate somewhat lighter oil than the Shublik.
“We expect that the Eagle Ford is going to be a pretty good place to look to answer questions that we don’t yet know from direct evidence from our own source rock,” Decker said.
Does that mean Alaska is as prolific as the Eagle Ford or the Bakken?
Decker said it’s still too soon to say, but noted that a U.S. Geological Survey assessment of the unconventional oil and gas resources in Arctic Alaska slated for release next year should shed some light on just how much oil is down there.
“We are very encouraged from what we know right now, but the proof is in the drilling,” Decker said.
Currently, only Great Bear Petroleum is looking to explore source rocks, but if it can successfully develop the resource it would likely create a rush on the North Slope. Great Beat President and COO Ed Duncan told lawmakers that he believes his leases alone could contain some 2 billion barrels of oil and 12 trillion cubic feet of natural gas.
The learning curve ahead With unconventional oil plays, though, the trick is recovery.
Unlike a conventional reservoir, there are no “dry holes” in source rocks because the rocks are saturated with oil or gas. The question is whether the oil can be recovered.
Decker said success on the North Slope would depend on gathering enough good data about the source rocks to support a pilot project. “We are going to need to get on that learning curve and lower the cost of drilling wells. It is partly learning. It’s partly just getting enough equipment up there I think. But we need to lower those costs,” he said.
A pilot project would help craft an Alaska model for development. Drillers in the Bakken Shale typically drill from five-acre pads spaced every 640 acres. From each pad, one horizontal or multilateral well extends up to two miles in length. Spacing is much tighter in the Eagle Ford, between 125 and 140 acres per well, and would likely be tighter in Alaska, as well, with multiple horizontal wells drilled from each pad. Great Bear plans to use one-acre pads every 120 to160 acres.
Because source rocks don’t yield their resources like conventional resources, drillers must fracture and stimulate the rocks with large amounts of water and sand. Production rates usually decline quickly over the first two years, but decline more slowly over the next decade or more.
Decker said Alaska needs more equipment, more crews, a sufficient water supply, transparent fracturing practices to guarantee that permafrost and drinking water supplies are adequately protected and new all-seasons roads to allow for year-round surface access.
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