Shale oil could be 'game changer' for Slope

Shale oil could be a “game changer” for the Alaska North Slope, and the state Department of Natural Resources is moving to facilitate shale development and find answers to problems that could impede it.


Paul Decker, a petroleum geologist and section chief of the resource evaluation group in the Division of Oil and Gas, briefed members of the Alaska Geological Society Sept. 22 on what the state now knows about the resource.

All of this started last year when Great Bear Petroleum, a Texas-based independent company, acquired more than 500,000 acres of unleased state land in a state North Slope areawide lease sale.

“Our jaws dropped when we saw what Great Bear was planning. We immediately put a lot of people on the problem of what to do about the shale resource,” and its evaluation, Decker told members of the geological society.

The area is to the south of the Prudhoe Bay field and companies have explored several times looking for conventional oil fields. Great Bear said it was looking for something new, potentially recoverable oil from shale formations that are the source rocks for the big conventional fields on the Slope.

Many geologists believe most of the oil contained in the source rocks is still there. However, until recently it wasn’t thought that oil and gas fluids can flow through extremely small pore spaces in the shale, which are much smaller than the pores in conventional oil reservoirs that contain oil.

Other companies may be onto shale oil, too. Since Great Bear’s leases were purchased, Repsol, the Spain-based major company, acquired leases on a substantial amount of acreage west of Great Bear’s leases in a deal with independent Armstrong Oil and Gas.

In his presentation, Decker compared the North Slope potential to the Bakken shale oil play in North Dakota and the Eagleford shale play in Texas, places where industry activity is now intense. There are many similarities between the shale there and on the Slope, he said.

Shale oil plays, like other unconventional oil and gas resources, generally occur in a continuous “fairway” of hydrocarbon-saturated rocks over broad areas, as opposed to conventional oil that is found in discrete traps, Decker said.

In other words, the resource is big and its presence is known. The North Slope shale fairway may be as long as 120 miles, east to west. With shale formations covering large areas the drilling and production is more like a manufacturing than conventional oil and gas drilling, which has risks that the petroleum won’t be there.

The resource risk is less than conventional oil because it is known that the oil is there. The question is whether costs are reasonable enough that it can be produced profitably.

North Slope costs are high, and a key question facing Great Bear is whether the wells, roads, pads and other facilities can be built at a low enough cost.

Decker’s second point is that massive stimulations are needed to get the oil to flow. The accepted procedure is commonly now called “fracking,” where the rocks are fractured by high-pressure injection of large volumes of fluid. The practice has become controversial in parts of the Lower 48 due to environmental problems.

Great Bear’s interest is primarily in two shale formations, the Shublik formation, which appears to be about 150 feet to 250 feet thick, and the Lower Kingak formation, which appears to be about 175 feet to 550 thick, based on the available data. There is also a third shale formation in the area, the Hue.

Oil in these shales are thought to be of good quality. Oil is known to have seeped from the Shublik shale over geologic time to accumulate in the Kuparuk River and the Northstar fields, where the API gravity (an index of oil quality) ranges from 21 degrees to 27 degrees API at Kuparuk and 43 degrees to 45 degrees at Northstar. (Higher API numbers indicate greater quality of the oil).

The Kingak shale, meanwhile, has been identified as the source of the high-quality 45 degree API oil in the Alpine field, and the Hue shale is believed to be the source of the 38 degree API oil found in the small Tarn deposit that is south of the Kuparuk field.

There’s no guarantee that the oil in the shale is as high an API gravity as the oil in the producing fields, but the odds are good that it is given that the Kuparuk, Alpine, North Star and Tarn oils originated in the shales being considered as targets for drilling.

Also, the high gravity numbers are encouraging in regard to another concern of whether the oil is light enough to actually flow through the tight rock of the shale. Lighter oils with higher API numbers generally flow well, however.

Decker said the shale formations in the area where Great Bear has leased appear to have the right composition of organic content and porosity and permeability of the rocks based on research by the U.S. Geological Survey.

There are still a lot of questions. Great Bear plans four test wells this winter aimed at answering some unknowns. The wells will be drilled off gravel pads near the Dalton Highway.

If the results of those wells are positive, the next step would be to drill pilot production wells, which would probably be done in the next two years, Decker said.

Decker said some information on the whether oil and gas will flow through the North Slope shales came from a production test natural gas from a well at the Kemek gas discovery on the eastern North Slope. The well flowed at 12 million cubic feet a day from the Shublik shale, the same shale Great Bear is targeting farther west.

Another indicator, this time with oil, came from production tests of the Gull Island and West Kuparuk exploration wells, which flowed at rates of 1,100 barrels per day to 2,000 barrels per day, also from the Shublik shale.

“This is really encouraging,” Decker said.

Information also is needed on the mechanical properties of the rock, particularly how brittle it is. Since shale oil and gas production depends on fracking, or fracturing, the tight rocks to allow the hydrocarbons to flow, the shale rocks must be brittle enough to fracture when high pressure fluids are injected.

There are a number of other issues that need answering, Decker said. A big one is where the water will come from to use in fracturing. The process requires large volumes of water, up to 6 million gallons a well, and water access from tundra lakes is already a concern on the Slope for certain uses, like building winter ice roads.

Water from the Beaufort Sea, treated at an existing seawater treatment plant, is one possible solution, Decker said. Another is water produced from underground reservoirs near the shale wells being drilled.

Disposal of the fluids used in the fracturing is another major concern. Some of the fluids may be recycled, and experience from the Lower 48 indicates that this might be done with about 25 percent of the fluids, Decker said. The fluids used in fracturing are typically 96 percent water, 3.8 percent sand with the remainder being chemicals like gels, which add special properties to the fluid mixture.

Another concern is the surface impact of the network of pads and roads that will be needed for shale oil production, Decker said. There is no doubt that a network of permanent year-round roads will be needed, along with numerous gravel pads.

A principal concern will be the effect of this on wildlife in the area, particularly caribou. The surface developments in the existing  oil fields involve production pads, roads and pipelines that are widely spaced and miles apart.

These have had no discernible effect on caribou, birds or other wildlife. A more intense surface footprint of a dense network of roads, pads and pipelines could be another question, however.

Tim Bradner can be reached at


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