State agencies have identified some key technology and permitting challenges for a North Slope shale oil play, an official in the state Division of Oil and Gas says.
Alaska-based independent Great Bear Petroleum and Halliburton are working in a partnership to test the production potential of a large shale formation south of the producing Prudhoe Bay and Kuparuk Ruver fields, with the first two test wells planned this spring, said Greg Hobbs, a petroleum engineer in the state Division of Oil and Gas.
Great Bear acquired 500,000 acres of state leases in the shale area in a 2010 lease sale and negotiated its deal with Halliburton in 2011. Separately, San Diego-based Royale Energy Inc. acquired 100,480 acres in the shale areas in a December 2011 state lease sale.
If it happens, a North Slope shale play could potentially affect an area as large as the Prudhoe Bay and Kuparuk River fields 30 miles to the north.
Hobbs is leading a state team assessing problems with securing state and federal permits for such a large undertaking, which would have substantial effects on surface lands.
“We believe a North Slope shale play would be very similar to the Eagleford shale development now happening in Texas,” in terms of the scale of surface facilities and resource potential, Hobbs said.
High costs on the North Slope could be a barrier. Also, a shale oil development on the Slope would be done substantially different than those in the Bakken in North Dakota and Eagleford.
There are three shale formations in the area that are known to be the source rocks for the large conventional fields a few miles north, the most important being the Shublik shale, the source of oil for the conventional Prudhoe Bay field, he said.
State geologists have little doubt oil is in the shale and that it is of good quality, but a key technical question is whether the shales are brittle enough to be fractured so the oil will flow, Hobbs said.
Once that is answered in the tests to be drilled this spring, the second concern is for a source of water to make fracturing fluid, he said. Unlike in the Eagleford and Bakken, there is no practical source of surface water on the North Slope for fluids needed for large-scale hydraulic fracturing operations.
The state team assumed that 1 million to 4 million gallons of water will be needed for each horizontal shale oil well, based on data from the Eagleford, Hobbs said. In conventional drilling on the Slope, tundra lakes, even when frozen, are tapped for water, but doing this on a scale needed for shale oil drilling would be major issues for federal and state environmental agencies.
“The state is very concerned about any use of fresh water,” Hobbs said.
A solution could be tapping underground reservoir water if it exists in the area. This could be present if the water-bearing part of the large Ivishak formation from Prudhoe Bay extends that far south, which geologists believe. Still, the availability of the water must be confirmed by drilling, Hobbs said.
However that water would be brackish, and shale oil operators in the Lower 48 have typically used fresh water. The state believes the effectiveness of brackish water for use in fracturing is an uncertain, although both Great Bear and Halliburton have said they believe it can be used, Hobbs said.
The are a host of other technical questions such as what types of down-hole pumps can function in highly-deviated wells drilled on multi-well pads.
Pumping jacks, the well-known lift mechanisms typically seen in low-producing Lower 48 oil wells, would be impractical on the North Slope because of weather and the deviated, high-angle wells. Semi-submersible pumps could be used but they do not accommodate easily to the declines in production commonly seen with shale oil wells, at least at first, Hobbs said.
A key difference with Lower 48 shale plays is that North Slope conditions will require multi-well pads instead of single-well pads that are common in the Bakken and Eagleford.
A scenario developed by the state, to assess permitting difficulties, assumes each pad covering about four acres with 12 wells per pad and each well with two below-ground horizontal production legs about 10,000 feet in length. In its planning, the state is assuming four miles between each producing pad, with gravel roads connecting the pads.
The gravel requirements for pads and roads would be substantial, Hobbs said, with 105,000 cubic yards of gravel needed for each pad and about 54,000 cubic yards needed for each mile of road.
The development scenario assumes an operator using 12 rigs and drilling about 200 wells per year, and working over a 10-year period.
Development could begin where Great Bear and Halliburton are planning the initial test wells on gravel pads adjacent to at the existing Dalton Highway, and extending east or west.
The initial shale play area could extend across an area of 50 miles east and west and about 19 miles north-south, Hobbs said, although the shale formations are believed to extend far to the west into the National Petroleum Reserve-Alaska.