Independents exploring potential North Slope shale oil resources are bullish on test drilling results so far, but the companies also admit to big unknowns. Some key questions will be answered by drilling this winter in Icewine No. 2, a follow-up test to Icewine No. 1 drilled last winter.
Drilling last year did result in an important step forward, however, by confirming the finding of hydrocarbons in the liquid, or oil, phase, at Icewine No. 1.
Paul Basinski, CEO of Burgundy Xploration of Houston, one of the companies, said that questions now include how “brittle” the shale is, whether it can be fractured in a way that oil can be extracted and at what rates oil may flow.
Burgundy and its partner, Australia-based 88 Energy, plan to do a test fracture and flow test of the vertical well at Icewine No. 2. If the results are positive the companies would drill a 5,000-foot horizontal leg that would also be tested.
Steve Moothart, a geologist at the state Division of Oil and Gas, said the Slope shale formations appear to differ in their brittleness based on what is known so far. The Shublik, one formation, appears to be more brittle and easier to fracture compared with a second formation, the Hue Shale/GRZ. Much more work needs to be done, he said. “We need to have test fractures done in both to really know,” Moothart said.
Even if shales can be fractured and oil extracted it’s not known that production will really be economic given the notorious high costs of the Slope.
Development issuesA North Slope shale play can’t be developed in the way it is done in the Bakken and Eagle Ford with small pads and the wide spread of infrastructure with flow lines and roads, Basinski said.
What might be feasible, Basinski said, is to adapt a method ConocoPhillips is using to develop thin sections of conventional reservoir on the west-central North Slope. This is with long extended-reach horizontal wells, possibly as long as 20,000 feet laterally, drilled from rigs on a single surface production pad.
ConocoPhillips is now drilling 26,000-feet horizontal wells and with a new, specialized rig being built will be able to drill 33,000 feet, which would allow that company to drain a 125-square-mile area.
Basinski said that long horizontal wells drilled in the shale and clustered at the surface on a single pad would be able to reach into large areas of underground rock. This spreads out the cost of the infrastructure and would lower per-barrel costs of production.
Another challenge, however, would be sourcing and disposing of the large quantities of water needed for large-scale hydraulic fracturing on the Slope, which is actually an arid area where the only fresh water available is in nearby shallow tundra lakes.
Sea water could be brought from the Beaufort Sea, which is several miles north, but that would be cost-prohibitive, Basinski said. Great Bear Petroleum, another independent interested in a Slope shale play, has developed an idea of tapping a deep reservoir of saline water that company found below its leases. This could provide the water, which could also be recycled or for used water to be injected back underground.
The current shale exploration is near the existing Dalton Highway, a state highway that connects the North Slope to Interior Alaska, as well as the Trans Alaska Pipeline System, which has ample available capacity.
Recovery rate unknownBased on modeling, but without the fracture and flow test, 88 Energy and Burgundy predicted a resource base on the companies’ leases of 1.4 billion to 3.6 billion barrels of oil equivalent, although how much of this could actually be recovered is not known.
There is one independent estimate, however, of potential shale oil resources that might be produced from the North Slope shales. That is by the U.S. Geological Survey, in 2012.
The USGS was modest in its assessment of how much oil could be extracted, with a mean estimate of 940 million barrels and an upper range estimate of 2 billion barrels. That was undiscovered oil that could be technically produced, without consideration of economics.
What may be significant, however, is that the USGS Slope numbers are similar to what the agency initially predicted, using similar methodologies, for the Eagle Ford Shale in Texas, which was 853 million barrels. The USGS early assessment for the Bakken was much larger, however, at 3.45 billion barrels of technically recoverable resources.
Lower organic contentMoothart, at the Division of Oil and Gas, said the organic content of the North Slope shales appear to be lower than the Bakken but on par with the Eagle Ford. The Slope total organic content, or TOC, has been measured at 2 percent to 5 percent, which is not as high as the Bakken, which averages 11 percent TOC. However, they appear similar to the Eagle Ford, which averages 2 percent to 7 percent. Burgundy and 88 Energy reported the TOC at 3.7 percent in their Icewine No. 1 results.
State geologists say Alaska’s shale belt lies in a large east-way “fairway” across the North Slope from the border of the Arctic National Wildlife Refuge in the east and extending into the National Petroleum Reserve-Alaska and the Chukchi Sea in the west.
Moothart said geologists know the most about the shale areas south of the currently producing oil fields in the central Slope, although characteristics of the shales farther west in NPR-A are believed to be similar.
The Shublik and Hue/HRZ, two of the large North Slope shales, are also known to be the source rocks for oil that accumulated in large conventional North Slope producing fields north of the shale belt.