With Great Bear Petroleum preparing to drill its first Alaska shale oil test well, investigating the possibility of producing oil direct from the prolific North Slope oil source rocks, state officials are taking an active interest in smoothing the path toward shale oil development if production proves feasible.
The state views the region of highest shale oil potential as lying along a 400-mile-long fairway, running east from the Chukchi Sea coast into and across the area where Great Bear has its leases to the south of the producing oil fields in the central North Slope, Greg Hobbs, a petroleum engineer with Alaska's Division of Oil and Gas, told Petroleum News. That fairway is similar in size to the region occupied by the successful Eagle Ford shale oil and gas play in Texas, Hobbs said.
But although the U.S. Geological Survey has estimated the possibility of up to 2 billion barrels of shale oil resources in northern Alaska, USGS has also said that until someone demonstrates that oil will flow from North Slope source rock there remains the possibility of zero Alaska shale oil production.
On the other hand, with some of the most promising shale oil possibilities on state land, with known high-quality oil originating from North Slope sources, and with the possibility of exploiting three different source rock intervals at single locations, the North Slope would seem to have things going for it when it comes to unconventional oil.
Experience in Texas has shown that shale oil can move into production mode as soon as three years from drilling the first successful proof-of-concept well, so the state wants to make sure that it is ready to efficiently handle shale oil development if the opportunity arises, Hobbs said.
A task force of eight to 10 people from state agencies has been meeting to evaluate what might be involved in North Slope shale oil development, Hobbs said. The Alaska departments of Natural Resources, Fish and Game and Environmental Conservation have representatives on the task force, which also has contacts with the Department of Transportation & Public Facilities, and the Alaska Oil and Gas Conservation Commission, Hobbs said.
The development of shale oil resources would increase state production and revenue at a time when production is falling. So the state is eager to see development but must also figure out how to achieve the necessary environmental conservation and protection.
From an environmental and permitting perspective, the state sees four main issues that could prove challenging for such development: subsistence resources, wetlands air quality and fresh water supply, Hobbs said.
Commercial success in shale oil hinges on development and production costs, oil productivity and the price of oil, Hobbs said. A key to the productivity part of this three-variable equation is the ability to drill many wells.
"The production of an oil shale play is maintained by the drilling," Hobbs said.
Although a shale oil well may initially produce oil at a high rate, perhaps 1,000 barrels per day or more, production tends to decline rapidly, typically stabilizing at a more long-term rate of perhaps 100 to 200 barrels a day. In the Bakken play in North Dakota, for example, total production is running at about 488,000 barrels a day from 6,000 wells, which is an average daily well production of just 80 barrels, Hobbs said.
The need for a continuous drilling program to sustain production on Alaska's North Slope may require the packaging of permits, enabling multiple drilling operations to be permitted in batches, without losing agencies' regulatory authority and oversight.
Hobbs said he does not think the type of single-well drilling pad used in the Bakken, for example, would be practical in the tundra of northern Alaska, given the intense amount of drilling required.
"In my opinion it would be cost-prohibitive to try to do a development in Alaska like they're doing in the Lower 48," Hobbs said. "They're not contending with wetlands there."
Instead, Hobbs has proposed a multi-well pad scheme for North Slope shale oil development. This model is entirely hypothetical and may not represent what a developer would actually do, Hobbs emphasized. However, the model can provide some insights into what might be involved, and how the permitting of a development might be carried out, he said.
Hobbs envisions a series of 840-foot-by-420-foot gravel pads, perhaps connected by a gravel road, extending east-west through a shale oil development area from the existing North Slope haul road. Each pad would accommodate 12 wellheads, with each well running at a steep angle down to the oil source before splitting into two horizontal, lateral well bores. The result would be 24 lateral wells penetrating subsurface source rock in an area centered under the pad and extending four miles east-west and three miles north-south.
To access the entire extent of subsurface source rock across a leased area, the pads would be four miles apart in an east-west orientation, with similar east-west lines of pads developed at three-mile intervals, north and south.
Hobbs' concept involves a single rig drilling all of the wells for a single pad during a single year. While that drilling is in progress, the next pad and its associated gravel road would be constructed, ready for drilling in the following year. Thus, year by year, the development would move out across the area of the shale oil play, along a development corridor.
The wells would probably go to depths of around 10,000 feet, with 10,000-foot horizontal laterals, similar to deviated and horizontal wells already drilled on the North Slope, Hobbs said.
"I don't see a whole lot of difference in well design," he said.
And, although shale oil production depends on the hydraulic fracturing of the oil source rock, companies operating in Alaska already have extensive experience in using "fracking" techniques -- about 25 percent of the oil wells that have been drilled in Alaska have used hydraulic fracturing to improve productivity, Hobbs said.
With this type of development, it would potentially be possible to use relatively lightweight, truckable production facilities, with a high capacity facility moved to serve pads that have come newly online and which have the high initial production rates characteristic of shale oil development. The more mature pads could perhaps be hooked up to smaller, lower capacity systems, Hobbs said.